2018 Annual Report
The Williams Companies, Inc.
We make energy happen.®
Financial Highlights
Dollars in millions, except per-share amounts
2018
2017
2016
2015
2014
Revenues
$8,686
$8,031
$7,499
$7,360
$7,637
Net income (loss) from continuing operations 1
193
2,509
(350)
(1,314)
2,335
Amounts attributable to The Williams Companies, Inc.:
Net income (loss) from continuing operations1
(155)
2,174
(424)
(571)
2,110
Diluted earnings (loss) per common share:
Net income (loss) from continuing operations1
(0.16)
2.62
(0.57)
(0.76)
2.91
Total assets at December 31
45,302
46,352
46,835
49,020
50,455
Commercial paper and long-term debt
due within one year at December 31
47
501
878
675
802
Long-term debt at December 31
22,367
20,434
22,624
23,812
20,780
Stockholders’ equity at December 312
Cash dividends declared per common share
14,660
1.360
9,656
1.200
4,643
1.680
6,148
2.450
8,777
1.958
1 Net income (loss) from continuing operations:
• For 2018 includes a $1.849 billion impairment of certain assets located in the Barnett Shale region, partially offset by a $591 million gain on
the sale of our Four Corners area assets, a $141 million gain on the deconsolidation of certain Permian assets, and a $101 million gain from
the sale of our Gulf Coast pipeline system assets;
• 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.
2 Stockholders’ equity at December 31:
• The increase in 2018 reflects our merger with WPZ;
• The increase in 2017 includes our issuance of common stock as part of our Financial Repositioning.
Front Cover: Station 32 in Wharton County, Texas, is one of three compressor stations constructed
as part of the Gulf Connector project, which was placed into service in January 2019. Photo by
Williams employee Trey Moore, Houston, Texas.
Forward-Looking Statements: Any statements included in this 2018 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 Stockholder Letter
3 Directors and Officers
5 Form 10-K
“We continue to collaborate with our customers to deliver
safe, reliable and more efficient ways to provide the
services our customers value.”
President and Chief Executive Officer
Alan S. Armstrong
Dear Fellow Stockholders,
Our consistent, natural gas-focused
strategy delivered solid and
predictable growth in 2018, allowing
us to once again post financial
metrics at the top end of our guidance
range. We achieved an all-time record
for Adjusted EBITDA, and $4.6 billion
in asset sales over the past two and
a half years has dramatically reduced
commodity exposure and improved
leverage metrics for Williams. We
also successfully executed the
Williams Partners roll-up transaction,
re-establishing the company as a
simplified C-Corp with investment-
grade credit.
I’m extremely pleased with our
teams’ strong execution in 2018.
We continue to collaborate with our
customers to deliver safe, reliable
and more efficient ways to provide
the services our customers value.
This includes making great progress
in overcoming a highly challenging
regulatory and permitting environment
to place critical new Transco projects,
like Atlantic Sunrise, into full service.
Backed by long-term shipper
commitments, this historic project,
brought into service in October, made
the largest-volume pipeline system in
the country an even bigger network,
adding an additional 1.7 billion
cubic feet per day (approximately
12 percent) to the Transco system.
In 2019, Williams will benefit from
a full year of revenue from Atlantic
Sunrise — a project that is significant
for our customers in Pennsylvania and
our fast-growing demand markets.
Atlantic Sunrise has helped alleviate
infrastructure bottlenecks and
extended the bi-directional flow
of the Transco system, directly
connecting Marcellus gas supplies
with markets as far south as Alabama.
Atlantic Sunrise’s impact on the
debottlenecking of the Northeast
has helped spur the beginnings of
what we believe will be accelerated
growth in that region for many years
to come. In our Northeast G&P
segment, for example, fourth-quarter
2018 gathering volumes increased by
13 percent over fourth-quarter 2017
— increasing fourth-quarter 2018
Northeast G&P segment EBITDA by
nearly 30 percent. We expect the
increasing trend for gathered volumes
to persist in 2019.
Our robust capital investment
program continues to provide much
higher than the industry average
returns because our projects take
advantage of our powerful network
of existing assets. These investments
further strengthen our competitive
advantage and connect our
customers to the best markets and
long-term reliable supplies.
We also exercised capital discipline in
2018 by funding much of these high
return projects via the sale of less
strategic assets with lower growth.
This includes opportunities like our
growth in the DJ Basin, which was
funded through our exit from our
legacy Four Corners Area position.
The quality and predictability of
our cash flows, combined with the
accelerating demand for natural gas,
point to continued growth in 2019.
In fact, after setting Transco delivery
records in 2018 and establishing
the annual throughput record for
Northwest Pipeline in 2018, we’ve
already eclipsed Transco’s one-day
and three-day delivery records in
2019. We’ve also placed the Gulf
Connector project into service to
serve two global LNG export facilities
and continue to explore value-
creating transactions to optimize
our portfolio and strengthen our
balance sheet.
We are committed to delivering
results in a way that also meets the
needs of our stakeholders, and
we remain engaged in the critical
discussions on key issues shaping
our industry. In 2018, we expanded
our Environmental, Social and
Governance (ESG) disclosures
on our website and will further
expand these disclosures in
2019. We also strengthened our
exceptional Board of Directors
with two new appointments.
2018 Annual Report
The Williams Companies, Inc.
1
Our execution and results over the
past year highlight why we are so
bullish on the future. Williams has
positioned itself as the leading
natural gas infrastructure company
in the United States, now operating
as a simplified and focused C-Corp,
with an attractive suite of assets,
investment-grade credit ratings and
strong, steady, growing earnings
and EBITDA.
On behalf of the Board of Directors
and our employees across the
country, thank you for your continued
trust in Williams.
Sincerely,
Alan S. Armstrong
President and Chief Executive Officer
March 28, 2019
2
The Williams Companies, Inc.
2018 Annual Report
BOARD COMMITTEES
Audit Committee
Stephen I. Chazen
Charles I. Cogut
Michael A. Creel
Vicki L. Fuller
Peter A. Ragauss (Chair)
William H. Spence
Compensation & Management
Development Committee
Stephen W. Bergstrom
Nancy K. Buese
Kathleen B. Cooper
Scott D. Sheffield (Chair)
Murray D. Smith
Nominating & Governance
Committee
Stephen W. Bergstrom
Stephen I. Chazen
Charles I. Cogut
Kathleen B. Cooper (Chair)
Vicki L. Fuller
Peter A. Ragauss
Environmental, Health
& Safety Committee
Nancy K. Buese
Michael A. Creel
Scott D. Sheffield
Murray D. Smith (Chair)
William H. Spence
D I R E C T O R S A N D O F F I C E R S
DIRECTORS
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.
NANCY K. BUESE
Denver, Colorado
Executive Vice President
and Chief Financial Officer,
Newmont Mining Corporation.
Director since 2018.
STEPHEN I. CHAZEN
Houston, Texas
President, Chief Executive
Officer and Chairman,
Magnolia Oil & Gas Corporation.
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.
VICKI L. FULLER
Brooklyn, New York
Former Chief Investment Officer, New
York State Common Retirement Fund.
Director since 2018.
PETER A. RAGAUSS
Houston, Texas
Former Senior Vice President
and Chief Financial Officer,
Baker Hughes Incorporated.
Director since 2016.
SCOTT D. SHEFFIELD
Irving, Texas
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.
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
DEBBIE L. COWAN
Senior Vice President and
Chief Human Resources Officer
SCOTT A. HALLAM
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
2018 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, 2018
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 every Interactive Data File required to be submitted 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
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 $21,489,112,717.
The number of shares outstanding of the registrant’s common stock outstanding at February 15, 2019 was 1,210,981,263.
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 9, 2019, are incorporated
into Part III, as specifically set forth in Part III.
THE WILLIAMS COMPANIES, INC.
FORM 10-K
TABLE OF CONTENTS
PART I
Item 1.
Business ..........................................................................................................................................................
Website Access to Reports and Other Information .........................................................................................
General............................................................................................................................................................
Business Segments..........................................................................................................................................
Northeast G&P................................................................................................................................................
Atlantic-Gulf...................................................................................................................................................
West ................................................................................................................................................................
Other ...............................................................................................................................................................
Service Assets, Customers, and Contracts ......................................................................................................
Additional Business Segment Information .....................................................................................................
Regulatory Matters .........................................................................................................................................
Environmental Matters ...................................................................................................................................
Competition ....................................................................................................................................................
Employees.......................................................................................................................................................
Item 1A. Risk Factors ....................................................................................................................................................
Item 1B. Unresolved Staff Comments ...........................................................................................................................
Item 2.
Properties ........................................................................................................................................................
Legal Proceedings...........................................................................................................................................
Item 3.
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.........................................................................................................................................................
Item 6.
Selected Financial Data ..................................................................................................................................
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations .........................
Item 7A. Quantitative and Qualitative Disclosures About Market Risk........................................................................
Financial Statements and Supplementary Data ..............................................................................................
Item 8.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.........................
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 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
Northwest Pipeline: Northwest Pipeline LLC
Transco: Transcontinental Gas Pipe Line Company, LLC
WPZ: Williams Partners L.P. Effective August 10, 2018, we completed our merger with WPZ, pursuant to which
we acquired all outstanding common units of WPZ held by others and Williams continued as the surviving
entity.
Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of
December 31, 2018, we account for as an equity-method investment, including principally the following:
Aux Sable: Aux Sable Liquid Products LP
Brazos Permian II: Brazos Permian II, LLC
Caiman II: Caiman Energy II, LLC
Discovery: Discovery Producer Services LLC
Gulfstream: Gulfstream Natural Gas System, L.L.C.
Jackalope: Jackalope Gas Gathering Services, L.L.C.
Laurel Mountain: Laurel Mountain Midstream, LLC
OPPL: Overland Pass Pipeline Company LLC
RMM: Rocky Mountain Midstream Holdings 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 2015 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
ETE Merger Agreement: Merger Agreement and Plan of Merger of Williams with Energy Transfer Equity, L.P.
and certain of its affiliates
Fractionation: The process by which a mixed stream of natural gas liquids is separated into its constituent products,
such as ethane, propane, and butane
Geismar Incident: An explosion and fire which occurred on June 13, 2013, at our formerly owned Geismar olefins
plant and rendered the facility temporarily inoperable.
IDR: Incentive distribution right
LNG: Liquefied natural gas; natural gas which has been liquefied at cryogenic temperatures
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
WPZ Merger: The August 10, 2018, merger transactions pursuant to which we acquired all outstanding common
units of WPZ held by others, merged WPZ into Williams, and Williams continued as the surviving entity.
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.
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, information regarding corporate social responsibility, 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 in the United States.
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; and Pittsburgh, Pennsylvania. Our telephone number is
918-573-2000.
On August 10, 2018, we completed our merger with Williams Partners L.P. (WPZ), our previously consolidated
master limited partnership, pursuant to which we acquired all of the approximately 256 million publicly held outstanding
common units of WPZ in exchange for 382 million shares of our common stock in a noncash equity transaction.
WPZ MERGER
BUSINESS SEGMENTS
Prior to our merger with WPZ, we had one reportable segment, Williams Partners. Beginning in the third-quarter
2018, consistent with the manner in which our chief operating decision maker evaluates performance and allocates
resources, our operations are now presented within the following reportable segments: Northeast G&P, Atlantic-Gulf,
and West. Prior period segment disclosures have been recast for the new segment presentation. Our reportable segments
are comprised of the following businesses:
• Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus Shale
region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern 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 equity-method investments with an
approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia
Midstream Investments).
4
• Atlantic-Gulf is comprised of our 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 60 percent equity-method investment in Discovery, and a 41 percent
interest in Constitution (a consolidated entity), which is developing a pipeline project (see Note 4 – Variable
Interest Entities of Notes to Consolidated Financial Statements).
• West is comprised of our interstate natural gas pipeline, Northwest Pipeline, and our gathering, processing,
and treating operations in Colorado, Wyoming, and 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. This segment also includes our
NGL and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL
fractionator near Conway, Kansas, and a 50 percent equity-method investment in OPPL, a 50 percent interest
in Jackalope (an equity-method investment following deconsolidation as of June 30, 2018), a 50 percent equity-
method investment in RMM, a 15 percent equity-method investment in Brazos Permian II, and our previously
owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-
Continent region (see Note 6 – Investing Activities of Notes to Consolidated Financial Statements). West also
included our former natural gas gathering and processing assets in the Four Corners area of New Mexico and
Colorado (see Note 3 – Divestitures of Notes to Consolidated Financial Statements).
• Other includes our 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 3 – Divestitures of Notes to
Consolidated Financial Statements), and a refinery grade propylene splitter in the Gulf region, which was sold
in June 2017. This segment also included our previously owned Canadian assets, which included 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. Other also includes minor business activities
that are not operating segments, as well as corporate operations.
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.
Northeast G&P
This segment includes our natural gas gathering, compression, processing, and NGL fractionation business in the
Marcellus and Utica Shale regions in Pennsylvania, West Virginia, New York, and Ohio.
The following tables summarize the significant consolidated assets of this segment:
Ohio Valley Midstream.........
Susquehanna Supply Hub.....
Cardinal (1)...........................
Flint.......................................
Beaver Creek ........................
Location
Ohio, West Virginia, &
Pennsylvania
Pennsylvania & New York
Ohio
Ohio
Pennsylvania
Natural Gas Gathering Assets
Inlet
Pipeline
Miles
Capacity Ownership
(Bcf/d)
Interest
216
454
360
75
41
0.8
3.6
0.9
0.5
0.1
100%
100%
66%
100%
100%
Supply Basins
Appalachian
Appalachian
Appalachian
Appalachian
Appalachian
_____________
(1) Statistics reflect 100 percent of the assets from our 66 percent ownership of Cardinal gathering system.
5
Natural Gas Processing Facilities
NGL
Inlet
Production
Capacity
Capacity
Ownership
Fort Beeler ...........................
Oak Grove............................
Marshall County, WV
Marshall County, WV
0.5
0.2
62
25
100%
100%
Appalachian
Appalachian
Location
(Bcf/d)
(Mbbls/d)
Interest
Supply Basins
We also own and operate fractionation facilities at Moundsville, de-ethanization and condensate facilities at our
Oak Grove plant, a condensate stabilization facility near our Moundsville fractionator, and an ethane transportation
pipeline. Our condensate stabilizers are capable of handling approximately 17 Mbbls/d of field condensate. NGLs are
extracted from the natural gas stream in our Oak Grove and Fort Beeler 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. Ethane produced at our de-ethanizer is transported to markets via our 50-mile ethane pipeline from
Oak Grove to Houston, Pennsylvania. The remaining mixed NGL stream from the de-ethanizer is then transported via
pipeline and fractionated at our Moundsville fractionation facilities, which are capable of handling approximately 43
Mbbls/d of mixed NGLs. The resulting products are then transported on truck or rail. Ohio Valley Midstream provides
residue natural gas take away options for our customers with interconnections to three interstate transmission pipelines.
Northeast G&P Operating Statistics
Volumes: (1)..................................................................................................
Gathering (Bcf/d) .......................................................................................
Plant inlet natural gas volumes (Bcf/d) ......................................................
NGL production volumes (Mbbls/d) (2) ....................................................
__________
(1) Excludes volumes associated with equity-method investments.
(2) Annual average Mbbls/d.
Certain Equity-Method Investments
Laurel Mountain
2018
2017
2016
3.63
0.52
46
3.31
0.43
38
3.21
0.33
32
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 0.6 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 723 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 134 Mbbls/
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. Blue Racer provides gathering, processing,
and marketing service primarily under percentage of liquids and fixed fee agreements.
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. Our partner operates a natural gas gathering pipeline,
inlet compression, two processing plants with a total capacity of 800 MMcf/d, 36 Mbbls/d of condensate stabilization
6
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 1,028 miles of gathering pipeline in
the Marcellus Shale region with the capacity to gather 4,623 MMcf/d of natural gas. 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. We operate the assets under long-term, 100 percent fixed-fee
gathering agreements that include significant acreage dedications and, in the Bradford Supply Hub, a cost of service
mechanism.
During the first quarter of 2017, we exchanged all of our 50 percent interest in the Delaware basin gas gathering
system, previously reported within the West segment, 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 6 – Investing Activities of Notes to Consolidated Financial Statements.)
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.
Atlantic-Gulf
This segment includes the Transco interstate natural gas pipeline that extends from the Gulf of Mexico to the
eastern seaboard, as well as natural gas gathering, processing and treating, crude oil production handling, and NGL
fractionation assets within the onshore, offshore shelf, and deepwater areas in and around the Gulf Coast states of Texas,
Louisiana, Mississippi, and Alabama. This segment also includes various petrochemical and feedstock pipelines in the
Gulf Coast region.
Transco
Transco is an interstate natural gas transmission company that owns and operates a 9,900-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.
At December 31, 2018, Transco’s system, which extends from Texas to New York, had a system-wide delivery
capacity totaling approximately 16.7 MMdth of natural gas per day. During 2018, Transco completed two fully-
contracted expansions, which added more than 1.75 MMdth of firm transportation capacity per day to the existing
pipeline system. Transco’s system includes 55 compressor stations, four underground storage fields, and one LNG
storage facility. Compression facilities at sea level-rated capacity total approximately 2.2 million horsepower.
Transco has natural gas storage capacity in four underground storage fields located on or near its pipeline system
or market areas and operates two of these storage fields. Transco also has storage capacity in an LNG storage facility
that 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.
7
At December 31, 2018, Transco’s customers had stored in its facilities approximately 130 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.
Gas Gathering, Processing, and Treating Assets
The following tables summarize the significant consolidated assets of this segment:
Natural Gas Gathering Assets
Inlet
Pipeline
Capacity
Ownership
Location
Miles
(Bcf/d)
Interest
Supply Basins
Canyon Chief, including
Blind Faith and Gulfstar
extensions ........................ Deepwater Gulf of Mexico
Other Eastern Gulf...............
Offshore shelf and other
Seahawk............................... Deepwater Gulf of Mexico
Perdido Norte....................... Deepwater Gulf of Mexico
Other Western Gulf ..............
Offshore shelf and other
156
46
115
105
105
0.5
0.2
0.4
0.3
0.5
100%
100%
100%
100%
100%
Eastern Gulf of Mexico
Eastern Gulf of Mexico
Western Gulf of Mexico
Western Gulf of Mexico
Western Gulf of Mexico
Natural Gas Processing Facilities
NGL
Inlet
Production
Capacity
Capacity
Ownership
Markham..............................
Mobile Bay ..........................
Markham, TX
Coden, AL
0.5
0.7
45
30
100%
100%
Western Gulf of Mexico
Eastern Gulf of Mexico
Location
(Bcf/d)
(Mbbls/d)
Interest
Supply Basins
Crude Oil Transportation and Production Handling Assets
In addition to our natural gas assets, we own and operate four deepwater crude oil pipelines and own production
platforms serving the deepwater in the Gulf of Mexico. Our offshore floating production platforms provide centralized
services to deepwater producers such as compression, separation, production handling, water removal, and pipeline
landings.
The following tables summarize the significant crude oil transportation pipelines and production handling platforms
of this segment:
Crude Oil Pipelines
Pipeline
Miles
Capacity
Ownership
(Mbbls/d)
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
8
Production Handling Platforms
Gas Inlet
Capacity
(MMcf/d)
Crude/NGL
Handling
Capacity
(Mbbls/d)
Devils Tower ...................................................
Gulfstar I FPS (1) ............................................
210
172
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.
Other NGL & Petchem Operations
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 previously owned pipelines in the Houston Ship Channel area which were used to transport a variety of products
including ethane, propane, ammonia, tertiary butyl alcohol, and other industrial products. These assets were sold in
November 2018.
Atlantic-Gulf Operating Statistics
Volumes: (1)
2018
2017
2016
Interstate natural gas pipeline throughput (Tbtu)..........................................
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)..........................................................
4,309
0.26
0.50
32
6
140
3,783
0.31
0.55
33
9
134
3,503
0.41
0.72
41
13
113
_____________
(1) Excludes volumes associated with equity-method investments.
(2) Annual average Mbbls/d.
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 594-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.
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. We own, through a subsidiary, a 50 percent equity-
method investment in Gulfstream. We share operating responsibilities for Gulfstream with the other 50 percent owner.
9
West
This segment includes the Northwest Pipeline interstate natural gas pipeline, as well as natural gas gathering,
processing, and treating assets in Colorado, Wyoming, Louisiana, Texas, Arkansas, and Oklahoma. This segment also
includes an NGL and natural gas marketing business, storage facilities, and an undivided 50 percent interest in an NGL
fractionator near Conway, Kansas.
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.
At December 31, 2018, Northwest Pipeline’s system, having long-term firm transportation and storage redelivery
agreements with aggregate capacity reservations of approximately 3.9 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 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.
Gas Gathering, Processing, and Treating Assets
The following tables summarize the significant consolidated assets of this segment:
Wamsutter ..........................
Southwest Wyoming ..........
Piceance .............................
Barnett Shale......................
Eagle Ford Shale ................
Haynesville Shale...............
Permian ..............................
Location
Wyoming
Wyoming
Colorado
Texas
Texas
Louisiana
Texas
Natural Gas Gathering Assets
Pipeline
Miles
Inlet
Capacity
(Bcf/d)
Ownership
Interest
Supply Basins/Shale
Formations
2,084
1,614
352
845
1,275
626
100
0.7
0.5
1.8
0.8
0.6
1.8
0.1
0.9
100%
100%
(1)
100%
100%
100%
100%
100%
Wamsutter
Southwest Wyoming
Piceance
Barnett Shale
Eagle Ford Shale
Haynesville Shale
Permian
Miss-Lime, Granite
Wash, Colony Wash,
Arkoma
Mid-Continent....................
Oklahoma & Texas
2,248
__________
(1) 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.
10
Natural Gas Processing Facilities
Inlet
Capacity
(Bcf/d)
NGL
Production
Capacity
(Mbbls/d)
Location
Echo Springs .......................
Opal.....................................
Willow Creek ......................
Parachute.............................
Echo Springs, WY
Opal, WY
Rio Blanco County, CO
Garfield County, CO
0.7
1.1
0.5
1.1
58
47
30
6
Marketing Services
Ownership
Interest
100%
100%
100%
100%
Supply Basins
Wamsutter
Southwest Wyoming
Piceance
Piceance
We market NGL products to a wide range of users in the energy and petrochemical industries. The NGL marketing
business transports and markets our equity NGLs from the production at our processing plants, and also markets NGLs
on behalf of third-party NGL producers, including some of our fee-based processing customers, and the NGL volumes
owned by Discovery. The NGL marketing business bears the risk of price changes in these NGL volumes while they
are being transported to final sales delivery points. In order to meet sales contract obligations, we may purchase products
in the spot market for resale.
In certain situations to facilitate our gas gathering and processing activities, we buy natural gas from our producer
customers for resale.
Other NGL 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.
West Operating Statistics
Volumes:
2018
2017
2016
Interstate natural gas pipeline throughput (Tbtu) .......................................
Gathering (Bcf/d) .......................................................................................
Plant inlet natural gas (Bcf/d).....................................................................
NGL production (Mbbls/d) (1)...................................................................
NGL equity sales (Mbbls/d) (1) .................................................................
820
4.27
2.01
84
33
750
4.53
2.07
77
29
727
4.62
2.45
78
28
__________
(1) Annual average Mbbls/d.
Certain Equity-Method Investments
Jackalope gathering system
We operate and own a 50 percent interest in Jackalope which provides gas gathering and processing services for
the Powder River basin. During the second quarter of 2018, we deconsolidated Jackalope (see Note 4 – Variable Interest
Entities of Notes to Consolidated Financial Statements). Jackalope, which includes the Bucking Horse gas processing
plant, consists of a 257-mile natural gas pipeline, 0.2 Bcf/d of gas gathering inlet capacity, 0.1 Bcf/d of natural gas
processing inlet capacity, and 12 Mbbls/d of NGL production capacity.
11
Brazos Permian II
We acquired a non-operated 15 percent interest in Brazos Permian II in December 2018 by contributing cash and
our existing Delaware basin assets. This partnership consists of 725 miles of gas gathering pipelines, 260 MMcf/d of
natural gas processing inlet capacity, and 75 miles of crude oil gathering pipelines.
Rocky Mountain Midstream
During the third quarter of 2018, our joint venture, RMM, purchased a natural gas and oil gathering and natural
gas processing business in Colorado’s Denver-Julesburg basin. As of December 31, 2018, we own 50 percent of RMM.
RMM consists of 60 MMcf/d of gas processing capacity, an approximate 105-mile natural gas gathering system, and
an approximate 70-mile oil gathering system. There are two additional processing plants currently under construction
that are expected to increase natural gas processing capacity to 480 MMcf/d by the end of 2019.
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 1,035 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.
NGL volumes from our RMM equity-method investment are also expected to be transported on OPPL.
Other
Other includes our previously owned operations, minor business activities that are not operating segments, as well
as corporate operations.
Geismar Interest
In July 2017, we 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). Upon closing the sale, we entered
into a long-term supply and transportation agreement with the purchaser to provide feedstock to the plant via our Bayou
Ethane pipeline system.
Canadian Operations
We completed the sale of our 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, iso-butane, alky feedstock, and
condensate recovered from a third-party oil sands bitumen upgrader.
Service Assets, Customers, and Contracts
Interstate Natural Gas Pipeline Assets
Our interstate natural gas pipelines are subject to regulation by the FERC and as such, our rates and charges for
the transportation of natural gas in interstate commerce are subject to regulation. The rates are established through the
FERC’s ratemaking process.
12
Our interstate natural gas pipelines transport and store natural gas for a broad mix of customers, including local
natural gas distribution companies, public utilities, municipalities, direct industrial users, electric power generators,
and natural gas marketers and producers. We have firm transportation and storage contracts that are generally long-
term contracts with various expiration dates and account for the major portion of our regulated businesses. Additionally,
we offer storage services and interruptible transportation services under shorter-term agreements.
On August 31, 2018, Transco filed a general rate case with the FERC for an overall increase in rates. In September
2018, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general
rate filing to be effective March 1, 2019, subject to refund and the outcome of a hearing. The specific rates that reflected
a rate decrease were accepted, without suspension, to be effective October 1, 2018, as requested by Transco, and will
not be subject to refund.
Gathering, Processing and Treating Assets
Our gathering systems receive natural gas from producers’ oil and natural gas wells and gather these volumes to
gas processing, treating or redelivery facilities. Typically, natural gas, in its raw form, is not acceptable for transportation
in major interstate natural gas pipelines or for commercial use as a fuel. Our treating facilities remove water vapor,
carbon dioxide and other contaminants and collect condensate, but do not extract NGLs. We are generally paid a fee
based on the volume of natural gas gathered and/or treated, generally measured in the Btu heating value.
In addition, natural gas contains various amounts of NGLs, which generally have a higher value when separated
from the natural gas stream. Our processing plants extract the NGLs in addition to removing water vapor, carbon
dioxide, and other contaminants. NGL products include:
• Ethane, primarily used in the petrochemical industry as a feedstock for ethylene production, one of the basic
building blocks for plastics;
• Propane, used for heating, fuel and as a petrochemical feedstock in the production of ethylene and propylene,
another building block for petrochemical-based products such as carpets, packing materials, and molded plastic
parts;
• Normal butane, isobutane, and natural gasoline, primarily used by the refining industry as blending stocks for
motor gasoline or as a petrochemical feedstock.
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 revenue includes a share of the margins on the NGLs
produced. For the year ended December 31, 2018, 74 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, 2018, 26 percent of our NGL production volumes were under noncash
commodity-based contracts.
13
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 a customer
under such an agreement fails to meet its MVC for a specified period, it is obligated to pay a contractually determined
fee based upon the shortfall between the actual gathered or processed volumes and the MVC for the period contained
in the contract. When we conclude it is probable that the customer will not exercise all or a portion of its remaining
rights, we recognize revenue in an amount in proportion to the pattern of exercised rights within the respective MVC
period.
Demand for gas gathering and processing services is dependent on producers’ drilling activities, which is impacted
by the strength of the economy, natural gas prices, and the resulting demand for natural gas by manufacturing and
industrial companies and consumers. Our gas gathering and processing customers are generally natural gas producers
who have proved and/or producing natural gas fields in the areas surrounding our infrastructure. During 2018, our
facilities gathered and processed gas and crude oil for approximately 260 customers. Our top ten customers accounted
for approximately 70 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.
Key variables for our business will continue to be:
• Producer drilling activities impacting natural gas supplies supporting our gathering and processing volumes;
• Prices impacting our commodity-based activities;
• Retaining and attracting customers by continuing to provide reliable services;
• Revenue growth associated with additional infrastructure either completed or currently under construction;
• Disciplined growth in our service areas.
Crude Oil Transportation and Production Handling Assets
Our crude oil transportation revenues are typically volumetric-based fee arrangements. Crude oil marketing activity
is now presented on a net basis within Product costs in the Consolidated Statement of Operations in 2018 in conjunction
with the adoption of ASC 606. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary
of Significant Accounting Policies of Notes to Consolidated Financial Statements.) 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.
Additional Business Segment Information
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 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
14
our credit agreement, which also govern 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.
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 of our gas pipeline companies 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 gas 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. Our interstate gas pipeline companies establish rates
through the FERC’s ratemaking process. In addition, our interstate gas pipelines may enter into negotiated rate
agreements where cost-based recourse rates are made available. Key determinants in the FERC ratemaking process
include:
• Costs of providing service, including depreciation expense;
• Allowed rate of return, including the equity component of the capital structure and related income taxes;
• Contract and volume throughput assumptions.
The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the
reservation and commodity rates also impact profitability. As a result of these proceedings, certain revenues previously
collected may be subject to refund.
We also own interests in and operate two offshore transmission pipelines that are regulated by the FERC because
they are deemed to transport gas in interstate commerce. Black Marlin Pipeline Company provides transportation service
for offshore Texas production in the High Island area and redelivers that gas to intrastate pipeline interconnects near
Texas City. Discovery provides transportation service for offshore Louisiana production from the South Timbalier,
Grand Isle, Ewing Bank, and Green Canyon (deepwater) areas to an onshore processing facility and downstream
interconnect points with major interstate pipelines. In addition, we own a 50 percent equity-method investment in and
are 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.
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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.
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 2019
associated with this program to be approximately $86 million. Management considers costs associated with compliance
with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through Northwest
Pipeline’s and Transco’s rates.
We 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 2019 associated
with this program will be approximately $3 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 Regulations
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.
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Intrastate Liquids Pipelines in the Gulf Coast
Our intrastate liquids pipelines in the Gulf Coast are regulated by the Louisiana Public Service Commission, 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 gas and liquids pipelines located on the outer continental shelf are subject to the Outer Continental
Shelf Lands Act, 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 18 – 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 Part 1, Item 1A. “Risk Factors” — “The operation of our
businesses might 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;
• 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 Part 1, Item 1A. “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 18 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements.
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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
supply basins, our solid positions in growing shale plays, our reputation as a reliable operator, 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 Part 1, Item 1A. “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, 2019, we had 5,322 full-time employees.
EMPLOYEES
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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. 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 as discussed below. 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:
• Levels of dividends to Williams stockholders;
• Future credit ratings of Williams and its 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:
• Whether we are able to pay current and expected levels of dividends;
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• Whether we will be able to effectively execute our financing plan;
• Availability of supplies, market demand, and volatility of prices;
•
Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the
global credit markets and the impact of these events on 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 investment
opportunities;
• Our ability to acquire new businesses and assets and successfully integrate those operations and assets into
existing businesses as well as successfully expand our facilities, and to consummate asset sales on acceptable
terms;
• Development and rate of adoption of alternative energy sources;
• The impact of operational and developmental hazards and unforeseen interruptions;
• The impact of existing and future laws and regulations (including but not limited to the Tax Cuts and Jobs Act
of 2017), 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, as well as our ability to obtain sufficient construction related
inputs including skilled labor;
• 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;
• Acts of terrorism, cybersecurity incidents, and related disruptions;
• Additional risks described in our filings with the Securities and Exchange Commission.
Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained
in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We
disclaim any obligations to and do not intend to update the above list or announce publicly the result of any revisions
to any of the forward-looking statements to reflect future events or developments.
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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.
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 low commodity prices, or
a 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
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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 and domestic exports 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, 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. 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.
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We face opposition to operation and expansion of our pipelines and facilities from various individuals and groups.
We have experienced, and we anticipate that we will continue to face, opposition to the operation and expansion
of our pipelines and facilities from governmental officials, environmental groups, landowners, tribal groups, local
groups and other advocates. In some instances, we encounter opposition which disfavors hydrocarbon-based energy
supplies regardless of practical implementation or financial considerations. Opposition to our operation and expansion
can take many forms, including the delay or denial of required governmental permits, organized protests, attempts to
block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets, or
lawsuits or other actions designed to prevent, disrupt or delay the operation or expansion 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 delays or prevents the expansion
of our business, 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.
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 or assets may not be available
on terms and conditions we find acceptable or, where multiple parties are trying to acquire an acquisition candidate or
assets, 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. 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 proceeds from 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.
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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 our 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 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
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 100 percent of the equity interests of certain subsidiaries, including the Partially Owned Entities,
which may limit our ability to operate and control these subsidiaries. Certain operations, including the Partially
Owned Entities, are conducted through arrangements that may limit our ability to operate and control these
operations.
The operations of our current non-wholly-owned subsidiaries, including the Partially Owned Entities, are conducted
in accordance with their organizational documents. We anticipate that we will enter into more such arrangements,
including through new joint venture structures or new Partially Owned Entities. We may have limited operational
flexibility in such current and future arrangements and we may not be able to control the timing or amount of cash
distributions received. In certain cases:
• We cannot control the amount of cash reserves determined to be necessary to operate the business, which
reduces cash available for distributions;
• We cannot control the amount of capital expenditures that we are required to fund and 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;
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• We have limited ability to influence or control certain day to day activities affecting the operations;
• We may have additional obligations, such as required capital contributions, that are important to the success
of the operations.
In addition, conflicts of interest may arise between us, on the one hand, and other interest owners, on the other
hand. If such conflicts of interest arise, we may not have the ability to control the outcome with respect to the matter
in question. Disputes between us and other interest owners may also result in delays, litigation or operational impasses.
The risks described above or the failure to continue such arrangements could adversely affect our ability to conduct
the operations that are the subject of such arrangements which could, in turn, negatively affect our business, growth
strategy, financial condition and results of operations.
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.
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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.
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 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 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;
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• Operating in a marine environment.
Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental
pollution, impairment of our operations, loss of services to our customers, reputational damage, and substantial losses
to us. The location of certain segments of our facilities in or near populated areas, including residential areas, commercial
business centers, and industrial sites, could increase the level of damages resulting from these risks. An event such as
those described above could have a material adverse effect on our financial condition and results of operations,
particularly if the event is not fully covered by insurance.
We do not insure against all potential risks and losses and could be seriously harmed by unexpected liabilities or by
the inability of our insurers to satisfy our claims.
In accordance with customary industry practice, we maintain insurance against some, but not all, risks and losses,
and only at levels we believe to be appropriate. 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 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.
A breach of our information technology infrastructure, including a breach caused by a cybersecurity attack on us
or third parties with whom we are interconnected, may interfere with the safe operation of our assets, result in the
disclosure of personal or proprietary information, and harm our reputation.
We rely on our information technology infrastructure to process, transmit, and store electronic information,
including information we use to safely operate our assets. Our Board of Directors has oversight responsibility with
regard to assessment of the major risks inherent in our business, including cybersecurity risks, and reviews management’s
efforts to address and mitigate such risks, including the establishment and implementation of policies to address
cybersecurity threats. We have invested, and expect to continue to invest, significant time, manpower and capital in
our information technology infrastructure. However, 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. While we believe that we maintain appropriate information security policies, practices,
and protocols, we regularly face cybersecurity and other security threats to our information technology infrastructure,
which could include threats to our operational industrial control systems that are used to operate our pipelines, plants,
and assets. We face unlawful attempts to gain access to our information technology infrastructure, including coordinated
27
attacks from hackers, whether state-sponsored groups, “hacktivists”, or private individuals. We face the threat of theft
and misuse of sensitive data and information, including customer and employee information. We 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. We also are subject to
cybersecurity risks arising from the fact that our business operations are interconnected with third parties, including
third-party pipelines, other facilities and our contractors and vendors. In addition, the breach of certain business systems
could affect our ability to correctly record, process and report financial 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 or destruction of our assets, unnecessary waste, safety incidents, damage
to the environment, reputational damage, potential liability, the loss of contracts, the imposition of significant costs
associated with remediation and litigation, heightened regulatory scrutiny, increased insurance costs, and 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
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,
28
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.
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.
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 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.
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.
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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 an investment-grade credit rating by each of the three
credit ratings agencies.
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, 2018, was $22.4 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:
• 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.
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Our ability to comply with our debt covenants, to repay, extend, or refinance our existing debt obligations and to
obtain future credit will depend primarily on our operating performance. Our ability to refinance existing debt obligations
or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit
generally. If we are unable to comply with these covenants, meet our debt service obligations, or obtain future credit
on favorable terms, or at all, we could be forced to restructure or refinance our indebtedness, seek additional equity
capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.
Our failure to comply with the covenants in the documents governing our indebtedness could result in events of
default, which could render such indebtedness due and payable. We may not have sufficient liquidity to repay our
indebtedness in such circumstances. In addition, cross-default or cross-acceleration provisions in our debt agreements
could cause a default or acceleration to have a wider impact on our liquidity than might otherwise arise from a default
or acceleration of a single debt instrument. For more information regarding our debt agreements, please read Note 14
– 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.
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, 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;
31
• 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 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.
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
32
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 the 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.
Tax Reform made 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. 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. Although we expect the decreased
federal income tax rates will require us to return amounts to certain customers 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.
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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, Region 6, 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 July 23, 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 $1.6 million. We are continuing to work with the agencies to resolve this matter.
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 Transco’s Dalton expansion project. Pursuant to the
Consent Order, we paid a fine of $168,750 and agreed to perform a Corrective Action Plan, the completion of which
is pending.
On March 19, 2018, we received a Notice of Violation from the EPA, Region 8, regarding certain alleged violations
of the Clean Air Act at our Ignacio Gas Plant in Durango, Colorado, following a previous on-site inspection of the
facility. We were subsequently informed that this matter has been referred to the DOJ for handling. The Notice of
Violation does not contain an initial penalty assessment. We have responded to the alleged violations and continue to
work with the agencies to resolve this matter.
On March 20, 2018, we also received a Notice of Violation from the EPA, Region 8, regarding certain alleged
violations of the Clean Air Act at our Parachute Creek Gas Plant in Parachute, Colorado, following a previous on-site
inspection of the facility. We were informed that this matter has been referred to the DOJ for handling. The Notice of
Violation does not contain an initial penalty assessment. We have responded to the alleged violations and continue to
work with the agencies to resolve this matter.
On August 27, 2018, Northwest Pipeline LLC received a Notice of Violation/Cease and Desist Order from the
Colorado Department of Public Health & Environment regarding certain alleged violations of the Colorado Water
Quality Control Act and its General Permit under the Colorado Discharge Permit System related to its stormwater
management practices at two construction sites. The Notice of Violation does not contain an initial penalty assessment.
We have responded to the alleged violations and continue to work with the agency to resolve this matter.
Other environmental matters called for by this Item are described under the caption “Environmental Matters” in
Note 18 – 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.
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Other Litigation
The additional information called for by this Item is provided in Note 18 – 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.
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Executive Officers of the Registrant
The name, title, age, period of service, and recent business experience of each of our executive officers as of
February 21, 2019, 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.
Name and Title
Alan S. Armstrong
Director, Chief Executive Officer, and
President
Age
Period of Service
Business Experience in Past Five Years
56
2011 to present
Director, Chief Executive Officer, and President, The
Williams Companies, Inc.
2015 to 2018
Chairman of the Board, ACMP/WPZ
2014 to 2018
Chief Executive Officer, ACMP/WPZ
2012 to 2018
Director of the general partner, ACMP/WPZ
2011 to 2015
Walter J. Bennett
49
2015 to present
Senior Vice President - West
2013 to 2018
2017
2015
Chairman of the Board and Chief Executive Officer
of the general partner of Pre-merger WPZ
Senior Vice President- West, The Williams
Companies, Inc.
Senior Vice President - West of the general partner,
ACMP/WPZ
Director of the general partner, ACMP/WPZ
Senior Vice President - West of the general partner,
Pre-merger WPZ
John D. Chandler
49
2017 to present
Senior Vice President and Chief Financial Officer,
Senior Vice President and Chief Financial
Officer
2017 to 2018
2009 to 2014
Debbie Cowan
41
2018 to present
2013 to 2018
Senior Vice President - Chief Human
Resources Officer
Micheal G. Dunn
Executive Vice President and Chief
Operating Officer
The Williams Companies, Inc.
Director of the general partner, ACMP/WPZ
Senior Vice President and Chief Financial Officer,
Magellan GP, LLC
Senior Vice President - Chief Human Resources
Officer, The Williams Companies, Inc.
Global Vice President of Human Resources, Koch
Chemical Technology Group, LLC
53
2017 to present
Executive Vice President and Chief Operating Officer,
2017 to 2018
2015 to 2017
2010 to 2015
The Williams Companies, Inc.
Director of the general partner, ACMP/WPZ
President / Executive Vice President, Questar
Pipeline / Questar Corporation
President and Chief Executive Officer, PacifiCorp
Energy
Scott A. Hallam
42
2019 to present
Senior Vice President - Atlantic-Gulf, The Williams
Senior Vice President - Atlantic-Gulf
2017 to 2019
2015 to 2017
2013 to 2015
Companies, Inc.
Vice President GM Atlantic-Gulf, The Williams
Companies, Inc.
Vice President Northeast OA, The Williams
Companies, Inc.
General Manager - Utica, ACMP
John E. Poarch
53
2017 to present
Senior Vice President - Engineering Services, The
Senior Vice President - Engineering
Services
2017
2015 to 2017
Williams Companies, Inc.
Vice President - Commercial - West, The Williams
Companies, Inc.
Vice President - Commercial & Business
Development, The Williams Companies, Inc.
2011 to 2015
General Manager - Eagle Ford, ACMP
36
Name and Title
James E. Scheel
Age
Period of Service
Business Experience in Past Five Years
54
2014 to present
Senior Vice President - Northeast G&P, The Williams
Senior Vice President - Northeast G&P
2015 to 2017
Companies, Inc.
Director of the general partner, ACMP/WPZ
2012 to 2015
Director of the general partner, Pre-merger WPZ
2012 to 2014
Director of the general partner, Pre-merger ACMP
2012 to 2014
2012 to 2014
Senior Vice President - Corporate Strategic
Development, The Williams Companies, Inc.
Senior Vice President - Corporate Strategic
Development of the general partner, Pre-merger WPZ
Ted T. Timmermans
62
2005 to present
Vice President, Controller, and Chief Accounting
Vice President, Controller, and Chief
Accounting Officer
T. Lane Wilson
Senior Vice President and General
Counsel
2015 to 2018
Officer, The Williams Companies, Inc.
Vice President, Controller, and Chief Accounting
Officer of the general partner, ACMP/WPZ
52
2018 to present
Senior Vice President and General Counsel, The
2017 to 2018
2009 to 2017
Williams Companies, Inc.
Senior Vice President, General Counsel, and Chief
Compliance Officer, The Williams Companies, Inc.
United States Magistrate Judge for the Northern
District of Oklahoma
Chad J. Zamarin
42
2017 to present
Senior Vice President - Corporate Strategic
Senior Vice President - Corporate
Strategic Development
2017 to 2018
Development, The Williams Companies, Inc.
Director of the general partner, ACMP/WPZ
2014 to 2017
President - Pipeline and Midstream, Cheniere Energy
2011 to 2014
Chief Operating Officer, NiSource Midstream, LLC
and NiSource Energy Ventures, LLC
37
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 15, 2019, we had 6,780 holders of record of our common stock.
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, 2014. 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.,
Tallgrass Energy L.P., and Williams. The graph below assumes an investment of $100 at the beginning of the period.
Cumulative Total Shareholder Return
The Williams Companies, Inc.
S&P 500 Index
Bloomberg Americas Pipelines Index
s
r
a
l
l
o
D
$180
$160
$140
$120
$100
$80
$60
2013
2014
2015
2016
2017
2018
The Williams Companies, Inc................
S&P 500 Index .......................................
Bloomberg Americas Pipelines Index....
2013
100.0
100.0
100.0
2014
121.4
113.7
117.1
2015
73.8
115.2
64.4
2016
97.0
129.0
94.5
2017
98.9
157.2
94.3
2018
75.3
150.3
80.8
38
Item 6. Selected Financial Data
The following financial data at December 31, 2018 and 2017, and for each of the three preceding years in the
period ended December 31, 2018, 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 .................................................................................. $ 8,686
Net income (loss) from continuing operations (1) ...................
193
Amounts attributable to The Williams Companies, Inc.:
(Millions, except per-share amounts)
$ 7,360
$ 7,499
$ 8,031
(1,314)
(350)
2,509
$ 7,637
2,335
2018
2017
2016
2015
2014
Net income (loss) from continuing operations (1) ............
Diluted earnings (loss) per common share:
Net income (loss) from continuing operations (1).....
Total assets at December 31 .....................................................
Commercial paper and long-term debt due within one year at
December 31.........................................................................
Long-term debt at December 31...............................................
Stockholders’ equity at December 31 (2).................................
Cash dividends declared per common share ............................
_________
(1) Net income (loss) from continuing operations:
(155)
2,174
(424)
(571)
2,110
(.16)
45,302
2.62
46,352
(.57)
46,835
(.76)
49,020
2.91
50,455
47
22,367
14,660
1.360
501
20,434
9,656
1.200
878
22,624
4,643
1.680
675
23,812
6,148
2.450
802
20,780
8,777
1.958
• For 2018 includes a $1.849 billion impairment of certain assets located in the Barnett Shale region, partially
offset by a $591 million gain on the sale of our Four Corners area assets, a $141 million gain on the
deconsolidation of certain Permian assets, and a $101 million gain from the sale of our Gulf Coast pipeline
system assets;
• 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.
(2) Stockholders’ equity at December 31:
• The increase in 2018 reflects our merger with WPZ;
• The increase in 2017 includes our issuance of common stock as part of our Financial Repositioning.
39
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 through our gas pipeline and midstream business. Our operations
are located in the United States.
Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity
by providing high quality, low cost transportation of natural gas to large and growing markets. Our gas pipeline
businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates
and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment
of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through
the FERC’s ratemaking process. Changes in commodity prices and volumes transported have limited near-term impact
on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in
transportation rates.
The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream
infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting
new business by providing highly reliable service to our customers. These services include natural gas gathering,
processing, treating, and compression, NGL fractionation and transportation, crude oil production handling and
transportation, marketing services for NGL, oil and natural gas, as well as storage facilities.
Prior to our merger with Williams Partners L.P., our previously consolidated master limited partnership, in August
2018, we had one reportable segment, Williams Partners. Beginning in the third-quarter 2018, consistent with the
manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are
now presented within the following reportable segments: Northeast G&P, Atlantic-Gulf, and West. Prior period segment
disclosures have been recast for the new segment presentation. Our reportable segments are comprised of the following
businesses:
• Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus Shale
region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern 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 equity-method investments with an
approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia
Midstream Investments).
• Atlantic-Gulf is comprised of our 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 60 percent equity-method investment in Discovery, and a 41 percent
interest in Constitution (a consolidated entity), which is developing a pipeline project (see Note 4 – Variable
Interest Entities of Notes to Consolidated Financial Statements).
• West is comprised of our interstate natural gas pipeline, Northwest Pipeline, and our gathering, processing,
and treating operations in Colorado, Wyoming, and 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. This segment also includes our
NGL and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL
fractionator near Conway, Kansas, and a 50 percent equity-method investment in OPPL, a 50 percent interest
in Jackalope (an equity-method investment following deconsolidation as of June 30, 2018), a 50 percent equity-
method investment in RMM, a 15 percent equity-method investment in Brazos Permian II, and our previously
owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-
40
Continent region (see Note 6 – Investing Activities of Notes to Consolidated Financial Statements). West also
included our former natural gas gathering and processing assets in the Four Corners area of New Mexico and
Colorado (see Note 3 – Divestitures of Notes to Consolidated Financial Statements).
• Other includes our 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 3 – Divestitures of Notes to
Consolidated Financial Statements), and a refinery grade propylene splitter in the Gulf region, which was sold
in June 2017. This segment also included our previously owned Canadian assets, which included 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. Other also includes minor business activities
that are not operating segments, as well as corporate operations.
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 2018, we paid a regular quarterly dividend of $0.34 per share. On February 20, 2019, our board of
directors approved a regular quarterly dividend of $0.38 per share payable on March 25, 2019.
Overview
Net income (loss) attributable to The Williams Companies, Inc., for the year ended December 31, 2018, decreased
by $2.329 billion compared to the year ended December 31, 2017, reflecting a $2.112 billion increase to the provision
for income taxes driven by the absence of a 2017 benefit resulting from Tax Reform and a $159 million decrease in
operating income. The decrease in operating income reflects an increase of $667 million in Impairment of certain assets
and $403 million in lower gains from the sale of certain assets. These unfavorable changes were partially offset by the
absence of $674 million in regulatory charges resulting from Tax Reform in 2017, and a $190 million increase in service
revenues primarily resulting from expansion projects placed into service in 2017 and 2018.
WPZ Merger
On August 10, 2018, we completed our merger with Williams Partners L.P. (WPZ), pursuant to which we acquired
all of the approximately 256 million publicly held outstanding common units of WPZ in exchange for 382 million shares
of our common stock in a noncash equity transaction. Williams continued as the surviving entity. (See Note 1 – General,
Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to
Consolidated Financial Statements.)
FERC Income Tax Policy Revision
On March 15, 2018, the FERC issued a revised policy statement (the revised policy statement) regarding the
recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery
results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity
pursuant to the discounted cash flow methodology. As a result, the FERC will no longer permit an MLP pipeline to
recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this
policy to non-MLP partnership forms as those issues arise in subsequent proceedings. One of the benefits of the recent
WPZ Merger is to allow our FERC-regulated pipelines to continue to recover an income tax allowance in their cost of
service rates.
On July 18, 2018, the FERC issued an order dismissing the requests for rehearing and clarification of the revised
policy statement. In addition, the FERC provided guidance that an MLP pipeline (or other pass-through entity) no
longer recovering an income tax allowance pursuant to the revised policy may eliminate previously accumulated deferred
income taxes (ADIT) from its cost of service instead of flowing these ADIT balances to ratepayers. This guidance, if
implemented, would significantly mitigate the impact of the revised policy statement. However, the FERC stated that
the revised policy statement and such guidance do not establish a binding rule but are instead expressions of general
41
policy intent designed to provide guidance by notifying entities of the course of action the FERC intends to follow in
future adjudications. To the extent the FERC addresses these issues in future proceedings, it will consider any arguments
regarding not only the application of the revised policy to the facts of the case, but also any arguments regarding the
underlying validity of the policy itself. The FERC’s guidance on ADIT likely will be challenged by customers and
state commissions, which would result in a long period of revenue uncertainty for pipelines eliminating ADIT from
their cost of service. The WPZ Merger has the additional benefit of eliminating this uncertainty.
On March 15, 2018, the FERC also issued a Notice of Proposed Rulemaking proposing a filing process that will
allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent
reduction in the corporate income tax rate in the Tax Cuts and Jobs Act (Tax Reform) and the revised policy statement.
On July 18, 2018, the FERC issued a Final Rule, retaining the filing requirement and reaffirming the options that
pipelines have to either reflect the reduced tax rate or explain why no rate change is necessary. The FERC also clarified
that a natural gas company organized as a pass-through entity and all of whose income or losses are consolidated on
the federal income tax return of its corporate parent is considered to be subject to the federal corporate income tax and
is thus eligible for a tax allowance. We believe this Final Rule and the previously discussed WPZ Merger allow for the
continued recovery of income tax allowances in Transco’s and Northwest Pipeline’s rates. Transco’s August 31, 2018,
general rate case filing reflects a tax allowance based on this clarification, and the FERC’s September 28, 2018, order
in that rate case proceeding finds that Transco is exempt from the Final Rule’s Form 501-G filing requirement. In
addition, on October 19, 2018, Northwest Pipeline filed a petition requesting that the FERC waive its Form 501-G
filing requirement under this Final Rule because (i) the reduction in the corporate income tax is already addressed in
Northwest Pipeline’s 2017 rate settlement, and (ii) as discussed above, the WPZ Merger allows for the continued
recovery of income tax allowances in Northwest Pipeline’s rates. The FERC agreed and granted Northwest Pipeline’s
petition for waiver on November 19, 2018. On October 11, 2018 and December 6, 2018, Discovery Gas Transmission,
LLC and Pine Needle LNG Company, LLC, respectively, filed their Form 501-Gs, including explanations as to why
no adjustments to rates are needed.
On March 15, 2018, the FERC also issued a Notice of Inquiry seeking comments on the additional impacts of Tax
Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to ADIT
amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features
of Tax Reform require FERC action. We are evaluating the impact of these developments on our interstate natural gas
pipelines and currently expect any associated impacts would be prospective and determined through subsequent rate
proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax
Reform. It is reasonably possible that future tariff-based rates collected by our interstate natural gas pipelines may be
adversely impacted.
Revenue Recognition
As a result of the adoption of Accounting Standards Update 2014-09, Revenues from Contracts with Customers
(ASC 606) in January 2018, we now record revenues for transactions where we receive noncash consideration, primarily
in certain of our gas processing contracts that provide commodities as full or partial consideration for services provided.
These revenues are reflected as Service revenues - commodity consideration in the Consolidated Statement of Operations.
The costs associated with these revenues, primarily related to natural gas shrink replacement, are reported as Processing
commodity expenses. The revenues and costs associated with the subsequent sale of the commodity consideration
received is reflected within Product sales and Product costs in the Consolidated Statement of Operations. Service
revenues - commodity consideration plus Product sales, less Product costs and Processing commodity expenses
represents the margin that we have historically characterized as commodity margin. This presentation is being reflected
prospectively in the Consolidated Statement of Operations. (See Note 1 – General, Description of Business, Basis of
Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements.)
Additionally, future revenues are 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
42
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.
Filing of Rate Case
On August 31, 2018, Transco filed a general rate case with the FERC for an overall increase in rates. In September
2018, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general
rate filing to be effective March 1, 2019, subject to refund and the outcome of a hearing. The specific rates that reflected
a rate decrease were accepted, without suspension, to be effective October 1, 2018, as requested by Transco, and will
not be subject to refund. The impact of these specific new rates is expected to reduce revenues by approximately $2
million per month beginning October 1, 2018.
RMM Equity-Method Investment
During the third quarter of 2018, our joint venture, RMM, purchased a natural gas and oil gathering and natural
gas processing business in Colorado’s Denver-Julesburg basin. Our initial economic ownership was 40 percent, which
has since increased to 50 percent at December 31, 2018, based on additional capital contributions made since the initial
purchase. This investment is reported in the West segment.
Sale of Four Corners Assets
In October 2018, we completed the sale of our natural gas gathering and processing assets in the Four Corners
area of New Mexico and Colorado for total consideration of $1.125 billion, subject to customary working capital
adjustments. These assets were designated as held for sale during the third quarter of 2018. As a result of this sale, we
recorded a gain of approximately $591 million within the West segment in the fourth quarter of 2018 (see Note 3 –
Divestitures of Notes to Consolidated Financial Statements).
Sale of Gulf Coast Pipeline Systems
In November 2018, we completed the sale of certain assets and operations located in the Gulf Coast area for $177
million in cash. These assets were designated as held for sale during the third quarter of 2018. As a result of this sale,
we recorded a gain of approximately $101 million in the fourth quarter of 2018, consisting of $81 million in our Atlantic-
Gulf segment and $20 million in Other (see Note 3 – Divestitures of Notes to Consolidated Financial Statements).
Brazos Permian II Equity-Method Investment
In December 2018, we entered into a joint venture partnership in the Delaware basin. Under the terms of the
agreement, we contributed the majority of our existing Delaware basin assets in the West segment and $27 million in
cash to the partnership in exchange for a 15 percent interest. Our partner operates the partnership, which consists of
approximately 725 miles of gas gathering pipelines, 260 MMcf/d of natural gas processing, 75 miles of crude oil
gathering pipelines, and 75 thousand barrels of oil storage. The partnership anticipates processing capacity in the
Delaware basin to reach 460 MMcf/d and will be supported by over 500,000 acres of long-term dedications from major
and independent oil and gas producers. We recorded our interest in the partnership as an equity-method investment and
recognized a gain on the deconsolidation of our contributed assets of $141 million (see Note 6 – Investing Activities
of Notes to Consolidated Financial Statements).
Expansion Project Updates
Significant expansion project updates for the period, including projects placed into service are described below.
Ongoing major expansion projects are discussed later in Company Outlook.
Northeast G&P
Susquehanna Supply Hub
During the first quarter of 2018, the remaining facilities that comprise the Susquehanna Supply Hub Expansion
were fully commissioned. The project added two new compression facilities with an additional 49,000 horsepower
43
and 59 miles of 12- to 24-inch pipeline, and increased gathering capacity, allowing a certain producer to fulfill its
commitment to deliver 850 Mdth/d to our Atlantic Sunrise development.
Atlantic-Gulf
Gulf Connector
In January 2019, the Gulf Connector project was placed into service. This project expanded Transco’s 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 increased capacity by 475 Mdth/d.
Atlantic Sunrise
In October 2018, the Atlantic Sunrise project was placed into service. This project expanded 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, which
increased capacity by 400 Mdth/d. We placed additional mainline facilities into service in June 2018, which
increased capacity by an additional 150 Mdth/d. In total, the project increased Transco’s capacity by
1,700 Mdth/d.
Garden State
In March 2018, Phase 2 of the Garden State Expansion project was placed into service. This project expanded
Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from
Station 210 in New Jersey to a new interconnection on our Trenton Woodbury Lateral in New Jersey. Phase 1 of
the project was placed into service in September 2017, and together Phases 1 and 2 increased capacity by
180 Mdth/d.
Commodity Prices
NGL per-unit margins were approximately 19 percent higher in 2018 compared to 2017 primarily due to a 22
percent increase in realized per-unit non-ethane prices and an approximate 9 percent decrease 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 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 2019 includes a continued focus on growing our fee-based businesses, executing growth
projects, including through joint ventures, and accomplishing cost discipline initiatives to ensure operations support
our strategy. We anticipate operating results will increase through organic business growth driven by continued
expansion in the Northeast region and Transco expansion projects.
44
Our growth capital and investment expenditures in 2019 are expected to be in a range from $2.7 billion to $2.9
billion. Growth capital spending in 2019 includes Transco expansions, all of which are fully contracted with firm
transportation agreements, and continuing to develop our gathering and processing infrastructure in the Northeast G&P
and West segments. 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.
As a result of our significant continued capital and investment expenditures on Transco expansion projects 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 2019, current forward market prices indicate oil, natural gas, and NGL prices are expected
to be lower compared to 2018. We continue to address certain pricing risks through the utilization of commodity
hedging strategies.
In 2019, our operating results are expected to include increases from our regulated Transco fee-based business,
primarily related to projects recently placed in-service. For our non-regulated businesses, we anticipate increases in
fee-based revenue in the Northeast G&P segment associated with recent expansion projects, partially offset with a
decrease in the West segment primarily due to recent asset divestitures. We expect overall gathering and processing
volumes to grow in 2019 for our continuing businesses and anticipate an increase in our equity earnings primarily
associated with new investments. Additionally, we believe general and administrative expenses will be slightly lower
due to recent asset divestitures and the effect of the WPZ merger.
Potential risks and obstacles that could impact the execution of our plan include:
• Opposition to, and legal regulations affecting, our 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;
• Unexpected changes in customer drilling and production activities, which could negatively impact gathering
and processing volumes;
• 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;
• 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.
45
Expansion Projects
Our ongoing major expansion projects include the following:
Northeast G&P
Ohio River Supply Hub Expansion
We agreed to expand our services for certain customers to provide additional rich gas processing capacity in
the Marcellus and Upper Devonian Shale in West Virginia and Pennsylvania. Associated with these agreements,
we plan to further expand the processing capacity of our Oak Grove facility up to 400 MMcf/d. With one of these
customers, we secured a gathering dedication agreement to gather dry gas in this same region. Additionally, we
will be constructing a new NGL pipeline from Moundsville to the Harrison Hub fractionation facility to provide
a new outlet for NGLs. These expansions will be supported by long-term, fee-based agreements and volumetric
commitments.
Susquehanna Supply Hub Expansion
We continue to expand the gathering systems in the Susquehanna Supply Hub that are needed to meet our
customers’ production plans by 2020. This next expansion of the gathering infrastructure includes an additional
40,000 horsepower of new compression and gathering pipelines to bring the capacity to approximately 4.5 Bcf/d.
Atlantic-Gulf
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 (D.C. 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 2017 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. We filed a request for rehearing of the FERC’s decision, but in July 2018
the FERC denied our request.
The project’s sponsors remain committed to the project. On November 5, 2018, the FERC granted our request
for an extension of time to December 2, 2020, to construct and place into service the Constitution pipeline. And,
in September 2018, we filed a petition with the D.C. Circuit for review of the FERC’s denial of our petition for
declaratory order. (See Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements.)
46
Gateway
In December 2018, we received approval from 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.
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 is being
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 Phases I and II are expected to increase capacity by 1,025 Mdth/d.
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 completed 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 quarter of 2019.
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. On April 20, 2018, the NYSDEC denied, without prejudice, Transco’s
application for certain permits required for the project. We addressed the technical issues identified by NYSDEC
and in May 2018, we refiled our application for the permits. We plan to place the project into service in the fourth
quarter of 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase
capacity by 400 Mdth/d.
Rivervale South to Market
In August 2018, we received approval from 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.
Southeastern Trail
In April 2018, we filed an application with the FERC to expand Transco’s existing natural gas transmission
system to provide incremental firm transportation capacity from the Pleasant Valley interconnect with Dominion’s
Cove Point Pipeline in Virginia to the Station 65 pooling point in Louisiana. We plan to place the project into
service in late 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to
increase capacity by 296 Mdth/d.
47
West
North Seattle Lateral Upgrade
In July 2018, we received approval from 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, assuming timely receipt of all necessary regulatory approvals. The project is expected to
increase delivery capacity by approximately 159 Mdth/d.
Wamsutter Expansion
We are expanding our gathering and processing infrastructure in the Wamsutter region of Wyoming in order
to meet our customers’ production plans. The expansion includes the addition of approximately 60 miles of
gathering pipelines and compression, and modifications to existing treating and processing facilities. We plan to
place the first phase of the project into service during the first quarter of 2019.
Project Bluestem
We are expanding our presence in the Mid-Continent region through building a 188-mile pipeline from our
fractionator in Conway, Kansas to an interconnect with a third-party NGL pipeline system in Oklahoma, providing
us with firm access to Mt. Belvieu pricing. As part of the project, the third-party intends to construct a 110-mile
pipeline extension of their existing NGL pipeline system that will have an initial capacity of 120 Mbbls/d. Further,
we will have an option to purchase a 20 percent equity interest in a Mt. Belvieu fractionation train developed by
the third party. The pipeline and extension projects are expected to be placed into service during the first quarter
of 2021.
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, cash balance interest crediting rate, expected
rate of compensation increase, 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 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements.
48
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................
Cash balance interest crediting rate ....................................
Rate of compensation increase ...........................................
Other postretirement benefits:
Discount rate ......................................................................
Expected long-term rate of return on plan assets................
(7) $
(12)
16
1
1
(2)
(Millions)
$
8
12
(13)
(1)
1
2
(101) $
—
76
5
(19)
—
119
—
(64)
(4)
23
—
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.
Our expected long-term rate of return on plan assets used for our pension plans was 5.34 percent in 2018. The
2018 actual return on plan assets for our pension plans was a loss of approximately 3.6 percent. The 10-year average
rate of return on pension plan assets through December 2018 was approximately 8.3 percent. While the 2018 investment
performance was less 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 the expected rates of return.
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 10 – 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 cash balance interest crediting rate assumption represents the average long-term rate by which the pension
plans’ cash balance accounts are expected to grow. Interest on the cash balance accounts is based on the 30-year U.S.
Treasury securities rate and is credited to the accounts quarterly. An increase in this rate causes the pension obligation
and cost to increase.
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.
49
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.
Certain of our contractual gathering rates, primarily those in the Barnett Shale, are based on a percentage of the
New York Mercantile Exchange (NYMEX) natural gas prices. During the fourth quarter of 2018, we determined there
was a sustained decline in the forward price curves for natural gas. During this same period, a large producer customer
in the Barnett Shale removed their remaining drilling rig. These factors gave rise to an impairment evaluation of these
assets. The historical carrying value of our Barnett assets was initially recorded based on the estimated fair value during
the third quarter of 2014 in conjunction with the acquisition of ACMP.
Our evaluation incorporated management’s projections of future drilling levels and gathering rates, taking into
consideration the information noted above as well as recently available information regarding producer drilling cost
assumptions in this basin. The resulting estimate of future undiscounted cash flows was less than our carrying value,
necessitating the estimation of the fair value of these assets. In arriving at the fair value, we utilized an income approach
with a discount rate of 8.5 percent, reflecting an estimated cost of capital and risks associated with the underlying assets.
As a result, we recorded an impairment charge of $1.849 billion to reduce the carrying value to our estimate of fair
value. A one-percentage-point increase in the discount rate would decrease our estimate of fair value by approximately
$37 million.
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.
Constitution Pipeline Capitalized Project Costs
As of December 31, 2018, Property, plant, and equipment – net in our Consolidated Balance Sheet includes
approximately $377 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 at 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. Subsequently, there have been no events or changes in circumstances
that impact our conclusion. 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 have historically permitted the recovery of an income tax allowance that includes
a deferred income tax component. Due to 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. As a result, we established regulatory liabilities during
2017 and at December 31, 2018, these liabilities total $657 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.
50
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, 2018. The results of operations by segment are discussed in further detail following this consolidated
overview discussion.
Years Ended December 31,
$ Change
from
2017*
% Change
from
2017*
2018
2017
(Millions)
$ Change
from
2016*
% Change
from
2016*
2016
Revenues:
Service revenues .......................................... $ 5,502
Service revenues - commodity
+4% $ 5,312
+141
+3% $ 5,171
consideration............................................
Product sales ................................................
Total revenues..........................................
Costs and expenses:
Product costs................................................
Processing commodity expenses .................
Operating and maintenance expenses..........
Depreciation and amortization expenses .....
Selling, general, and administrative
expenses...................................................
Impairment of certain assets ........................
Gain on sale of certain assets.......................
Regulatory charges resulting from Tax
Reform .....................................................
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 .........................
400
2,784
8,686
2,707
137
1,507
1,725
569
1,915
(692)
(17)
67
7,918
768
396
(32)
219
(1,112)
92
331
138
193
+190
+400
+65
-407
-137
+69
+11
+25
-667
-403
+691
+4
-38
-32
-63
-29
+117
-2,112
—
+391
NM
+17%
NM
+2%
-18%
NM
+4%
+1%
—
2,719
8,031
2,300
—
1,576
1,736
-575
—
+16
+27
594
+4%
-53%
1,248
-37% (1,095)
+128
-375
+1,095
—
2,328
7,499
1,725
—
1,592
1,763
722
873
—
-33%
NM
+1%
+2%
+18%
-43%
NM
-9%
NM
-22%
NM
+6%
674
71
7,104
927
434
—
282
-3% (1,083)
(25)
NM
535
(1,974)
2,509
NM
-674
+64
+37
+430
+219
+96
-110
+1,949
NM
+47%
—
135
6,810
689
397
+9%
(430)
+100%
NM
63
+8% (1,179)
85
NM
(375)
(25)
(350)
NM
348
-13
-4%
335
-261
NM
74
Net income (loss) attributable to The
Williams Companies, Inc......................... $
(155)
$ 2,174
$
(424)
_______
* + = 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.
2018 vs. 2017
Service revenues increased primarily due to higher transportation fee revenues at Transco associated with expansion
projects placed in-service in 2017 and 2018, as well as higher gathering volumes at the Susquehanna Supply Hub and
51
Ohio River Supply Hub. These increases are partially offset by a change in the rate of deferred revenue recognition
resulting from implementing ASC 606, reduced revenues from our Four Corners area operations that were sold in
October 2018, a reduction of rates resulting from a Northwest Pipeline rate case settlement, and a decrease following
the Jackalope deconsolidation.
Service revenues - commodity consideration increased as the result of implementing ASC 606 using a modified
retrospective approach, effective January 1, 2018. Therefore, prior periods have not been recast under the new guidance.
These revenues represent consideration we receive in the form of commodities as full or partial payment for gathering
and processing services provided. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary
of Significant Accounting Policies of Notes to Consolidated Financial Statements.) Most of these NGL volumes are
sold within the month processed and therefore are offset in Product costs below.
Product sales increased primarily due to higher marketing revenues and higher system management gas sales,
which are offset in Product costs, and higher sales from the production of our equity NGLs, reflecting higher NGL
prices. These increases are partially offset by the absence of $269 million in olefin sales revenue associated with our
former Gulf Olefins operations in 2017.
The increase in Product costs is primarily due to the impact of ASC 606 in which costs reflected in this line item
for 2018 include volumes acquired as commodity consideration for NGL processing services, as well as higher marketing
and system management gas costs. This increase is partially offset by the absence of $147 million of olefin feedstock
costs due to the sale of our former Gulf Olefins operations, as well as the absence of natural gas purchases associated
with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with
the implementation of ASC 606.
Processing commodity expenses presents the natural gas purchases associated with the production of equity NGLs
as previously described in conjunction with the implementation of ASC 606.
Operating and maintenance expenses decreased primarily due to the absence of $80 million of costs associated
with our former Gulf Olefins and Four Corners area operations.
Depreciation and amortization expenses decreased primarily due to the absence of our former Gulf Olefins and
Four Corners area operations, partially offset by new assets placed in-service.
Selling, general, and administrative expenses decreased primarily due to the absence of severance-related,
organizational realignment, and Financial Repositioning costs incurred in 2017, $25 million in reduced costs associated
with our former Gulf Olefins and Four Corners area operations, and ongoing cost containment efforts. These decreases
are partially offset by a charitable contribution of preferred stock to The Williams Companies Foundation, Inc. (see
Note 15 – Stockholders' Equity of Notes to Consolidated Financial Statements) and fees associated with the WPZ
Merger.
The unfavorable change in Impairment of certain assets includes 2018 impairments on certain assets in the Barnett
Shale region and certain idle pipelines, partially offset by the absence of 2017 impairments associated with certain
assets in the Mid-Continent, Marcellus South, and Houston Ship Channel areas (see Note 17 – Fair Value Measurements,
Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
The unfavorable change in Gain on sale of certain assets reflects the absence of a gain recognized on the sale of
our Geismar Interest in July 2017, partially offset by gains recognized on the sales of our Four Corners area in October
2018 and our Gulf Coast pipeline systems in December 2018 (see Note 3 – Divestitures of Notes to Consolidated
Financial Statements).
Regulatory charges resulting from Tax Reform relates to the 2017 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).
52
The favorable change in Other (income) expense – net within Operating income (loss) includes the benefit of
establishing a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following
the WPZ Merger, substantially offset by the absence of gains from certain contract settlements and terminations in
2017, the absence of a gain on the sale of our RGP Splitter in 2017, and 2018 charges establishing a regulatory liability
associated with a decrease in Northwest Pipeline's estimated deferred state income tax rate following the WPZ Merger.
Operating income (loss) changed unfavorably primarily due to higher impairments of assets, lower gains on sales
of assets, and the absence of operating income associated with our former Gulf Olefins and Four Corners area operations,
partially offset by the absence of regulatory charges resulting from Tax Reform, higher Service revenues primarily from
expansion projects, and an increase in NGL margins.
The unfavorable change in Equity earnings (losses) is primarily due to a decrease in volumes at Discovery, partially
offset by improved results at our Appalachia Midstream Investments and the deconsolidation of our Jackalope interest,
which is now accounted for as an equity-method investment beginning in the second quarter of 2018.
The Impairment of equity-method investments in 2018 reflects an impairment related to our investment in UEOM.
Other investing income (loss) – net reflects the absence of the gain on disposition of our investments in DBJV and
Ranch Westex JV LLC in 2017, partially offset by gains on the 2018 deconsolidations of certain Permian basin assets
and of our interest in Jackalope. (See Note 6 – Investing Activities of Notes to Consolidated Financial Statements.)
Interest expense increased primarily due to an increase in other financing obligations associated with Transco's
Dalton and Atlantic Sunrise projects, as well as expense related to the deemed financing component of certain contract
liabilities resulting from our implementation of ASC 606 in 2018, offset by lower interest rates on our outstanding
debt in 2018 and lower borrowings on our credit facilities in 2018. (See Note 14 – Debt, Banking Arrangements, and
Leases of Notes to Consolidated Financial Statements.)
Other income (expense) – net below Operating income (loss) changed favorably primarily due to a decrease in
charges reducing regulatory assets related to deferred taxes on the allowance for funds used during construction
(AFUDC) resulting from Tax Reform, an increase in equity AFUDC, and a lower settlement charge from the pension
early payout program, partially offset by a decrease due to the absence of a net gain on early retirement of debt in 2017
and a loss on early retirement of debt in 2018. (See Note 7 – Other Income and Expenses of Notes to Consolidated
Financial Statements.)
Provision (benefit) for income taxes changed unfavorably primarily due to the absence of a $1.923 billion tax
provision benefit associated with Tax Reform and releasing a $127 million valuation allowance in 2017. The unfavorable
change also reflects a $105 million valuation allowance in 2018 associated with certain foreign tax credits. See Note
8 – 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 related to WPZ,
reflective of both our acquisition of the publicly held interests in WPZ associated with the WPZ Merger and a fourth
quarter 2017 net loss incurred by WPZ, partially offset by lower operating results at Gulfstar.
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
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.
53
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 decreased primarily due to 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, partially offset by higher pipeline integrity
testing and general maintenance at Transco.
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 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 Olefins operations. These
decreases were partially offset by higher severance and organizational realignment costs in 2017 (see Note 7 – Other
Income and Expenses of Notes to Consolidated Financial Statements).
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 17 – Fair Value Measurements, Guarantees, and
Concentration of Credit Risk of Notes to Consolidated Financial Statements).
The Gain on sale of certain assets reflects the gain recognized on the sale of our Geismar Interest in July 2017.
(See Note 3 – 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 certain assets, 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
certain gathering operations in the Mid-Continent and Marcellus South regions and certain NGL pipeline assets, and
regulatory charges resulting from Tax Reform, as well as the absence of operating income associated with our former
Gulf Olefins operations.
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.
54
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 17 – 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 6 – 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 14 – 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 (see Note 10 – Employee Benefit Plans of Notes to
Consolidated Financial Statements), partially offset by a net gain on early debt retirements in 2017, and other favorable
changes related to AFUDC. (See Note 7 – 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 8 – 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.
Year-Over-Year Operating Results – Segments
We evaluate segment operating performance based upon Modified EBITDA. Note 19 – 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.
55
Northeast G&P
Service revenues.............................................................................................. $
Service revenues - commodity consideration..................................................
Product sales....................................................................................................
Segment revenues............................................................................................
Product costs....................................................................................................
Processing commodity expenses .....................................................................
Other segment costs and expenses ..................................................................
Impairment of certain assets............................................................................
Proportional Modified EBITDA of equity-method investments.....................
Northeast G&P Modified EBITDA ................................................................. $
2018 vs. 2017
Years Ended December 31,
2018
2017
2016
(Millions)
976
20
287
1,283
(289)
(9)
(392)
—
493
1,086
$
$
872
—
291
1,163
(286)
—
(386)
(124)
452
819
$
$
870
—
162
1,032
(159)
—
(364)
(13)
357
853
Northeast G&P Modified EBITDA increased primarily due to the absence of Impairment of certain assets in 2017,
and higher Service revenues and Proportional Modified EBITDA of equity-method investments.
Service revenues increased due to:
• A $65 million increase in gathering fee revenues at Susquehanna Supply Hub due to 13 percent higher gathering
volumes reflecting increased customer production;
• A $24 million increase at Ohio River Supply Hub reflecting higher gathering volumes due to increased customer
production;
• An $11 million increase in Utica gathering fee revenues reflecting higher rates and volumes.
Service revenues - commodity consideration increased as a result of implementing ASC 606 using a modified
retrospective approach. These revenues represent consideration we receive in the form of commodities as full or partial
payment for gathering and processing services provided. Most of these NGL volumes are sold within the month processed
and therefore are offset in Processing commodity expenses below.
Product sales decreased primarily due to $31 million lower marketing sales, driven by lower non-ethane volumes
and prices. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above
as Product costs. The decrease in Product sales is partially offset by $21 million in higher system management gas
sales. System management gas sales are offset in Product costs and therefore have no impact on Modified EBITDA.
Impairment of certain assets reflects the absence of a $115 million impairment of certain gathering operations in
the Marcellus South region in 2017.
Proportional Modified EBITDA of equity-method investments increased primarily due to a $33 million increase at
Appalachia Midstream Investments reflecting our increased ownership acquired in late first-quarter 2017 and higher
volumes. Improvements at Aux Sable and Caiman II also contributed to the increase.
2017 vs. 2016
Northeast G&P Modified EBITDA decreased primarily due to higher Impairment of certain assets and Other
segment costs and expenses, partially offset by higher Proportional Modified EBITDA of equity-method investments.
56
Service revenues increased slightly reflecting:
• A $38 million increase in gathering fee revenue at Susquehanna Supply Hub driven by 11 percent higher
gathered volumes reflecting increased customer production;
• 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;
• A $56 million decrease in Utica gathering fee revenues primarily due to 14 percent lower gathered volumes
driven by natural declines in the wet gas areas, partially offset by higher volumes from new development in
the dry gas areas.
Product sales increased primarily due to higher non-ethane and ethane prices and higher non-ethane volumes
within our marketing activities. The changes in marketing revenues are offset by similar changes in marketing purchases,
reflected above as Product costs.
Other segment costs and expenses increased due to a $31 million increase in operating and maintenance expenses
primarily resulting from higher costs related to various maintenance expenses and ad valorem taxes, and $7 million
related to a settlement charge from a pension early payout program (see Note 10 – Employee Benefit Plans of Notes
to Consolidated Financial Statements). These increases are partially offset by $16 million lower general and
administrative expenses primarily due to a reduced share of allocated support costs, ongoing cost containment efforts,
and 2016 workforce reductions.
Impairment of certain assets increased primarily due to a $115 million impairment of certain gathering operations
in the Marcellus South region.
Proportional Modified EBITDA of equity-method investments changed favorably primarily due to a $100 million
increase at Appalachia Midstream Investments reflecting our increased ownership acquired late in the first quarter of
2017 and higher gathering volumes reflecting the absence of shut-in volumes from 2016 and increased customer
production, a $20 million increase at Aux Sable due to increased customer production and the absence of the $9 million
impairment in 2016, an $8 million increase at Laurel Mountain Midstream associated with higher gathering revenue
due to higher rates reflecting higher natural gas prices, partially offset by a $34 million decrease at UEOM driven by
lower processing volumes from the wet gas areas of the Utica gathering system as noted above.
57
Atlantic-Gulf
Years Ended December 31,
2018
2017
2016
(Millions)
Service revenues.............................................................................................. $
Service revenues - commodity consideration..................................................
Product sales....................................................................................................
Segment revenues............................................................................................
Product costs....................................................................................................
Processing commodity expenses .....................................................................
Other segment costs and expenses ..................................................................
Impairment of certain assets............................................................................
Gain on sale of certain assets...........................................................................
Regulatory charges resulting from Tax Reform ..............................................
Proportional Modified EBITDA of equity-method investments.....................
Atlantic-Gulf Modified EBITDA .................................................................... $
2,509
59
435
3,003
(438)
(16)
(799)
—
81
9
183
2,023
NGL margin..................................................................................................... $
39
$
$
$
2,239
—
484
2,723
(437)
—
(819)
—
—
(493)
264
1,238
41
$
$
$
1,998
—
450
2,448
(405)
—
(707)
(2)
—
—
287
1,621
38
2018 vs. 2017
Atlantic-Gulf Modified EBITDA increased primarily due to the absence of regulatory charges associated with the
impact of Tax Reform at Transco, higher Service revenues, and a 2018 Gain on sale of certain assets; partially offset
by lower Proportional Modified EBITDA of equity-method investments.
Service revenues increased primarily due to a $253 million increase in Transco’s natural gas transportation fee
revenues primarily due to a $241 million increase associated with expansion projects placed in-service in 2017 and
2018.
Service revenues – commodity consideration increased as a result of implementing ASC 606 using a modified
retrospective approach. These revenues represent consideration we receive in the form of commodities as full or partial
payment for gathering and processing services provided. Most of these NGL volumes are sold within the month processed
and therefore are offset in Product costs below.
The decrease in Product sales includes:
• A $90 million decrease in commodity marketing revenues driven by a $149 million decrease in crude oil
revenues as this activity is now presented on a net basis within Product costs in conjunction with the adoption
of ASC 606, partially offset by a $59 million increase in NGL marketing revenues primarily reflecting 20
percent higher non-ethane prices;
• A $14 million decrease in revenues associated with our equity NGLs, as further described below as part of
our commodity product margins;
• A $57 million increase in system management gas sales. System management gas sales are offset in Product
costs and therefore have little impact to Modified EBITDA.
Product costs slightly increased primarily due to a $59 million increase in system management gas costs
(substantially offset in Product sales) and the impact of ASC 606 in which costs reflected in this line item for 2018
include volumes acquired as commodity consideration for NGL processing services. This increase was partially offset
by an $87 million decrease in marketing purchases (more than offset in Product sales) and the absence of natural gas
58
purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses
in conjunction with the implementation of ASC 606.
Processing commodity expenses presents the natural gas purchases associated with the production of equity NGLs
as previously described in conjunction with the implementation of ASC 606.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing
commodity expenses comprise our commodity product margins.
Other segment costs and expenses decreased primarily due to a $17 million increase in Transco’s equity AFUDC
as a result of projects placed in service in 2018.
Gain on sale of certain assets reflects an $81 million gain from the sale of our Gulf Coast pipeline system assets
in fourth quarter 2018.
The decrease in Regulatory charges resulting from Tax Reform reflects the absence of $493 million of regulatory
charges in 2017 associated with the impact of Tax Reform at Transco (See Note 1 – General, Description of Business,
Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements).
The decrease in Proportional Modified EBITDA of equity-method investments is due to an $89 million decrease
at Discovery, primarily related to a $76 million decrease associated with production ending on certain wells.
2017 vs. 2016
Atlantic-Gulf Modified EBITDA decreased primarily due to regulatory charges associated with the impact of Tax
Reform at our regulated entities, higher Other segment costs and expenses, and lower Proportional Modified EBITDA
from Discovery, partially offset by higher Service revenues.
Service revenues increased primarily due to:
• A $135 million increase in Transco’s natural gas transportation fee revenues 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;
• A $103 million increase in eastern Gulf Coast region fee revenues primarily related to 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, partially offset by lower volumes as a result of a temporary increase in 2016 due to
disrupted operations of a competitor;
• A $15 million increase in Transco’s storage revenue primarily related to the absence of an accrual for potential
refunds associated with a ruling received in certain rate case litigation in 2016;
• 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 $31 million increase in NGL and crude oil marketing revenues primarily due to a $72 million increase driven
by higher prices, partially offset by a $41 million decrease driven by lower volumes. Average realized non-
ethane prices were 47 percent higher and average realized crude prices were 18 percent higher. Non-ethane
volumes were 16 percent lower and crude volumes were 13 percent lower driven by shut-ins of certain wells
behind Devils Tower as a result of production issues and temporary hurricane-related shut-ins. (Increases in
marketing revenues are substantially offset by higher Product costs);
59
• 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 $5 million decrease in revenues associated with our equity NGLs due to a $19 million decrease driven by
lower volumes, partially offset by a $14 million increase driven by higher prices. Realized non-ethane prices
increased by 32 percent. Non-ethane volumes decreased by 31 percent primarily as a result of a temporary
increase in 2016 due to disrupted operations of a competitor.
Product costs increased primarily due to:
• A $28 million increase in marketing purchases (more than offset in Product sales);
• A $12 million increase in system management gas costs (offset in Product sales);
• An $8 million decrease in natural gas purchases associated with the production of equity NGLs primarily due
to lower volumes.
Other segment costs and expenses increased primarily due to $89 million higher operating costs, primarily
associated with Transco pipeline integrity testing and general maintenance, a $17 million increase in expense associated
with an annual revision to the ARO liability, $9 million of higher general and administrative costs due to an increased
share of allocated support costs, and a $15 million expense in 2017 related to a settlement charge from a pension early
payout program (see Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements). These increases
are partially offset by a $14 million favorable change in equity AFUDC associated with an increase in Transco’s capital
spending, which is offset by an $8 million decrease in Constitution’s equity AFUDC. Other favorable changes include
$12 million lower project development costs at Constitution and favorable impacts related to gains on asset retirements.
Regulatory charges resulting from Tax Reform reflects $493 million of regulatory charges associated with the
impact of Tax Reform at Transco (See Note 1 – General, Description of Business, Basis of Presentation, and Summary
of Significant Accounting Policies of Notes to Consolidated Financial Statements).
The decrease in Proportional Modified EBITDA of equity-method investments includes a $12 million decrease
from Discovery, a $7 million decrease in Cardinal Pipeline Company, LLC and a $5 million decrease in Pine Needle
LNG Company, LLC. The decrease in Discovery is primarily associated with lower fee revenue driven by significant
production issues at certain wells, higher turbine maintenance expenses, temporary hurricane-related shut-ins, and
maintenance on the Keathley Canyon connector pipeline. The decrease in Cardinal Pipeline Company, LLC and Pine
Needle LNG Company, LLC is primarily due to $11 million of regulatory charges associated with the impact of Tax
Reform.
60
West
Years Ended December 31,
2018
2017
(Millions)
2016
Service revenues.............................................................................................. $
Service revenues – commodity consideration .................................................
Product sales....................................................................................................
Segment revenues............................................................................................
$
2,085
321
2,448
4,854
$
2,246
—
2,013
4,259
Product costs....................................................................................................
Processing commodity expenses .....................................................................
Other segment costs and expenses ..................................................................
Impairment of certain assets............................................................................
Gain on sale of certain assets...........................................................................
Regulatory charges resulting from Tax Reform ..............................................
Proportional Modified EBITDA of equity-method investments.....................
West Modified EBITDA.................................................................................. $
(2,448)
(116)
(825)
(1,849)
591
7
94
308
NGL margin..................................................................................................... $
194
(1,842)
—
(832)
(1,032)
—
(220)
79
412
154
$
$
$
$
2,328
—
1,380
3,708
(1,256)
—
(918)
(100)
—
—
110
1,544
112
2018 vs. 2017
West Modified EBITDA decreased primarily due to the increase in Impairment of certain assets and lower Service
revenues. These decreases were partially offset by the Gain on sale of certain assets in 2018, the absence of regulatory
charges associated with the impact of Tax Reform, and higher NGL margins driven by higher NGL prices and lower
realized natural gas prices, partially offset by lower NGL volumes.
Service revenues decreased primarily due to:
• A $64 million decrease primarily associated with implementing the new revenue guidance under ASC 606
including a $118 million decrease related to lower amortization of deferred revenue associated with the up-
front cash payments received in conjunction with the fourth quarter 2016 Barnett Shale and Mid-Continent
contract restructurings, partially offset by a $54 million increase related to other deferred revenue amortization
primarily in the Permian basin;
• A $42 million decrease associated with the sale of our Four Corners area assets in October 2018;
• A $30 million decrease at Northwest Pipeline primarily due to the reduction of its rates as a result of a rate
case settlement that became effective January 1, 2018;
• A $29 million decrease following the Jackalope deconsolidation in second quarter 2018;
• A $15 million decrease driven by lower gathering volumes primarily in the Eagle Ford Shale, Barnett Shale,
and Mid-Continent regions, partially offset by higher volumes in the Niobrara (prior to the Jackalope
deconsolidation), Piceance, and Permian regions;
• A $21 million increase associated with higher gathering and processing rates in the Piceance region driven
by higher NGL prices as well as higher average gathering and processing rates across most other areas, partially
offset by lower contract rates primarily in the Haynesville Shale region.
Service revenues – commodity consideration increased as a result of implementing ASC 606 using a modified
retrospective approach. These revenues represent consideration we receive in the form of commodities as full or partial
61
payment for gathering and processing services provided. Most of these NGL volumes are sold within the month processed
and therefore are offset in Product costs below.
The increase in Product sales includes:
• A $373 million increase in marketing revenues primarily due to increases in realized NGL prices including a
14 percent increase in average non-ethane per-unit sales prices and a 25 percent increase in ethane prices, in
addition to a 15 percent increase in ethane volumes (more than offset by higher Product costs);
• A $47 million increase associated with sales of our equity NGLs, as further described below as part of our
commodity product margins;
• An $18 million increase in system management gas sales due to a change in presentation in accordance with
ASC 606, which are more than offset in Product costs and, therefore, have little impact on Modified EBITDA.
The increase in Product costs includes the impact of ASC 606 in which costs reflected in this line item for 2018
include volumes acquired as commodity consideration for NGL processing services, a $381 million increase in marketing
purchases (substantially offset in Product sales), a $19 million increase in system management gas costs (substantially
offset in Product sales), partially offset by the absence of natural gas purchases associated with the production of equity
NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606.
Processing commodity expenses presents the natural gas purchases associated with the production of equity NGLs
as previously described in conjunction with the implementation of ASC 606.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing
commodity expenses comprise our commodity product margins. Our commodity product margins increased primarily
due to a $40 million increase in NGL product margins partially offset by an $8 million decrease in marketing margins.
NGL margins are driven by $56 million in higher ethane and non-ethane per-unit prices, reflecting 19 percent higher
realized non-ethane per-unit sales prices and 50 percent higher realized ethane per-unit sales prices. These increases
were partially offset by $18 million in lower volumes primarily due to the sale of our Four Corners area assets in October
2018.
Other segment costs and expenses decreased primarily due to $57 million lower operating and maintenance and
general and administrative costs. This reduction in costs is due primarily to the Four Corners area sale in October 2018,
ongoing cost containment efforts, and the deconsolidation of our Jackalope interest in second quarter 2018. These
reductions are partially offset by a $24 million regulatory charge associated with Northwest Pipeline’s approved rates
related to Tax Reform, the absence of a $15 million gain from contract settlements and terminations in 2017, and a $12
million charge for a regulatory liability associated with a decrease in Northwest Pipeline’s estimated deferred state
income tax rate following the WPZ Merger.
Impairment of certain assets increased primarily due to the $1.849 billion impairment of certain assets in the
Barnett Shale region in 2018, partially offset by the absence of a $1.019 billion impairment of certain gathering operations
in the Mid-Continent region in 2017 (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit
Risk of Notes to Consolidated Financial Statements).
Gain on sale of certain assets reflects a gain from the sale of our Four Corners area assets in fourth quarter 2018.
Regulatory charges resulting from Tax Reform decreased primarily due to the absence of the $220 million initial
regulatory charge associated with the impact of Tax Reform at Northwest Pipeline (see Note 1 – General, Description
of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial
Statements).
Proportional Modified EBITDA of equity-method investments increased primarily due to the deconsolidation of
our Jackalope interest, which is accounted for as an equity-method investment beginning in the second quarter of 2018.
62
2017 vs. 2016
West Modified EBITDA decreased primarily due to higher Impairment of certain assets, regulatory charges
associated with the impact of Tax Reform at Northwest Pipeline, lower gathering rates, and lower volumes as a result
of natural declines, partially offset by lower segment costs and expenses, higher per-unit NGL margins, and higher
amortization of deferred revenue associated with the up-front cash payment received in conjunction with the fourth
quarter 2016 Barnett Shale contract restructuring.
Service revenues decreased primarily due to:
• A $79 million decrease related to net lower gathering rates, primarily in the Barnett Shale area primarily due
to the fourth quarter 2016 contract restructuring, as well as 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 most gathering and processing regions 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 $39 million increase related to the rate of amortization of deferred revenue associated with the up-front cash
payment received in conjunction with the fourth quarter 2016 Barnett Shale contract restructuring.
Product sales increased primarily due to:
• A $532 million increase in marketing revenues primarily due to a $450 million increase driven by higher prices
and an $82 million increase driven by higher volumes. The average non-ethane per-unit sales price increased
by 43 percent, the average ethane per-unit sales prices increased by 30 percent, and the average natural gas
per-unit sales price increased by 13 percent. Ethane and non-ethane sales volumes were 28 percent and six
percent higher, respectively, partially offset by 17 percent lower natural gas sales volumes. (Higher marketing
sales revenues are substantially offset by higher Product costs);
• A $72 million increase in revenues associated with our equity NGLs primarily due to an $80 million increase
driven by higher prices, partially offset by an $8 million decrease driven by lower volumes. Realized non-
ethane prices increased by 42 percent and realized ethane prices increased by 46 percent. Non-ethane volumes
decreased by six percent primarily due to natural declines and to severe winter conditions in the first quarter
of 2017;
• A $24 million increase in other product sales related to certain fabricated equipment sales to affiliates (more
than offset by higher other Product costs).
Product costs increased primarily due to:
• A $529 million increase in marketing purchases (more than offset in Product sales);
• A $30 million increase in natural gas purchases associated with the production of equity NGLs primarily due
to a 26 percent increase in per-unit natural gas prices;
• A $25 million increase in other product costs related to certain fabricated equipment sales to affiliates (offset
by higher other Product sales).
63
The decrease in Other segment costs and expenses reflects a $56 million decline in operating expenses, a $27
million reduction in general and administrative expenses, and $15 million of gains from contract settlements and
terminations in Other (income) expense – net within Operating income (loss). The reductions in operating and general
and administrative expenses are primarily due to the 2016 workforce reductions, ongoing cost containment efforts,
lower compression expenses, favorable system gains and gas imbalance revaluations, and a reduced share of allocated
support costs. These items are partially offset by a $13 million expense in 2017 related to a settlement charge from a
pension early payout program (See Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements).
Impairment of certain assets increased primarily due to the $1.032 billion impairment of certain gathering operations
primarily in the Mid-Continent region in 2017, partially offset by the absence of $100 million in impairments 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 in 2016.
Regulatory charges resulting from Tax Reform reflects $220 million of regulatory charges associated with the
impact of Tax Reform at Northwest Pipeline (See Note 1 – General, Description of Business, Basis of Presentation,
and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements).
Proportional Modified EBITDA of equity-method investments decreased primarily due to the divestiture of our
interests of DBJV and Ranch Westex LLC late in the first quarter of 2017.
Other
Other Modified EBITDA..................................................................... $
(29) $
997
$
(696)
Years Ended December 31,
2018
2017
(Millions)
2016
2018 vs. 2017
Modified EBITDA changed unfavorably primarily due to:
• The absence of a $1.095 billion gain on the sale of our Geismar Interest in 2017 (see Note 3 – Divestitures of
Notes to Consolidated Financial Statements);
• The absence of $54 million of Modified EBITDA associated with the results of our former Geismar Olefins
and RGP Splitter plants subsequent to their sale in July 2017;
• A $35 million charge in 2018 associated with a charitable contribution of preferred stock to The Williams
Companies Foundation, Inc. (a not-for-profit corporation) (see Note 15 – Stockholders' Equity of Notes to
Consolidated Financial Statements);
• A $34 million decrease due to the absence of a net gain on early retirement of debt in 2017 and a loss on early
retirement of debt in 2018 (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial
Statements);
• A $26 million decrease in income associated with a regulatory asset related to deferred taxes on equity funds
used during construction;
•
$20 million in costs in 2018 associated with the WPZ Merger (see Note 1 – General, Description of Business,
Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial
Statements);
• The absence of a $12 million gain on the sale of the Refinery Grade Propylene Splitter in 2017 (see Note 7 –
Other Income and Expenses of Notes to Consolidated Financial Statements).
64
These decreases were partially offset by:
• The absence of a $68 million impairment for a certain NGL pipeline asset in the third quarter of 2017 and a
$23 million impairment of an olefins pipeline project in the Gulf Coast region in the second quarter of 2017,
partially offset by a $66 million impairment of certain idle pipelines in the second quarter of 2018 (see Note
17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated
Financial Statements);
• A decrease of $62 million for charges reducing regulatory assets related to deferred taxes on AFUDC resulting
from Tax Reform (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements);
•
$40 million of lower costs, driven by the absence of expenses associated with severance and related costs,
Financial Repositioning, and strategic alternative costs (see Note 1 – General, Description of Business, Basis
of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial
Statements);
• A $37 million increase associated with the benefit of establishing a regulatory asset associated with an increase
in Transco’s estimated deferred state income tax rate following the WPZ Merger;
• A $30 million favorable change in the settlement charge expense related to the program to pay out certain
deferred vested pension benefits of employees associated with former operations (see Note 10 – Employee
Benefit Plans of Notes to Consolidated Financial Statements);
• A $20 million gain on the sale of certain assets and operations located in the Gulf Coast area (see Note 3 –
Divestitures of Notes to Consolidated Financial Statements).
2017 vs. 2016
The favorable change in Modified EBITDA is primarily due to:
• A $1.095 billion gain recognized on the sale of our Geismar Interest in July 2017. (See Note 3 – Divestitures
of Notes to Consolidated Financial Statements);
• The absence of the $747 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 17 – 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 $65 million favorable change in the loss on the sale of our Canadian operations in September 2016;
• A $38 million decrease in costs related to our evaluation of strategic alternatives;
• 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 $29 million increase in income associated with an increase in a regulatory asset primarily driven by our
increased ownership in WPZ.
65
These favorable changes are partially offset by:
• A $164 million decrease due to the absence of results from our former Geismar Olefins and RGP Splitter
plants subsequent to their sale in July 2017;
• A $63 million charge reducing regulatory assets related to deferred taxes on AFUDC resulting from Tax Reform
(see Note 7 – 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 10 – Employee Benefit Plans of Notes to
Consolidated Financial Statements);
• 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.
66
Management’s Discussion and Analysis of Financial Condition and Liquidity
Overview
In 2018, through the WPZ Merger, we streamlined our corporate structure and governance while improving our
credit ratings to investment-grade. Additionally, we monetized assets, through sales of the Four Corners area assets and
certain Gulf Coast pipeline systems which were not core to our business strategy, into a source for growth capital for
acquisitions such as our RMM equity-method investment and a driver for improving credit metrics while continuing
to reduce our direct commodity exposure.
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
2019 are currently expected to be in a range from $2.7 billion to $2.9 billion. Growth capital spending in 2019 includes
Transco expansions, all of which are fully contracted with firm transportation agreements, and continuing to develop
our gathering and processing infrastructure in the Northeast G&P and West segments. 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. We intend to fund our planned 2019
growth capital with retained cash flow and certain sources of available liquidity described below. 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 2019. Our potential material internal and external sources and uses of
consolidated liquidity for 2019 are as follows:
Sources:
Uses:
Cash and cash equivalents on hand
Cash generated from operations
Distributions from our equity-method investees
Utilization of our credit facility 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
Quarterly dividends to our 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.
67
As of December 31, 2018, we had a working capital deficit of $347 million, including cash and cash equivalents.
Our available liquidity is as follows:
Available Liquidity
December 31, 2018
(Millions)
Cash and cash equivalents ...................................................................................................................... $
Capacity available under our $4.5 billion credit facility, less amounts outstanding under our $4
billion commercial paper program (1) ................................................................................................
$
168
4,340
4,508
__________
(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. Through
completion of the WPZ Merger on August 10, 2018, the highest combined amount outstanding under WPZ’s
commercial paper program and credit facility and our former credit facility during 2018 was $1.325 billion. In
July 2018, we along with Transco and Northwest Pipeline entered into a new unsecured revolving credit agreement
with aggregate commitments available of $4.5 billion under the credit facility, which became effective upon
completion of the WPZ Merger. The highest amount outstanding under our current commercial paper program and
credit facility during 2018 was $886 million. At December 31, 2018, we were in compliance with the financial
covenants associated with our credit facility. See Note 14 – Debt, Banking Arrangements, and Leases of Notes to
Consolidated Financial Statements for additional information on our credit facility and commercial paper program.
Borrowing capacity available under our credit facility as of February 19, 2019, was $4.5 billion.
Dividends
We increased our regular quarterly cash dividend by approximately 13 percent from the previous quarterly cash
dividends of $0.30 per share paid in each quarter of 2017, to $0.34 per share for the quarterly cash dividends paid in
each quarter of 2018.
Registrations
In February 2018, we filed a shelf registration statement, as a well-known seasoned issuer. In August 2018, we
filed a prospectus supplement for the offer and sale from time to time of shares of our common stock 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 then-current prices. Such sales are to be made pursuant to an equity distribution agreement between us and certain
entities who may act as sales agents or purchase for their own accounts as principals at a price agreed upon at the time
of the sale. There was no activity during 2018.
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 6 – Investing Activities of Notes to
Consolidated Financial Statements for our more significant equity-method investees.)
Credit Ratings
The interest rates at which we are able to borrow money is impacted by our credit ratings. The current ratings are
as follows:
Rating Agency
S&P Global Ratings
Moody’s Investors Service
Fitch Ratings
Outlook
Negative
Stable
Positive
Senior Unsecured
Debt Rating
BBB
Baa3
BBB-
Corporate
Credit Rating
BBB
N/A
N/A
68
These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our
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 investment-grade ratings even if we meet or exceed their current criteria
for investment-grade ratios. A downgrade of our credit ratings might increase our future cost of borrowing and would
require us to provide additional collateral to third parties, negatively impacting our available liquidity.
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,
2018
2017
2016
Sources of cash and cash equivalents:
Operating activities – net .......................................................... Operating
Proceeds from long-term debt (see Note 14)............................
Financing
Proceeds from credit-facility borrowings .................................
Financing
Proceeds from sale of businesses, net of cash divested (see
$
Note 3)...................................................................................
Contributions in aid of construction .........................................
Proceeds from equity offerings.................................................
Proceeds from dispositions of equity-method investments
(see Note 6) ...........................................................................
Uses of cash and cash equivalents:
Capital expenditures .................................................................
Payments on credit-facility borrowings....................................
Common dividends paid ...........................................................
Payments of long-term debt (see Note 14) ...............................
Purchases of and contributions to equity-method investments.
Dividends and distributions paid to noncontrolling interests ...
Payments of commercial paper – net........................................
Contribution to Gulfstream for repayment of debt (see
Note 6)...................................................................................
(Millions)
$
$
3,293
2,086
1,840
1,296
411
15
3,089
1,698
1,635
2,067
426
2,131
Investing
Investing
Financing
Investing
—
200
Investing
Financing
Financing
Financing
Investing
Financing
Financing
(3,256)
(1,950)
(1,386)
(1,254)
(1,132)
(591)
(2)
(2,399)
(2,140)
(992)
(3,785)
(132)
(822)
(93)
4,155
998
5,530
1,020
218
123
34
(2,051)
(6,715)
(1,261)
(375)
(177)
(940)
(409)
Financing
—
—
(148)
Other sources / (uses) – net ..........................................................
Increase (decrease) in cash and cash equivalents.........................
Financing
and Investing
(101)
(731) $
(154)
729
$
$
68
70
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, Equity
(earnings) losses, Net (gain) loss on disposition of equity-method investments, Impairment of equity-method investments,
Gain on sale of certain assets, Impairment of and net (gain) loss on sale of other assets and businesses, Gain on
deconsolidation of businesses, and Regulatory charges resulting from Tax Reform.
Our Net cash provided (used) by operating activities in 2018 increased from 2017 primarily due to higher operating
income (excluding noncash items as previously discussed) in 2018, partially offset by the impact of decreased
distributions from unconsolidated affiliates in 2018.
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 and increased
distributions from unconsolidated affiliates in 2017.
69
Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments
We have various other guarantees and commitments which are disclosed in Note 4 – Variable Interest Entities,
Note 11 – Property, Plant, and Equipment, Note 14 – Debt, Banking Arrangements, and Leases, Note 17 – Fair Value
Measurements, Guarantees, and Concentration of Credit Risk, and Note 18 – 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, 2018:
2019
2020 - 2021
2022 - 2023
Thereafter
Total
(Millions)
Long-term debt: (1)
Principal ............................................................... $
Interest ..................................................................
Operating leases .......................................................
Purchase obligations (2) ...........................................
Other obligations (3)(4) ...........................................
Total .......................................................... $
47
1,170
34
1,194
2
2,447
$
$
3,028
2,147
59
819
4
6,057
$
$
3,654
1,868
39
457
1
6,019
$
$
15,878
9,410
86
363
—
25,737
$
$
22,607
14,595
218
2,833
7
40,260
______________
(1) Includes the borrowings outstanding under credit facilities, but does not include any related variable-rate interest
payments.
(2) Includes approximately $480 million in open property, plant, and equipment purchase orders. Includes an estimated
$329 million long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at
December 31, 2018 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 $453 million long-term ethane purchase obligation with index-
based pricing terms that primarily supplies third parties at their plants and is reflected in this table at a value
calculated using December 31, 2018 prices. Any excess purchased volumes may be sold at comparable market
prices. Includes an estimated $211 million long-term mixed NGLs purchase obligation with index-based pricing
terms that is reflected in this table at December 31, 2018 prices. Includes an estimated $312 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 value calculated using December 31, 2018 prices. Any excess purchased
volumes may be sold at comparable market prices. Includes an estimated $332 million long-term mixed NGLs
purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2018 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 $93 million in 2018 and $90 million in 2017.
In 2019, we expect to contribute approximately $69 million to these plans (see Note 10 – 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 2018, 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 2019, we expect to contribute approximately $60 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
70
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.
(4) We have not included income tax liabilities in the table above. See Note 8 – 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 50 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 18 – 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 $35 million, all of which are included in Accrued
liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet at December 31,
2018. We will seek recovery of the accrued costs related to remediation activities by our interstate gas pipelines totaling
approximately $6 million through future natural gas transmission rates. The remainder of these costs will be funded
from operations. During 2018, we paid approximately $4 million for cleanup and/or remediation and monitoring
activities. We expect to pay approximately $11 million in 2019 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, 2018, 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. These 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. The EPA previously issued its rule regarding National Ambient Air Quality
Standards for ground-level ozone. We are monitoring the rule's implementation as it 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.
71
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 our
credit facility and any issuances under our 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 14 – 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, 2018 and 2017. See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
of Notes to Consolidated Financial Statements for the methods used in determining the fair value of our long-term debt.
2019
2020
2021
2022
2023
Thereafter (1)
Total
(Millions)
Fair Value
December 31,
2018
Long-term debt, including
current portion:
Fixed rate .......................
$
47
$ 2,138
$
890
$ 2,021
$ 1,473
Weighted-average
interest rate ................
5.2%
5.2%
5.2%
5.3%
5.5%
Variable rate (2)..............
$
— $
— $
— $
— $
160
$
$
15,685
$ 22,254
$
23,170
5.7%
— $
160
$
160
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 (3)..............
$
— $
— $
— $
270
$
— $
— $
270
$
270
__________________
(1) Includes unamortized discount / premium and debt issuance costs.
(2) The weighted-average interest rate for our $160 million credit facility borrowing at December 31, 2018 was 3.77
percent.
(3) The weighted-average interest rate for our $270 million credit facility borrowing at December 31, 2017 was
3.16 percent.
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
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, 2018 and 2017, our derivative activity
was not material. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to
Consolidated Financial Statements.)
72
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, 2018 and 2017, 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, 2018, and the related notes and
the financial statement schedule 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, 2018 and
2017, and the consolidated results of its operations and its cash flows for each of the three years in the period ended
December 31, 2018, 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 $225 million and $244 million as of December 31, 2018 and 2017, respectively, and the
Company’s equity earnings in the net income of Gulfstream were $75 million in 2018, $75 million in 2017 and $69
million in 2016. 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, 2018, 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 21, 2019 expressed an unqualified opinion
thereon.
Adoption of New Accounting Standards
As discussed in Note 1 and Note 2 to the consolidated financial statements, the Company changed its method for
accounting for revenue in 2018.
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 21, 2019
73
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 sheets of Gulfstream Natural Gas System, L.L.C. (the “Company”) as of December 31,
2018 and 2017, and the related statements of operations, comprehensive income, cash flows, and members’ equity for
the years 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, 2018 and 2017, and the results of its operations and its cash flows for the years 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 audits. 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 audits 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 audits 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 audits 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 audits provide a reasonable basis for our
opinion.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 21, 2019
We have served as the Company’s auditor since 2018.
74
Report of Independent Registered Public Accounting Firm
To the Members of Gulfstream Natural Gas System, L.L.C.
We have audited the statement of operations, comprehensive income, cash flows, and members’ equity of Gulfstream
Natural Gas System, L.L.C. (the "Company") for 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 audit.
We conducted our audit 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 audit included consideration of internal control over financial reporting
as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing
an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no
such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis
for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the results of operations of Gulfstream
Natural Gas System, L.L.C. and its cash flows for 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
75
The Williams Companies, Inc.
Consolidated Statement of Operations
Years Ended December 31,
2018
2017
2016
(Millions, except per-share amounts)
$
5,502
400
2,784
8,686
2,707
137
1,507
1,725
569
1,915
(692)
(17)
67
7,918
768
396
(32)
219
(1,160)
48
92
331
138
193
348
(155)
1
(156) $
$
5,312
—
2,719
8,031
2,300
—
1,576
1,736
594
1,248
(1,095)
674
71
7,104
927
434
—
282
(1,116)
33
(25)
535
(1,974)
2,509
335
2,174
—
2,174
$
$
$
(.16) $
973,626
2.63
826,177
(.16) $
973,626
2.62
828,518
5,171
—
2,328
7,499
1,725
—
1,592
1,763
722
873
—
—
135
6,810
689
397
(430)
63
(1,217)
38
85
(375)
(25)
(350)
74
(424)
—
(424)
(.57)
750,673
(.57)
750,673
Revenues:
Service revenues ...................................................................................
Service revenues - commodity consideration (Note 1).........................
Product sales .........................................................................................
Total revenues .................................................................................
$
Costs and expenses:
Product costs ........................................................................................
Processing commodity expenses (Note 1) ............................................
Operating and maintenance expenses ...................................................
Depreciation and amortization expenses ..............................................
Selling, general, and administrative expenses ......................................
Impairment of certain assets (Note 17) ................................................
Gain on sale of certain assets (Note 3) .................................................
Regulatory charges resulting from Tax Reform (Note 1) .....................
Other (income) expense – net ...............................................................
Total costs and expenses ..................................................................
Operating income (loss) ..........................................................................
Equity earnings (losses) ..........................................................................
Impairment of equity-method investments (Note 17) .............................
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. .........
Preferred stock dividends (Note 15) .....................................................
Net income (loss) available to common stockholders ..........................
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.
76
The Williams Companies, Inc.
Consolidated Statement of Comprehensive Income (Loss)
Years Ended December 31,
2018
2017
2016
(Millions)
Net income (loss) .......................................................................................................
$
193
$
2,509
$
(350)
Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $1, $2,
and ($1) in 2018, 2017, and 2016, respectively ..............................................
Reclassifications into earnings of net derivative instruments (gain) loss, net of
taxes of ($1), ($1), and $1 in 2018, 2017, and 2016, respectively..................
Foreign currency translation activities:
Foreign currency translation adjustments, net of taxes of ($37) in 2016 ...........
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 and $2 in 2017, and 2016, respectively.........
Net actuarial gain (loss) arising during the year, net of taxes of $3, ($15), and
$8 in 2018, 2017 and 2016, respectively ........................................................
Amortization of actuarial (gain) loss and net actuarial loss from settlements
included in net periodic benefit cost (credit), net of taxes of ($11), ($37),
and ($12) in 2018, 2017, and 2016, respectively (Note 10) ..........................
Other comprehensive income (loss) ..........................................................................
Comprehensive income (loss) ...................................................................................
Less: Comprehensive income (loss) attributable to noncontrolling interests ..........
(7)
8
—
—
—
(6)
35
30
223
346
(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. ...........
$
(123) $
2,275
$
(321)
See accompanying notes.
77
The Williams Companies, Inc.
Consolidated Balance Sheet
December 31,
2018
2017
(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,
2018 and $9 at December 31, 2017)......................................................................
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 .....................................................................................................
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 18)
$
168
$
992
130
174
1,464
7,821
27,504
7,767
746
45,302
662
1,102
47
1,811
22,367
1,524
3,603
$
$
$
$
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
Equity:
Stockholders’ equity:
Preferred stock (Note 15) .....................................................................................
35
—
Common stock ($1 par value; 1,470 million shares authorized at December 31,
2018 and 960 million shares authorized at December 31, 2017; 1,245
million shares issued at December 31, 2018 and 861 million shares issued at
December 31, 2017)..........................................................................................
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 ...............................................................................
$
1,245
24,693
(10,002)
(270)
(1,041)
14,660
1,337
15,997
45,302
$
861
18,508
(8,434)
(238)
(1,041)
9,656
6,519
16,175
46,352
See accompanying notes.
78
The Williams Companies, Inc.
Consolidated Statement of Changes in Equity
The Williams Companies, Inc. Stockholders
Preferred
Stock
Common
Stock
Capital in
Excess of
Par Value
Retained
Deficit
AOCI*
Treasury
Stock
(Millions)
Total
Stockholders’
Equity
Noncontrolling
Interests
Total
Equity
Balance – December 31, 2015 ........................... $
— $
784
$
14,807
$
(7,960)
$
(442)
$
(1,041)
$
6,148
$
10,077
$ 16,225
Net income (loss).................................................
Other comprehensive income (loss) ....................
Cash dividends – common stock ($1.68 per
share) ...................................................................
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.........................
Balance – December 31, 2016 ...........................
Net income (loss).................................................
Other comprehensive income (loss) ....................
Issuance of common stock (Note 15) ..................
Cash dividends – common stock ($1.20 per
share) ...................................................................
Dividends and distributions to noncontrolling
interests .............................................................
Stock-based compensation and related common
stock issuances, net of tax .................................
Adoption of new accounting standard .................
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.........................
Balance – December 31, 2017 ...........................
Adoption of new accounting standards (Note 1) .
Net income (loss).................................................
Other comprehensive income (loss) ....................
WPZ Merger (Note 1)..........................................
Issuance of preferred stock (Note 15)..................
Cash dividends – common stock ($1.36 per
share) ...................................................................
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........
Deconsolidation of subsidiary (Note 4)...............
Other ....................................................................
Net increase (decrease) in equity.........................
Balance – December 31, 2018 ........................... $
* Accumulated Other Comprehensive Income (Loss)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
35
—
—
—
—
—
—
—
—
35
35
—
—
—
—
1
—
—
—
—
1
—
—
—
—
56
—
12
—
12
80
785
14,887
—
—
2,043
—
—
73
1
—
1,497
—
7
3,621
18,508
—
—
—
6,112
—
—
—
60
—
14
—
—
—
—
75
—
—
1
—
—
—
—
—
76
861
—
—
—
382
—
—
—
1
—
—
—
—
1
(424)
—
(1,261)
—
—
—
—
—
(4)
(1,689)
(9,649)
2,174
—
—
(992)
—
—
36
—
—
—
(3)
1,215
(8,434)
(23)
(155)
—
—
—
(1,386)
—
—
—
—
—
—
—
103
—
—
—
—
—
—
—
103
(339)
—
101
—
—
—
—
—
—
—
—
—
101
(238)
(61)
—
32
(3)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(1,041)
—
—
—
—
—
—
—
—
—
—
—
—
(1,041)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(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
(84)
(155)
32
6,491
35
(1,386)
—
61
—
14
—
—
(4)
5,004
74
69
—
(350)
172
(1,261)
(940)
(940)
—
114
(18)
29
(2)
(674)
9,403
335
(1)
—
—
(883)
—
—
61
57
114
(6)
29
6
(2,179)
14,046
2,509
100
2,118
(992)
(883)
74
37
61
(2,407)
(910)
17
(6)
(2,884)
6,519
(37)
348
(2)
(4,629)
—
—
17
(2)
2,129
16,175
(121)
193
30
1,862
35
(1,386)
(637)
(637)
—
46
(18)
15
(267)
(1)
(5,182)
61
46
(4)
15
(267)
(5)
(178)
(1)
(4)
384
6,185
(1,568)
(32)
$
1,245
$
24,693
$ (10,002)
$
(270)
$
(1,041)
$
14,660
$
1,337
$ 15,997
See accompanying notes.
79
The Williams Companies, Inc.
Consolidated Statement of Cash Flows
Years Ended December 31,
2016
2017
2018
(Millions)
OPERATING ACTIVITIES:
Net income (loss) ................................................................................................................
Adjustments to reconcile to net cash provided (used) by operating activities:
$
193
$
2,509
$
(350)
Depreciation and amortization ......................................................................................
Provision (benefit) for deferred income taxes ...............................................................
Equity (earnings) losses.................................................................................................
Distributions from unconsolidated affiliates .................................................................
Net (gain) loss on disposition of equity-method investments .......................................
Impairment of equity-method investments (Note 17) ...................................................
Gain on sale of certain assets (Note 3) ..........................................................................
Impairment of and net (gain) loss on sale of other assets and businesses (Note 17) ....
Gain on deconsolidation of businesses (Note 6) ...........................................................
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............................
Common dividends paid .....................................................................................................
Dividends and distributions paid to noncontrolling interests .............................................
Contributions from noncontrolling interests.......................................................................
Payments for debt issuance costs........................................................................................
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 and contributions to equity-method investments...........................................
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.........................................................................................................
$
$
$
See accompanying notes.
1,725
220
(396)
693
—
32
(692)
1,915
(203)
55
(15)
(36)
(16)
17
(93)
23
(129)
3,293
(2)
3,926
(3,204)
15
—
(1,386)
(591)
15
(26)
—
(46)
(1,299)
(3,256)
(7)
411
1,296
—
(1,132)
(37)
(2,725)
(731)
899
168
$
1,736
(2,012)
(434)
784
(269)
—
(1,095)
1,249
—
78
776
(88)
8
(21)
118
(92)
(158)
3,089
(93)
3,333
(5,925)
2,131
—
(992)
(822)
17
(17)
—
(92)
(2,460)
(2,399)
(41)
426
2,067
200
(132)
(21)
100
729
170
899
$
1,763
(26)
(397)
742
(27)
430
—
918
—
73
—
82
(25)
(4)
35
512
429
4,155
(409)
6,528
(7,091)
9
114
(1,261)
(940)
29
(9)
(148)
(16)
(3,194)
(2,051)
30
218
1,020
34
(177)
35
(891)
70
100
170
(3,021) $
(235)
(3,256) $
(2,662) $
263
(2,399) $
(1,912)
(139)
(2,051)
80
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.
WPZ Merger
On August 10, 2018, we completed our merger with Williams Partners L.P. (WPZ), our previously consolidated
master limited partnership, pursuant to which we acquired all of the approximately 256 million publicly held outstanding
common units of WPZ in exchange for 382 million shares of our common stock (WPZ Merger). Williams continued
as the surviving entity. The WPZ Merger was accounted for as a noncash equity transaction resulting in increases to
Common stock of $382 million, Capital in excess of par value of $6.112 billion, and Regulatory assets, deferred charges,
and other of $33 million and decreases to Accumulated other comprehensive income (loss) (AOCI) of $3 million,
Noncontrolling interests in consolidated subsidiaries of $4.629 billion, and Deferred income tax liabilities of $1.829
billion in the Consolidated Balance Sheet. Prior to the completion of the WPZ Merger and pursuant to its distribution
reinvestment program, WPZ had issued common units to the public in 2018, 2017, and 2016 associated with reinvested
distributions of $46 million, $61 million, and $10 million, respectively.
Financial Repositioning
In January 2017, we entered into agreements with WPZ, wherein we permanently waived the general partner’s
incentive distribution rights 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 15 – 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.
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 in the United States. Prior to the WPZ Merger, we had one reportable segment, Williams Partners.
Beginning in the third-quarter 2018, consistent with the manner in which our chief operating decision maker evaluates
performance and allocates resources, our operations are now presented within the following reportable segments:
Northeast G&P, Atlantic-Gulf, and West. Prior period segment disclosures have been recast for the new segment
presentation.
Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus Shale region
primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern Ohio, as well as a 66
percent interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated entity), 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),
and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66
percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).
Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transcontinental Gas Pipe Line Company, LLC
(Transco), and significant natural gas gathering and processing and crude oil production handling and transportation
81
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One LLC (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 Natural Gas System, L.L.C.
(Gulfstream), a 60 percent equity-method investment in Discovery Producer Services LLC (Discovery), and a 41 percent
interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), which is developing a pipeline
project (see Note 4 – Variable Interest Entities).
West is comprised of our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline), and our
gathering, processing, and treating operations in Colorado, Wyoming, and 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. This segment also includes
our natural gas liquid (NGL) and natural gas marketing business, storage facilities, an undivided 50 percent interest in
an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in Overland Pass Pipeline, LLC
(OPPL), a 50 percent interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope) (an equity-method investment
following deconsolidation as of June 30, 2018), a 50 percent equity-method investment in Rocky Mountain Midstream
Holdings LLC (RMM), a 15 percent equity-method investment in Brazos Permian II, LLC (Brazos Permian II), and
our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the
Mid-Continent region (see Note 6 – Investing Activities). West also included our former natural gas gathering and
processing assets in the Four Corners area of New Mexico and Colorado (see Note 3 – Divestitures).
Other includes our previously owned operations, including our former 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),
which was sold in July 2017 (see Note 3 – Divestitures), and a refinery grade propylene splitter in the Gulf region,
which was sold in June 2017. This segment also included our previously owned Canadian assets, which included 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. Other also includes minor business activities that
are not operating segments, as well as corporate operations.
Basis of Presentation
Significant risks and uncertainties
We believe that the carrying value of certain of our property, plant, and equipment and other identifiable intangible
assets, notably certain acquired assets accounted for as business combinations between 2012 and 2014, may be in excess
of current fair value. However, the carrying value of these assets, in our judgment, continues to be recoverable based
on our evaluation of undiscounted future cash flows. It is reasonably possible that future strategic decisions, including
transactions such as monetizing non-core assets or contributing assets to new ventures with third parties, as well as
unfavorable changes in expected producer activities could impact our assumptions and ultimately result in impairments
of these assets. Such transactions or developments may also indicate that certain of our equity-method investments
have experienced other-than-temporary declines in value, which could also result in impairment.
On March 15, 2018, the Federal Energy Regulatory Commission (FERC) issued a revised policy statement (the
revised policy statement) regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found
that an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an
income tax allowance and a return on equity pursuant to the discounted cash flow methodology. As a result, the FERC
will no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. The FERC further
stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent
proceedings. One of the benefits of the recent WPZ Merger is to allow our FERC-regulated pipelines to continue to
recover an income tax allowance in their cost of service rates.
On July 18, 2018, the FERC issued an order dismissing the requests for rehearing and clarification of the revised
policy statement. In addition, the FERC provided guidance that an MLP pipeline (or other pass-through entity) no
longer recovering an income tax allowance pursuant to the revised policy may eliminate previously accumulated deferred
82
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
income taxes (ADIT) from its cost of service instead of flowing these ADIT balances to ratepayers. This guidance, if
implemented, would significantly mitigate the impact of the revised policy statement. However, the FERC stated that
the revised policy statement and such guidance do not establish a binding rule but are instead expressions of general
policy intent designed to provide guidance by notifying entities of the course of action the FERC intends to follow in
future adjudications. To the extent the FERC addresses these issues in future proceedings, it will consider any arguments
regarding not only the application of the revised policy to the facts of the case, but also any arguments regarding the
underlying validity of the policy itself. The FERC’s guidance on ADIT likely will be challenged by customers and state
commissions, which would result in a long period of revenue uncertainty for pipelines eliminating ADIT from their
cost of service. The WPZ Merger has the additional benefit of eliminating this uncertainty.
On March 15, 2018, the FERC also issued a Notice of Proposed Rulemaking proposing a filing process that will
allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent
reduction in the corporate income tax rate in the Tax Cuts and Jobs Act (Tax Reform) and the revised policy statement.
On July 18, 2018, the FERC issued a Final Rule, retaining the filing requirement and reaffirming the options that
pipelines have to either reflect the reduced tax rate or explain why no rate change is necessary. The FERC also clarified
that a natural gas company organized as a pass-through entity and all of whose income or losses are consolidated on
the federal income tax return of its corporate parent is considered to be subject to the federal corporate income tax and
is thus eligible for a tax allowance. We believe this Final Rule and the previously discussed WPZ Merger allow for the
continued recovery of income tax allowances in Transco’s and Northwest Pipeline’s rates. Transco’s August 31, 2018
general rate case filing reflects a tax allowance based on this clarification, and the FERC’s September 28, 2018 order
in that rate case proceeding finds that Transco is exempt from the Final Rule’s Form 501-G filing requirement. In
addition, on October 19, 2018, Northwest Pipeline filed a petition requesting that the FERC waive its Form 501-G
filing requirement under this Final Rule because (i) the reduction in the corporate income tax is already addressed in
Northwest Pipeline’s 2017 rate settlement, and (ii) as discussed above, the WPZ Merger allows for the continued
recovery of income tax allowances in Northwest Pipeline’s rates. The FERC agreed and granted Northwest Pipeline’s
petition for waiver on November 19, 2018. On October 11, 2018 and December 6, 2018, Discovery Gas Transmission,
LLC and Pine Needle LNG Company, LLC, respectively, filed their Form 501-Gs, including explanations as to why
no adjustments to rates are needed.
On March 15, 2018, the FERC also issued a Notice of Inquiry seeking comments on the additional impacts of Tax
Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to ADIT
amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features
of Tax Reform require FERC action. We are evaluating the impact of these developments on our interstate natural gas
pipelines and currently expect any associated impacts would be prospective and determined through subsequent rate
proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax
Reform. It is reasonably possible that future tariff-based rates collected by our interstate natural gas pipelines may be
adversely impacted.
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 variable interest entity (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;
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Notes to Consolidated Financial Statements – (Continued)
•
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.
Significant estimates and assumptions include:
•
Impairment assessments of investments, property, plant, and equipment, and other identifiable intangible
assets;
• Litigation-related contingencies;
• Environmental remediation obligations;
• Depreciation and/or amortization of long-lived assets;
• Depreciation and/or amortization of equity-method investment basis differences;
• Asset retirement obligations (AROs);
• Pension and postretirement valuation variables;
• Measurement of regulatory liabilities;
• Measurement of deferred income tax assets and liabilities, including assumptions related to the realization of
deferred income tax assets.
These estimates are discussed further throughout these notes.
Regulatory accounting
Transco and Northwest Pipeline are regulated by the 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,” (ASC 980) 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
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The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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, Tax Reform was enacted, which, among other things, reduced the federal corporate income
tax rate from 35 percent to 21 percent (see Note 8 – 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. As of December 31, 2018, the balance of these regulatory liabilities totaled $657 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.
Certain of our equity-method investees recorded similar regulatory liabilities, for which our Equity earnings (losses)
in the Consolidated Statement of Operations for 2017 were 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 7 – 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, 2018 and 2017
are as follows:
December 31,
2018
2017
Current assets reported within Other current assets and deferred charges ........................... $
Noncurrent assets reported within Regulatory assets, deferred charges, and other ..............
Total regulated assets ...................................................................................................... $
$
(Millions)
103
495
598
$
102
376
478
Current liabilities reported within Accrued liabilities............................................................ $
Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other ....
Total regulated liabilities................................................................................................. $
5
1,321
1,326
$
$
18
1,250
1,268
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Notes to Consolidated Financial Statements – (Continued)
Cash and cash equivalents
Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less
when acquired.
Accounts receivable
Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We
estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our
customers, and the amount and age of past due accounts. We do not offer extended payment terms and typically receive
payment within one month. 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 NGLs, 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.
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
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.
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
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Notes to Consolidated Financial Statements – (Continued)
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.
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.
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
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 14 – 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
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Notes to Consolidated Financial Statements – (Continued)
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 17 – 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.
For commodity derivatives designated as a cash flow hedge, the change in fair value of the derivative is reported
in AOCI in the Consolidated Balance Sheet and reclassified into earnings in the period in which the hedged item affects
earnings. 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
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The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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 (subsequent to the adoption of ASC 606)
Customers in our gas pipeline businesses are comprised of public utilities, municipalities, gas marketers and
producers, intrastate pipelines, direct industrial users, and electrical generators. Customers in our midstream businesses
are comprised of oil and natural gas producer counterparties. Customers for our product sales are comprised of public
utilities, gas marketers, and direct industrial users.
A performance obligation is a promise in a contract to transfer a distinct good or service (or integrated package of
goods or services) to the customer. A contract’s transaction price is allocated to each distinct performance obligation
and recognized as revenue, when, or as, the performance obligation is satisfied. A performance obligation is distinct if
the service is separately identifiable from other items in the integrated package of services and if a customer can benefit
from it on its own or with other resources that are readily available to the customer. An integrated package of services
typically represents a single performance obligation if the services are contained within the same contract or within
multiple contracts entered into in contemplation with one another that are highly interdependent or highly interrelated,
meaning each of the services is significantly affected by one or more of the other services in the contract. Service
revenue contracts from our gas pipeline and midstream businesses contain a series of distinct services, with the majority
of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously
receives and consumes the benefits provided by our performance. Most of our product sales contracts have a single
performance obligation with revenue recognized at a point in time when the products have been sold and delivered to
the customer.
Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment
utilized in our operations. For our rate-regulated gas pipeline businesses that apply ASC 980, we follow FERC guidelines
with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-
negotiable in nature; thus, the construction activities do not represent an ongoing major and central operation of our
gas pipeline businesses and are not within the scope of ASC Topic 606, “Revenue from Contracts with Customers” (ASC
606). Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset. For our midstream
businesses, reimbursement and service contracts with customers are viewed together as providing the same commercial
objective, as we have the ability to negotiate the mix of consideration between reimbursements and amounts billed
over time. Accordingly, we generally recognize reimbursements of construction costs from customers on a gross basis
as a contract liability separate from the associated costs included within property, plant, and equipment. The contract
liability is recognized into service revenues as the underlying performance obligations are satisfied.
Service Revenues
Gas pipeline businesses: Revenues from our regulated interstate natural gas pipeline businesses, which are subject
to regulation by certain state and federal authorities, including the FERC, include both firm and interruptible
transportation and storage contracts. Firm transportation and storage agreements provide for a fixed reservation
charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural
gas delivered/stored, each at rates specified in our FERC tariffs or based on negotiated contractual rates, with
contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision,
which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of
times following the specified contract term and until terminated generally by either us or the customer. Interruptible
transportation and storage agreements provide for a volumetric charge based on actual commodity transportation
or storage utilized in the period in which those services are provided, and the contracts are generally limited to
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The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
one-month periods or less. Our performance obligations related to our interstate natural gas pipeline businesses
include the following:
• Firm transportation or storage under firm transportation and storage contracts—an integrated package of
services typically constituting a single performance obligation, which includes standing ready to provide such
services and receiving, transporting or storing (as applicable), and redelivering commodities;
•
Interruptible transportation and storage under interruptible transportation and storage contracts—an integrated
package of services typically constituting a single performance obligation once scheduled, which includes
receiving, transporting or storing (as applicable), and redelivering commodities.
In situations where, in our judgment, we consider the integrated package of services as a single performance
obligation, which represents a majority of our interstate natural gas pipeline contracts with customers, we do not
consider there to be multiple performance obligations because the nature of the overall promise in the contract is
to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver
natural gas to the customer; therefore, revenue is recognized over time upon satisfaction of our daily stand ready
performance obligation.
We recognize revenues for reservation charges over the performance obligation period, which is the contract
term, 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 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 because
they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and
commodity charges in our interstate natural gas pipeline businesses are recognized as revenue in the same period
they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be
subject to refund upon the issuance of final orders by the FERC in pending rate proceedings. We use judgment to
record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of
counsel, and other risks.
Midstream businesses: Revenues from our non-regulated gathering, processing, transportation, and storage
midstream businesses include contracts for natural gas gathering, processing, treating, compression, transportation,
and other related services with contract terms that are generally long-term in nature and may extend up to the
production life of the associated reservoir. Additionally, our midstream businesses generate revenues from fees
charged for storing customers’ natural gas and NGLs, generally under prepaid contracted storage capacity contracts.
In situations where, in our judgment, we provide an integrated package of services combined into a single
performance obligation, which represents a majority of this class of contracts with customers, we do not consider
there to be multiple performance obligations because the nature of the overall promise in the contract is to provide
gathering, processing, transportation, storage, and related services resulting in the delivery, or redelivery in the
context of storage services, of pipeline-quality natural gas and NGLs to the customer. As such, revenue is recognized
at the daily completion of the integrated package of services as the integrated package represents a single
performance obligation. Additionally, certain contracts in our midstream businesses contain fixed or upfront
payment terms that result in the deferral of revenues until such services have been performed or such capacity has
been made available.
We also earn revenues from offshore crude oil and natural gas gathering and transportation and offshore
production handling. These services represent an integrated package of services and are considered a single distinct
performance obligation for which we recognize revenues as the services are provided to the customer.
We generally earn a contractually stated fee per unit for the volume of product transported, gathered, processed,
or stored. The rate is generally fixed; however, certain contracts contain variable rates that are subject to change
based on commodity prices, levels of throughput, or an annual adjustment based on a formulaic cost of service
calculation. In addition, we have contracts with contractually stated fees that decline over the contract term, such
as declines based on the passage of time periods or achievement of cumulative throughput amounts. For all of our
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The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
contracts, we allocate the transaction price to each performance obligation based on the judgmentally determined
relative standalone selling price. The excess of consideration received over revenue recognized results in the
deferral of those amounts until future periods based on a units of production or straight-line methodology as these
methods appropriately match the consumption of services provided to the customer. The units of production
methodology requires the use of production estimates that are uncertain and the use of judgment when developing
estimates of future production volumes, thus impacting the rate of revenue recognition. Production estimates are
monitored as circumstances and events warrant. Certain of our gas gathering and processing agreements have
minimum volume commitments (MVC). If a customer under such an agreement fails to meet its MVC for a specified
period (thus not exercising all the contractual rights to gathering and processing services within the specified period,
herein referred to as “breakage”), it is obligated to pay a contractually determined fee based upon the shortfall
between the actual gathered or processed volumes and the MVC for the period contained in the contract. When
we conclude, based on management’s judgment, it is probable that the customer will not exercise all or a portion
of its remaining rights, we recognize revenue associated with such breakage amount in proportion to the pattern
of exercised rights within the respective MVC period.
Under keep-whole and percent-of-liquids processing contracts, we receive commodity consideration in the
form of NGLs and take title to the NGLs at the tailgate of the plant. We recognize such commodity consideration
as service revenue based on the market value of the NGLs retained at the time the processing is provided. The
current market value, as opposed to the market value at the contract inception date, is used due to a combination
of factors, including the fact that the volume, mix, and market price of NGL consideration to be received is unknown
at the time of contract execution and is not specified in our contracts with customers. Additionally, product sales
revenue (discussed below) is recognized upon the sale of the NGLs to a third party based on the sales price at the
time of sale. As a result, revenue is recognized both at the time the processing service is provided in Service revenues
– commodity consideration and at the time the NGLs retained as part of the processing service are sold in Product
sales. The recognition of revenue related to commodity consideration has the impact of increasing the book value
of NGL inventory, resulting in higher cost of goods sold at the time of sale. Given that most inventory is sold in
the same period that it is generated, the impact of these transactions is expected to have little impact to operating
income.
Product Sales
In the course of providing transportation services to customers of our gas pipeline businesses and gathering
and processing services to customers of our midstream businesses, we may receive different quantities of natural
gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are
primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our
FERC tariffs or gathering and processing agreements, respectively. Revenue is recognized from the sale of natural
gas upon settlement of imbalances.
In certain instances, we purchase NGLs, crude oil, and natural gas from our oil and natural gas producer
customers. In addition, we retain NGLs as consideration in certain processing arrangements, as discussed above
in the Service Revenues - Midstream businesses section. We recognize revenue from the sale of these commodities
when the products have been sold and delivered. Our product sales contracts are primarily short-term contracts
based on prevailing market rates at the time of the transaction.
Contract Assets
Our contract assets primarily consist of revenue recognized under contracts containing MVC features whereby
management has concluded it is probable there will be a short-fall payment at the end of the current MVC period,
which typically follows the calendar year, and that a significant reversal of revenue recognized currently for the
future MVC payment will not occur. As a result, our contract assets related to our future MVC payments are
generally expected to be collected within the next 12 months and are included within Other current assets and
deferred charges in our Consolidated Balance Sheet until such time as the MVC short-fall payments are invoiced
to the customer.
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Notes to Consolidated Financial Statements – (Continued)
Contract Liabilities
Our contract liabilities consist of advance payments primarily from midstream business customers which
include construction reimbursements, prepayments, and other billings for which future services are to be provided
under the contract. These amounts are deferred until recognized in revenue when the associated performance
obligation has been satisfied, which is primarily based on a units of production methodology over the remaining
contractual service periods, and are classified as current or noncurrent according to when such amounts are expected
to be recognized. Current and noncurrent contract liabilities are included within Accrued liabilities and Regulatory
liabilities, deferred income, and other, respectively, in our Consolidated Balance Sheet.
Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine
whether the advance payments provide us with a significant financing benefit. This determination is based on the
combined effect of the expected length of time between when we transfer the promised good or service to the
customer, when the customer pays for those goods or services, and the prevailing interest rates. We have assessed
our contracts for significant financing components and determined, in our judgment, that one group of contracts
entered into in contemplation of one another for certain capital reimbursements contains a significant financing
component. As a result, we recognize noncash interest expense based on the effective interest method and revenue
(noncash) is recognized when the underlying asset is placed into service utilizing a units of production or straight-
line methodology over the life of the corresponding customer contract.
Revenue recognition (prior to the adoption of ASC 606)
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.
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.
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The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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 16 – 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 10 – Employee Benefit Plans.)
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.
93
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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.
Accounting standards issued and adopted
During the first quarter of 2018, we early adopted Accounting Standards Update (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 and
prior to adopting this standard, the tax effects of items within accumulated other comprehensive income may not have
reflected 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. The adoption of ASU 2018-02 resulted
in the reclassification of $61 million from Accumulated other comprehensive income (loss) to Retained deficit on our
Consolidated Balance Sheet.
Effective January 1, 2018, we adopted 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 ASC 815. The ASU affects both the designation and measurement guidance for hedging
relationships and the presentation of hedging results. ASU 2017-12 was 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. The adoption of ASU 2017-12 did not have a significant impact on our consolidated financial
statements.
In May 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-09 establishing 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
94
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per
ASU 2015-14, the standard became effective for interim and annual reporting periods beginning after December 15,
2017.
We adopted the provisions of ASC 606 effective January 1, 2018, utilizing the modified retrospective transition
method for all contracts with customers, which included applying the provisions of ASC 606 beginning January 1,
2018, to all contracts not completed as of that date with the cumulative effect of applying the standard for periods prior
to January 1, 2018, as an adjustment to Total equity, net of tax, upon adoption. As a result of our adoption, the cumulative
impact to our Total equity, net of tax, at January 1, 2018, was a decrease of $121 million in the Consolidated Balance
Sheet.
For each revenue contract type, we conducted a formal contract review process to evaluate the impact of ASC 606.
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. ASC 606 requires that the transaction price, including any remaining contract liabilities from the old contract,
be allocated to the performance obligations over the term of the new contract. The contract modification 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 contract liabilities 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. Financial
systems and internal controls necessary for adoption were implemented effective January 1, 2018. (See Note 2 – Revenue
Recognition.)
Accounting standards issued but not yet adopted
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 could 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 operating 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.”
95
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
In July 2018, the FASB issued ASU 2018-11 “Leases (Topic 842): Targeted Improvements” (ASU 2018-11). Prior
to ASU 2018-11, a modified retrospective transition was required for financing or operating leases existing at or entered
into after the beginning of the earliest comparative period presented in the financial statements. ASU 2018-11 allows
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. ASU 2018-11 also allows a
practical expedient that permits lessors to not separate non-lease components from the associated lease component if
certain conditions are present. ASU 2016-02 is effective for interim and annual periods beginning after December 15,
2018. Early adoption is permitted. We are adopting ASU 2016-02 effective January 1, 2019.
We are substantially complete with our review of contracts to identify leases based on the modified definition of
a lease and implementing changes to our internal controls to support management in the accounting for and disclosure
of leasing activities upon adoption of ASU 2016-02. We implemented a financial lease accounting system to assist
management in the accounting for leases upon adoption. We are substantially complete with the implementation of
ASU 2016-02 and believe the most significant changes to our financial statements relate to the recognition of a lease
liability and offsetting right-of-use asset in our Consolidated Balance Sheet for operating leases, which we estimate to
be less than 1 percent of total liabilities and total assets, respectively. We have also evaluated ASU 2016-02’s available
practical expedients on adoption. We generally elected to adopt the practical expedients, which includes the practical
expedient to not separate lease and non-lease components by both lessees and lessors by class of underlying assets and
the land easements practical expedient.
96
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Note 2 – Revenue Recognition
Revenue by Category
The following table presents our revenue disaggregated by major service line:
Northeast
Midstream
Atlantic-
Gulf
Midstream
West
Midstream Transco
Northwest
Pipeline
Other
Intercompany
Eliminations
Total
(Millions)
Year Ended December 31, 2018
Revenues from contracts with
customers:
Service revenues:
Non-regulated gathering,
processing, transportation,
and storage:
Monetary consideration ........ $
861
$
541
$
1,590
$
— $
— $
Commodity consideration .....
Regulated interstate natural
gas transportation and
storage ...................................
Other .......................................
Total service revenues ..........
Product Sales:
NGL and natural gas................
Other .......................................
Total product sales................
Total revenues from contracts with
customers ....................................
Other revenues (1) ..........................
20
—
94
975
287
—
287
1,262
21
59
—
17
617
307
—
307
924
18
321
—
—
46
1,921
2
1,957
1,923
2,421
21
2,442
127
—
127
4,399
2,050
12
11
—
443
—
443
—
—
—
443
—
Total revenues ...................... $
1,283
$
942
$
4,411
$
2,061
$
443
$
2
—
—
—
2
—
—
—
2
32
34
$
(73) $
2,921
—
400
(2)
(15)
(90)
(382)
(4)
(386)
(476)
(12)
2,362
144
5,827
2,760
17
2,777
8,604
82
$
(488) $
8,686
______________________________
(1) Service revenues in our Consolidated Statement of Operations include leasing revenues associated with our
headquarters building and management fees that we receive for certain services we provide to operated joint
ventures and other investments. The leasing revenues and the management fees do not constitute revenue from
contracts with customers. Product sales in our Consolidated Statement of Operations include amounts associated
with our derivative contracts that are not within the scope of ASC 606.
Contract Assets
The following table presents a reconciliation of our contract assets:
Balance at beginning of period ..................................................................................................... $
Revenue recognized in excess of amounts invoiced................................................................
Minimum volume commitments invoiced...............................................................................
Balance at end of period................................................................................................................ $
4
66
(66)
4
Year Ended
December 31, 2018
(Millions)
97
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Contract Liabilities
The following table presents a reconciliation of our contract liabilities:
Year Ended
December 31, 2018
(Millions)
Balance at beginning of period ..................................................................................................... $
Payments received and deferred ..............................................................................................
Noncash interest expense for significant financing component ..............................................
Deconsolidation of Jackalope interest (Note 4).......................................................................
Deconsolidation of certain Permian assets (Note 6)................................................................
Recognized in revenue.............................................................................................................
Balance at end of period................................................................................................................ $
1,596
314
16
(52)
(26)
(451)
1,397
The following table presents the amount of the contract liabilities balance as of December 31, 2018, expected to
be recognized as revenue in each of the next five years as performance obligations are expected to be satisfied:
2019 .................................................................................................................................................. $
2020 ..................................................................................................................................................
2021 ..................................................................................................................................................
2022 ..................................................................................................................................................
2023 ..................................................................................................................................................
Thereafter..........................................................................................................................................
Total ............................................................................................................................................... $
(Millions)
271
142
121
102
95
666
1,397
Remaining Performance Obligations
The following table presents the transaction price allocated to the remaining performance obligations under certain
contracts as of December 31, 2018. These primarily include long-term contracts containing MVCs associated with our
midstream businesses, fixed payments associated with offshore production handling, and reservation charges on
contracted capacity on our gas pipeline firm transportation contracts with customers, as well as storage capacity
contracts. Amounts included in the table below for our interstate natural gas pipeline businesses reflect the rates for
such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based
on future tariffs approved by the FERC and the amount and timing of these changes is not currently known. As a
practical expedient permitted by ASC 606, this table excludes variable consideration as well as consideration in contracts
that is recognized in revenue as billed. It also excludes consideration received prior to December 31, 2018, that will
be recognized in future periods (see above for Contract Liabilities and the expected recognition of those amounts within
revenue). Certain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term
of the contract. The remaining performance obligation amounts as of December 31, 2018, do not consider potential
future performance obligations for which the renewal has not been exercised.
98
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The table below also does not include contracts with customers for which the underlying facilities have not received
FERC authorization to be placed into service.
2019 .................................................................................................................................................. $
2020 ..................................................................................................................................................
2021 ..................................................................................................................................................
2022 ..................................................................................................................................................
2023 ..................................................................................................................................................
Thereafter..........................................................................................................................................
Total ................................................................................................................................................ $
(Millions)
2,909
2,728
2,622
2,262
2,089
16,916
29,526
Accounts Receivable
The following is a summary of our Trade accounts and other receivables:
Accounts receivable related to revenues from contracts with customers............ $
Other accounts receivable....................................................................................
Total reflected in Trade accounts and other receivables ..................................... $
(Millions)
$
858
134
992
$
958
18
976
December 31, 2018
January 1, 2018
Impact of Adoption of ASC 606
The following table depicts the impact of the adoption of ASC 606 on our 2018 financial statements. The adjustment
to Intangible assets – net of accumulated amortization in the table below relates to the recognition under ASC 606 of
contract assets for MVC-related contracts associated with a 2014 acquisition. The recognition of these contract assets
resulted in a lower purchase price allocation to intangible assets. The adoption of ASC 606 did not result in adjustments
to total operating, investing, or financing cash flows.
Adjustments
resulting from
adoption of
ASC 606
Balance
without
adoption of
ASC 606
As Reported
(Millions, except per-share amounts)
Consolidated Statement of Operations
Year Ended December 31, 2018
Service revenues................................................................................................. $
Service revenues – commodity consideration ....................................................
Product sales.......................................................................................................
Total revenues.....................................................................................................
Product costs.......................................................................................................
Processing commodity expenses ........................................................................
Operating and maintenance expenses.................................................................
Depreciation and amortization expenses............................................................
Impairment of certain assets...............................................................................
Total costs and expenses.....................................................................................
Operating income (loss) .....................................................................................
Equity earnings (losses)......................................................................................
Other investing income (loss) – net....................................................................
Interest incurred..................................................................................................
$
5,502
400
2,784
8,686
2,707
137
1,507
1,725
1,915
7,918
768
396
219
(1,160)
$
89
(400)
135
(176)
(124)
(137)
1
2
202
(56)
(120)
1
84
16
5,591
—
2,919
8,510
2,583
—
1,508
1,727
2,117
7,862
648
397
303
(1,144)
99
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Adjustments
resulting from
adoption of
ASC 606
Balance
without
adoption of
ASC 606
As Reported
(Millions, except per-share amounts)
Interest capitalized..............................................................................................
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 ............................................................ $
Diluted earnings (loss) per common share .........................................................
48
331
138
193
348
(155)
(0.16) $
(0.16)
Consolidated Statement of Comprehensive Income (Loss)
Year Ended December 31, 2018
Net income (loss)................................................................................................ $
Comprehensive income (loss) ............................................................................
Less: Comprehensive income (loss) attributable to noncontrolling interests.....
Comprehensive income (loss) attributable to The Williams Companies, Inc. ...
Consolidated Balance Sheet
December 31, 2018
Inventories .......................................................................................................... $
Total current assets .............................................................................................
Investments.........................................................................................................
Property, plant, and equipment – net..................................................................
Intangible assets – net of accumulated amortization..........................................
Regulatory assets, deferred charges, and other ..................................................
Total assets .........................................................................................................
Accrued liabilities...............................................................................................
Total current liabilities........................................................................................
Deferred income tax liabilities ...........................................................................
Regulatory liabilities, deferred income, and other .............................................
Retained deficit...................................................................................................
Total stockholders’ equity...................................................................................
Noncontrolling interests in consolidated subsidiaries ........................................
Total equity.........................................................................................................
Total liabilities and equity ..................................................................................
$
$
193
223
346
(123)
130
1,464
7,821
27,504
7,767
746
45,302
1,102
1,811
1,524
3,603
(10,002)
14,660
1,337
15,997
45,302
(10)
(29)
(9)
(20)
(1)
(19)
(0.02) $
(0.02)
(20) $
(20)
(1)
(19)
(13) $
(13)
1
(212)
61
(4)
(167)
67
67
20
(346)
64
64
28
92
(167)
Consolidated Statement of Changes in Equity
December 31, 2018
Adoption of ASC 606 ............................................................................................... $
Net income (loss) ......................................................................................................
Deconsolidation of subsidiary ..................................................................................
Net increase (decrease) in equity ..............................................................................
Balance at December 31, 2018 .................................................................................
(121) $
121
$
193
(267)
(178)
15,997
(20)
(9)
92
92
38
302
129
173
347
(174)
(0.18)
(0.18)
173
203
345
(142)
117
1,451
7,822
27,292
7,828
742
45,135
1,169
1,878
1,544
3,257
(9,938)
14,724
1,365
16,089
45,135
—
173
(276)
(86)
16,089
100
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Note 3 – Divestitures
Sale of Gulf Coast Pipeline Systems
In November 2018, we completed the sale of certain assets and operations located in the Gulf Coast area for $177
million in cash. These assets were designated as held for sale during the third quarter of 2018. As a result of this sale,
we recorded a gain of approximately $101 million in the fourth quarter of 2018, consisting of $81 million in our Atlantic-
Gulf segment and $20 million in Other.
Previous impairments made to a portion of these assets and operations include $66 million related to certain idle
pipelines in the second quarter of 2018, as well as $68 million and $23 million related to an NGL pipeline near the
Houston Ship Channel region and project development costs associated with an olefins pipeline project, respectively,
in 2017. These impairments are reflected in Impairment of certain assets in the Consolidated Statement of Operations.
(See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) The results of operations for
this disposal group, excluding the impairments and gains noted, were not significant for the reporting periods.
Sale of Four Corners Assets
In October 2018, we completed the sale of our natural gas gathering and processing assets in the Four Corners
area of New Mexico and Colorado for total consideration of $1.125 billion, subject to customary working capital
adjustments. These assets were designated as held for sale during the third quarter of 2018. As a result of this sale, we
recorded a gain of approximately $591 million within the West segment in the fourth quarter of 2018.
The following table presents the results of operations for the Four Corners area, excluding the gain noted above:
Years Ended December 31,
2018
2017
2016
Income (loss) before income taxes of Four Corners area................................. $
Income (loss) before income taxes of Four Corners area attributable to The
Williams Companies, Inc. ..................................................................................
52
43
(Millions)
47
$
$
35
37
23
Sale of Geismar Interest
In July 2017, we completed the sale of Williams Olefins, L.L.C., a wholly owned subsidiary which owned our
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 of the sale, we entered into a long-term supply and transportation agreement
with the purchaser to provide feedstock to the plant via its Bayou Ethane pipeline system. As a result of this sale, we
recorded a gain of $1.095 billion in the third quarter of 2017 in our Other segment. Following this sale, the cash proceeds
were used to repay our $850 million term loan.
The following table presents the results of operations for the Geismar Interest, excluding the gain noted above:
Income (loss) before income taxes of the Geismar Interest............................... $
Income (loss) before income taxes of the Geismar Interest attributable to The
Williams Companies, Inc. ....................................................................................
Years Ended December 31,
2018
2017
2016
(Millions)
26
— $
$
141
—
19
85
101
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Sale of Canadian Operations
In September 2016, we completed the sale of subsidiaries conducting Canadian operations (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.
During 2016, we designated these operations as held for sale. As a result, we measured the fair value of the disposal
group, resulting in an impairment charge of $747 million, reflected in Impairment of certain assets in the Consolidated
Statement of Operations. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.)
Upon completion of the sale, we also recorded a loss of $66 million in Other, primarily reflecting revisions to the sales
price and estimated contingent consideration. This included 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.
For the year ended December 31, 2016, the results of operations for the Canadian disposal group, excluding the
impairment and loss noted, were a loss before income taxes of $98 million, and a loss before income taxes attributable
to The Williams Companies, Inc. of $95 million, in Other.
Note 4 – Variable Interest Entities
Consolidated VIEs
As of December 31, 2018, we consolidate the following VIEs:
Gulfstar One
We own a 51 percent interest in 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. We are
the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s
economic performance.
Constitution
We own 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. We are the primary beneficiary because we have the power to
direct the activities that most significantly impact Constitution’s economic performance. We, as operator of Constitution,
are 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 us
and the other equity partners on a proportional basis.
In December 2014, Constitution received approval from the 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 (D.C. 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 2017 the court denied our petition.
102
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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. We filed a request for rehearing of the FERC’s decision, but in July 2018 the FERC denied our
request.
The project’s sponsors remain committed to the project. On November 5, 2018, the FERC granted our request for
an extension of time to December 2, 2020, to construct and place into service the Constitution pipeline. And, in September
2018, we filed a petition with the D.C. Circuit for review of the FERC’s denial of our petition for declaratory order.
An unfavorable resolution of that appeal could result in the impairment of a significant portion of the capitalized project
costs, which total $377 million on a consolidated basis at December 31, 2018, 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 continued prolonged delay or termination of the project.
Cardinal
We own a 66 percent interest in Cardinal, a subsidiary that provides gathering services for the Utica Shale region
and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have 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 us and the other equity partner on a proportional basis.
103
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 our consolidated VIEs:
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.......................................
Long-term debt due within one year ..................
Long-term debt ...................................................
Deferred income tax liabilities ...........................
Noncurrent asset retirement obligations.............
Long-term deferred income................................
Regulatory liabilities and other ..........................
December 31,
2018
2017 (1)
Classification
(Millions)
33
62
—
2
—
2,363
1,177
—
(15)
(115)
—
—
—
(105)
(159)
—
$
881 Cash and cash equivalents
972
113
Trade accounts and other receivables
Inventories
176 Other current assets and deferred charges
6,552
Investments
27,912
Property, plant, and equipment – net
8,790
507
Intangible assets – net of accumulated
amortization
Regulatory assets, deferred charges, and
other
(957) Accounts payable
(857) Accrued liabilities
(501) Long-term debt due within one year
(15,996) Long-term debt
(16) Deferred income tax liabilities
(944) Regulatory liabilities, deferred income,
and other
(1,119) Regulatory liabilities, deferred income,
and other
(1,690) Regulatory liabilities, deferred income,
and other
_________________
(1) Includes WPZ, which was a consolidated VIE at December 31, 2017 (see Note 1 – General, Description of Business,
Basis of Presentation, and Summary of Significant Accounting Policies).
Nonconsolidated VIEs
Jackalope
We own a 50 percent interest in Jackalope, which provides gathering and processing services for the Powder River
basin and is a VIE due to certain risks shared with customers. Prior to the second quarter of 2018 we were the primary
beneficiary of Jackalope. During the second quarter of 2018, the scope of Jackalope’s planned future activities changed,
resulting in a VIE reconsideration event. Upon evaluation, we determined that we are no longer the primary beneficiary,
most notably due to changes in the activities that most significantly impact Jackalope’s economic performance and our
determination that we do not control the power to direct such activities. These activities are primarily related to the
capital decision making process. As a result, we deconsolidated Jackalope on June 30, 2018 and now account for our
interest using the equity method of accounting as we exert significant influence over the financial and operational
policies of Jackalope (see Note 6 – Investing Activities). At December 31, 2018, the carrying value of our investment
in Jackalope was $343 million. Our maximum exposure to loss is limited to the carrying value of our investment.
Jackalope is currently undertaking an expansion project with a remaining cost up to approximately $350 million as of
December 31, 2018, which will be funded on a proportional basis.
104
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Brazos Permian II
We own a 15 percent interest in Brazos Permian II (see Note 6 – Investing Activities), which provides gathering
and processing services in the Delaware basin and is a VIE due primarily to our limited participating rights as the
minority equity holder. At December 31, 2018, the carrying value of our investment in Brazos Permian II was $191
million. Our maximum exposure to loss is limited to the carrying value of our investment.
Note 5 – 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 $236 million, $226 million, and $180 million for the years ended 2018, 2017, and 2016, respectively.
We have $18 million and $20 million included in Accounts payable in the Consolidated Balance Sheet with our equity-
method investees at December 31, 2018 and 2017, respectively.
We have operating agreements with certain equity-method investees. These operating agreements typically provide
for reimbursement or payment to us for certain direct operational payroll and employee benefit costs, materials, supplies,
and other charges and also for management services. The total charges to equity-method investees for these fees are
$75 million, $67 million, and $66 million for the years ended 2018, 2017, and 2016, 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 in Service revenues in the Consolidated Statement of Operations from this company for transportation
and storage of natural gas for the year ended December 31, 2016.
Note 6 – Investing Activities
Brazos Permian II Equity-Method Investment
During the fourth quarter of 2018, we contributed the majority of our existing Delaware basin assets and $27
million in cash in exchange for a 15 percent interest in the Brazos Permian II, which consists of gas and crude oil
gathering pipelines, natural gas processing, and oil storage facilities. We recorded a deconsolidation gain of $141 million
reflected in Other investing income (loss) – net in the Consolidated Statement of Operations reflecting the excess of the
fair value of our acquired interest over the carrying value of the assets contributed. We estimated the fair value of our
interest to be $192 million primarily using a market approach (a Level 3 measurement within the fair value hierarchy).
This approach involved the observation of recent transaction multiples in the Permian basin, including recent acquisitions
consummated during 2018. Our interest in Brazos Permian II is considered an equity-method investment due to the
fact that we are able to exert significant influence over its operating and financial policies.
RMM Equity-Method Investment
During the third quarter of 2018, our joint venture, RMM, purchased a natural gas and oil gathering and natural
gas processing business in Colorado’s Denver-Julesburg basin. Our initial economic ownership was 40 percent, which
has since increased to 50 percent at December 31, 2018, based on additional capital contributions made since the initial
purchase.
Jackalope Deconsolidation
During the second quarter of 2018, we deconsolidated our interest in Jackalope (see Note 4 – Variable Interest
Entities). We recorded our interest in Jackalope as an equity-method investment at its estimated fair value, resulting in
a deconsolidation gain of $62 million reflected in Other investing income (loss) – net in the Consolidated Statement of
Operations. We estimated the fair value of our interest to be $310 million using an income approach based on expected
105
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
future cash flows and an appropriate discount rate (a Level 3 measurement within the fair value hierarchy). The
determination of expected future cash flows involved significant assumptions regarding gathering and processing
volumes and related capital spending. A 10.9 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. The deconsolidated
carrying value of the net assets of Jackalope included $47 million of goodwill.
Acquisition of Additional Interests in Appalachia Midstream Investments
During the first quarter of 2017, we exchanged all of our 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, we have an approximate average 66 percent
interest in the Appalachia Midstream Investments. We continue to account for this investment under the equity method
of accounting due to the significant participatory rights of our partners such that we do not exercise control. We also
sold all of our 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.
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.
Impairment of equity-method investments
The following table presents other-than-temporary impairment charges related to certain equity-method
investments (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk):
2018
Years Ended December 31,
2017
(Millions)
2016
Northeast G&P
UEOM ...............................................................................................................
Appalachia Midstream Investments ..................................................................
Laurel Mountain ................................................................................................
West
DBJV .................................................................................................................
Ranch Westex ....................................................................................................
Other ....................................................................................................................
$
$
32
—
—
—
—
—
32
$
$
— $
—
—
—
—
—
— $
—
294
50
59
24
3
430
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 of interest income for 2016 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.
106
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Investments
Ownership
Interest at
December 31,
2018
Equity-method investments:
Appalachia Midstream Investments .................................................................
UEOM ..............................................................................................................
RMM ................................................................................................................
Discovery .........................................................................................................
OPPL ................................................................................................................
Caiman II ..........................................................................................................
Jackalope ..........................................................................................................
Laurel Mountain ...............................................................................................
Gulfstream ........................................................................................................
Brazos Permian II .............................................................................................
Other .................................................................................................................
(1)
62%
50%
60%
50%
58%
50%
69%
50%
15%
Various
December 31,
2018
2017
(Millions)
$
$
3,218
1,293
776
507
415
412
343
314
225
191
127
7,821
$
$
3,104
1,383
—
534
422
429
—
309
244
—
127
6,552
___________
(1) Includes equity-method investments in multiple gathering systems in the Marcellus Shale with an approximate
average 66 percent interest.
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, 2018 and 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.
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:
RMM ............................................................................................................... $
Appalachia Midstream Investments ................................................................
Jackalope .........................................................................................................
Brazos Permian II ............................................................................................
Laurel Mountain ..............................................................................................
Discovery.........................................................................................................
DBJV ...............................................................................................................
Caiman II .........................................................................................................
Other ................................................................................................................
$
Years Ended December 31,
2018
2017
(Millions)
2016
795
246
42
27
16
5
—
—
1
1,132
$
$
— $
70
—
—
—
1
32
24
5
132
$
—
28
—
—
—
—
105
22
22
177
107
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Dividends and distributions
The organizational documents of entities in which we have an equity-method investment 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:
Appalachia Midstream Investments ................................................................ $
Gulfstream .......................................................................................................
OPPL ...............................................................................................................
UEOM .............................................................................................................
Caiman II .........................................................................................................
Discovery.........................................................................................................
DBJV ...............................................................................................................
Laurel Mountain ..............................................................................................
Other ................................................................................................................
$
Years Ended December 31,
2018
2017
(Millions)
2016
297
93
73
70
46
45
—
23
46
693
$
$
270
92
68
80
49
127
39
32
27
784
$
$
211
100
69
92
40
141
39
28
22
742
In addition, on September 24, 2015, we received a special distribution of $396 million from Gulfstream reflecting
our proportional share of the proceeds from new debt issued by Gulfstream. The new debt was issued to refinance
Gulfstream’s debt maturities. Subsequently, we contributed $248 million and $148 million to Gulfstream for our
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.
Summarized Financial Position and Results of Operations of All Equity-Method Investments
December 31,
2018
2017
(Millions)
Assets (liabilities):
Current assets..................................................................................................................... $
Noncurrent assets...............................................................................................................
Current liabilities ...............................................................................................................
Noncurrent liabilities .........................................................................................................
$
834
13,199
(605)
(2,491)
447
9,181
(295)
(1,538)
Gross revenue .................................................................................................. $
Operating income ............................................................................................
Net income.......................................................................................................
$
2,411
804
795
$
1,961
871
806
1,883
799
726
Years Ended December 31,
2018
2017
(Millions)
2016
108
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Note 7 – 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:
Atlantic-Gulf
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 4)...........................
Gains on asset retirements..............................................................................
West
Gains on contract settlements and terminations .............................................
Regulatory charge per approved rates related to Tax Reform........................
Charge for regulatory liability associated with the decrease in Northwest
Pipeline’s estimated deferred state income tax rates following WPZ
Merger.........................................................................................................
Other
Gain on sale of Refinery Grade Propylene Splitter........................................
Loss on sale of Canadian operations (Note 3)................................................
Net foreign currency exchange (gains) losses (1) ..........................................
Gain on sale of unused pipe ...........................................................................
Benefit of regulatory asset associated with increase in Transco’s estimated
deferred state income tax rate following WPZ Merger ..............................
Years Ended December 31,
2018
2017
2016
(Millions)
33
$
33
$
33
22
4
(12)
—
24
12
—
—
—
—
(37)
22
16
—
(15)
—
—
(12)
5
—
—
—
25
28
(11)
—
—
—
—
66
10
(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 3 – Divestitures).
Additional Items
Certain additional items included in the Consolidated Statement of Operations are as follows:
•
•
•
•
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 West segment.
Service revenues for the year ended December 31, 2016 were reduced by $15 million related to potential
refunds associated with a ruling received in certain rate case litigation within the Atlantic-Gulf segment.
Selling, general, and administrative expenses for the year ended December 31, 2018, includes a $35 million
charge associated with a charitable contribution of preferred stock to The Williams Companies Foundation,
Inc. (a not-for-profit corporation) within the Other segment (see Note 15 – Stockholders' Equity). Selling,
general, and administrative expenses for the year ended December 31, 2018, also includes $20 million for
WPZ Merger related costs within the Other segment.
Selling, general, and administrative expenses and Operating and maintenance expenses for the year ended
December 31, 2017, included $22 million in severance and other related costs within the Other segment. The
year ended December 31, 2016, included $42 million in severance and other related costs associated with an
109
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
approximate 10 percent reduction in workforce in the first quarter of 2016, comprised of $3 million associated
with the Northeast G&P segment, $8 million associated with the Atlantic-Gulf segment, $13 million associated
with the West segment, and $18 million associated with the Other segment.
•
Selling, general, and administrative expenses for the years ended December 31, 2017 and 2016 included $9
million and $47 million, respectively, of costs associated with our evaluation of strategic alternatives within
the Other segment. Selling, general, and administrative expenses for the year ended December 31, 2016, also
included $61 million 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.
• Other income (expense) – net below Operating income (loss) includes $89 million, $71 million, and $66
million for equity AFUDC primarily within the Atlantic-Gulf segment for the years ended December 31, 2018,
2017, and 2016, respectively. Other income (expense) – net below Operating income (loss) also includes $35
million, $52 million, and $23 million for the years ended December 31, 2018, 2017, and 2016, respectively,
of income associated with regulatory assets related to the effects of deferred taxes on equity funds used during
construction primarily within the Other segment.
• Other income (expense) – net below Operating income (loss) for the year ended December 31, 2018, includes
a $7 million net loss associated with the March 28, 2018, early retirement of $750 million of 4.875 percent
senior unsecured notes that were due in 2024. The net loss within the Other segment reflects $34 million in
premiums paid, partially offset by $27 million of unamortized premium. The year ended December 31, 2017,
included 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 $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 14 – Debt, Banking Arrangements, and Leases).
• Other income (expense) – net below Operating income (loss) includes settlement charge expense related to
the program to pay out certain deferred vested pension benefits as follows (see Note 10 – Employee Benefit
Plans):
Atlantic-Gulf
Northeast
West
Other
Years Ended December 31,
2018
2017
$
$
(Millions)
7
4
6
5
15
7
13
35
• Other income (expense) – net below Operating income (loss) for the year ended December 31, 2017, included
a $102 million charge for regulatory assets associated with the effects of deferred taxes on equity funds used
during construction as a result of Tax Reform, comprised of $33 million within the Atlantic-Gulf segment, $6
million within the West segment, and $63 million within the Other segment (see Note 1 – General, Description
of Business, Basis of Presentation, and Summary of Significant Accounting Policies).
110
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Note 8 – Provision (Benefit) for Income Taxes
The Provision (benefit) for income taxes includes:
Current:
Federal........................................................................................................ $
State............................................................................................................
Foreign .......................................................................................................
Deferred:
Federal........................................................................................................
State............................................................................................................
Foreign .......................................................................................................
Provision (benefit) for income taxes............................................................... $
Years Ended December 31,
2018
2017
(Millions)
2016
(83) $
1
—
(82)
183
37
—
220
138
$
$
15
23
—
38
(2,004)
(8)
—
(2,012)
(1,974) $
—
2
(1)
1
(6)
61
(81)
(26)
(25)
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).....
Valuation allowance ..........................................................................
Translation adjustment of certain unrecognized tax benefits............
Other – net.........................................................................................
Provision (benefit) for income taxes..................................................... $
Years Ended December 31,
2018
2017
(Millions)
2016
69
$
187
$
(131)
(73)
—
(10)
38
—
105
—
9
138
$
(117)
(1,932)
(17)
26
(127)
—
—
6
(1,974) $
(22)
—
3
43
78
—
(1)
5
(25)
Income (loss) before income taxes includes $3 million, $7 million, and $885 million of foreign loss in 2018, 2017,
and 2016, respectively.
Foreign operations – net (including tax effect of Canadian Sale) in 2016 reflects a valuation allowance associated
with impairments and losses on the sale of our Canadian operations (see Note 3 – Divestitures) and the reversal of
anticipatory foreign tax credits, partially offset by the tax effect of the impairments associated with our Canadian
disposition. 2017 reflects the release of this valuation allowance.
On December 22, 2017, Tax Reform was enacted. Most of the provisions of Tax Reform were effective after
January 1, 2018. However, the deferred tax impact of reducing the U.S. corporate tax rate from 35 percent to 21 percent
was 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 in 2017.
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
111
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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.
Significant components of Deferred income tax liabilities and Deferred income tax assets are as follows. Following
the WPZ Merger, the attributes below are presented based on the underlying assets.
Deferred income tax liabilities:
Property, plant and equipment........................................................................................... $
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,
2018
2017
(Millions)
2,317
295
30
2,642
667
71
140
147
319
94
1,438
320
1,118
1,524
$
$
—
3,565
19
3,584
53
155
140
—
283
30
661
224
437
3,147
The valuation allowance at December 31, 2018 and 2017 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, which incorporates available tax planning strategies, 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 the Foreign tax credit and State losses and credits may not be realized. The Valuation
allowance change from 2017 is primarily due to a $105 million valuation allowance associated with foreign tax credits,
that expire between 2024 and 2028. The completion of the WPZ Merger (see Note 1 – General, Description of Business,
Basis of Presentation, and Summary of Significant Accounting Policies) was a taxable exchange to the WPZ unit
holders, which resulted in an adjustment to the tax basis in the underlying assets deemed acquired. A reduction to the
deferred tax liability of $1.829 billion related to the book-tax basis difference in this investment has been recorded.
Increased tax depreciation from the additional tax basis will reduce future taxable income, which serves to impact our
expected realization of the Foreign tax credit. 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 reflects 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. Additionally, valuation allowances on state net operating losses
decreased by $31 million after the completion of the WPZ Merger. These attributes generally expire between 2019 and
2038 with some carryovers having indefinite carryforward periods. The remaining federal Minimum tax credit of $71
million will be refunded/utilized no later than 2021.
Federal loss carryovers includes deferred tax assets of $5 million at the end of 2018 that are expected to be utilized
by us prior to expiration between 2019 and 2023. Deferred tax assets on net operating loss carryovers of $142 million
have no expiration date.
112
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Cash payments for income taxes (net of refunds) were $11 million, $28 million, and $5 million in 2018, 2017, and
2016, respectively.
As of December 31, 2018, we had approximately $51 million of unrecognized tax benefits. If recognized, income
tax expense would be reduced by $51 million and $50 million for 2018 and 2017, 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:
2018
2017
Balance at beginning of period ............................................................................................. $
Additions for tax positions of prior years .............................................................................
Balance at end of period........................................................................................................ $
$
(Millions)
50
1
51
$
50
—
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 expenses of $800 thousand and $300 thousand for 2018
and 2016, respectively, and a benefit of $400 thousand for 2017. Approximately $3 million and $2 million of interest
and penalties primarily relating to uncertain tax positions have been accrued as of December 31, 2018 and 2017,
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 Internal Revenue Service (IRS) examination for years
after 2010. As of December 31, 2018, 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 2013. Tax years 2013 through 2016 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.
Note 9 – Earnings (Loss) Per Common Share
Years Ended December 31,
2018
2017
2016
Net income (loss) available to common stockholders ........................................... $
Basic weighted-average shares........................................................................
Effect of dilutive securities:
Nonvested restricted stock units...................................................................
Stock options ................................................................................................
Diluted weighted-average shares (1) ...............................................................
Earnings (loss) per common share:
973,626
—
—
973,626
(Dollars in millions, except per-share
amounts; shares in thousands)
(156) $
$
2,174
826,177
(424)
750,673
1,704
637
828,518
—
—
750,673
Basic ............................................................................................................. $
Diluted .......................................................................................................... $
(.16) $
(.16) $
2.63
2.62
$
$
(.57)
(.57)
________________
(1) For the years ended December 31, 2018 and December 31, 2016, 2.0 million and 0.6 million weighted-average
nonvested restricted stock units, respectively, and 0.5 million and 0.5 million weighted-average stock options,
respectively, have been excluded from the computation of diluted earnings (loss) per common share as their
inclusion would be antidilutive due to our loss attributable to The Williams Companies, Inc.
113
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Note 10 – 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. 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. 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 this plan 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 November 2018, we announced changes to our defined benefit pension plans and our defined contribution plan.
Eligible employees hired or rehired on or after January 1, 2019, will not be eligible to participate in the pension plan,
but will be eligible for an additional fixed annual contribution made by us to the defined contribution plan. Additionally,
as of January 1, 2020, certain active eligible employees will no longer receive future compensation credits under the
defined benefit pension plan, but will be eligible for an additional fixed annual contribution made by us to the defined
contribution plan. Also as of January 1, 2020, certain active eligible employees will continue to receive compensation
credits under the defined benefit pension plans and these employees will not be eligible to receive the fixed annual
contribution under the defined contribution plan. As a result of this amendment, a curtailment gain and a prior service
credit were recorded to Accumulated other comprehensive income (loss). The amounts of the curtailment gain and prior
service credit were not significant and are reported in Net actuarial gain (loss) within the subsequent tables of changes
in benefit obligations, amounts included in Accumulated other comprehensive income (loss), and other changes in plan
assets and benefit obligations recognized in other comprehensive income (loss) before taxes.
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 and August 2018, lump-sum payments were
made, and annuity payments commenced in relation to this program. As a result of these lump-sum payments, as well
as lump-sum benefit payments made throughout 2017 and 2018, settlement accounting was required. We settled $103
million in liabilities of our pension plans in 2018 and $261 million in 2017 and recognized pre-tax, noncash settlement
charges of $23 million in 2018 and $71 million in 2017, which are substantially reported in Other income (expense) –
net below Operating income (loss) in the Consolidated Statement of Operations (see Note 7 – 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.
114
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
2018
2017
2018
2017
(Millions)
Change in benefit obligation:
Benefit obligation at beginning of year.................................. $
Service cost ............................................................................
Interest cost ............................................................................
Plan participants’ contributions..............................................
Benefits paid...........................................................................
Net 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................................................. $
$
1,319
50
46
—
(35)
(90)
(103)
(132)
1,187
1,227
(45)
88
—
(35)
(103)
(95)
1,132
$
1,466
50
59
—
(35)
40
(261)
(147)
1,319
1,254
184
85
—
(35)
(261)
(27)
1,227
(55) $
$
1,171
(92) $
1,294
206
1
7
2
(13)
(17)
—
(20)
186
227
(7)
5
2
(13)
—
(13)
214
28
$
$
197
1
8
3
(14)
11
—
9
206
208
25
5
3
(14)
—
19
227
21
The overfunded (underfunded) status of our pension plans and other postretirement benefit plan presented in the
previous table are recognized in the Consolidated Balance Sheet within the following accounts:
December 31,
2018
2017
(Millions)
Underfunded pension plans:
Current liabilities............................................................................................................ $
Noncurrent liabilities......................................................................................................
(2) $
(53)
Overfunded (underfunded) other postretirement benefit plan:
Current liabilities............................................................................................................
Noncurrent assets ...........................................................................................................
(6)
34
(2)
(90)
(6)
27
The plan assets within our other postretirement benefit plan is intended to be used for the payment of benefits for
certain groups of participants. The Current liabilities for the other postretirement benefit plan 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.
115
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The pension plans’ benefit obligation Net actuarial loss (gain) of $(90) million in 2018 is primarily due to the
impact of an increase in the discount rates utilized to calculate the benefit obligation. The pension plans’ benefit
obligation Net 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 2018 benefit obligation Net actuarial loss (gain) of $(17) million for our other postretirement benefit plan is
primarily due to an increase in the discount rate used to calculate the benefit obligation. The 2017 benefit obligation
Net actuarial loss (gain) of $11 million for our other postretirement benefit plan is primarily due to a decrease in the
discount rate used to calculate the benefit obligation.
At December 31, 2018, one of our pension plans had plan assets in excess of its accumulated benefit obligation.
For our other pension plans, the accumulated benefit obligation of $367 million exceeded plan assets of $326 million.
All of our pension plans had a projected benefit obligation in excess of plan assets at December 31, 2018. At
December 31, 2017, 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
2018
2017
2018
2017
(Millions)
Amounts included in Accumulated other comprehensive
income (loss):
Net actuarial loss................................................................. $
(347) $
(375) $
(12) $
(21)
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
— $
4
2
14
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 plan 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 $116 million at December 31, 2018 and $108 million at December 31, 2017, 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, 2018 and 2017, these regulatory liabilities were $49 million and
$33 million, respectively. These pension and other postretirement plans amounts will be reflected in future rates based
on the rate structures of these gas pipelines.
116
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Net Periodic Benefit Cost (Credit)
Net periodic benefit cost (credit) for the years ended December 31 consist of the following:
Pension Benefits
2018
2017
2016
Other
Postretirement Benefits
2017
2018
2016
(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
46
(63)
—
23
23
—
79
$
$
50
59
(82)
—
27
71
—
125
$
$
54
62
(85)
—
30
2
—
63
$
$
$
1
7
(11)
(2)
—
—
2
(3) $
$
1
8
(11)
(13)
—
—
3
(12) $
1
8
(12)
(15)
—
—
4
(14)
The components of Net periodic benefit cost (credit) other than the service cost component are included in Other
income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations.
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
2018
2017
2016
2018
2017
2016
(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 ............................
(18) $
—
23
23
62
—
27
71
$
(23) $
—
30
2
9
—
—
—
$
(3) $ —
(6)
(5)
—
—
—
—
Other changes in plan assets and benefit obligations
recognized in Other comprehensive income (loss)........ $
28
$ 160
$
9
$
9
$
(8) $
(6)
Other changes in plan assets and benefit obligations for our other postretirement benefit plan 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 .......................................................
$
(10) $
(2)
$
6
(8)
2
(9)
2018
2017
2016
(Millions)
117
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Key Assumptions
The weighted-average assumptions utilized to determine benefit obligations as of December 31 are as follows:
Pension Benefits
Other
Postretirement
Benefits
2018
2017
2018
2017
Discount rate ..............................................................................
Rate of compensation increase...................................................
Cash balance interest crediting rate ...........................................
4.34%
4.83
4.25
3.66%
4.93
4.25
4.39%
N/A
N/A
3.71%
N/A
N/A
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 ............
Cash balance interest crediting rate.....
Pension Benefits
Other
Postretirement Benefits
2018
2017
2016
2018
2017
2016
3.67%
4.17%
4.37%
3.71%
4.27%
4.50%
5.34
4.93
4.25
6.45
4.87
4.25
6.85
4.88
4.25
4.95
N/A
N/A
5.53
N/A
N/A
6.11
N/A
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 2019 is 7.5 percent. This rate decreases to 4.5 percent by 2026.
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 38 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, 2018, of 25
percent equity securities and 75 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
118
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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,
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, 2018 and 2017 by asset class are as follows:
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
2018
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, 2018...
10
$
— $
— $
30
22
157
—
—
—
—
219
$
—
—
—
21
48
210
6
285
$
—
—
—
—
—
—
—
—
$
10
30
22
157
21
48
210
6
504
123
8
19
51
335
92
1,132
119
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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
120
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The fair values of our other postretirement benefits plan assets at December 31, 2018 and 2017 by asset class are
as follows:
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
2018
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, 2018...
11
$
— $
— $
20
9
—
19
—
—
—
43
102
$
—
—
5
—
2
6
25
—
38
$
—
—
—
—
—
—
—
—
—
$
11
20
9
5
19
2
6
25
43
140
14
1
2
6
40
11
214
121
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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
____________
(1) The weighted-average credit quality rating of the fixed income security portfolio is investment grade with a
weighted-average duration of approximately 13 years for 2018 and 12 years for 2017.
(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 days
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
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.
122
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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, 2018 and
2017. Additionally, there were no transfers or reclassifications of investments between Level 1 and Level 2 from
December 2017 to December 2018. 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.
2019........................................................................................................................... $
2020...........................................................................................................................
2021...........................................................................................................................
2022...........................................................................................................................
2023...........................................................................................................................
2024-2028 .................................................................................................................
Pension
Benefits
Other
Postretirement
Benefits
$
(Millions)
85
87
90
90
89
467
14
14
13
14
14
59
In 2019, we expect to contribute approximately $60 million to our tax-qualified pension plans and approximately
$3 million to our nonqualified pension plans, for a total of approximately $63 million, and approximately $6 million
to our other postretirement benefit plans.
Defined Contribution Plan
We also maintain a defined contribution plan 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
plan’s guidelines. We match employees’ contributions up to certain limits. Our matching contributions charged to
expense were $35 million in 2018, $34 million in 2017, and $36 million in 2016.
123
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Note 11 – 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,
2018
2017
(Millions)
Natural gas gathering and processing facilities......
Construction in progress......................................... Not applicable
Other.......................................................................
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
$
$
$
15,324
778
2,356
18,440
566
2,776
17,312
965
1,926
38,661
(11,157)
27,504
$
14,460
1,637
1,634
39,513
(11,302)
28,211
__________
(1) Estimated useful life and depreciation rates are presented as of December 31, 2018. Depreciation rates and estimated
useful lives for regulated assets are prescribed by the FERC.
Depreciation and amortization expense for Property, plant, and equipment – net was $1.392 billion, $1.389 billion,
and $1.407 billion in 2018, 2017, and 2016, respectively.
Regulated Property, plant, and equipment – net includes approximately $586 million and $626 million at
December 31, 2018 and 2017, 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.
124
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The following table presents the significant changes to our ARO, of which $968 million and $946 million are
included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued liabilities
at December 31, 2018 and 2017, respectively.
December 31,
2018
2017
Beginning balance ......................................................................................................... $
Liabilities incurred.........................................................................................................
Liabilities settled ...........................................................................................................
Accretion expense (1)....................................................................................................
Revisions (2)..................................................................................................................
Ending balance .............................................................................................................. $
___________
(1) The decrease in accretion expense in 2018 primarily reflects the absence of a 2017 adjustment associated with
862
33
(16)
141
(22)
998
$
(Millions)
998
21
(19)
71
(39)
1,032
$
obligations identified from 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 2018 revisions
reflect changes in removal cost estimates, decreases in the estimated remaining useful life of certain assets and
increases in the discount rates used in the annual review process. 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 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 17 – 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 12 – 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:
2018
2017
Gross
Carrying
Amount
Accumulated
Amortization
Gross
Carrying
Amount
Accumulated
Amortization
(Millions)
Contractual customer relationships......................................... $
9,232
$
(1,465) $
10,027
$
(1,283)
Other intangible assets primarily relate to gas gathering, processing, and fractionation contractual customer
relationships recognized in acquisitions. The decrease in the gross carrying amount of other intangible assets during
2018 is primarily related to the impairment of certain assets located in the Barnett Shale and the deconsolidation of our
interest in Jackalope (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk and Note
6 – Investing Activities, respectively). These decreases are the primary reasons for the difference between the change
in accumulated amortization during 2018 indicated above and the amortization expense for 2018 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 (the weighted-average periods prior
to the next renewal or extension of the associated contractual customer relationships as estimated at the time of the
125
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
acquisition). 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 $333 million, $347 million, and $356 million in
2018, 2017, and 2016, respectively. The estimated amortization expense for each of the next five succeeding fiscal
years is approximately $312 million.
Note 13 – Accrued Liabilities
December 31,
2018
2017
$
(Millions)
282
244
205
371
1,102
$
267
361
202
337
1,167
Interest on debt.............................................................................................................. $
Revenue contract liabilities (Note 2) ............................................................................
Employee costs .............................................................................................................
Other, including other loss contingencies .....................................................................
$
126
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Note 14 – 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 ........................................................................................
4% Notes due 2028 .............................................................................................
5.4% Notes due 2041 ..........................................................................................
4.45% Notes due 2042 ........................................................................................
4.6% Notes due 2048 ..........................................................................................
Other financing obligations .................................................................................
Northwest Pipeline:
6.05% Notes due 2018 ........................................................................................
7.125% Debentures due 2025 ..............................................................................
4% Notes due 2027 .............................................................................................
WMB:
4.125% Notes due 2020 ......................................................................................
5.25% Notes due 2020 ........................................................................................
4% Notes due 2021 .............................................................................................
7.875% Notes due 2021 ......................................................................................
3.35% Notes due 2022 ........................................................................................
3.6% Notes due 2022 ..........................................................................................
3.7% Notes due 2023 ..........................................................................................
4.5% Notes due 2023 ..........................................................................................
4.3% Notes due 2024 ..........................................................................................
4.55% Notes due 2024 ........................................................................................
4.875% Notes due 2024 ......................................................................................
3.9% Notes due 2025 ..........................................................................................
4% Notes due 2025 .............................................................................................
3.75% Notes due 2027 ........................................................................................
7.5% Debentures due 2031 ..................................................................................
7.75% Notes due 2031 ........................................................................................
8.75% Notes due 2032 ........................................................................................
6.3% Notes due 2040 ..........................................................................................
5.8% Notes due 2043 ..........................................................................................
5.4% Notes due 2044 ..........................................................................................
5.75% Notes due 2044 ........................................................................................
4.9% Notes due 2045 ..........................................................................................
5.1% Notes due 2045 ..........................................................................................
4.85% Notes due 2048 ........................................................................................
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 ........................................................................................................... $
December 31,
2018
2017
(Millions)
— $
8
200
1,000
400
375
400
600
1,067
—
85
500
600
1,500
500
371
750
1,250
850
600
1,000
1,250
—
750
750
1,450
339
252
445
1,250
400
500
650
500
1,000
800
55
160
(131)
(62)
22,414
(47)
22,367
$
250
8
200
1,000
—
375
400
—
231
250
85
250
600
1,500
500
371
750
1,250
850
600
1,000
1,250
750
750
750
1,450
339
252
445
1,250
400
500
650
500
1,000
—
55
270
(122)
(24)
20,935
(501)
20,434
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.
127
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The following table presents aggregate minimum maturities of long-term debt and other financing obligations,
excluding net unamortized debt premium (discount) and debt issuance costs, for each of the next five years:
December 31,
2018
(Millions)
2019 .................................................................................................................................................... $
2020 ....................................................................................................................................................
2021 ....................................................................................................................................................
2022 ....................................................................................................................................................
2023 ....................................................................................................................................................
47
2,138
890
2,021
1,633
Issuances and retirements
On August 24, 2018, Northwest Pipeline issued $250 million of 4 percent senior unsecured notes to investors in
a private debt placement. The notes are an additional issuance of Northwest Pipeline’s existing 4 percent senior unsecured
notes due 2027. In the fourth quarter of 2018, Northwest Pipeline filed a registration statement and completed an
exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as
amended.
Northwest Pipeline retired $250 million of 6.05 percent senior unsecured notes that matured on June 15, 2018.
On March 5, 2018, WPZ completed a public offering of $800 million of 4.85 percent senior unsecured notes due
2048. WPZ used the net proceeds for general partnership purposes, primarily the March 28, 2018 repayment of $750
million of 4.875 percent senior unsecured notes that were due in 2024.
On March 15, 2018, Transco issued $400 million of 4 percent senior unsecured notes due 2028 and $600 million
of 4.6 percent senior unsecured notes due 2048 to investors in a private debt placement. Transco used the net proceeds
to retire $250 million of 6.05 percent senior unsecured notes that matured on June 15, 2018, and for general corporate
purposes, including the funding of capital expenditures. In the third quarter of 2018, Transco filed a registration statement
and completed an exchange of these notes for substantially identical new notes that are registered under the Securities
Act of 1933, as amended.
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 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. In the first quarter of 2018,
Northwest Pipeline completed an exchange of these notes for substantially identical new notes that are registered under
the Securities Act of 1933, as amended.
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.
128
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Other financing obligations
During the construction of the Dalton expansion project, Transco 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
in our Consolidated Balance Sheet. Upon placing the project in service during the third quarter of 2017, Transco began
utilizing this partner’s undivided interest in the lateral, including the associated pipeline capacity, and reclassified the
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. Amounts related to this financing obligation included in debt within
our Consolidated Balance Sheet were $260 million and $231 million at December 31, 2018 and 2017, respectively.
During the construction of the Atlantic Sunrise project, Transco received funding from a partner for its proportionate
share of construction costs related to an undivided ownership interest in certain parts of the project. Amounts received
were recorded within noncurrent liabilities and 100 percent of the costs associated with construction were capitalized
in our Consolidated Balance Sheet. Upon placing the project in service during the fourth quarter of 2018, Transco began
utilizing this partner’s undivided interest in the lateral, including the associated pipeline capacity, and reclassified the
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 20 years. At December 31, 2018, $807 million related to this financing obligation
was included in debt within our Consolidated Balance Sheet.
Credit Facilities
Long-term credit facility (1) ....................................................................................... $
Letters of credit under certain bilateral bank agreements ...........................................
(Millions)
4,500
$
160
14
________________
(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.
December 31, 2018
Stated Capacity
Outstanding
Revolving credit facility
On July 13, 2018, we along with Transco and Northwest Pipeline, the lenders named therein, and an administrative
agent entered into a new credit agreement (Credit Agreement) with aggregate commitments available of $4.5 billion,
with up to an additional $500 million increase in aggregate commitments available under certain circumstances. On
August 10, 2018, following the completion of the WPZ Merger, the Credit Agreement became effective and we
terminated both our and WPZ’s existing credit facilities. The maturity date of the new credit facility is August 10, 2023.
However, the co-borrowers may request up to two extensions of the maturity date each for an additional one-year period
to allow a maturity date as late as August 10, 2025, under certain circumstances. The Credit Agreement allows for
swing line loans up to an aggregate of $200 million, subject to available capacity under the new credit facility, and
letters of credit commitments of $1 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 Credit Agreement 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, make
certain distributions during an event of default, and enter into certain restrictive agreements.
•
If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to
terminate the commitments and accelerate the maturity of the loans and exercise other rights and remedies.
129
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
• Other than swing line loans, each time funds are borrowed, the applicable borrower may choose from two
methods of calculating interest: a fluctuating base rate equal to Citibank N.A.'s alternate base rate plus an
applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate plus an applicable
margin. We are required to pay a commitment fee based on the unused portion of the credit facility. The
applicable margin and the commitment fee are determined by reference to a pricing schedule based on the
applicable borrower’s senior unsecured long-term debt ratings.
Significant financial covenants under the Credit Agreement require the ratio of debt to EBITDA (earnings before
interest, taxes, depreciation, and amortization), each as defined in the credit facility, to be no greater than:
•
•
•
5.75 to 1 for each fiscal quarter end through June 30, 2019;
5.5 to 1 for the fiscal quarters ending September 30, 2019, and December 31, 2019;
5.0 to 1 for the fiscal quarter ending March 31, 2020, and each subsequent fiscal quarter end, except for the
fiscal quarter and the two following fiscal quarters in which one or more acquisitions with a total aggregate
purchase price of $25 million or more has been executed, in which case the ratio of debt to EBITDA is to be
no greater than 5.5 to 1.
The ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for each of
Transco and Northwest Pipeline.
At December 31, 2018, we are in compliance with these covenants.
Commercial Paper Program
On August 10, 2018, following the consummation of the WPZ Merger, WPZ’s $3 billion commercial paper program
was discontinued and we entered into a new $4 billion commercial paper program. 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. The net proceeds of issuances of the commercial paper notes
are expected to be used to fund planned capital expenditures and for other general corporate purposes. At December 31,
2018 and 2017, no Commercial paper was outstanding. At February 19, 2019, no commercial paper was outstanding.
Cash Payments for Interest (Net of Amounts Capitalized)
Cash payments for interest (net of amounts capitalized) were $1.064 billion in 2018, $1.110 billion in 2017, and
$1.152 billion in 2016.
Leases-Lessee
The future minimum annual rentals under noncancelable operating leases, are payable as follows:
2019 .................................................................................................................................................... $
2020 ....................................................................................................................................................
2021 ....................................................................................................................................................
2022 ....................................................................................................................................................
2023 ....................................................................................................................................................
Thereafter............................................................................................................................................
Total.................................................................................................................................................. $
32
31
28
24
15
86
216
December 31,
2018
(Millions)
130
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Total rent expense was $73 million in 2018, $62 million in 2017, and $64 million in 2016 and primarily included
in Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement
of Operations.
Note 15 – Stockholders' Equity
On February 20, 2019, our board of directors approved a regular quarterly dividend of $0.38 per share payable on
March 25, 2019.
In July 2018, through a wholly owned subsidiary, we contributed 35,000 shares of newly issued Series B Non-
Voting Perpetual Preferred Stock (Preferred Stock) to The Williams Companies Foundation, Inc. (a not-for-profit
corporation) for use in future charitable and nonprofit causes. The charitable contribution of Preferred Stock was
recorded as an expense in the third quarter of 2018. The Preferred Stock was issued for an aggregate value of $35
million and pays non-cumulative quarterly cash dividends when, as and if declared, at a rate of 7.25 percent per year.
We paid dividends totaling $1.1 million on the shares of Preferred Stock in 2018. Our certificate of incorporation
authorizes 30 million shares of Preferred Stock, $1 par value per share.
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.)
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, 2017 .................................. $
Adoption of new accounting standard (Note 1).........
WPZ Merger (Note 1)................................................
Other comprehensive income (loss):
Other comprehensive income (loss) before
reclassifications ..................................................
Amounts reclassified from accumulated other
comprehensive income (loss) .............................
Other comprehensive income (loss)...........................
Balance at December 31, 2018 .................................. $
(2) $
—
(3)
(2)
5
3
(2) $
(Millions)
(1) $
—
—
—
—
—
(1) $
(235) $
(61)
—
(6)
35
29
(267) $
(238)
(61)
(3)
(8)
40
32
(270)
131
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Reclassifications out of AOCI are presented in the following table by component for the year ended December 31,
2018:
Cash flow hedges:
Component
Reclassifications
(Millions)
Classification
Energy commodity contracts.......................................
$
9 Product sales
Pension and other postretirement benefits:
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 ..........................................................
46 Note 10 – Employee Benefit Plans
55
(12) Provision (benefit) for income taxes
43
Noncontrolling interest..................................................
Reclassifications during the period .................................
$
(3)
40
Net income (loss) attributable to
noncontrolling interests
Note 16 – 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, 2018, 24 million shares of our common stock were reserved
for issuance pursuant to existing and future stock awards, of which 12 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 338 thousand shares at an average price of $20.70
per share during 2018. Approximately 746 thousand shares were available for purchase under the ESPP at December 31,
2018.
Operating and maintenance expenses and Selling, general, and administrative expenses include equity-based
compensation expense for the years ended December 31, 2018, 2017, and 2016 of $54 million, $70 million, and $53
million, respectively. Income tax benefit recognized related to the stock-based compensation expense for the years
ended December 31, 2018, 2017, and 2016 was $14 million, $17 million, and $20 million, respectively. Measured but
unrecognized stock-based compensation expense at December 31, 2018, was $56 million, comprised of $4 million
related to stock options and $52 million related to restricted stock units. These amounts are expected to be recognized
over a weighted-average period of 1.8 years.
132
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Stock Options
The following summary reflects stock option activity and related information for the year ended December 31,
2018:
Stock Options
Weighted-
Average
Exercise
Price
Aggregate
Intrinsic
Value
(Millions)
Options
(Millions)
Outstanding at December 31, 2017 ...............................................
Granted ..........................................................................................
Exercised .......................................................................................
Cancelled .......................................................................................
Outstanding at December 31, 2018 ...............................................
Exercisable at December 31, 2018 ................................................
$
6.6
1.3
$
(0.4) $
(0.2) $
$
7.3
$
5.3
31.53
29.09
23.06
31.45
31.55
32.63
$
$
6
6
The following table summarizes additional information related to stock option activity during each of the last three
years:
Years Ended December 31,
2018
2017
(Millions)
2016
Total intrinsic value of options exercised........................................................ $
Tax benefits realized on options exercised...................................................... $
Cash received from the exercise of options..................................................... $
3
$
— $
$
9
4
1
7
$
$
$
2
1
4
The weighted-average remaining contractual life for stock options outstanding and exercisable at December 31,
2018, was 5.1 years and 3.7 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................................................................ $
5.49
$
6.61
$
7.90
Weighted-average assumptions:
Dividend yield..............................................................................................
Volatility.......................................................................................................
Risk-free interest rate...................................................................................
Expected life (years) ....................................................................................
4.7%
30.1%
2.7%
6.0
4.2%
35.1%
2.1%
6.0
3.2%
44.7%
1.2%
6.0
2018
2017
2016
The 2018 expected dividend yield is based on the 2018 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.
133
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Nonvested Restricted Stock Units
The following summary reflects nonvested restricted stock unit activity and related information for the year ended
December 31, 2018:
Restricted Stock Units Outstanding
Weighted-
Average
Fair Value (1)
Shares
(Millions)
Nonvested at December 31, 2017 .............................................................................
Granted......................................................................................................................
Forfeited ....................................................................................................................
Vested........................................................................................................................
Nonvested at December 31, 2018 .............................................................................
______________
(1) Performance-based restricted stock units are valued considering measures of total shareholder return, utilizing a
Monte Carlo valuation method, and return on capital employed. All other restricted stock units are valued at the
grant-date market price. Restricted stock units generally vest after three years.
$
4.2
1.7
$
(0.5) $
(0.9) $
$
4.5
31.02
30.48
32.97
39.30
28.96
Value of Restricted Stock Units
Weighted-average grant date fair value of restricted stock units granted
2018
2017
2016
during the year, per share............................................................................. $
30.48
Total fair value of restricted stock units vested during the year ($s in
millions) ....................................................................................................... $
35
$
$
29.47
33
$
$
26.51
32
Performance-based restricted stock units granted under the Plan represent 34 percent of nonvested restricted stock
units outstanding at December 31, 2018. 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 the general partner of Access Midstream Partners, L.P. (ACMP) 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 February 2, 2015 merger of Williams Partners L.P. with
and into Access Midstream Partners, L.P (which was subsequently renamed Williams Partners L.P.). During 2018, no
additional grants of restricted common units were awarded through WPZ’s equity-based compensation programs, and
all outstanding shares were vested and exercised. Equity-based compensation expense of less than $1 million, $8
million, and $20 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, 2018, 2017,
and 2016, respectively. The total fair value of the restricted common units vested during 2018, 2017, and 2016 was $5
million, $24 million, and $34 million, respectively. This plan is no longer active.
Note 17 – 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, margin deposits, 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.
134
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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, 2018:
Measured on a recurring basis:
ARO Trust investments ........................................... $
150
$
150
$
150
$
— $
Energy derivatives assets not designated as
hedging instruments ............................................
Energy derivatives liabilities not designated as
hedging instruments ............................................
Additional disclosures:
3
(7)
3
(7)
Long-term debt, including current portion ..............
Guarantees ...............................................................
(22,414)
(43)
(23,330)
(30)
3
(4)
—
—
—
—
(23,330)
(14)
Assets (liabilities) at December 31, 2017:
Measured on a recurring basis:
ARO Trust investments ........................................... $
Energy derivatives liabilities designated as
hedging instruments ............................................
Energy derivatives liabilities not designated as
hedging instruments ............................................
Additional disclosures:
Long-term debt, including current portion ..............
Guarantees ...............................................................
(20,935)
(43)
(23,005)
(30)
Fair Value Methods
135
$
135
$
135
$
— $
(3)
(3)
(3)
(3)
(2)
—
—
—
(1)
—
(23,005)
(14)
—
—
(3)
—
(16)
—
—
(3)
—
(16)
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 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.
135
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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,
2018 or 2017.
Additional fair value disclosures
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 values of the financing obligations
associated with our Dalton lateral and Atlantic Sunrise projects, which are included within long-term debt, were
determined using an income approach (see Note 14 – 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 $29 million at December 31, 2018. 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.
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 agreement 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.
136
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Nonrecurring fair value measurements
The following table presents impairments of assets and investments associated with certain nonrecurring fair
value measurements within Level 3 of the fair value hierarchy, except as specifically noted.
Classification
Segment
Date of
Measurement
Fair
Value
Impairments
Years Ended December 31,
2018
2017
2016
(Millions)
Property, plant,
and equipment –
net and Intangible
assets - net of
accumulated
amortization
Property, plant,
and equipment –
net
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
Property, plant,
and equipment –
net
Property, plant,
and equipment –
net
Certain gathering operations (1) ..
Certain idle pipeline assets (2).....
Certain gathering operations (3) ..
Certain gathering operations (4) ..
Certain NGL pipeline (5).............
Certain olefins pipeline project
(6).............................................
Canadian operations (7)...............
Certain gathering operations (8) ..
Certain idle pipeline assets ..........
Fair value measurements of
certain assets ............................
Other impairments and write-
downs (9) .................................
Impairment of certain assets ........
Equity-method investments (10)..
Investments
Equity-method investments (11)..
Investments
West
December 31,
2018
$ 470
$ 1,849
Other
June 30, 2018
25
66
West
September 30,
2017
439
$1,019
Northeast
G&P
September 30,
2017
Other
September 30,
2017
Other
June 30, 2017
21
32
18
115
68
23
Other
June 30, 2016
1,130
$
747
West
June 30, 2016
Other
December 31,
2016
18
73
48
8
803
70
1,915
1,225
—
23
$ 1,915
$1,248
$
873
December 31,
2018
$1,293
$
32
December 31,
2016
1,295
$
318
Northeast
G&P
West and
Northeast
G&P
137
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Classification
Segment
Date of
Measurement
Fair
Value
Equity-method investments (12)..
Investments
West and
Northeast
G&P
Other equity-method investment .
Investments
West
March 31,
2016
March 31,
2016
1,294
—
Impairment of equity-method
investments ..............................
Impairments
Years Ended December 31,
2018
2017
2016
(Millions)
109
3
$
32
$
430
______________
(1) Relates to our gathering operations in the Barnett Shale. Certain of our contractual gathering rates, primarily
those in the Barnett Shale, are based on a percentage of the New York Mercantile Exchange (NYMEX) natural
gas prices. During the fourth quarter of 2018, we determined there was a sustained decline in the forward price
curves for natural gas. During this same period, a large producer customer in the Barnett Shale removed their
remaining drilling rig. These factors gave rise to an impairment evaluation of these assets, which incorporated
management’s projections of future drilling activity and gathering rates, taking into consideration the information
previously noted as well as recently available information regarding producer drilling cost assumptions in the
basin. The resulting estimate of future undiscounted cash flows was less than our carrying value, necessitating
the estimation of the fair value of these assets. To arrive at the fair value, we utilized an income approach with
a discount rate of 8.5 percent, reflecting an estimated cost of capital and risks associated with the underlying
assets.
(2) Relates to certain idle pipelines. The estimated fair value was determined by a market approach incorporating
information derived from bids received for these assets, which we marketed for sale together with certain other
assets. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. We sold
these assets in the fourth quarter of 2018. (See Note 3 – Divestitures.)
(3) 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.
(4) 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.
(5) Relates to an NGL pipeline near the Houston Ship Channel region which we anticipated would 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. We sold these assets in the fourth quarter of 2018.
(See Note 3 – Divestitures.)
(6) Relates primarily to project development costs associated with an olefins pipeline project in the Gulf Coast region,
the likelihood of completion we 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. We sold these assets in the fourth quarter of 2018. (See Note 3 – Divestitures.)
138
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
(7) 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 3 – Divestitures.)
(8) 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.
(9) 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.
(10) Relates to Northeast G&P’s equity-method investment in UEOM. The estimated fair value was determined by
a market approach based on our analysis of inputs in the principal market.
(11) Relates to West’s previously held interest in Ranch Westex and multiple, currently held Appalachia Midstream
Investments at Northeast G&P. 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 6 – Investing Activities.)
(12) Relates to West’s previously held interest in DBJV and Northeast G&P’s 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.
Concentration of Credit Risk
Trade accounts and other receivables
The following table summarizes concentration of receivables, net of allowances:
December 31,
2018
2017
NGLs, natural gas, and related products and services .............................................. $
Transportation of natural gas and related products ...................................................
Other..........................................................................................................................
Total ....................................................................................................................... $
139
$
(Millions)
626
232
134
992
$
760
212
4
976
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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, 2018 and 2017, Chesapeake Energy Corporation, and its affiliates
(Chesapeake), a customer primarily within our Northeast G&P and West segments, accounted for $65 million and $176
million, respectively, of the consolidated Trade accounts and other receivables balances. The increase in Other is
primarily due to an increase in our federal income tax receivable.
Revenues
In 2018, 2017, and 2016, Chesapeake accounted for 8 percent, 10 percent, and 14 percent, respectively, of our
consolidated revenues.
Note 18 – Contingent Liabilities and Commitments
Reporting of Natural Gas-Related Information to Trade Publications
Direct and indirect purchasers of natural gas in various states filed 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 appealed. On March 27, 2018, the
appellate court reversed the district court’s grant of summary judgment, and on April 10, 2018, the defendants filed a
petition for rehearing with the appellate court, which was denied on May 9, 2018. The case has been remanded to the
Nevada federal district court.
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. On August 6, 2018, the Ninth Circuit reversed the order denying class certification
and remanded the case to the Nevada federal district court.
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.
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.
140
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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. Several trial dates encompassing all three cases have been
scheduled and stricken; we are awaiting a new trial date. 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 intends 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. That customer has reached a tentative settlement to resolve substantially all Pennsylvania royalty cases
pending, which settlement would apply to both the customer and us. The settlement as reported would not require any
contribution from us.
Litigation Against Energy Transfer and Related Parties
On April 6, 2016, we filed suit in Delaware Chancery Court against Energy Transfer Equity, L.P. (Energy Transfer)
and LE GP, LLC (the general partner for Energy Transfer) alleging willful and material breaches of the Agreement and
Plan of Merger (ETE 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 ETE 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 ETE Merger Agreement, alleging material breaches
of the ETE Merger Agreement for failing to cooperate and use necessary efforts to obtain a tax opinion required under
the ETE Merger Agreement (Tax Opinion) and for otherwise failing to use necessary efforts to consummate the merger
under the ETE 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 ETE Merger Agreement due to any failure
to obtain the Tax Opinion.
141
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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 ETE 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 ETE 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 ETE 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,
which the Court of Chancery denied on April 16, 2018. Although the Court of Chancery scheduled trial for May 20
through May 24, 2019, the parties anticipate trial will be re-scheduled for a later date.
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, 2018, we have accrued liabilities totaling $35 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, 2018, 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. These 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. The EPA previously issued its rule regarding National Ambient Air Quality
Standards for ground-level ozone. We are monitoring the rule’s implementation as it 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
142
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund
waste sites. At December 31, 2018, we have accrued liabilities of $6 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, 2018, we have accrued liabilities totaling $7 million for these
costs.
Former operations
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;
• Former petroleum refining facilities;
• Former exploration and production and mining operations;
• Former electricity and natural gas marketing and trading operations.
At December 31, 2018, we have accrued environmental liabilities of $22 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, 2018, 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.
143
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Commitments
Commitments for construction and acquisition of property, plant, and equipment are approximately $480 million
at December 31, 2018.
Note 19 – Segment Disclosures
Our reportable segments are Northeast G&P, Atlantic-Gulf, and West. All remaining business activities are included
in Other. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting
Policies.)
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
performance measure used by our chief operating decision maker in measuring performance and allocating resources
among our reportable segments. Intersegment revenues primarily represent the sale of NGLs from our natural gas
processing plants to our marketing business.
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;
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:
Revenues from external customers:
2018............................................................................................
2017............................................................................................
2016............................................................................................
$
$
8,686
8,030
7,425
— $
1
74
8,686
8,031
7,499
United States
Canada
(Millions)
Total
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:
Northeast
G&P
Atlantic-
Gulf
West
Other
Eliminations
Total
(Millions)
2018
Segment revenues:
Service revenues
External ............................................................ $
Internal .............................................................
Total service revenues .........................................
Total service revenues – commodity
consideration (external only) ...........................
Product sales
External ............................................................
Internal .............................................................
Total product sales ...............................................
Total revenues ........................................................ $
935
41
976
20
245
42
287
1,283
$
$
2,460
49
2,509
59
174
261
435
3,003
$
$
2,085
—
2,085
321
2,365
83
2,448
4,854
$
$
Other financial information:
Additions to long-lived assets .............................. $
Proportional Modified EBITDA of equity-
method investments .........................................
477
$
2,297
$
361
$
493
183
94
2017
Segment revenues:
Service revenues
External ............................................................ $
Internal .............................................................
Total service revenues .........................................
Product sales
External ............................................................
Internal .............................................................
Total product sales ...............................................
Total revenues ........................................................ $
837
35
872
264
27
291
1,163
$
$
2,202
37
2,239
257
227
484
2,723
$
$
2,246
—
2,246
1,840
173
2,013
4,259
$
$
Other financial information:
Additions to long-lived assets .............................. $
Proportional Modified EBITDA of equity-
method investments .........................................
460
$
2,001
$
321
$
452
264
79
2016
Segment revenues:
Service revenues
External .......................................................... $
Internal ...........................................................
Total service revenues .........................................
Product sales
External ..........................................................
Internal ...........................................................
Total product sales ...............................................
Total revenues ........................................................ $
836
34
870
134
28
162
1,032
$
$
1,959
39
1,998
245
205
450
2,448
$
$
2,328
—
2,328
1,183
197
1,380
3,708
$
$
Other financial information:
Additions to long-lived assets .............................. $
Proportional Modified EBITDA of equity-
method investments .........................................
223
$
1,608
$
223
$
357
287
110
145
22
12
34
—
—
—
—
34
36
—
27
11
38
358
8
366
404
32
—
48
11
59
766
22
788
847
92
—
$
$
$
$
$
$
$
$
$
— $
(102)
(102)
—
—
(386)
(386)
(488) $
5,502
—
5,502
400
2,784
—
2,784
8,686
— $
3,171
—
770
— $
(83)
(83)
—
(435)
(435)
(518) $
5,312
—
5,312
2,719
—
2,719
8,031
— $
2,814
—
795
— $
(84)
(84)
—
(452)
(452)
(536) $
5,171
—
5,171
2,328
—
2,328
7,499
(1) $
2,145
—
754
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:
Northeast G&P ................................................................................................ $
Atlantic-Gulf....................................................................................................
West .................................................................................................................
Other ................................................................................................................
Accretion expense associated with asset retirement obligations for
nonregulated operations....................................................................................
Depreciation and amortization expenses..............................................................
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,
2018
2017
(Millions)
2016
1,086
2,023
308
(29)
3,388
(33)
(1,725)
396
(32)
219
(770)
(1,112)
(138)
193
$
$
819
1,238
412
997
3,466
(33)
(1,736)
434
—
282
(795)
(1,083)
1,974
2,509
$
$
853
1,621
1,544
(696)
3,322
(31)
(1,763)
397
(430)
63
(754)
(1,179)
25
(350)
The following table reflects Total assets and Equity-method investments by reportable segments:
Total Assets
December 31,
2018
December 31,
2017
Equity-Method Investments
December 31,
December 31,
2017
2018
Northeast G&P ......................................................
Atlantic-Gulf .........................................................
West.......................................................................
Other (1) ................................................................
Eliminations (2).....................................................
Total .................................................................
$
$
14,526
16,346
13,948
849
(367)
45,302
$
$
______________
(1) Decrease in Other is due primarily to a decreased cash balance.
(Millions)
14,397
14,989
16,143
1,449
(626)
46,352
$
$
5,319
776
1,726
—
—
7,821
$
$
5,307
823
422
—
—
6,552
(2) Eliminations primarily relate to the intercompany notes and accounts receivable generated by our cash management
program.
146
The Williams Companies Inc.
Quarterly Financial Data – (Continued)
(Unaudited)
Summarized quarterly financial data are as follows:
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
(Millions, except per-share amounts)
2018
Revenues ........................................................................................ $
Product costs and processing commodity expenses........................
Net income (loss) ............................................................................
Amounts attributable to The Williams Companies, Inc.:
Net income (loss) ....................................................................
Basic earnings (loss) per common share .................................
Diluted earnings (loss) per common share ..............................
2017
Revenues ........................................................................................ $
Product costs ..................................................................................
Net income (loss) ............................................................................
Amounts attributable to The Williams Companies, Inc.:
Net income (loss) ....................................................................
Basic earnings (loss) per common share .................................
Diluted earnings (loss) per common share: .............................
$
$
2,088
648
270
152
.18
.18
1,988
579
569
373
.45
.45
$
$
2,091
662
269
135
.16
.16
1,924
537
193
81
.10
.10
$
$
2,303
820
200
129
.13
.13
1,891
504
125
33
.04
.04
2,204
714
(546)
(571)
(.47)
(.47)
2,228
680
1,622
1,687
2.04
2.03
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.
2018
Net income (loss) for fourth-quarter 2018 includes:
$1.849 billion impairment of certain assets in the Barnett Shale region (see Note 17 – Fair Value Measurements,
Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements);
$591 million gain on the sale of our natural gas gathering and processing assets in the Four Corners area of
New Mexico and Colorado (see Note 3 – Divestitures);
$141 million deconsolidation gain associated with our investment in the Brazos Permian II joint venture (see
Note 6 – Investing Activities);
$101 million gain on the sale of certain assets and operations located in the Gulf Coast area (see Note 3 –
Divestitures).
•
•
•
•
2017
Net income (loss) for fourth-quarter 2017 includes:
•
•
$1.923 billion benefit for income taxes resulting from Tax Reform rate change (see Note 8 – Provision (Benefit)
for Income Taxes);
$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
7 – Other Income and Expenses).
147
The Williams Companies Inc.
Quarterly Financial Data – (Continued)
(Unaudited)
Net income (loss) for third-quarter 2017 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 3 – Divestitures);
$1.210 billion impairment on certain assets (see Note 17 – 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 6 – Investing Activities).
148
The Williams Companies, Inc.
Schedule II — Valuation and Qualifying Accounts
Additions
Charged
(Credited)
To Costs and
Expenses
Beginning
Balance
Other
Deductions
Ending
Balance
(Millions)
2018
Deferred tax asset valuation allowance (1) ................ $
224
$
96
$
— $
— $
320
2017
Deferred tax asset valuation allowance (1) ................
2016
Deferred tax asset valuation allowance (1) ................
334
190
(110)
144
—
—
—
—
224
334
__________
(1) Deducted from related assets.
149
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 2018 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.
150
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,
2018, 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, 2018, 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.
151
Report of Independent Registered Public Accounting Firm
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, 2018,
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, 2018, 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, 2018 and 2017, 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, 2018, and the related notes and the financial statement schedule listed
in the index at Item 15(a) and our report dated February 21, 2019 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 21, 2019
152
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 9, 2019, which shall be filed no later
than March 28, 2019 (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
Ownership of Certain Beneficial Owners and Management” in our Proxy Statement, which information is incorporated
by reference herein.
153
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.
154
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, 2018 ..
Consolidated statement of comprehensive income (loss) for each year in the three-year period ended
December 31, 2018 ..................................................................................................................................
Consolidated balance sheet at December 31, 2018 and 2017 .....................................................................
Consolidated statement of changes in equity for each year in the three-year period ended December 31,
2018..........................................................................................................................................................
Consolidated statement of cash flows for each year in the three-year period ended December 31, 2018 ..
Notes to consolidated financial statements .....................................................................................................
Schedule for each year in the three-year period ended December 31, 2018:
II — Valuation and qualifying accounts ....................................................................................................
Not covered by report of independent auditors:
Quarterly financial data (unaudited) ...............................................................................................................
Page
76
77
78
79
80
81
149
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).
155
Exhibit
No.
2.4
2.5
3.1
3.2
3.3
Description
— 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).
— Certificate of Designations of Series B Preferred Stock of the Williams Companies, Inc. (filed on
July17, 2018, as Exhibit 3.1 to The Williams Companies, Inc. current report on Form 8-K (File
No. 001-04174) and Incorporated herein by reference).
— Certificate of Amendment dated August 10, 2018 (filed on August 10, 2018, 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).
3.4
— 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
4.6
— 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).
— 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).
156
Exhibit
No.
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
Description
— 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 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).
— Second Supplemental Indenture, dated as of August 10, 2018, between The Williams Companies,
Inc. and The bank of New York Mellon Trust Company, N.A. (filed on August 10, 2018, 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 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).
157
Exhibit
No.
4.19
4.20
4.21
4.22
4.23
4.24
4.25
4.26
4.27
4.28
4.29
Description
— 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).
__ Tenth Supplemental Indenture, dated as of March 5, 2018, between Williams Partners L.P. and The
bank of New York Mellon Trust Company, N.A., as trustee (filed on March 5, 2018, 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).
__ Eleventh Supplemental Indenture, dated as of August 10, 2018, between The Williams Companies
Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on August 10, 2018, 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).
158
Exhibit
No.
4.30
4.31
4.32
4.33
4.34
4.35
4.36
Description
— 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 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 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).
— Indenture, dated as of March 15, 2018, between Transcontinental Gas Pipe Line Company, LLC
and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 15, 2018, as
Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174)
and incorporated by reference).
10.1§ — The Williams Companies Amended and Restated Retirement Restoration Plan effective as of
December 1, 2017 (filed on February 22, 2018, as Exhibit 10.1 to The Williams Companies, Inc.’s
annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
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).
10.5§ — 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).
10.6§ — 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).
159
Exhibit
No.
Description
10.7§ — 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).
10.8§ — 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).
10.9§ — 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).
10.10§ — 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).
10.11§ — 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).
10.12§
— 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).
10.13§ — 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).
10.14§
— 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).
10.15§ — 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).
10.16§ — 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).
10.17§ — 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).
10.18§ — 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).
10.19§
10.20§
__ 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).
__ Form of 2018 Time-Based Restricted Stock Unit Agreement among Williams and certain employees
and officers (filed on May 3, 2018, as Exhibit 10.3 to The Williams Companies Inc.’s quarterly
report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
160
Exhibit
No.
10.21§
10.22§
10.23§
Description
__ Form of 2018 Performance-Based Restricted Stock Unit Agreement among Williams and certain
employees and officers (filed on May 3, 2018, as Exhibit 10.4 to The Williams Companies Inc.’s
quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
__ Form of 2018 Nonqualified Stock Option Agreement among Williams and certain employees and
officers (filed on May 3, 2018, as Exhibit 10.5 to The Williams Companies Inc.’s quarterly report
on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
__ Form of 2018 Time-Based Restricted Stock Unit Agreement among Williams and certain non-
management directors (filed on August 2, 2018, 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).
10.24§ — 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§* — Change in Control and Restrictive Covenant Agreement between certain executive officers (Tier
One Executives) and The Williams Companies, Inc.
10.29§* — Change in Control and Restrictive Covenant Agreement between certain executive officers (Tier
Two Executives) and The Williams Companies, Inc.
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).
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).
161
Exhibit
No.
Description
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 — Credit Agreement dated as of July 13, 2018, between The Williams Companies, Inc., Northwest
Pipeline LLC, and Transcontinental Gas Pipe Line Company, LLC as co-borrowers, the lenders
named therein, and Citibank, N.A. as Administrative Agent (filed on July 17, 2018, 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).
10.37 — Form of Commercial Paper Dealer Agreement, dated as of August 10, 2018, between The Williams
Companies, Inc., as Issuer, and the Dealer party thereto(filed on August 10, 2018, 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).
10.38 — 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).
10.39 — Registration Rights Agreement, dated March 15, 2018, among Transcontinental Gas Pipe line
Company, LLC and the initial purchasers listed therein (filed on March 15, 2018, 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).
10.40 — 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).
14
— 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.
162
Exhibit
No.
Description
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.
163
Item 16. Form 10-K Summary
Not applicable.
164
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 21, 2019
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 21, 2019
Alan S. Armstrong
(Principal Executive Officer)
/s/ JOHN D. CHANDLER
Senior Vice President and Chief Financial Officer
February 21, 2019
John D. Chandler
(Principal Financial Officer)
/s/ TED T. TIMMERMANS
Ted T. Timmermans
Vice President, Controller and Chief Accounting
Officer
(Principal Accounting Officer)
February 21, 2019
/s/ STEPHEN W. BERGSTROM
Chairman of the Board
February 21, 2019
Stephen W. Bergstrom
/s/ NANCY K. BUESE
Nancy K. Buese
/s/ STEPHEN I. CHAZEN
Stephen I. Chazen
/s/ CHARLES I. COGUT
Charles I. Cogut
Director
Director
Director
February 21, 2019
February 21, 2019
February 21, 2019
/s/ KATHLEEN B. COOPER
Director
February 21, 2019
Kathleen B. Cooper
/s/ MICHAEL A. CREEL
Michael A. Creel
/s/ VICKI L. FULLER
Vicki L. Fuller
/s/ PETER A. RAGAUSS
Peter A. Ragauss
February 21, 2019
February 21, 2019
February 21, 2019
Director
Director
Director
165
Signature
/s/ SCOTT D. SHEFFIELD
Scott D. Sheffield
/s/ MURRAY D. SMITH
Murray D. Smith
/s/ WILLIAM H. SPENCE
William H. Spence
Title
Director
Director
Director
Date
February 21, 2019
February 21, 2019
February 21, 2019
166
Corporate Data
ANNUAL MEETING
AUDITORS
Stockholders are invited to our annual
meeting at 2 p.m. Central Daylight Time
on May 9, 2019, 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, President
and Chief Executive Officer, to the
New York Stock Exchange pursuant
to NYSE Section 303A.12(a) on
June 8, 2018.
We also filed with the Securities and
Exchange Commission on February
21, 2019, as Exhibits 31.1 and 31.2 to
our Annual Report on Form 10-K for
the year ended December 31, 2018,
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
veterans 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 stockholder correspondence:
Computershare Trust Company, N.A.
P.O. Box 5050000
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 40233-5000
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 15, 2019
was approximately $22.6 billion. On
that date, 6,780 stockholders of record
held 1,210,981,263 shares of Williams
common stock. The company’s common
stock traded at an average daily volume
of 9.6 million shares in 2018.
WMB COMMON STOCK ACTIVITY
(dividend/share)
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
2018
0.34
0.34
0.34
0.34
2017
0.30
0.30
0.30
0.30
WMB AVERAGE DAILY VOLUMES TRADED
(thousands of shares)
2014
2015
2016
2017
2018
20,000
16,000
12,000
8,000
4,000
43214321432143214321
WMB PRICE RANGES
($/share)
High
Low
2014
2015
2016
2017
2018
70
60
50
40
30
20
10
0
43214321432143214321
WMB DAILY PRICES
($/share)
2018
2017
High
Low
High
Low
1st Quarter
33.67
24.59
32.69
27.68
2nd Quarter
28.23
24.00
31.25
27.65
3rd Quarter
32.22
26.51
32.18
28.76
4th Quarter
28.19
20.36
30.72
26.82
We make energy happen.®
(800) WILLIAMS l www.williams.com
© 2019 The Williams Companies, Inc.