2019 ANNUAL REPORT
The Williams Companies, Inc.
Financial Highlights
Dollars in millions, except per-share amounts
2019
2018
2017
2016
2015
Revenues
$8,201
$8,686
$8,031
$7,499
$7,360
Income (loss) from continuing operations 1
729
193
2,509
(350)
(1,314)
Amounts attributable to The Williams Companies, Inc.
available to common stockholders:
Income (loss) from continuing operations2
862
(156)
2,174
(424)
(571)
Diluted income (loss) from continuing operations
per common share
0.71
(0.16)
2.62
(0.57)
(0.76)
Total assets at December 31
46,040
45,302
46,352
46,835
49,020
Commercial paper, lease liabilities, and long-term debt
(including current portions) at December 31
22,497
22,414
20,935
23,502
24,487
Stockholders’ equity at December 313
13,363
14,660
9,656
Cash dividends declared per common share
1.52
1.36
1.20
4,643
1.68
6,148
2.45
Diluted weighted-average shares outstanding (thousands)
1,214,011
973,626
828,518
750,673
749,271
1 Income (loss) from continuing operations:
• For 2019 includes $464 million of impairments of certain assets, including a $354 million impairment of Constitution’s capitalized project
costs, and $186 million impairments of certain equity-method investments, partially offset by a $122 million gain on the sale of our
Jackalope equity-method investment;
• 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 and 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.
2 Income (loss) from continuing operations attributable to the Williams Companies, Inc. available to common stockholders:
• For 2019 includes benefit of $209 million reflecting the noncontrolling interests’ share of the impairment of Constitution’s capitalized
project costs.
3 Stockholders’ equity at December 31:
• For 2019 includes a decrease related to a sale of a partial interest in our Northeast JV business;
• For 2018 includes an increase reflecting our issuance of common stock associated with our merger with WPZ in August 2018;
• For 2017 includes increases reflecting our issuance of common stock as part of our Financial Repositioning and a significant increase
in our ownership of WPZ.
Front Cover: Williams employees positively impact lives every day by fueling the clean energy
economy with large-scale energy infrastructure that connects natural gas supplies to markets
with growing demand for cleaner fuel.
Forward-Looking Statements: Any statements included in this 2019 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 MAKE CLEAN ENERGY HAPPEN SM
President and Chief Executive Officer
Alan S. Armstrong
Dear Fellow Stockholders:
Williams achieved yet another year
of record results in 2019, once again
delivering impressive year-over-year
growth and exceeding guidance in
our key financial metrics. In 2019,
Williams produced record annual
Adjusted EBITDA, record distributable
cash flow, record gathered volumes
and improved credit metrics over
2018. This highly reliable and
predictable performance is the result
of continuous improvement by our
operating teams on many fronts,
including capital project execution,
reliable and on-time services to our
customers, safety performance,
environmental stewardship, capital
discipline and operating efficiency.
Our record average daily gathering
volume of 12.9 Bcf/d for full-year 2019
was driven by 15% growth in the
prolific Marcellus and Utica Basins.
The company also saw continued
growth in interstate gas transmission,
driven by 11% growth in the long-term
firm contracted capacity on Transco,
the nation’s largest and fastest
growing pipeline system.
As our strong 2019 results illustrate,
we are successfully delivering on
a deliberate strategy to provide
infrastructure services for natural
gas — an economically and
environmentally superior energy
source — with dramatically less
commodity margin exposure and
an improved balance sheet to
provide flexibility and unquestioned
financial stability.
SAFETY DRIVEN
We continue to drive a safety-first
culture by training and empowering
our people to complete projects,
perform maintenance and operate our
assets in a way that sets the industry
standard. All employees have full stop
work authority when they recognize
a safety issue and are empowered to
make it right. Thanks to the ongoing
efforts of our employees, we’ve seen
an impressive 50% improvement in
our Total Recordable Incident Rate
over the past two years.
RELIABLE PERFORMANCE
Demand for clean, reliable natural
gas is at an all-time high, particularly
in markets where it has had a direct
impact on significantly improving
regional air quality, and we continue
to build strong partnerships with
our customers in order to support
their unique needs. In 2019, we
demonstrated our ability to work
with a wide range of stakeholders
in a constructive manner to address
regulatory, political and community
concerns while still permitting and
building important infrastructure
expansions. Our Rivervale South
and Gateway expansion projects,
designed to meet growing natural gas
demand in New Jersey, both went
into service ahead of schedule, as
did Northwest Pipeline’s North Seattle
Lateral Upgrade Project, which
commenced service in time to meet
the winter heating demands of the
North Seattle market area. These are
regions of the country with extremely
rigorous permitting processes that we
were able to successfully navigate,
in large part due to our ability to
construct projects along our existing
right of ways, which allows us to place
projects into service with significantly
less impact to the environment and
landowners.
In 2019, we placed our Gulf
Connector Project into full service,
our second project designed to
serve Gulf Coast LNG terminals.
This project leveraged existing gas
pipeline infrastructure in the Gulf of
Mexico, making it possible to connect
abundant domestic supply with
emerging international markets. As
global demand for clean natural gas
grows, Williams is well-positioned to
2019 Annual Report
The Williams Companies, Inc.
1
take advantage of the projected
surge in LNG demand growth,
as our Transco pipeline passes
through every U.S. state with an
LNG export facility.
STRATEGIC TRANSACTIONS
In 2019, we formed a $3.8 billion
joint venture partnership with the
Canada Pension Plan Investment
Board (CPPIB) in the Marcellus/
Utica Basins, creating a platform
for continued optimization and
growth. We purchased the remaining
38% stake in the Utica East Ohio
Midstream system from Momentum
Midstream, allowing us to reduce
operating and maintenance expenses
and creating enhanced capabilities
and benefits for producers in the
area. And, we sold our 50% interest
in Jackalope Gas Gathering to an
affiliate of Crestwood Equity Partners
at an attractive multiple, freeing up
capital to be re-deployed into high-
return assets that are better linked
to our strategy. As transactions like
these and others demonstrate, our
balance sheet is further strengthened
by our ability to leverage our unique
and diverse platform while we
continuously look to optimize our
portfolio to achieve results through
various market cycles.
RESPONSIBLE STEWARDSHIP
We remain engaged in the
critical discussions on key issues
shaping our industry, including
the opportunities and challenges
that come with transporting
natural gas as a reliable source
of clean fuel, heat and power. We
published our Sustainability Report
in June 2019 after conducting a
thorough materiality assessment
to transparently share information
about the sustainability topics that
are most critical to our company and
our stakeholders. We also filed our
response to the Carbon Disclosure
Project climate change questionnaire.
Natural gas continues to provide
immediate, practical solutions for
reducing emissions, and in 2019,
we expanded our commitment to
voluntary reductions by joining
ONE Future and The Environmental
Partnership. Both of these
organizations represent a coalition of
companies responsible for meeting
the nation’s growing demand for low
cost energy and have committed to
improving environmental performance
and accelerating emissions
reductions. The efforts of these
organizations align with our own
commitment to contribute to a safe
and sustainable future.
In closing, we strongly believe that
natural gas has been — and will
continue to be — a cornerstone of our
nation’s prosperity in the 21st century.
Natural gas is safely moving across
the nation, delivering an affordable
fuel source, creating thousands
of jobs, and driving a resurgence in
U.S. manufacturing. Natural gas has
driven significant reductions in U.S.
CO2 emissions, lowered consumers’
utility bills and paved the way for
investment in renewables. It is a
critical part of our clean energy
future, and as the American energy
leader that safely handles 30%
of the nation’s natural gas, Williams’
large-scale infrastructure is ready
to meet continued demand growth,
both in the U.S. and abroad.
On behalf of the Board of Directors
and our employees across the
country, thank you for your continued
trust and investment in Williams.
Sincerely,
Alan S. Armstrong
President and Chief Executive Officer
March 19, 2020
2
The Williams Companies, Inc.
2019 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 and Management
Development Committee
Stephen W. Bergstrom
Nancy K. Buese
Kathleen B. Cooper
Scott D. Sheffield (Chair)
Murray D. Smith
Nominating and
Governance Committee
Stephen W. Bergstrom
Stephen I. Chazen
Charles I. Cogut
Kathleen B. Cooper (Chair)
Vicki L. Fuller
Peter A. Ragauss
Environmental, Health
and 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,
Gathering & Processing
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,
Transmission & Gulf of Mexico
T. LANE WILSON
Senior Vice President
and General Counsel
CHAD J. ZAMARIN
Senior Vice President,
Corporate Strategic Development
2019 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, 2019
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
Trading Symbol(s)
WMB
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 such
files). Yes
No
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 $32,986,794,536.
The number of shares outstanding of the registrant’s common stock outstanding at February 19, 2020 was 1,212,494,859.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s Definitive Proxy Statement for the Registrant’s Annual Meeting of Stockholders to be held on April 28, 2020, 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 ..........................................................................................................................................................
General............................................................................................................................................................
Service Assets, Customers, and Contracts ......................................................................................................
Business Segments..........................................................................................................................................
Transmission & Gulf of Mexico .....................................................................................................................
Northeast G&P................................................................................................................................................
West ................................................................................................................................................................
Other ...............................................................................................................................................................
Additional Business Segment Information .....................................................................................................
Regulatory Matters .........................................................................................................................................
Environmental Matters ...................................................................................................................................
Competition ....................................................................................................................................................
Employees.......................................................................................................................................................
Website Access to Reports and Other Information .........................................................................................
Item 1A. Risk Factors ....................................................................................................................................................
Item 1B. Unresolved Staff Comments ...........................................................................................................................
Item 2.
Properties ........................................................................................................................................................
Legal Proceedings...........................................................................................................................................
Item 3.
Item 4. Mine Safety Disclosures .................................................................................................................................
Information About Our Executive Officers ....................................................................................................
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.
Gulfstar One: Gulfstar One LLC
Northwest Pipeline: Northwest Pipeline LLC
Transco: Transcontinental Gas Pipe Line Company, LLC
UEOM: Utica East Ohio Midstream LLC, previously a Partially Owned Entity until acquiring remaining interest
in March 2019
Northeast JV: Ohio Valley Midstream LLC, a partially owned venture that includes our Ohio Valley assets and
UEOM
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, 2019, 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
Constitution: Constitution Pipeline Company, LLC
Discovery: Discovery Producer Services LLC
Gulfstream: Gulfstream Natural Gas System, L.L.C.
Jackalope: Jackalope Gas Gathering Services, L.L.C., which was sold in April 2019
2
Laurel Mountain: Laurel Mountain Midstream, LLC
OPPL: Overland Pass Pipeline Company LLC
RMM: Rocky Mountain Midstream Holdings LLC
Government and Regulatory:
EPA: Environmental Protection Agency
Exchange Act, the: Securities and Exchange Act of 1934, as amended
FERC: Federal Energy Regulatory Commission
IRS: Internal Revenue Service
SEC: Securities and Exchange Commission
Other:
Fractionation: The process by which a mixed stream of natural gas liquids is separated into its constituent products,
such as ethane, propane, and butane
GAAP: U.S. generally accepted accounting principles
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.
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
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.”
GENERAL
We are an energy infrastructure company committed to be the leader in providing infrastructure that safely delivers
natural gas products to reliably fuel the clean energy economy. We have operations in 15 supply areas that provide
natural gas gathering, processing, and transmission services and natural gas liquids fractionation, transportation, and
storage services to more than 600 customers. We own an interest in and operate over 30,000 miles of pipelines, 28
processing facilities, 7 fractionation facilities, and approximately 23 million barrels of NGL storage capacity, handling
approximately 30 percent of the nation’s natural gas volumes.
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. Our common stock trades on the New York Stock Exchange under the
symbol “WMB.” Our operations are located in the United States. 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.
4
Service Assets, Customers, and Contracts
Interstate Natural Gas Pipeline Assets
Our interstate natural gas pipelines, which are presented in our Transmission & Gulf of Mexico segment as described
under the heading “Business Segments,” are subject to regulation by the FERC and as such, our rates and charges for
the transportation of natural gas in interstate commerce are subject to regulation. The rates are established through the
FERC’s ratemaking process.
Our interstate natural gas pipelines transport and store natural gas for a broad mix of customers, including local
natural gas distribution companies, 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. Transco’s and
Northwest Pipeline’s three largest customers in 2019 accounted for approximately 28 percent and 48 percent,
respectively, of their total revenues.
Gathering, Processing, and Treating Assets
Our gathering, processing, and treating operations are presented within our Transmission & Gulf of Mexico,
Northeast G&P, and West reporting segments as described under the heading “Business Segments.”
Our gathering systems receive natural gas from producers’ crude 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. We are generally paid a fee based on the
volume of natural gas gathered and/or treated, generally measured in the Btu heating value.
5
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, which include ethane, primarily used in the
petrochemical industry; propane, used for heating, fuel, and also in the petrochemical industry; and, normal butane,
isobutane, and natural gasoline, primarily used by the refining industry.
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. A portion of our fee-based processing revenue includes a share of the margins on the NGLs
produced. For the year ended December 31, 2019, 80 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. For a keep-
whole arrangement we replace the Btu content of the retained NGLs with natural gas purchases, also known
as shrink replacement gas. For a percent-of-liquids arrangement, we deliver an agreed-upon percentage of the
extracted NGLs and retain the remainder. Retained NGLs are referred to as our equity NGL production. For
the year ended December 31, 2019, 20 percent of our NGL production volumes were under noncash
commodity-based contracts.
Generally, our gathering and processing agreements are long-term agreements, with terms ranging from month-
to-month to the life of the producing lease. 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. We also have certain gas gathering and processing agreements with minimum volume
commitments (MVC), whereby the customer is obligated to pay a contractually determined fee based on any shortfall
between the actual gathered and processed volumes and the MVC for a stated 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. During 2019, our facilities gathered and processed gas and crude oil for
approximately 230 customers. Our top ten customers accounted for approximately 75 percent of our gathering and
processing fee revenues and NGL margins from our noncash commodity-based agreements.
Crude Oil Transportation and Production Handling Assets
Our crude oil transportation operations, which are presented in our Transmission & Gulf of Mexico segment as
described under the heading “Business Segments,” earn revenues typically by volumetric-based fee arrangements.
Revenue sources have historically included a combination of fixed-fee, volumetric-based fee, and cost reimbursement
arrangements. Generally, fixed fees associated with the production at our Gulf Coast production handling facilities are
recognized on a units-of-production basis. Certain fixed fees associated with the production at our Gulfstar One facility
are recognized based on contractually determined maximum daily quantities. Crude oil marketing activity is presented
on a net basis within Product costs in the Consolidated Statement of Operations subsequent to the adoption of Accounting
Standard Update 2014-09, Revenue from Contracts with Customers (Topic 606) as of January 1, 2018.
Key variables for our all of our businesses will continue to be:
• Obstacles to our expansion efforts, including delays or denials of necessary permits and opposition to
hydrocarbon-based energy development;
• Producer drilling activities impacting natural gas supplies supporting our gathering and processing volumes;
• Retaining and attracting customers by continuing to provide reliable services;
6
• Revenue growth associated with additional infrastructure either completed or currently under construction;
• Prices impacting our commodity-based activities;
• Disciplined growth in our service areas.
BUSINESS SEGMENTS
Effective January 1, 2020, following an organizational realignment, our interstate natural gas pipeline Northwest
Pipeline LLC, reported within the West reporting segment throughout 2019, is now managed within the Transmission
& Gulf of Mexico reporting segment (previously identified as the Atlantic-Gulf reporting segment). Consistent with
the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations
are conducted, managed, and presented in Part I of this Annual Report within the following reportable segments:
Transmission & Gulf of Mexico, Northeast G&P, and West.
Pursuant to the organizational realignment, our reportable segments are comprised of the following business
activities:
• Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco and Northwest
Pipeline, as well as natural gas gathering, processing, and treating assets and crude oil production handling
and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated
variable interest entity), which is a proprietary floating production system, and various petrochemical and
feedstock pipelines in the Gulf Coast region, a 50 percent equity-method investment in Gulfstream, and a 60
percent equity-method investment in Discovery.
• Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the
Marcellus Shale region primarily in Pennsylvania, New York, and the Utica Shale region of eastern Ohio, as
well as a 65 percent interest in our Northeast JV (a consolidated variable interest entity) which operates in
West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated variable interest entity)
which operates in Ohio, 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).
• West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of
Colorado and Wyoming, 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, 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, a
50 percent equity-method investment in OPPL, a 50 percent equity-method investment in RMM, and a 15
percent equity-method investment in Brazos Permian II.
• Other includes minor business activities that are not operating segments, as well as corporate operations.
Detailed discussion of each of our reporting segments follows. Part II, Item 7. Management’s Discussion and
Analysis of Financial Condition and Results of Operations (including the discussion of our ongoing expansion projects)
and Item 8. Financial Statements and Supplementary Data continue to present our segments as they were historically
defined before the organizational realignment on January 1, 2020.
Transmission & Gulf of Mexico
This segment includes the Transco interstate natural gas pipeline that extends from the Gulf of Mexico to the
eastern seaboard, the Northwest Pipeline interstate natural gas pipeline, as well as natural gas gathering, processing
and treating, crude oil production handling, and NGL fractionation assets within the onshore, offshore shelf, and
7
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 9,800-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, 2019, Transco’s system, which extends from Texas to New York, had a system-wide delivery
capacity totaling approximately 17.4 MMdth/d. During 2019, Transco completed four fully-contracted expansions,
which added more than 0.6 MMdth of firm transportation capacity per day to our pipeline. Transco’s system includes
57 compressor stations, four underground storage fields, and one LNG storage facility. Compression facilities at sea
level-rated capacity total approximately 2.3 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 198 Bcf of natural gas.
At December 31, 2019, Transco’s customers had stored in its facilities approximately 140 Bcf of natural gas. Storage
capacity permits our customers to inject gas into storage during the summer and off-peak periods for delivery during
peak winter demand periods.
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 were
not subject to refund. In March 2019, the FERC accepted our motion to place the rates that were suspended by the
September 2018 order into effect on March 1, 2019, subject to refund. In October 2019, we reached an agreement on
the terms of a settlement with the participants that would resolve all issues in the rate case without the need for a hearing,
and on December 31, 2019, we filed a formal stipulation and agreement with the FERC setting forth such terms of the
settlement. We anticipate FERC approval of the stipulation and agreement in the second quarter of 2020. As of
December 31, 2019, we have provided a $189 million reserve for rate refunds related to increased rates collected since
March 2019, which we believe is adequate for any refunds that may be required.
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, 2019, 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 undivided 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-
8
party natural gas. These natural gas storage facilities enable Northwest Pipeline to balance daily receipts and deliveries
and provide storage services to customers.
Gas Transportation, Processing, and Treating Assets
The following tables summarize the significant operated assets of this segment:
Offshore Natural Gas Pipelines
Inlet
Capacity
(Bcf/d)
Pipeline
Miles
Ownership
Interest
Location
Supply Basins
Consolidated:
Canyon Chief, including
Blind Faith and
Gulfstar extensions ...... Deepwater Gulf of Mexico
Offshore shelf and other
Other Eastern Gulf...........
Seahawk........................... Deepwater Gulf of Mexico
Perdido Norte................... Deepwater Gulf of Mexico
Norphlet ........................... Deepwater Gulf of Mexico
Other Western Gulf ..........
Offshore shelf and other
156
46
115
105
58
103
Non-consolidated: (1)
Discovery.........................
Central Gulf of Mexico
594
0.5
0.2
0.4
0.3
0.3
0.4
0.6
100%
100%
100%
100%
100%
100%
Eastern Gulf of Mexico
Eastern Gulf of Mexico
Western Gulf of Mexico
Western Gulf of Mexico
Eastern Gulf of Mexico
Western Gulf of Mexico
60%
Western Gulf of Mexico
Consolidated:
Markham..........................
Mobile Bay ......................
Non-consolidated: (1)
Discovery...........................
Location
Markham, TX
Coden, AL
Larose, LA
Natural Gas Processing Facilities
NGL
Production
Capacity
(Mbbls/d)
Inlet
Capacity
(Bcf/d)
Ownership
Interest
Supply Basins
0.5
0.7
0.6
45
35
32
100%
100%
Western Gulf of Mexico
Eastern Gulf of Mexico
60%
Western Gulf of Mexico
_____________
(1) Includes 100 percent of the statistics associated with operated equity-method investments.
9
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
Consolidated:
Mountaineer, including Blind Faith and
Gulfstar extensions ....................................
BANJO ........................................................
Alpine ..........................................................
Perdido Norte...............................................
155
57
96
74
150
90
85
150
100%
100%
100%
100%
Eastern Gulf of Mexico
Western Gulf of Mexico
Western Gulf of Mexico
Western Gulf of Mexico
Production Handling Platforms
Gas Inlet
Capacity
(MMcf/d)
Crude/NGL
Handling
Capacity
(Mbbls/d)
Ownership
Interest
Supply Basins
Consolidated:
Devils Tower .................................................
Gulfstar I FPS (1) ..........................................
Non-consolidated: (2)
Discovery ......................................................
110
172
75
60
80
10
100%
51%
Eastern Gulf of Mexico
Eastern Gulf of Mexico
60%
Western Gulf of Mexico
__________
(1) Statistics reflect 100 percent of the assets from our 51 percent interest in Gulfstar One.
(2)
Includes 100 percent of the statistics associated with operated equity-method investments.
10
Transmission & Gulf of Mexico Operating Statistics
2019
2018
2017
Volumes:
Interstate natural gas pipeline throughput (Tbtu)..........................................
Gathering volumes (Bcf/d) - Consolidated ...................................................
Gathering volumes (Bcf/d) - Non-consolidated (1) ......................................
Plant inlet natural gas volumes (Bcf/d) - Consolidated ................................
Plant inlet natural gas volumes (Bcf/d) - Non-consolidated (1) ...................
NGL production (Mbbls/d) - Consolidated (2) .............................................
NGL production (Mbbls/d) - Non-consolidated (1) (2) ................................
NGL equity sales (Mbbls/d) - Consolidated (2)............................................
NGL equity sales (Mbbls/d) - Non-consolidated (1) (2)...............................
Crude oil transportation (Mbbls/d) - Consolidated (2) .................................
5,593
0.25
0.36
0.54
0.36
32
25
7
6
136
5,129
0.26
0.26
0.50
0.27
32
20
6
4
140
4,533
0.31
0.44
0.55
0.43
33
21
9
5
134
_____________
(1) Includes 100 percent of the volumes associated with operated 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 capacity of 10 Mbbls/d and gas handling and separation
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.
Northeast G&P
This segment includes our natural gas gathering, compression, processing, and NGL fractionation businesses in
the Marcellus and Utica Shale regions in Pennsylvania, West Virginia, New York, and Ohio.
Acquisition of UEOM and formation of Northeast JV
As of December 31, 2018, we owned a 62 percent interest in UEOM which we accounted for as an equity-method
investment. On March 18, 2019, we signed and closed the acquisition of the remaining 38 percent interest in UEOM.
Total consideration paid, including post-closing adjustments, was $741 million in cash funded through credit facility
borrowings and cash on hand. As a result of acquiring this additional interest, we obtained control of and now consolidate
UEOM. (See Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).
Concurrent with the UEOM acquisition, we executed an agreement whereby we contributed our consolidated
interests in UEOM and our Ohio Valley midstream business to a newly formed partnership. In June 2019, our partner
invested approximately $1.33 billion for a 35 percent ownership interest, and we retained 65 percent ownership of, as
well as operate and consolidate, the Northeast JV business.
11
The following tables summarize the significant operated assets of this segment:
Natural Gas Gathering Assets
Inlet
Location
Pipeline
Miles
Capacity Ownership
(Bcf/d)
Interest
Supply Basins
Consolidated:
Ohio Valley Midstream (1) ...........
Utica East Ohio Midstream (1) .....
Susquehanna Supply Hub .............
Cardinal (1) ...................................
Flint ...............................................
Beaver Creek.................................
Non-consolidated: (2)
Bradford Supply Hub ....................
Marcellus South ............................
Laurel Mountain............................
Ohio, West Virginia, &
Pennsylvania
Ohio
Pennsylvania & New York
Ohio
Ohio
Pennsylvania
216
53
451
365
95
41
Pennsylvania
Pennsylvania & West Virginia
Pennsylvania
726
306
2,053
0.8
0.4
4.3
0.9
0.5
0.1
3.7
0.9
0.7
65%
65%
100%
66%
100%
100%
66%
68%
69%
Appalachian
Appalachian
Appalachian
Appalachian
Appalachian
Appalachian
Appalachian
Appalachian
Appalachian
Natural Gas Processing Facilities
NGL
Inlet
Production
Capacity
Capacity
Ownership
Location
(Bcf/d)
(Mbbls/d)
Interest
Supply Basins
Consolidated:
Fort Beeler...................................
Oak Grove ...................................
Kensington ..................................
Leesville ......................................
_____________
(1) Statistics reflect 100 percent of the assets from our 65 percent ownership in our Northeast JV and 66 percent
Marshall County, WV
Marshall County, WV
Columbiana Co., OH
Carroll Co., OH
Appalachian
Appalachian
Appalachian
Appalachian
65%
65%
65%
65%
0.5
0.4
0.6
0.2
62
50
68
18
ownership of Cardinal gathering system.
(2) Includes 100 percent of the statistics associated with operated equity-method investments.
Other NGL Operations
We also own and operate fractionation facilities at Moundsville, West Virginia, 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. We also have an NGL pipeline that transports product from our Oak Grove plant to Harrison
County, Ohio.
We also own and operate 39 Mbbls/d of condensate stabilization capacity, a 135 Mbbls/d NGL fractionation facility,
approximately 970,000 barrels of NGL storage capacity, and other ancillary assets, including loading and terminal
facilities in Harrison County, Ohio.
12
Northeast G&P Operating Statistics
Volumes:
2019
2018
2017
Gathering (Bcf/d) - Consolidated (1).............................................................
Gathering (Bcf/d) - Non-consolidated (2)......................................................
Plant inlet natural gas (Bcf/d) - Consolidated (1) ..........................................
NGL production (Mbbls/d) (3) ......................................................................
4.24
4.29
1.04
76
3.63
3.76
0.52
46
3.31
3.55
0.43
38
__________
(1) Includes volumes associated with Susquehanna Supply Hub, the Northeast JV, and Utica Supply Hub, all of which
are consolidated.
(2) Includes 100 percent of the volumes associated with operated equity-method investments, including the Laurel
Mountain Midstream partnership; and the Bradford Supply Hub and a portion of the Marcellus South Supply Hub
within Appalachia Midstream Investments. Volumes handled by Blue Racer Midstream, LLC (Blue Racer),
(gathering and processing), which we do not operate, are not included.
(3) Annual average Mbbls/d.
Certain Equity-Method Investments
Laurel Mountain
We operate and own a 69 percent interest in a joint venture, Laurel Mountain, that includes a 2,053-mile gathering
system that we operate in western Pennsylvania with the capacity to gather 0.7 Bcf/d of natural gas. Laurel Mountain
has a long-term, dedicated, volumetric-based fee agreement, with exposure to natural gas prices, to gather the anchor
customer’s production in the western Pennsylvania area of the Marcellus Shale.
Caiman II
We own a 58 percent interest in third-party operated Caiman II, which owns a 50 percent interest in Blue Racer,
a joint venture 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 600 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.
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 1,032 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.)
13
West
Gas Gathering, Processing, and Treating Assets
The following tables summarize the significant operated assets of this segment:
Consolidated:
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
2,265
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%
(2)
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
Non-consolidated: (1)
Rocky Mountain
Midstream ..........................
Colorado
192
0.6
50%
Denver-Julesburg
____________
(1) Includes 100 percent of the statistics associated with an operated equity-method investment.
(2) 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.
Consolidated:
Echo Springs .......................
Opal.....................................
Willow Creek ......................
Parachute.............................
Non-consolidated: (1)
Fort Lupton .........................
Keenesburg I .......................
Location
Echo Springs, WY
Opal, WY
Rio Blanco County, CO
Garfield County, CO
Colorado
Colorado
Natural Gas Processing Facilities
Inlet
Capacity
(Bcf/d)
NGL
Production
Capacity
(Mbbls/d)
Ownership
Interest
Supply Basins
0.7
1.1
0.5
1.1
0.2
0.2
58
47
30
6
50
40
100%
100%
100%
100%
50%
50%
Wamsutter
Southwest Wyoming
Piceance
Piceance
Denver-Julesburg
Denver-Julesburg
____________
(1) Includes 100 percent of the statistics associated with operated equity-method investments.
14
Marketing Services
We market gas and 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 and RMM. The NGL marketing business bears the risk of price changes in
these NGL volumes while they are being transported to final sales delivery points. In order to meet sales contract
obligations, we may purchase products in the spot market for resale.
Other 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:
2019
2018
2017
Gathering (Bcf/d) - Consolidated...................................................................
Gathering (Bcf/d) - Non-consolidated (1)......................................................
Plant inlet natural gas (Bcf/d) - Consolidated................................................
Plant inlet natural gas (Bcf/d) - Non-consolidated (1)...................................
NGL production (Mbbls/d) - Consolidated (2) ..............................................
NGL production (Mbbls/d) - Non-consolidated (1) (2) .................................
NGL equity sales (Mbbls/d) - Consolidated (2).............................................
3.52
0.20
1.48
0.08
54
12
22
4.27
0.08
2.01
0.08
84
3
33
4.53
—
2.07
—
77
—
29
__________
(1) Includes 100 percent of the volumes associated with operated equity-method investments, including RMM and
Jackalope. Jackalope was a consolidated entity in 2017 and first- and second-quarter 2018, an equity-method
investment during third- and fourth-quarter 2018 as well as first-quarter 2019, and sold effective with second-
quarter 2019.
(2) Annual average Mbbls/d.
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. The system was comprised of 3,742 miles of gathering pipeline with 1.8 Bcf/d of
gas gathering inlet capacity and two processing facilities with a combined 0.7 Bcf/d of natural gas processing inlet
capacity and 41 Mbbls/d of NGL production capacity.
Certain Equity-Method Investments
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, 460 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 crude oil gathering and
natural gas processing business in Colorado’s Denver-Julesburg basin. As of December 31, 2019, we operate and own
50 percent of RMM. RMM includes an approximate 80-mile crude oil gathering system.
15
Overland Pass Pipeline
We also operate and own a 50 percent interest in OPPL. OPPL is capable of transporting 255 Mbbls/d of NGLs
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 our 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 transported on OPPL.
Jackalope
We previously owned and operated 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 6 –
Investing Activities of Notes to Consolidated Financial Statements). During the second quarter of 2019, we sold our
interest in Jackalope. Jackalope, which included the Bucking Horse gas processing plant, consisted 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.
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.
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.
Additional Business Segment Information
Revenues by service that exceeded 10 percent of consolidated revenues are presented in Note 2 – Revenue
Recognition of Notes to Consolidated Financial Statements.
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 and sales of
partial interests of our subsidiaries. The terms of 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.
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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 natural gas liquids pipelines that are regulated by various federal and state
governmental agencies. Services provided on our interstate natural gas liquids pipelines are subject to regulation under
the Interstate Commerce Act by the FERC, which has authority over the terms and conditions of service; rates, including
depreciation and amortization policies; and initiation of service. Our intrastate natural gas liquids pipelines providing
common carrier service are subject to regulation by various state regulatory agencies.
Pipeline Safety
Our gas pipelines are subject to the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety
Improvement Act of 2002, the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011 (Pipeline Safety
Act), and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016, which regulate safety
requirements in the design, construction, operation, and maintenance of interstate natural gas transmission facilities.
The United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA)
administers federal pipeline safety laws.
Federal pipeline safety laws authorize PHMSA to establish minimum safety standards for pipeline facilities and
persons engaged in the transportation of gas or hazardous liquids by pipeline. These safety standards apply to the design,
construction, testing, operation, and maintenance of gas and hazardous liquids pipeline facilities affecting interstate or
foreign commerce. PHMSA has also established reporting requirements for operators of gas and hazardous liquid
pipeline facilities, as well as provisions for establishing the qualification of pipeline personnel and requirements for
managing the integrity of gas transmission and distribution lines and certain hazardous liquid pipelines. To ensure
compliance with these provisions, PHMSA performs pipeline safety inspections and has the authority to initiate
enforcement actions.
Federal pipeline safety regulations contain an exemption that applies to gathering lines in certain rural locations.
A substantial portion of our gathering lines qualify for that exemption and are currently not regulated under federal
law.
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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 2020
associated with this program to be approximately $133 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 2020 associated
with this program will be approximately $2 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.
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 19 – 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
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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 19 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements.
Gas Pipeline Business
COMPETITION
The market for supplying natural gas is highly competitive and new pipelines, storage facilities, and other related
services are expanding to service the growing demand for natural gas. Additionally, pipeline capacity in many growing
natural gas supply basins is constrained causing competition to increase among pipeline companies as they strive to
connect those basins to major natural gas demand centers.
In our business, we predominately 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 our past success in working with regulators and the public, the position of our existing
infrastructure, established strategic long-term contracts, and the fact that our pipelines have numerous receipt and
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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 companies of varying size and financial capabilities, including 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.
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 expertise and 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, 2020, we had 4,812 full-time employees.
EMPLOYEES
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 www.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, Sustainability Report, 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.
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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:
• Availability of supplies, market demand, and volatility of prices;
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• Development and rate of adoption of alternative energy sources;
• The impact of existing and future laws and regulations, the regulatory environment, environmental liabilities,
and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate
proceeding outcomes;
• Our exposure to the credit risk of our customers and counterparties;
• 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;
• Whether we are able to successfully identify, evaluate, and timely execute our capital projects and
investment opportunities;
• The strength and financial resources of our competitors and the effects of competition;
• The amount of cash distributions from and capital requirements of our investments and joint ventures in
which we participate;
• Whether we will be able to effectively execute our financing plan;
•
Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social
and governance practices;
• The physical and financial risks associated with climate change;
• The impact of operational and developmental hazards and unforeseen interruptions;
• Risks associated with weather and natural phenomena, including climate conditions and physical damage to
our facilities;
• Acts of terrorism, cybersecurity incidents, and related disruptions;
• 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;
•
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);
• 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;
• Changes in the current geopolitical situation;
• Whether we are able to pay current and expected levels of dividends;
• Additional risks described in our filings with the Securities and Exchange Commission.
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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.
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 have, and may continue to, adversely affect the development and production
of existing or additional natural gas reserves and the installation of gathering, storage, and pipeline transportation
facilities. The import and export of natural gas supplies may also be affected by such conditions. Low natural gas prices
in one or more of our existing supply basins, whether caused by a lack of infrastructure or otherwise, could also result
in depressed natural gas production in such basins and limit the supply of natural gas made available to us. The
competition for natural gas supplies to serve other markets could also reduce the amount of natural gas supply for our
customers. A failure to obtain access to sufficient natural gas supplies will adversely impact our ability to maximize
the capacities of our gathering, transportation, and processing facilities.
Demand for our services is dependent on the demand for gas in the markets we serve. Alternative fuel sources
such as electricity, coal, fuel oils, or nuclear energy, as well as technological advances and renewable sources of energy,
could reduce demand for natural gas in our markets and have an adverse effect on our business.
A failure to obtain access to sufficient natural gas supplies or a reduction in demand for our services in the markets
we serve could result in impairments of our assets and have a material adverse effect on our business, financial condition,
results of operations, and cash flows.
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Prices for natural gas, NGLs, oil, and other commodities, are volatile and this volatility has and could continue to
adversely affect our financial results, cash flows, access to capital, and ability to maintain our existing businesses.
Our revenues, operating results, future rate of growth, and the value of certain components of our businesses
depend primarily upon the prices of natural gas, NGLs, oil, or other commodities, and the differences between prices
of these commodities and could be materially adversely affected by an extended period of 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
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, are required to make prepayments or provide security to satisfy credit concerns or are dependent
upon us, in some cases without a readily available alternative, to provide necessary services. 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 have been or could be negatively impacted, causing them
significant economic stress resulting, in some cases, in a customer bankruptcy filing or an effort to renegotiate our
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, if we so
agree, 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
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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.
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;
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• 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.
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;
• 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.
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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.
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
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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.
Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social and
governance practices may impose additional costs on us or expose us to new or additional risks.
Companies across all industries are facing increasing scrutiny from stakeholders related to their environmental,
social and governance (“ESG”) practices. Investor advocacy groups, certain institutional investors, investment funds
and other influential investors are also increasingly focused on ESG practices and in recent years have placed increasing
importance on the implications and social cost of their investments. Regardless of the industry, investors’ increased
focus and activism related to ESG and similar matters may hinder access to capital, as investors may decide to reallocate
capital or to not commit capital as a result of their assessment of a company’s ESG practices. Companies which do not
adapt to or comply with investor or stakeholder expectations and standards, which are evolving, or which are perceived
to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal
requirement to do so, may suffer from reputational damage and the business, financial condition, and/or stock price of
such a company could be materially and adversely affected.
We face pressures from our stockholders, who are increasingly focused on climate change, to prioritize sustainable
energy practices, reduce our carbon footprint and promote sustainability. Our stockholders may require us to implement
ESG procedures or standards in order to remain invested in us or before they may make further investments in us.
Additionally, we may face reputational challenges in the event our ESG procedures or standards do not meet the
standards set by certain constituencies. We have adopted certain practices as highlighted in our 2018 Sustainability
Report, including with respect to air emissions, biodiversity and land use, climate change and environmental
stewardship. It is possible, however, that our stockholders might not be satisfied with our sustainability efforts or the
speed of their adoption. If we do not meet our stockholders’ expectations, our business, ability to access capital, and/
or our stock price could be harmed.
Additionally, adverse effects upon the oil and gas industry related to the worldwide social and political environment,
including uncertainty or instability resulting from climate change, changes in political leadership and environmental
policies, changes in geopolitical-social views toward fossil fuels and renewable energy, concern about the environmental
impact of climate change and investors’ expectations regarding ESG matters, may also adversely affect demand for
our services. Any long-term material adverse effect on the oil and gas industry could have a significant financial and
operational adverse impact on our business.
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The occurrence of any of the foregoing could have a material adverse effect on the price of our stock and our
business and financial condition.
We may be subject to physical and financial risks associated with climate change.
The threat of global climate change may create physical and financial risks to our business. Energy needs vary
with weather conditions. To the extent weather conditions may be affected by climate change, energy use could increase
or decrease depending on the duration and magnitude of any changes. Increased energy use due to weather changes
may require us to invest in more pipelines and other infrastructure to serve increased demand. A decrease in energy
use due to weather changes may affect our financial condition through decreased revenues. Extreme weather conditions
in general require more system backup, adding to costs, and can contribute to increased system stresses, including
service interruptions. Weather conditions outside of our operating territory could also have an impact on our revenues.
To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. We
may not be able to pass on the higher costs to our customers or recover all costs related to mitigating these physical
risks.
Additionally, many climate models indicate that global warming is likely to result in rising sea levels and increased
frequency and severity of weather events, which may lead to higher insurance costs, or a decrease in available coverage,
for our assets in areas subject to severe weather. These climate-related changes could damage our physical assets,
especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone
and rain-susceptible regions.
To the extent financial markets view climate change and greenhouse gas (“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. Our business could also be affected by the potential for lawsuits against GHG emitters, based
on links drawn between GHG emissions and climate change.
Our operations are subject to operational hazards and unforeseen interruptions.
There are operational risks associated with the gathering, transporting, storage, processing, and treating of natural
gas, the fractionation, transportation, and storage of NGLs, and crude oil transportation and production handling,
including:
• Aging infrastructure and mechanical problems;
• Damages to pipelines and pipeline blockages or other pipeline interruptions;
• Uncontrolled releases of natural gas (including sour gas), NGLs, crude oil, or other products;
• Collapse or failure of storage caverns;
• Operator error;
• Damage caused by third-party activity, such as operation of construction equipment;
• Pollution and other environmental risks;
• Fires, explosions, craterings, and blowouts;
• Security risks, including cybersecurity;
• Operating in a marine environment.
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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
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
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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.
We were the target of a proxy contest from a stockholder activist, which resulted in our incurring significant costs.
If stockholder activists were to again take or threaten to take actions against the Company or seek to involve themselves
in the governance, strategic direction or operations of the Company, we could incur significant costs as well as the
distraction of management, which could have an adverse effect on our business or financial results. In addition, actions
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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 and other postretirement benefit plans. 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, the
challenges of attracting new, qualified workers to the midstream energy industry, 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.
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.
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
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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.
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, 2019, was $22.3 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.
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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.
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 15 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements.
Changes to interest rates or increases in interest rates could adversely impact our access to credit, share price, our
ability to issue securities 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
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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 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.
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;
• Accounts and records;
• Depreciation and amortization policies;
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• 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.
Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate
change and greenhouse gas emissions, which may expose us to significant costs, liabilities, and expenditures that
could exceed our expectations.
Our operations are subject to extensive federal, state, tribal, and local laws and regulations governing environmental
protection, endangered and threatened species, the discharge of materials into the environment, and the security of
industrial facilities. Substantial costs, liabilities, delays, and other significant issues related to environmental laws and
regulations are inherent in the gathering, transportation, storage, processing, and treating of natural gas, fractionation,
transportation, and storage of NGLs, and crude oil transportation and production handling as well as waste disposal
practices and construction activities. Failure to comply with these laws, regulations, and permits may result in the
assessment of administrative, civil and/or criminal penalties, the imposition of remedial obligations, the imposition of
stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our
operations, and delays or denials in granting permits.
Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and
regulations, for the remediation of contaminated areas and in connection with spills or releases of materials associated
with natural gas, oil, and wastes on, under or from our properties and facilities. Private parties, including the owners
of properties through which our pipeline and gathering systems pass and facilities where our wastes are taken for
reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages
for noncompliance with environmental laws and regulations or for personal injury or property damage arising from
our operations. Some sites at which we operate are located near current or former third-party hydrocarbon storage and
processing or oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those
sites to ours.
We are generally responsible for all liabilities associated with the environmental condition of our facilities and
assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown.
In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification
against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In
addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively
expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause
us to incur losses.
In addition, climate change regulations and the costs associated with the regulation of emissions of greenhouse
gases 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. We believe
it is possible that future governmental legislation and/or regulation may require us either to limit GHG emissions
associated with our operations or to purchase allowances for such emissions. However, we cannot predict precisely
what form these future regulations might take, the stringency of any such regulations or when they might become
effective. Several legislative bills have been introduced in the United States Congress that would require carbon dioxide
emission reductions. Previously considered proposals have included, among other things, limitations on the amount of
GHGs that can be emitted (so called “caps”) together with systems of permitted emissions allowances. These proposals
could require us to reduce emissions or to purchase allowances for such emissions.
36
In addition to activities on the federal level, state and regional initiatives could also lead to the regulation of GHG
emissions sooner than and/or independent of federal regulation. These regulations could be more stringent than any
federal legislation that may be adopted. Future legislation and/or regulation designed to reduce GHG emissions could
make some of our activities uneconomic to maintain or operate. We continue to monitor legislative and regulatory
developments in this area and otherwise take efforts to limit and reduce GHG emissions from our facilities. Although
the regulation of GHG emissions may have a material impact on our operations and rates, we believe it is premature
to attempt to quantify the potential costs of the impacts.
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.
Item 1B. Unresolved Staff Comments
Not applicable.
Item 2. Properties
Please read “Business” for a description of the location and general character of our principal physical properties.
We generally own our facilities, although a substantial portion of our pipeline and gathering facilities is constructed
and maintained pursuant to rights-of-way, easements, permits, licenses, or consents on and across properties owned by
others.
Item 3. Legal Proceedings
Environmental
Certain reportable legal proceedings involving governmental authorities under federal, state, and local laws
regulating the discharge of materials into the environment are described below. While it is not possible for us to predict
the final outcome of the proceedings which are still pending, we do not anticipate a material effect on our consolidated
financial position if we receive an unfavorable outcome in any one or more of such proceedings.
On June 13, 2013, an explosion and fire occurred at our formerly owned Geismar olefins plant and rendered the
facility temporarily inoperable (Geismar Incident). On October 21, 2013, the EPA, 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. We have worked with the agency to resolve these
matters and in the second half of 2019, entered into a Stipulation of Settlement, which includes a penalty of $750,000
that will be due within thirty days of the Court’s entry of the settlement. The Court set a fairness hearing on the settlement
for December 11, 2019. Prior to the scheduled hearing, the Court continued the hearing without setting a new date.
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 a Corrective Action Plan.
On January 19, 2016, we received a Notice of Noncompliance with certain Leak Detection and Repair (LDAR)
regulations under the Clean Air Act at our Moundsville Fractionator Facility from the EPA, Region 3. Subsequently,
the EPA alleged similar violations of certain LDAR regulations at our Oak Grove Gas Plant. On March 19, 2018, we
received a Notice of Violation of certain LDAR regulations at our former Ignacio Gas Plant from the EPA, Region 8,
following an on-site inspection of the facility. On March 20, 2018, we also received a Notice of Violation of certain
LDAR regulations at our Parachute Creek Gas Plant from the EPA, Region 8. All Notices were subsequently referred
to a common attorney at the Department of Justice (DOJ). We are exploring global resolution of the claims at these
facilities, as well as alleged violations at certain other facilities, with the DOJ. Global resolution would include both
37
payment of a civil penalty and an injunctive relief component. We continue to work with the DOJ and the other agencies
to resolve these claims, whether individually or globally, and negotiations are ongoing.
Other environmental matters called for by this Item are described under the caption “Environmental Matters” in
Note 19 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements included under
Part II, Item 8 Financial Statements of this report, which information is incorporated by reference into this Item.
Other litigation
The additional information called for by this Item is provided in Note 19 – 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.
38
Information About Our Executive Officers
The name, title, age, period of service, and recent business experience of each of our executive officers as of
February 24, 2020, are listed below.
Name and Position
Alan S. Armstrong
Director, Chief Executive Officer, and
President
Age
Business Experience in Past Five Years
57
2011 to present
Director, Chief Executive Officer, and President, The
2015 to 2018
Williams Companies, Inc.
Chairman of the Board, WPZ
2014 to 2018
Chief Executive Officer, WPZ
2012 to 2018
Director of the general partner, WPZ
Walter J. Bennett
50
2020 to present
Senior Vice President Gathering &
Processing
2015 to 2019
2013 to 2018
2017
Senior Vice President Gathering & Processing, The
Williams Companies, Inc.
Senior Vice President – West, The Williams
Companies, Inc.
Senior Vice President – West of the general partner,
WPZ
Director of the general partner, WPZ
John D. Chandler
50
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
42
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, 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
54
2017 to present
Executive Vice President and Chief Operating Officer,
2017 to 2018
2015 to 2016
2010 to 2015
The Williams Companies, Inc.
Director of the general partner, WPZ
President / Executive Vice President, Questar
Pipeline / Questar Corporation
President and Chief Executive Officer, PacifiCorp
Energy
Scott A. Hallam
43
2020 to present
Senior Vice President Transmission & Gulf of
Senior Vice President Transmission &
Gulf of Mexico
2019
Senior Vice President – Atlantic-Gulf, The Williams
Mexico, The Williams Companies, Inc.
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
54
2020 to present
Senior Vice President Project Execution, The
Williams Companies, Inc.
Senior Vice President Project Execution
2017 to 2019
Senior Vice President – Engineering Services, The
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
39
Name and Position
John D. Porter
Age
Business Experience in Past Five Years
50
2020 to present
Vice President, Controller, and Chief Accounting
Officer, The Williams Companies, Inc.
Vice President, Controller, and Chief
Accounting Officer
2017 to 2019
Vice President Enterprise Financial Planning &
Analysis and Investor Relations, The Williams
Companies
T. Lane Wilson
53
2017 to present
Senior Vice President and General Counsel, The
2013 to 2017
Director of Investor Relations & Enterprise Planning
Senior Vice President, General Counsel
2009 to 2017
Chad J. Zamarin
43
2017 to present
Williams Companies, Inc.
United States Magistrate Judge for the Northern
District of Oklahoma
Senior Vice President – Corporate Strategic
Development, The Williams Companies, Inc.
Senior Vice President – Corporate
Strategic Development
2017 to 2018
Director of the general partner, WPZ
2014 to 2017
President – Pipeline and Midstream, Cheniere Energy
40
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Our common stock is listed on the New York Stock Exchange under the symbol “WMB.” At the close of business
on February 19, 2020, we had 6,512 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, the Bloomberg
Americas Pipelines Index, and the Arca Natural Gas Index for the period of five fiscal years commencing January 1,
2015. The Bloomberg Americas Pipelines Index is composed of Enbridge Inc., Kinder Morgan, Inc., TC Energy
Corporation, ONEOK, Inc., Pembina Pipeline Corporation, Cheniere Energy, Inc., Targa Resources Corp., Inter Pipeline
Ltd., and Williams. The Arca Natural Gas Index is comprised of over 20 highly capitalized companies in the natural
gas industry involved primarily in natural gas exploration and production and natural gas pipeline transportation and
transmission. The graph below assumes an investment of $100 at the beginning of the period.
The Williams Companies, Inc................
S&P 500 Index .......................................
Bloomberg Americas Pipelines Index....
Arca Natural Gas Index .........................
2014
100.0
100.0
100.0
100.0
2015
60.8
101.4
55.0
61.0
2016
79.8
113.5
80.7
89.7
2017
81.5
138.3
80.5
76.3
2018
62.0
132.2
69.0
52.1
2019
70.8
173.8
93.4
51.5
41
Item 6. Selected Financial Data
The following financial data at December 31, 2019 and 2018, and for each of the three preceding years in the
period ended December 31, 2019, 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 .............................................................................. $
Income (loss) from continuing operations (1)......................
Amounts attributable to The Williams Companies, Inc.
available to common stockholders:
Income (loss) from continuing operations (2) ...................
Diluted income (loss) from continuing operations per
common share ................................................................
Total assets at December 31 .................................................
Commercial paper, lease liabilities, and long-term debt
Year Ended December 31,
2019
2018
2017
2016
2015
(Millions, except per-share amounts)
$ 7,499
$ 8,031
$ 8,686
(350)
2,509
193
8,201
729
$ 7,360
(1,314)
862
(156)
2,174
(424)
(571)
.71
46,040
(.16)
45,302
2.62
46,352
(.57)
46,835
(.76)
49,020
22,497
(including current portions) at December 31....................
13,363
Stockholders’ equity at December 31 (3).............................
Cash dividends declared per common share ........................
1.52
Diluted weighted-average shares outstanding (thousands) .. 1,214,011
22,414
14,660
1.36
973,626
20,935
9,656
1.20
828,518
23,502
4,643
1.68
750,673
24,487
6,148
2.45
749,271
_________
(1)
Income (loss) from continuing operations:
• For 2019 includes $464 million of impairments of certain assets, including a $354 million impairment of
Constitution’s capitalized project costs, and $186 million impairments of certain equity-method investments,
partially offset by a $122 million gain on the sale of our Jackalope equity-method investment;
• 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 and 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.
(2)
Income (loss) from continuing operations attributable to the Williams Companies, Inc. available to common
stockholders:
• For 2019 includes benefit of $209 million reflecting the noncontrolling interests’ share of the impairment of
Constitution’s capitalized project costs.
(3) Stockholders’ equity at December 31:
• For 2019 includes a decrease related to a sale of a partial interest in our Northeast JV business;
• For 2018 includes an increase reflecting our issuance of common stock associated with our merger with WPZ
in August 2018;
• For 2017 includes increases reflecting our issuance of common stock as part of our Financial Repositioning
and a significant increase in our ownership of WPZ.
42
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, crude oil and natural gas, as well as storage facilities.
As of December 31, 2019, our operations are presented within the following reportable segments: Atlantic-Gulf,
Northeast G&P, and West, consistent with the manner in which our chief operating decision maker evaluates performance
and allocates resources. All remaining business activities as well as corporate activities are included in Other. Our
reportable segments are comprised of the following businesses:
• Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transco, and 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 variable interest entity), which is a proprietary floating
production system, as well as a 50 percent equity-method investment in Gulfstream, a 60 percent equity-
method investment in Discovery, and a 41 percent equity-method investment in Constitution as of December
31, 2019.
• Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the
Marcellus Shale region primarily in Pennsylvania, New York, and the Utica Shale region of eastern Ohio, as
well as a 65 percent interest in our Northeast JV (a consolidated variable interest entity) which operates in
West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated variable interest entity)
which operates in Ohio, 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).
• West is comprised of our interstate natural gas pipeline, Northwest Pipeline, and our gas gathering, processing,
and treating operations in the Rocky Mountain region of Colorado and Wyoming, 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, a 50 percent equity-method investment in
OPPL, a 50 percent equity-method investment in RMM, and a 15 percent equity-method investment in Brazos
Permian II. West also included our former natural gas gathering and processing assets in the Four Corners
area of New Mexico and Colorado, which were sold during the fourth quarter of 2018 (see Note 3 – Acquisitions
and Divestitures of Notes to Consolidated Financial Statements), and our former 50 percent interest in Jackalope
(an equity-method investment following deconsolidation as of June 30, 2018), which was sold in April 2019,
43
and our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system
(DBJV) (see Note 6 – Investing Activities of Notes to Consolidated Financial Statements).
• Other includes minor business activities that are not operating segments, as well as corporate operations. Other
also 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 – Acquisitions and
Divestitures of Notes to Consolidated Financial Statements), and a refinery grade propylene splitter in the
Gulf region, which was sold in June 2017.
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. Effective January 1, 2020, the composition
of our reportable segments changed (see Part I, Item I Business Segments for further discussion).
Dividends
In December 2019, we paid a regular quarterly dividend of $0.38 per share. On January 28, 2020, our board of
directors approved a regular quarterly dividend of $0.40 per share payable on March 30, 2020.
Overview
Net income (loss) attributable to The Williams Companies, Inc., for the year ended December 31, 2019, increased
$1.005 billion compared to the year ended December 31, 2018, reflecting:
• A $1.451 billion decrease in Impairment of certain assets;
• A $431 million increase in Service revenues primarily associated with Transco expansion projects, the
consolidation of UEOM beginning March 2019, and growth in Northeast G&P volumes, partially offset by
lower revenues from our Barnett Shale operations primarily associated with the reduced recognition of deferred
revenue and the end of a contractual MVC period, as well as the absence of revenues from operations sold or
deconsolidated during 2018;
• A $484 million decrease to Net income (loss) attributable to noncontrolling interests primarily due to the WPZ
Merger in the third quarter of 2018, as well as the noncontrolling interests’ share of the 2019 Constitution
impairment.
These favorable changes were partially offset by:
• A $694 million decrease in the Gain on sale of certain assets and businesses primarily related to the sale of
the Four Corners area business in the fourth quarter of 2018;
• A $266 million decrease in Other investing income (loss) – net primarily due to the absence of 2018 gains on
deconsolidations and 2019 impairments of equity-method investments, partially offset by a 2019 gain on the
sale of our interest in Jackalope;
•
•
•
$138 million of lower commodity margins;
$74 million of higher net interest expense;
$58 million lower allowance for equity funds used during construction (AFUDC);
• A $197 million increase in provision for income taxes driven by higher pre-tax income, partially offset by the
absence of a 2018 charge to establish a valuation allowance on deferred tax assets that may not be realized
following the WPZ merger.
44
Acquisition of UEOM
As of December 31, 2018, we owned a 62 percent interest in UEOM which we accounted for as an equity-method
investment. On March 18, 2019, we signed and closed the acquisition of the remaining 38 percent interest in UEOM.
Total consideration paid, including post-closing adjustments, was $741 million in cash funded through credit facility
borrowings and cash on hand. As a result of acquiring this additional interest, we obtained control of and now consolidate
UEOM. (See Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements.)
Northeast JV
Concurrent with the UEOM acquisition, we executed an agreement whereby we contributed our consolidated
interests in UEOM and our Ohio Valley midstream business to a newly formed partnership. In June 2019, our partner
invested approximately $1.33 billion for a 35 percent ownership interest, and we retained 65 percent ownership of, as
well as operate and consolidate, the Northeast JV business. (See Note 3 – Acquisitions and Divestitures of Notes to
Consolidated Financial Statements.)
Sale of Jackalope
In April 2019, we sold our 50 percent equity-method interest in Jackalope for $485 million in cash, resulting in a
gain on the disposition of $122 million. (See Note 6 – Investing Activities of Notes to Consolidated Financial Statements.)
Constitution
Although Constitution received a certificate of public convenience and necessity from the FERC to construct and
operate the proposed pipeline and obtained, among other approvals, a waiver of the water quality certification under
Section 401 of the Clean Water Act for the New York portion of the project, the members of Constitution, following
extensive evaluation and discussion, recently determined that the underlying risk-adjusted return for this greenfield
pipeline project has diminished in such a way that further development is no longer supported. (See Note 4 – Variable
Interest Entities of Notes to Consolidated Financial Statements for further discussion.)
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
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 have expanded the inlet processing capacity of our Oak Grove facility to 400 MMcf/d. We have also constructed
a new NGL pipeline from Moundsville to the Harrison Hub fractionation facility to provide an additional outlet
for NGLs. These expansions are supported by long-term, fee-based agreements and volumetric commitments.
Susquehanna Supply Hub Expansion
In November 2019, we completed a 500 MMcf/d expansion of the gathering systems in the Susquehanna
Supply Hub to bring the capacity to approximately 4.3 Bcf/d.
Atlantic-Gulf
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
45
Jersey. The project was placed into partial service in July 2019. The remaining portion of the project was placed
into service in September 2019. The full project increased capacity by 190 Mdth/d.
Norphlet Project
In March 2016, we announced that we reached an agreement to provide deepwater gas gathering services to
the Appomattox development in the Gulf of Mexico. We completed modifications to install an alternate delivery
route to our Main Pass 261 Platform, as well as modifications to our onshore Mobile Bay processing facility. The
project went in service early in July 2019, at which time we also purchased a 54-mile-long, 16-inch-diameter
pipeline (the Norphlet Pipeline) for $200 million. This pipeline transports gas from the Appomattox development
to our Main Pass 261 Platform.
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. The project was placed into service in December 2019 and increased capacity by 65 Mdth/d.
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.
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. The project was placed into service in November 2019. The
project increased delivery capacity by approximately 159 Mdth/d.
Wamsutter Expansion
We have expanded our gathering and processing infrastructure in the Wamsutter region of Wyoming in order
to meet our customers’ production plans. We have completed construction of new compressor stations and
modifications to our processing facilities, which were placed into service throughout 2019. The expansion added
approximately 20 miles of gathering pipelines and approximately 15,000 horsepower of compression.
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 were
not subject to refund. In March 2019, the FERC accepted our motion to place the rates that were suspended by the
September 2018 order into effect on March 1, 2019, subject to refund. In October 2019, we reached an agreement on
the terms of a settlement with the participants that would resolve all issues in the rate case without the need for a hearing,
and on December 31, 2019, we filed a formal stipulation and agreement with the FERC setting forth such terms of
settlement. We anticipate FERC approval of the stipulation and agreement in the second quarter of 2020. As of
December 31, 2019, we have provided a $189 million reserve for rate refunds related to increased rates collected since
March 2019, which we believe is adequate for any refunds that may be required.
46
Commodity Prices
NGL per-unit margins were approximately 44 percent lower in 2019 compared to 2018 primarily due to a 31 percent
and a 44 percent decrease in per-unit non-ethane and ethane sales prices, respectively, slightly offset by an approximate
10 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 2020 includes a continued focus on earnings and cash flow growth, while continuing to
improve leverage metrics and control operating costs. Many of our producer customers are being impacted by extremely
low natural gas and NGL prices, which are driving decreased drilling. We are responding by reducing the pace of our
capital growth spending in our gathering and processing business and remaining committed to operating cost discipline.
In 2020, our operating results are expected to include increases from Transco’s recent expansion projects placed
in-service and general rate settlement as previously discussed. We also expect an increase from a full year contribution
from the Norphlet project, partially offset by lower deferred revenue amortization from Gulfstar, both in the Eastern
Gulf region. Northeast results are expected to increase from higher gathering and processing volumes.We expect
decreases in the West primarily due to lower deferred revenue amortization in the Barnett Shale and lower revenues
from our Haynesville operations, partially offset by increased results from our DJ Basin and Eagle Ford operations.
Additionally, we expect our recently implemented organizational realignment will benefit our expenses.
Our growth capital and investment expenditures in 2020 are expected to be in a range from $1.1 billion to $1.3
billion. Growth capital spending in 2020 primarily includes Transco expansions, all of which are fully contracted with
firm transportation agreements, and our Bluestem NGL pipeline project in the Mid-Continent region. 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.
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;
• Counterparty credit and performance risk;
• Unexpected significant increases in capital expenditures or delays in capital project execution;
• Unexpected changes in customer drilling and production activities, which could negatively impact gathering
and processing volumes;
47
• 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 downturns, 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.
Expansion Projects
Our ongoing major expansion projects include the following:
Atlantic-Gulf
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. Phase I was completed in 2017 and it 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.
Northeast Supply Enhancement
In May 2019, we received approval from 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. Approvals required for the project from the New York State Department
of Environmental Conservation and the New Jersey Department of Environmental Protection remain pending,
with each such agency having denied, without prejudice, Transco’s applications for such approvals. We have refiled
our applications for those approvals and have addressed the technical issues identified by the agencies. We plan
to place the project into service in the fall of 2021, assuming timely receipt of these remaining approvals. The
project is expected to increase capacity by 400 Mdth/d.
Southeastern Trail
In October 2019, we received approval from 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. The project is expected to increase capacity by 296 Mdth/d.
Leidy South
In July 2019, we filed an application with the FERC for approval of the project to expand Transco’s existing
natural gas transmission system and also extend its system through a capacity lease with National Fuel Gas Supply
Corporation that will enable us to provide incremental firm transportation from Clermont, Pennsylvania and from
the Zick interconnection on Transco’s Leidy Line to the River Road regulating station in Lancaster County,
Pennsylvania. We plan to place the project into service as early as the fourth quarter of 2021, assuming timely
receipt of all necessary regulatory approvals. The project is expected to increase capacity by 582 Mdth/d.
48
West
Project Bluestem
We are expanding our presence in the Mid-Continent region through building a 188-mile NGL pipeline from
our fractionator near 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, during the first quarter of 2019, we exercised 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, 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.
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 ....................................
Other postretirement benefits:
Discount rate ......................................................................
Expected long-term rate of return on plan assets................
(2) $
(12)
12
1
(2)
(Millions)
$
4
12
(10)
2
2
(102) $
—
71
(23)
—
120
—
(60)
28
—
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.
49
Our expected long-term rate of return on plan assets used for our pension plans was 5.26 percent in 2019. The
2019 actual return on plan assets for our pension plans was approximately 19.0 percent. The 10-year average rate of
return on pension plan assets through December 2019 was approximately 8.1 percent. 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 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.
Equity-Method Investments
We continue to monitor our equity-method investments for any indications that the carrying value may have
experienced an other-than-temporary decline in value. When evidence of a loss in value has occurred, we compare our
estimate of the fair value of the investment to the carrying value of the investment to determine whether an impairment
has occurred. We generally estimate the fair value of our investments using an income approach where significant
judgments and assumptions include expected future cash flows and the appropriate discount rate. We also utilize a form
of market approach to estimate the fair value of our investments. During 2019, we recognized impairments totaling
$186 million related to our equity-method investments. (See Note 18 – Fair Value Measurements, Guarantees, and
Concentration of Credit Risk of Notes to Consolidated Financial Statements.)
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, 2019. The results of operations by segment are discussed in further detail following this consolidated
overview discussion.
Year Ended December 31,
$ Change
from
2018*
% Change
from
2018*
2019
2018
(Millions)
$ Change
from
2017*
% Change
from
2017*
2017
Revenues:
Service revenues .......................................... $ 5,933
Service revenues – commodity
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 and
businesses ................................................
Regulatory charges resulting from Tax
Reform .....................................................
Other (income) expense – net ......................
Total costs and expenses..........................
Operating income (loss)...................................
Equity earnings (losses)...................................
Other investing income (loss) – net .................
Interest expense ...............................................
Other income (expense) – net ..........................
Income (loss) from continuing operations
before income taxes .....................................
Provision (benefit) for income taxes................
Income (loss) from continuing operations.......
Income (loss) from discontinued operations....
Net income (loss).........................................
Less: Net income (loss) attributable to
noncontrolling interests .........................
203
2,065
8,201
1,961
105
1,468
1,714
558
464
2
—
8
6,280
1,921
375
(79)
(1,186)
33
1,064
335
729
(15)
714
Net income (loss) attributable to The
Williams Companies, Inc......................... $
850
+431
-197
-719
+746
+32
+39
+11
+11
+1,451
-694
-17
+59
-21
-266
-74
-59
+8% $ 5,502
-49%
-26%
+28%
+23%
+3%
+1%
+2%
+76%
400
2,784
8,686
2,707
137
1,507
1,725
569
1,915
NM
(692)
-100%
+88%
(17)
67
7,918
768
396
-5%
NM
187
-7% (1,112)
92
-64%
+190
+400
+65
-407
-137
+69
+11
+25
-667
-403
+691
+4
-38
-95
-29
+117
+4% $ 5,312
NM
+2%
-18%
NM
+4%
+1%
+4%
-53%
—
2,719
8,031
2,300
—
1,576
1,736
594
1,248
-37% (1,095)
NM
+6%
674
71
7,104
927
434
-9%
-34%
282
-3% (1,083)
(25)
NM
-197
-143%
-15
NM
(136)
+484
NM
331
138
193
—
193
348
-2,112
NM
—
—%
535
(1,974)
2,509
—
2,509
-13
-4%
335
$
(155)
$ 2,174
_______
* + = 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.
51
2019 vs. 2018
Service revenues increased primarily due to higher transportation fee revenues at Transco associated with expansion
projects placed in service in 2019 and 2018, as well as the impact of the consolidation of UEOM, higher Northeast
volumes at the Susquehanna Supply Hub and Ohio Valley Midstream regions, and higher gathering rates and volumes
at the Utica Shale region. These increases are partially offset by the absence of revenues associated with asset divestitures
and deconsolidations during 2018, including our former Four Corners area operations, as well as lower revenue in the
Barnett Shale associated with the end of a contractual MVC period and lower revenue at Gulfstar primarily associated
with producer operational issues.
Service revenues – commodity consideration decreased due to lower NGL prices and lower volumes primarily due
to the absence of our former Four Corners area operations. These revenues represent consideration we receive in the
form of commodities as full or partial payment for processing services provided. Most of these NGL volumes are sold
within the month processed and therefore are offset in Product costs below.
Product sales decreased primarily due to lower NGL and natural gas prices associated with our marketing and
equity NGL sales activities, lower volumes from our equity NGL sales primarily reflecting the absence of our former
Four Corners area operations, and lower system management gas sales, partially offset by higher marketing volumes.
Marketing sales and system management gas sales are substantially offset in Product costs.
Product costs decreased primarily due to lower NGL and natural gas prices associated with our marketing and
equity NGL production activities. This decrease also includes lower volumes acquired as commodity consideration for
NGL processing services reflecting the absence of our former Four Corners area operations and lower system
management gas purchases, partially offset by higher volumes for marketing activities.
Processing commodity expenses decreased primarily due to lower production of equity NGLs primarily related to
ethane rejection and the absence of our former Four Corners area operations, and lower prices for natural gas purchases
associated with our NGL production.
Operating and maintenance expenses decreased primarily due to the absence of our former Four Corners area
operations and lower contracted services at Transco primarily due to the timing of required engine overhauls and
integrity testing. These decreases are partially offset by the impact of the consolidation of UEOM and by a $32 million
charge for severance and related costs primarily associated with a voluntary separation program (VSP) in 2019.
Depreciation and amortization expenses decreased primarily due to the 2018 impairment of certain assets in the
Barnett Shale region and the absence of assets disposed including our former Four Corners area operations, partially
offset by new assets placed in service and by the impact of the consolidation of UEOM.
Selling, general, and administrative expenses decreased primarily due to the absences of a charitable contribution
of preferred stock to the Williams Foundation, Inc. (see Note 16 – Stockholders' Equity of Notes to Consolidated
Financial Statements) and fees associated with the WPZ Merger, partially offset by a $25 million charge for severance
and related costs primarily associated with our 2019 VSP, and transaction expenses associated with the acquisition of
UEOM and the formation of the Northeast JV.
Impairment of certain assets includes 2019 impairments of our Constitution development project, certain Eagle
Ford Shale gathering assets, and certain assets that may no longer be in use or are surplus in nature. Asset impairments
in 2018 included certain assets in the Barnett Shale region and certain idle pipelines (see Note 18 – Fair Value
Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
Gain on sale of certain assets and businesses includes gains recognized on the sales of our Four Corners area and
our Gulf Coast pipeline systems in 2018 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial
Statements).
The favorable change in Other (income) expense – net within Operating income (loss) includes net favorable
changes to charges and credits to regulatory assets and liabilities, partially offset by the absence of a 2018 gain on asset
retirement (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements).
52
The favorable change in Operating income (loss) includes lower impairments of assets, an increase in Service
revenues primarily associated with Transco projects placed in-service and higher volumes in the Northeast region, the
favorable impact of acquiring the additional interest of UEOM, and higher Transco rates and favorable changes in the
amortization of regulatory assets and liabilities. The change is also impacted favorably by the absence of a charitable
contribution of preferred stock to the Williams Foundation, Inc., and the absence of fees associated with the WPZ
Merger. These favorable changes were partially offset by the impact of asset divestitures and deconsolidations during
2018, including the related gains on sales. They were also partially offset by lower margins associated with our equity
NGL production primarily associated with lower prices, higher depreciation expense associated with new assets placed
in service, and charges for severance and related costs primarily associated with our VSP.
The unfavorable change in Equity earnings (losses) is primarily due to 2019 losses from our Brazos Permian II
investment acquired in December 2018 of $14 million, the impact of the consolidation of UEOM during the first quarter
of 2019 which reduced equity earnings by $9 million, and a $7 million unfavorable impact related to the April 2019
sale of our Jackalope investment. Additionally, equity earnings at Aux Sable decreased $9 million related to lower rates
reflecting lower NGL prices. These decreases are partially offset by improved results at our Appalachia Midstream
Investments of $20 million.
The unfavorable change in Other investing income (loss) – net includes higher impairments of equity-method
investments, the absence of 2018 gains on the deconsolidations of our Delaware basin assets and Jackalope, and a 2019
loss on the deconsolidation of Constitution. These were partially offset by a 2019 gain on the disposition of Jackalope
(see Note 6 – Investing Activities of Notes to Consolidated Financial Statements).
Interest expense increased primarily due to an increase in financing obligations associated with Transco’s Atlantic
Sunrise project and lower Interest capitalized related to construction projects that have been placed into service. (See
Note 15 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements.)
The unfavorable change in Other income (expense) – net below Operating income (loss) is primarily due to a
decrease in equity AFUDC associated with reduced capital expenditures on projects, partially offset by the absence of
2018 unfavorable settlement charges from our pension early payout program (see Note 7 – Other Income and Expenses
of Notes to Consolidated Financial Statements).
Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income attributable to
The Williams Companies, Inc, partially offset by the absence of a charge to establish a $105 million valuation allowance,
recorded in 2018, on certain deferred tax assets that may not be realized following the WPZ merger. 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 favorable change in Net income (loss) attributable to noncontrolling interests is primarily due to our third-
quarter 2018 acquisition of the publicly held interests in WPZ associated with the WPZ Merger, the impairment of
Constitution project costs, and lower results at Gulfstar.
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
Ohio River Supply Hub. These increases were partially offset by an unfavorable change in the rate of deferred revenue
recognition resulting from implementing Accounting Standards Update 2014-09 “Revenue from Contracts with
Customers” (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 were not recast. 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
53
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 sales 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 olefins sales associated with our former 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 purchases. This increase is partially offset by the absence of $147 million of olefin feedstock
purchases due to the sale of our former olefins operations, as well as the absence of natural gas purchases associated
with the production of equity NGLs, which are reported in Processing commodity expenses in conjunction with the
2018 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 olefins and Four Corners area operations.
Depreciation and amortization expenses decreased primarily due to the absence of our former 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 olefins and Four Corners area operations, and cost containment efforts. These decreases are partially
offset by a charitable contribution of preferred stock to The Williams Companies Foundation, Inc. and fees associated
with the WPZ Merger.
Impairment of certain assets includes 2018 impairments on certain assets in the Barnett Shale region and certain
idle pipelines and 2017 impairments associated with certain assets in the Mid-Continent, Marcellus South, and Houston
Ship Channel areas (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes
to Consolidated Financial Statements).
Gain on sale of certain assets and businesses includes gains recognized on the sales of our Four Corners area in
October 2018, our Gulf Coast pipeline systems in December 2018 and our Geismar Interest in July 2017 (see
Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).
Regulatory charges resulting from Tax Reform relates to the 2017 establishment 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 benefit of
establishing a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following
the WPZ Merger in 2018, 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 (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements).
Operating income (loss) changed unfavorably primarily due to higher impairments of assets, lower gains on sales
of assets and businesses, and the absence of operating income associated with our former 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 higher NGL margins.
54
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 accounted for as an equity-method investment beginning in the second quarter of 2018.
Other investing income (loss) – net includes a 2017 gain on disposition of our investments in DBJV and Ranch
Westex JV LLC, a 2018 impairment related to our investment in UEOM, and 2018 gains on the 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. This increase is partially offset by lower interest
rates on our outstanding debt in 2018 and lower borrowings on our credit facilities in 2018.
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 equity AFUDC resulting from Tax Reform, an increase
in equity AFUDC, and a lower settlement charge from the pension early payout program. These favorable changes
were 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.
Year-Over-Year Operating Results – Segments
We evaluate segment operating performance based upon Modified EBITDA. Note 20 – 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
Atlantic-Gulf
Year Ended December 31,
2019
2018
2017
(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 and businesses..................................................
Regulatory charges resulting from Tax Reform ..............................................
Proportional Modified EBITDA of equity-method investments.....................
Atlantic-Gulf Modified EBITDA .................................................................... $
2,861
41
288
3,190
(288)
(16)
(814)
(354)
—
—
177
1,895
Commodity margins ........................................................................................ $
25
$
$
$
2,509
59
435
3,003
(438)
(16)
(799)
—
81
9
183
2,023
40
$
$
$
2,239
—
484
2,723
(437)
—
(819)
—
—
(493)
264
1,238
47
2019 vs. 2018
Atlantic-Gulf Modified EBITDA decreased primarily due to the impairment of Constitution, the absence of a 2018
Gain on sale of certain assets and businesses , and higher Other segment costs and expenses, partially offset by increased
Service revenues related to expansion projects placed into service during 2018 and 2019.
Service revenues increased primarily due to a $403 million increase in Transco’s natural gas transportation revenues
primarily driven by a $358 million increase related to expansion projects placed in service in 2018 and 2019, as well
as higher revenue associated with Transco’s general rate case settlement and increased amounts for reimbursable power
and storage expenses. Partially offsetting these increases were lower fee revenues of $62 million primarily due to
producer operational issues and lower deferred revenue amortization at Gulfstar, as well as the sale of certain Gulf
Coast pipeline assets in fourth-quarter 2018.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing
commodity expenses comprise our commodity margins. Our commodity margins associated with our equity NGLs
decreased $16 million, consisting of a $26 million decrease associated with unfavorable net realized NGL sales prices,
partially offset by a $10 million increase associated with higher sales volumes. The higher NGL volumes were primarily
related to the absence of 2018 downtime to modify the Mobile Bay processing plant for the Norphlet project.
Additionally, the decrease in Product sales includes a $93 million decrease in commodity marketing sales due to lower
NGL prices and volumes and a $39 million decrease in system management gas sales. Marketing sales and system
management gas sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA.
Other segment costs and expenses increased primarily due a $56 million unfavorable change in equity AFUDC
due to lower construction activity, a $32 million charge in 2019 for severance and related costs primarily associated
with our 2019 VSP, a $21 million increase in reimbursable power and storage expenses, $16 million of expense in 2019
related to the reversal of expenditures previously capitalized, and the absence of a $12 million 2018 gain on asset
retirements. These unfavorable changes were partially offset by $77 million of net favorable changes to charges and
credits associated with regulatory assets and liabilities, which were significantly driven by the previously mentioned
settlement in Transco’s general rate case, and a $46 million decrease in Transco’s contracted services compared to 2018
mainly due to the timing of required engine overhauls and integrity testing.
56
Impairment of certain assets includes the 2019 impairment of our Constitution development project (see
Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial
Statements).
Gain on sale of certain assets and businesses reflects an $81 million gain from the sale of our Gulf Coast pipeline
system assets in fourth-quarter 2018 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial
Statements).
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 the 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 received 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 sales driven by a $149 million decrease in crude oil sales 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 sales primarily reflecting 20 percent higher
non-ethane prices;
• A $14 million decrease in sales associated with the production of our equity NGLs, as further described below
as part of our commodity 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 purchases
(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
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 margins.
Other segment costs and expenses decreased primarily due to a $17 million increase in Transco’s equity AFUDC
as a result of higher construction activity 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, as previously mentioned.
57
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.
Northeast G&P
Year Ended December 31,
2019
2018
2017
(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............................................................................
Proportional Modified EBITDA of equity-method investments.....................
Northeast G&P Modified EBITDA................................................................. $
1,338
12
150
1,500
(152)
(8)
(470)
(10)
454
1,314
Commodity margins ........................................................................................ $
2
$
$
$
976
20
287
1,283
(289)
(9)
(392)
—
493
1,086
9
$
$
$
872
—
291
1,163
(286)
—
(386)
(124)
452
819
5
2019 vs. 2018
Northeast G&P Modified EBITDA increased primarily due to higher Service revenues due to increased gathering
volumes, as well as the $38 million favorable impact of acquiring the additional interest of UEOM, partially offset by
2019 impairments.
Service revenues increased primarily due to:
• A $158 million increase associated with the consolidation of UEOM, as previously discussed;
• A $102 million increase associated with higher gathering revenues at Susquehanna Supply Hub reflecting 18
percent higher gathering volumes due to increased production from customers and higher rates;
• A $49 million increase at Ohio Valley Midstream primarily due to higher gathering, processing, and
transportation volumes;
• A $36 million increase in gathering revenues in the Utica Shale region due to higher rates and volumes from
new wells;
• A $14 million increase in compression revenues for services charged to an affiliate driven by higher volumes.
Product sales decreased primarily due to lower non-ethane volumes and prices within our marketing activities.
The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as Product
costs.
58
Other segment costs and expenses increased primarily due to:
• A $53 million increase associated with the consolidation of UEOM;
• A $10 million increase related to transaction expenses associated with the acquisition of UEOM and the
formation of the Northeast JV;
• A $7 million charge in 2019 for severance and related costs primarily associated with our VSP.
Impairment of certain assets increased due to a $10 million write-down of other certain assets that may no longer
be in use or are surplus in nature in 2019 (see Note 18 – Fair Value Measurements, Guarantees, and Concentration of
Credit Risk of Notes to Consolidated Financial Statements).
Proportional Modified EBITDA of equity-method investments decreased $59 million as a result of the consolidation
of UEOM and $10 million due to unfavorable rates reflecting lower NGL prices at Aux Sable. This decrease was
partially offset by a $29 million increase at Appalachia Midstream Investments, reflecting higher volumes due to
increased customer production.
2018 vs. 2017
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.
Product sales decreased primarily due to $31 million lower marketing sales, driven by lower non-ethane volumes
and prices. The changes in marketing sales 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.
59
West
Year Ended December 31,
2019
2018
(Millions)
2017
Service revenues.............................................................................................. $
Service revenues – commodity consideration .................................................
Product sales....................................................................................................
Segment revenues............................................................................................
$
1,813
150
1,797
3,760
$
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 and businesses..................................................
Regulatory charges resulting from Tax Reform ..............................................
Proportional Modified EBITDA of equity-method investments.....................
West Modified EBITDA.................................................................................. $
(1,774)
(79)
(688)
(100)
(2)
—
115
1,232
Commodity margins ........................................................................................ $
94
(2,448)
(116)
(825)
(1,849)
591
7
94
308
205
$
$
(1,842)
—
(832)
(1,032)
—
(220)
79
412
171
$
$
2019 vs. 2018
West Modified EBITDA increased primarily due to lower Impairment of certain assets and lower Other segment
costs and expenses, partially offset by a lower gain on sale of certain assets in 2019, lower Service revenues, and lower
commodity margins.
Service revenues decreased primarily due to:
• A $218 million decrease associated with asset divestitures and deconsolidations during 2018 and 2019,
including our former Four Corners area assets, certain Delaware basin assets that were contributed to our
Brazos Permian II equity-method investment, and our Jackalope assets which were deconsolidated in second-
quarter 2018 and subsequently sold in second-quarter 2019;
• A $57 million decrease driven by lower deferred revenue amortization and MVC deficiency fee revenues in
the Barnett Shale region primarily associated with the expiration of a certain MVC agreement;
• A $17 million decrease driven by lower gathering volumes primarily in the Mid-Continent, Barnett Shale, and
Wamsutter regions, partially offset by higher gathering volumes primarily in the Haynesville Shale and Eagle
Ford regions;
• A $15 million decrease associated with lower processing rates primarily driven by lower commodity pricing
in the Piceance region;
• A $15 million decrease associated with lower gathering rates primarily in the Mid-Continent and Haynesville
Shale regions;
• A $17 million increase related to other MVC deficiency fee revenues;
• A $13 million increase related to higher fractionation and storage fees;
• An $8 million increase associated with the resolution of a prior period performance obligation.
60
The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing
commodity expenses comprise our commodity margins. Our commodity margins associated with our equity NGLs
decreased $127 million primarily due to:
• A $98 million decrease associated with lower sales volumes, consisting of $54 million related to the absence
of our former Four Corners area assets and $44 million due to 12 percent lower non-ethane volumes and 33
percent lower ethane sales volumes primarily due to higher ethane rejection in 2019, natural declines, less
producer drilling activity, and more severe weather conditions in first-quarter 2019;
• A $66 million decrease associated with lower sales prices primarily due to 29 percent and 48 percent lower
average net realized per-unit non-ethane and ethane sales prices, respectively;
• A $37 million increase related to lower natural gas purchases associated with lower equity NGL production
volumes and lower natural gas prices, including $9 million related to the absence of our former Four Corners
area assets.
Additionally, the decrease in Product sales includes a $447 million decrease in marketing sales, which is due to lower
sales prices, partially offset by higher sales volumes, and a $36 million decrease related to the sale of other products.
These decreases are substantially offset in Product costs. Marketing margins increased by $27 million primarily due
to favorable changes in prices.
Other segment costs and expenses decreased primarily due to a $127 million reduction associated with the absences
of our former Four Corners area assets and from the Jackalope deconsolidation in second-quarter 2018, the absence of
a 2018 unfavorable charge of $12 million for a regulatory liability associated with a decrease in Northwest Pipeline’s
estimated deferred state income tax rate following the WPZ Merger, $12 million favorable settlements in 2019, as well
as $10 million lower ad valorem taxes. These decreases were partially offset by an unfavorable charge in 2019 for
severance and related costs primarily associated with our VSP of $17 million.
Impairment of certain assets decreased primarily due to the absence of the $1,849 million Barnett impairment in
2018, partially offset by various 2019 impairments (see Note 18 – Fair Value Measurements, Guarantees, and
Concentration of Credit Risk of Notes to Consolidated Financial Statements).
The decrease in Gain on sale of certain assets and businesses reflects the absence of the gain from the sale of
our Four Corners area assets recorded in the fourth quarter of 2018 (see Note 3 – Acquisitions and Divestitures of
Notes to Consolidated Financial Statements).
Proportional Modified EBITDA of equity-method investments increased primarily due to the additions of the RMM
and Brazos Permian II equity-method investments in the second half of 2018, partially offset by the sale of our Jackalope
investment in second-quarter 2019.
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 and businesses 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;
61
• 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
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 sales 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 in sales associated with the production of our equity NGLs, as further described below
as part of our commodity 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 purchases
(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 margins. Our commodity 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
62
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 18 – Fair Value Measurements, Guarantees, and Concentration of Credit
Risk of Notes to Consolidated Financial Statements).
Gain on sale of certain assets and businesses 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 in 2017 (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.
Other
Other Modified EBITDA..................................................................... $
6
$
(29) $
997
Year Ended December 31,
2019
2018
(Millions)
2017
2019 vs. 2018
Other Modified EBITDA increased primarily due to:
• The absence of the $66 million impairment of certain idle pipelines in the second quarter of 2018 (see
Note 18 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements);
• The absence of 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 16 – Stockholders’ Equity
of Notes to Consolidated Financial Statements);
• The absence of $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);
• An $8 million increase related to the absence of 2018 unfavorable Modified EBITDA associated with the
results of certain of our former Gulf Coast area operations sold in 2018;
• The absence of a $7 million loss on early retirement of debt in 2018 (see Note 7 – Other Income and Expenses
of Notes to Consolidated Financial Statements).
These increases were partially offset by:
• The absence of a $37 million benefit of establishing a regulatory asset associated with an increase in Transco’s
estimated deferred state income tax rate following the WPZ Merger in 2018 and a subsequent unfavorable
$12 million adjustment in the first quarter of 2019;
• A $26 million decrease in income associated with a regulatory asset related to deferred taxes on equity funds
used during construction;
63
• The absence of a $20 million gain on the sale of certain assets and operations located in the Gulf Coast area
in 2018 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).
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 – Acquisitions
and 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), as previously mentioned;
• 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, as previously mentioned;
• 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).
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 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated
Financial Statements);
• A $62 million favorable change for lower charges to reduce 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;
• 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, as previously mentioned;
• 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, as previously
mentioned.
64
Management’s Discussion and Analysis of Financial Condition and Liquidity
Overview
As previously discussed, we have continued to focus on earnings and cash flow growth, while continuing to improve
leverage metrics and control operating costs. In 2019, we acquired the remaining outstanding ownership interests in
UEOM for $728 million and subsequently formed a new partnership which includes UEOM and our Ohio Valley
Midstream business. Our partner purchased a 35 percent ownership interest in the partnership for $1.3 billion. Also,
during the second quarter of 2019 we sold our 50 percent ownership interest in Jackalope for $485 million. See also
the following table of Sources (Uses) of Cash.
Outlook
As previously discussed in Company Outlook, our growth capital and investment expenditures in 2020 are currently
expected to be in a range from $1.1 billion to $1.3 billion. Growth capital spending in 2020 includes Transco expansions,
all of which are fully contracted with firm transportation agreements, and our Bluestem NGL pipeline project in the
Mid-Continent region. 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 substantially all of our planned 2020 capital spending with cash available after paying
dividends. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response
to changes in economic conditions or business opportunities.
As of December 31, 2019, we have $2.121 billion of long-term debt maturing in 2020. Our potential sources of
liquidity available to address these maturities include proceeds from refinancing at attractive long-term rates or from
our credit facility, as well as proceeds from asset monetizations.
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 2020. Our potential material internal and external sources and uses of
liquidity 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
Contributions from noncontrolling interests
Working capital requirements
Capital and investment expenditures
Quarterly dividends to our shareholders
Debt service payments, including payments of long-term debt
Distributions to noncontrolling interests
Potential risks associated with our planned levels of liquidity discussed above include those previously discussed
in Company Outlook.
65
As of December 31, 2019, we had a working capital deficit of $2.388 billion, including cash and cash equivalents
and long-term debt due within one year. Our available liquidity is as follows:
Available Liquidity
December 31, 2019
(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) ................................................................................................
$
289
4,500
4,789
__________
(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. We had no
commercial paper outstanding as of December 31, 2019. The highest amount outstanding under our commercial
paper program and credit facility during 2019 was $1.226 billion. At December 31, 2019, we were in compliance
with the financial covenants associated with our credit facility. See Note 15 – Debt and Banking Arrangements of
Notes to Consolidated Financial Statements for additional information on our credit facility and commercial paper
program.
Dividends
We increased our regular quarterly cash dividend to common stockholders by approximately 12 percent from the
previous quarterly cash dividends of $0.34 per share paid in each quarter of 2018, to $0.38 per share for the quarterly
cash dividends paid in each quarter of 2019.
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.
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 are impacted by our credit ratings. The current ratings
are as follows:
Rating Agency
S&P Global Ratings
Moody’s Investors Service
Fitch Ratings
Outlook
Stable
Stable
Rating Watch Positive
Senior Unsecured
Debt Rating
BBB
Baa3
BBB-
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
66
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):
Sources of cash and cash equivalents:
Cash Flow
Category
Year Ended December 31,
2019
2018
2017
(Millions)
Operating activities – net .......................................................... Operating
Proceeds from sale of partial interest in consolidated
subsidiary (see Note 3)..........................................................
Proceeds from credit-facility borrowings .................................
Proceeds from dispositions of equity-method investments
(see Note 6) ...........................................................................
Proceeds from long-term debt (see Note 15)............................
Contributions in aid of construction .........................................
Proceeds from issuance of common stock................................
Proceeds from sale of businesses, net of cash divested (see
Note 3)...................................................................................
Financing
Financing
Investing
Financing
Investing
Financing
$
3,693
$
3,293
$
3,089
1,334
700
485
67
52
10
—
1,840
—
2,086
411
15
—
1,635
200
1,698
426
2,131
Investing
(2)
1,296
2,067
Uses of cash and cash equivalents:
Capital expenditures .................................................................
Common dividends paid ...........................................................
Payments on credit-facility borrowings....................................
Purchases of businesses, net of cash acquired (see Note 3) .....
Purchases of and contributions to equity-method investments
(see Note 6) ...........................................................................
Dividends and distributions paid to noncontrolling interests ...
Payments of long-term debt (see Note 15) ...............................
Payments of commercial paper – net........................................
Investing
Financing
Financing
Investing
Investing
Financing
Financing
Financing
(2,109)
(1,842)
(860)
(728)
(453)
(124)
(49)
(4)
(3,256)
(1,386)
(1,950)
—
(1,132)
(591)
(1,254)
(2)
(2,399)
(992)
(2,140)
—
(132)
(822)
(3,785)
(93)
Other sources / (uses) – net ..........................................................
Increase (decrease) in cash and cash equivalents.........................
Financing
and Investing
(49)
121
$
(101)
(731) $
(154)
729
$
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, Gain on disposition of equity-method investments, Impairment of equity-method investments, (Gain)
on sale of certain assets and businesses, Impairment of certain assets, (Gain) loss on deconsolidation of businesses,
and Regulatory charges resulting from Tax Reform.
Our Net cash provided (used) by operating activities in 2019 increased from 2018 primarily due to the net favorable
changes in operating working capital in 2019, including the collection of Transco’s filed rates subject to refund and the
receipt of an income tax refund, as well as higher operating income (excluding noncash items as previously discussed)
in 2019, partially offset by the impact of decreased distributions from unconsolidated affiliates in 2019.
67
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.
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 12 – Property, Plant, and Equipment, Note 18 – Fair Value Measurements, Guarantees, and Concentration of
Credit Risk, and Note 19 – 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, 2019:
2020
2021 - 2022
2023 - 2024
Thereafter
Total
(Millions)
Long-term debt, including current portion: (1)
Principal ............................................................... $
Interest ..................................................................
Operating leases .......................................................
Purchase obligations (2) ...........................................
Other obligations (3)(4) ...........................................
Total .......................................................... $
2,141
1,097
29
890
3
4,160
$
$
2,918
2,004
61
647
5
5,635
$
$
3,756
1,709
41
245
—
5,751
$
$
13,650
8,561
157
290
—
22,658
$
$
22,465
13,371
288
2,072
8
38,204
______________
(1) Includes any borrowings outstanding under credit facilities, but does not include any related variable-rate interest
payments.
(2) Includes:
• Approximately $206 million in open property, plant, and equipment purchase orders;
• An estimated $589 million long-term mixed NGLs purchase obligation with index-based pricing terms that
is reflected in this table at December 31, 2019 prices;
• An estimated $193 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, 2019
prices. Any excess purchased volumes may be sold at comparable market prices;
• An estimated $163 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, 2019 prices. Any excess purchased volumes may be sold at comparable market prices;
• An estimated $149 million long-term ethane purchase obligation with index-based pricing terms that is reflected
in this table at December 31, 2019 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;
• An estimated $129 million long-term mixed NGLs purchase obligation with index-based pricing terms that
is reflected in this table at December 31, 2019 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.)
68
(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 $68 million in 2019 and $93 million in 2018.
In 2020, we expect to contribute approximately $19 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 2019, we contributed $60 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 2020, we expect to contribute approximately $10 million to our tax-qualified pension plans and use excess
amounts to satisfy minimum contribution requirements, if needed. Additionally, estimated future minimum funding
requirements may vary significantly from historical requirements if actual results differ significantly from estimated
results for assumptions such as returns on plan assets, interest rates, retirement rates, mortality, and other significant
assumptions or by changes to current legislation and regulations.
(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 49 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 19 – 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 $31 million, all of which are included in Accrued
liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet at December 31,
2019. We will seek recovery of the accrued costs related to remediation activities by our interstate gas pipelines totaling
approximately $4 million through future natural gas transmission rates. The remainder of these costs will be funded
from operations. During 2019, we paid approximately $6 million for cleanup and/or remediation and monitoring
activities. We expect to pay approximately $8 million in 2020 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, 2019, 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 and combustion turbine 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
69
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.
70
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 15 – Debt and Banking Arrangements 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, 2019 and 2018. See Note 18 – 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.
2020
2021
2022
2023
2024
Thereafter (1)
Total
(Millions)
Fair Value
December 31,
2019
Long-term debt, including
current portion:
Fixed rate .......................
$ 2,141
$
893
$ 2,025
$ 1,477
$ 2,279
$
13,473
$ 22,288
$
25,319
Weighted-average
interest rate ................
5.2%
5.2%
5.3%
5.4%
5.6%
5.6%
Variable rate ...................
$
— $
— $
— $
— $
— $
— $
— $
—
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
__________________
(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.
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, 2019 and 2018, our derivative activity
was not material. (See Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to
Consolidated Financial Statements.)
71
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, 2019 and 2018, 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, 2019, 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 report of other auditors, the consolidated financial statements
present fairly, in all material respects, the consolidated financial position of the Company at December 31, 2019 and
2018, and the consolidated results of its operations and its cash flows for each of the three years in the period ended
December 31, 2019, 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 $217 million and $225 million as of December 31, 2019 and 2018, respectively, and the
Company’s equity earnings in the net income of Gulfstream were $74 million in 2019, $75 million in 2018 and $75
million in 2017. Gulfstream’s financial statements were audited by other auditors whose report has been furnished to
us, and our opinion, insofar as it relates to the amounts included for Gulfstream, is based solely on the report of 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, 2019, 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 24, 2020 expressed an unqualified opinion
thereon.
Adoption of New Accounting Standard
As discussed in Note 1 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 report of other auditors provide a reasonable basis for our
opinion.
72
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements
that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or
disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or
complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated
financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing
separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
UEOM Acquisition
Description of
the Matter
During 2019, the Company completed an acquisition of the remaining 38 percent interest in Utica
East Ohio Midstream LLC (UEOM) for consideration of $741 million, as disclosed in Note 3 to the
consolidated financial statements. The acquisition was accounted for as a business combination.
Auditing the Company's accounting for its acquisition of UEOM was complex due to the estimation
required in the Company’s determination of the fair value of the assets acquired and required the
involvement of specialists due to the highly judgmental nature of certain assumptions. Estimation
uncertainty was present due to the assets’ fair values being sensitive to changes in the underlying
significant assumptions. The significant assumptions included the weighted average cost of capital
and forecasted volume growth.
How We
Addressed the
Matter in Our
Audit
We tested the Company's controls over its accounting for the acquisition, including controls over
the estimation process supporting the recognition and measurement of the acquired assets. We also
tested controls over management’s review of the significant assumptions used in the valuation models.
To test the estimated fair value of the acquired assets, we performed audit procedures that included,
among others, evaluating the Company's selection of the valuation methodologies, evaluating the
significant assumptions used in the valuation, and testing the completeness and accuracy of the
underlying data supporting the significant assumptions and estimates. For example, we compared
the significant assumptions used to estimate future cash flows to historical operating results, obtained
third-party support, where available, to evaluate operating data, performed a sensitivity analysis to
evaluate the assumptions that were most significant to the fair value estimate, and recalculated
management’s estimate. We involved our valuation specialists to assist with our evaluation of the
methodologies used by the Company and significant assumptions included in the fair value estimates.
Pension and Other Postretirement Benefit Obligations
Description of
the Matter
At December 31, 2019, the Company’s aggregate pension and other postretirement benefit obligations
were $1,452 million and were exceeded by the fair value of pension and other postretirement plan
assets of $1,546 million, resulting in overfunded pension and other postretirement benefit obligations
of $94 million. As explained in Note 10 to the consolidated financial statements, the Company utilized
key assumptions to determine the pension and other postretirement benefit obligations.
Auditing the pension and other postretirement benefit obligations is complex and required the
involvement of specialists due to the highly judgmental nature of the actuarial assumptions (e.g.,
discount rates, future compensation levels, mortality rates, expected returns on plan assets) used in
the measurement process. These assumptions have a significant effect on the projected benefit
obligations.
73
How We
Addressed the
Matter in Our
Audit
We tested controls that address the risks of material misstatement relating to the measurement and
valuation of the pension and other postretirement benefit obligations. For example, we tested controls
over management’s review of the pension and postretirement benefit obligations, the significant
actuarial assumptions and the data inputs provided to the actuary.
To test the pension and other postretirement benefit obligations, our audit procedures included, among
others, evaluating the methodologies used, the significant actuarial assumptions discussed above
and the underlying data used by the Company. We compared the actuarial assumptions used by
management to historical trends and evaluated the changes in the funded status from prior year. In
addition, we involved our actuarial specialists to assist with our procedures. For example, we
evaluated management’s methodology for determining the discount rates that reflect the maturity
and duration of the benefit payments and are used to measure the pension and other postretirement
benefit obligations. As part of this assessment, we compared the projected cash flows to prior year
and compared the current year benefits paid to the prior year projected cash flows. To evaluate the
future compensation levels and the mortality rates, we assessed whether the information is consistent
with publicly available information, and whether any market data adjusted for entity-specific
adjustments were applied. Additionally, to evaluate the expected returns on plan assets, we assessed
whether management’s assumptions were consistent with a range of returns for portfolios of
comparative investments. We also tested the completeness and accuracy of the underlying data,
including the participant data.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 1962.
Tulsa, Oklahoma
February 24, 2020
74
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,
2019 and 2018, and the related statements of operations, comprehensive income, cash flows, and members’ equity for
each of the three years in the period ended December 31, 2019, 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, 2019 and 2018, and the results of its operations
and its cash flows for each of the three years in the period ended December 31, 2019 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 24, 2020
We have served as the Company’s auditor since 2018.
75
The Williams Companies, Inc.
Consolidated Statement of Operations
Year Ended December 31,
2018
2019
2017
(Millions, except per-share amounts)
Revenues:
Service revenues ...................................................................................
Service revenues – commodity consideration (Note 1) ........................
Product sales .........................................................................................
Total revenues .................................................................................
$
$
5,933
203
2,065
8,201
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 (Note 18) ................................................
Gain on sale of certain assets and businesses (Note 3) .........................
Regulatory charges resulting from Tax Reform (Note 1) .....................
Other (income) expense – net ...............................................................
Total costs and expenses ..................................................................
Operating income (loss) ..........................................................................
Equity earnings (losses) ..........................................................................
Other investing income (loss) – net ........................................................
Interest incurred ......................................................................................
Interest capitalized ..................................................................................
Other income (expense) – net .................................................................
Income (loss) from continuing operations before income taxes .............
Provision (benefit) for income taxes .......................................................
Income (loss) from continuing operations ..............................................
Income (loss) from discontinued operations ...........................................
Net income (loss) .................................................................................
Less: Net income (loss) attributable to noncontrolling interests .....
Net income (loss) attributable to The Williams Companies, Inc. .........
Preferred stock dividends (Note 16) .....................................................
Net income (loss) available to common stockholders ..........................
Amounts attributable to The Williams Companies, Inc. available to
common stockholders:
Income (loss) from continuing operations ............................................
Income (loss) from discontinued operations ........................................
Net income (loss) ............................................................................
Basic earnings (loss) per common share:
Income (loss) from continuing operations .......................................
Income (loss) from discontinued operations ...................................
Net income (loss) ..........................................................................
Weighted-average shares (thousands) .............................................
Diluted earnings (loss) per common share:
Income (loss) from continuing operations .......................................
Income (loss) from discontinued operations ...................................
Net income (loss) ..........................................................................
Weighted-average shares (thousands) .............................................
$
$
$
$
$
$
$
1,961
105
1,468
1,714
558
464
2
—
8
6,280
1,921
375
(79)
(1,218)
32
33
1,064
335
729
(15)
714
(136)
850
3
847
862
(15)
847
.71
(.01)
.70
1,212,037
.71
(.01)
.70
1,214,011
$
$
$
$
$
$
$
$
5,502
400
2,784
8,686
2,707
137
1,507
1,725
569
1,915
(692)
(17)
67
7,918
768
396
187
(1,160)
48
92
331
138
193
—
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
—
2,509
335
2,174
—
2,174
(156) $
—
(156) $
(.16) $
—
(.16) $
973,626
(.16) $
—
(.16) $
973,626
2,174
—
2,174
2.63
—
2.63
826,177
2.62
—
2.62
828,518
See accompanying notes.
76
The Williams Companies, Inc.
Consolidated Statement of Comprehensive Income (Loss)
Year Ended December 31,
2019
2018
2017
(Millions)
Net income (loss) .......................................................................................................
$
714
$
193
$
2,509
Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $1 and
$2 in 2018 and 2017, respectively ..................................................................
Reclassifications into earnings of net derivative instruments (gain) loss, net of
taxes of ($1) and ($1) in 2018 and 2017, respectively....................................
Foreign currency translation activities:
Foreign currency translation adjustments ...........................................................
Pension and other postretirement benefits:
Amortization of prior service cost (credit) included in net periodic benefit
cost (credit), net of taxes of $2 in 2017 ..........................................................
Net actuarial gain (loss) arising during the year, net of taxes of ($20), $3, and
($15) in 2019, 2018, and 2017, respectively ..................................................
Amortization of actuarial (gain) loss and net actuarial loss from settlements
included in net periodic benefit cost (credit), net of taxes of ($4), ($11), and
($37) in 2019, 2018, and 2017, respectively ..................................................
Other comprehensive income (loss) ..........................................................................
Comprehensive income (loss) ...................................................................................
Less: Comprehensive income (loss) attributable to noncontrolling interests ..........
—
—
—
—
59
12
71
785
(136)
(7)
8
—
—
(6)
35
30
223
346
(9)
6
1
(3)
44
61
100
2,609
334
Comprehensive income (loss) attributable to The Williams Companies, Inc. ...........
$
921
$
(123) $
2,275
See accompanying notes.
77
The Williams Companies, Inc.
Consolidated Balance Sheet
December 31,
2019
2018
(Millions, except per-share amounts)
ASSETS
Current assets:
Cash and cash equivalents.........................................................................................
Trade accounts and other receivables (net of allowance of $6 at December 31,
2019 and $9 at December 31, 2018)......................................................................
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 19)
Equity:
Stockholders’ equity:
Preferred stock......................................................................................................
Common stock ($1 par value; 1,470 million shares authorized at December 31,
2019 and December 31, 2018; 1,247 million shares issued at December 31,
2019 and 1,245 million shares issued at December 31, 2018) .........................
Capital in excess of par value...............................................................................
Retained deficit ....................................................................................................
Accumulated other comprehensive income (loss) ...............................................
Treasury stock, at cost (35 million shares of common stock) ..............................
Total stockholders’ equity................................................................................
Noncontrolling interests in consolidated subsidiaries...............................................
Total equity...........................................................................................................
Total liabilities and equity ...............................................................................
See accompanying notes.
78
$
$
$
$
289
$
996
125
170
1,580
6,235
29,200
7,959
1,066
46,040
552
1,276
2,140
3,968
20,148
1,782
3,778
$
$
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
35
35
1,247
24,323
(11,002)
(199)
(1,041)
13,363
3,001
16,364
46,040
$
1,245
24,693
(10,002)
(270)
(1,041)
14,660
1,337
15,997
45,302
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, 2016........................... $
— $
785
$
14,887
$
(9,649)
$
(339)
$
(1,041)
$
4,643
$
9,403
$ 14,046
Adoption of new accounting standard ................
Net income (loss) ................................................
Other comprehensive income (loss)....................
Issuance of common stock (Note 16)..................
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 ................................
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...............
Net income (loss) ................................................
Other comprehensive income (loss)....................
WPZ Merger (Note 1) .........................................
Issuance of preferred stock (Note 16) .................
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 6) ..............
Other....................................................................
Net increase (decrease) in equity ........................
Balance – December 31, 2018...........................
Net income (loss) ................................................
Other comprehensive income (loss)....................
Cash dividends – common stock ($1.52 per
share)...................................................................
Dividends and distributions to noncontrolling
interests.............................................................
Stock-based compensation and related common
stock issuances, net of tax ................................
Sale of partial interest in consolidated
subsidiary (Note 3) ...........................................
Changes in ownership of consolidated
subsidiaries, net (Note 3)..................................
Contributions from noncontrolling interests .......
Deconsolidation of subsidiary (Note 4) ..............
Other....................................................................
Net increase (decrease) in equity ........................
Balance – December 31, 2019........................... $
* Accumulated Other Comprehensive Income (Loss)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
35
—
—
—
—
—
—
—
—
35
35
—
—
—
—
—
—
—
—
—
—
—
35
—
—
—
75
—
—
1
—
—
—
—
76
861
—
—
—
382
—
—
—
1
—
—
—
—
1
384
1,245
—
—
—
—
2
—
—
—
—
—
2
1
—
—
2,043
—
—
73
—
1,497
—
7
3,621
18,508
—
—
—
6,112
—
—
—
60
—
14
—
—
(1)
6,185
24,693
—
—
—
—
56
—
(426)
—
—
—
36
2,174
—
—
(992)
—
—
—
—
—
(3)
1,215
(8,434)
(23)
(155)
—
—
—
(1,386)
—
—
—
—
—
—
(4)
(1,568)
(10,002)
850
—
(1,842)
—
—
—
—
—
—
(8)
(370)
(1,000)
—
—
101
—
—
—
—
—
—
—
—
101
(238)
(61)
—
32
(3)
—
—
—
—
—
—
—
—
—
(32)
(270)
—
71
—
—
—
—
—
—
—
—
71
—
—
—
—
—
—
—
—
—
—
—
—
(1,041)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(1,041)
—
—
—
—
—
—
—
—
—
—
—
37
2,174
101
2,118
(992)
—
74
—
1,497
—
4
5,013
9,656
(84)
(155)
32
6,491
35
(1,386)
—
61
—
14
—
—
(4)
5,004
14,660
850
71
(1,842)
—
58
—
(426)
—
—
(8)
(1,297)
$
1,247
$
24,323
$ (11,002)
$
(199)
$
(1,041)
$
13,363
$
See accompanying notes.
79
—
335
(1)
—
—
(883)
—
61
37
2,509
100
2,118
(992)
(883)
74
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)
1,337
(136)
—
—
61
46
(4)
15
(267)
(5)
(178)
15,997
714
71
(1,842)
(124)
(124)
—
58
1,334
1,334
567
36
(13)
—
1,664
3,001
141
36
(13)
(8)
367
$ 16,364
The Williams Companies, Inc.
Consolidated Statement of Cash Flows
Year Ended December 31,
2018
2019
2017
OPERATING ACTIVITIES:
Net income (loss) ...............................................................................................................
Adjustments to reconcile to net cash provided (used) by operating activities:
$
714
$
193
$
2,509
(Millions)
Depreciation and amortization......................................................................................
Provision (benefit) for deferred income taxes ..............................................................
Equity (earnings) losses................................................................................................
Distributions from unconsolidated affiliates ................................................................
Gain on disposition of equity-method investments (Note 6)........................................
Impairment of equity-method investments (Note 18) ..................................................
(Gain) on sale of certain assets and businesses (Note 3)..............................................
Impairment of certain assets (Note 18).........................................................................
(Gain) loss 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 partial interest in consolidated subsidiary (Note 3)........................
Common dividends paid ....................................................................................................
Dividends and distributions paid to noncontrolling interests ............................................
Contributions from noncontrolling interests......................................................................
Payments for debt issuance costs.......................................................................................
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 .....................................................
Purchases of businesses, net of cash acquired (Note 3).....................................................
Proceeds from dispositions of equity-method investments (Note 6) .................................
Purchases of and contributions to equity-method investments (Note 6) ...........................
Other – net..........................................................................................................................
Net cash provided (used) by investing activities.....................................................
Increase (decrease) in cash and cash equivalents .................................................................
Cash and cash equivalents at beginning of year ...................................................................
Cash and cash equivalents at end of year .............................................................................
_________
(1) Increases to property, plant, and equipment....................................................................
Changes in related accounts payable and accrued liabilities...........................................
Capital expenditures........................................................................................................
$
$
$
1,714
376
(375)
657
(122)
186
2
464
29
57
—
34
5
21
(46)
153
(176)
3,693
(4)
767
(909)
10
1,334
(1,842)
(124)
36
—
(13)
(745)
(2,109)
(40)
52
(2)
(728)
485
(453)
(32)
(2,827)
121
168
289
$
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
(2,023) $
(86)
(2,109) $
(3,021) $
(235)
(3,256) $
(2,662)
263
(2,399)
See accompanying notes.
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 and 2017 associated with reinvested
distributions of $46 million and $61 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 16 – 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 and are presented within the following reportable segments: Atlantic-Gulf,
Northeast G&P, and West, consistent with the manner in which our chief operating decision maker evaluates performance
and allocates resources. All remaining business activities as well as corporate activities are included in Other.
Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transcontinental Gas Pipe Line Company, LLC
(Transco), and 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 LLC (Gulfstar One) (a consolidated variable interest
entity, or VIE), which is a proprietary floating production system, 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, at December 31, 2019, a 41 percent equity-method investment in Constitution Pipeline
Company, LLC (Constitution) (see Note 4 – Variable Interest Entities).
Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus
Shale region primarily in Pennsylvania and New York, 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 VIE) which operates in Ohio, a 69 percent
equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 58 percent equity-method
81
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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). Northeast G&P includes a 65 percent interest in Ohio Valley Midstream
LLC (Northeast JV) (a consolidated VIE) which operates in West Virginia, Ohio, and Pennsylvania. The Northeast JV
includes our Ohio Valley assets and Utica East Ohio Midstream LLC (UEOM), a former equity-method investment in
which we acquired the remaining ownership interest in March 2019 (see Note 3 – Acquisitions and Divestitures).
West is comprised of our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline), and our
gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, 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, a 50 percent equity-method investment
in Overland Pass Pipeline Company LLC (OPPL), a 50 percent equity-method investment in Rocky Mountain Midstream
Holdings LLC (RMM), and a 15 percent equity-method investment in Brazos Permian II, LLC (Brazos Permian II).
West also included our former natural gas gathering and processing assets in the Four Corners area of New Mexico
and Colorado, which were sold during the fourth quarter of 2018 (see Note 3 – Acquisitions and Divestitures), our
former 50 percent interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope) (an equity-method investment
following deconsolidation as of June 30, 2018), which was sold in April 2019, and our previously owned 50 percent
equity-method investment in the Delaware basin gas gathering system (DBJV) (see Note 6 – Investing Activities).
Other includes minor business activities that are not operating segments, as well as corporate operations. Other
also includes our previously owned operations, including an 88.5 percent undivided interest in an olefins production
facility in Geismar, Louisiana (Geismar Interest), which was sold in July 2017 (see Note 3 – Acquisitions and
Divestitures), and a refinery grade propylene splitter in the Gulf region, which was sold in June 2017.
Basis of Presentation
Discontinued operations
Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our
continuing operations.
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 result in impairment, or that the fair value of
the reporting unit for our goodwill is less than its carrying amount, which would result in impairment.
Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the accounts of all entities that we control and our proportionate
interest in the accounts of certain ventures in which we own an undivided interest. Our judgment is required to evaluate
whether we control an entity. Key areas of that evaluation include:
• Determining whether an entity is a VIE;
82
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
• Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the
VIE most significantly impact its economic performance and the degree of power that we and our related
parties have over those activities through our variable interests;
•
Identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating
whether we are a VIE’s primary beneficiary;
• Evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant
decisions that would be expected to be made in the ordinary course of business such that we do not have the
power to control such entities.
We apply the equity method of accounting to investments over which we exercise significant influence but do not
control. Distributions received from equity-method investees are presented in the Consolidated Statement of Cash
Flows according to the nature of the distributions approach, which classifies distributions received from equity-method
investees as either returns on investment (cash inflows from operating activities) or returns of investment (cash inflows
from investing activities) based on the nature of the activities of the equity-method investee that generated the
distribution.
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 management to make estimates and assumptions that affect the amounts reported in the consolidated
financial statements and accompanying notes. Actual results could differ from those estimates.
Significant estimates and assumptions include:
•
Impairment assessments of investments, property, plant, and equipment, goodwill, and other identifiable
intangible assets;
• Litigation-related contingencies;
• Environmental remediation obligations;
• 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;
83
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
• Measurement of deferred income tax assets and liabilities, including assumptions related to the realization of
deferred income tax assets;
• Revenue recognition, including estimates utilized in recognition of deferred revenue;
• Purchase price accounting.
These estimates are discussed further throughout these notes.
Regulatory accounting
Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC). Their rates,
which are established by the FERC, are designed to recover the costs of providing the regulated services, and their
competitive environment makes it probable that such rates can be charged and collected. Therefore, we have determined
that it is appropriate under Accounting Standards Codification (ASC) Topic 980, “Regulated Operations,” (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 established. Accounting for these operations that are regulated can differ from the
accounting requirements for nonregulated operations. For example, for regulated operations, allowance for funds used
during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in the
process of construction and is capitalized as a cost of property, plant, and equipment because it constitutes an actual
cost of construction under established regulatory practices; nonregulated operations are only allowed to capitalize the
cost of debt funds related to construction activities, while a component for equity is prohibited. The components of our
regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset
retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, pension and other
postretirement benefits, and rate allowances for deferred income taxes at a historically higher federal income tax rate.
In December 2017, the Tax Cuts and Jobs Act (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. Adjustments recorded in 2018 decreased this amount by $17 million. For
Transco, the timing and actual amount of the return to the customers is stated in its formal stipulation and agreement
that has been filed, subject to FERC approval (See Note 19 – Contingent Liabilities and Commitments).
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.
84
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2019 and 2018
are as follows:
December 31,
2019
2018
Current assets reported within Other current assets and deferred charges ........................... $
Noncurrent assets reported within Regulatory assets, deferred charges, and other ..............
Total regulated assets ...................................................................................................... $
$
(Millions)
72
466
538
$
103
495
598
Current liabilities reported within Accrued liabilities............................................................ $
Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other ....
Total regulated liabilities................................................................................................. $
60
1,277
1,337
$
$
5
1,321
1,326
Cash and cash equivalents
Cash and cash equivalents in the Consolidated Balance Sheet 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
85
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that is attributable to capitalized
ARO cost to a regulatory asset as we expect to recover these amounts in future rates. We measure changes in the liability
due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in
the carrying amount of the liability and as a corresponding accretion expense included in Operating and maintenance
expenses in the Consolidated Statement of Operations, except for regulated entities, for which the liability is offset by
a regulatory asset. The regulatory asset is amortized commensurate with our collection of those costs in rates.
Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party
would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred
to as a market-risk premium.
Goodwill
Goodwill included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet
represents the excess of the consideration, plus the fair value of any noncontrolling interest or any previously held
equity interest, over the fair value of the net assets acquired. It is not subject to amortization but is evaluated annually
as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more
likely than not that the fair value of the reporting unit is less than its carrying amount. As part of the evaluation, we
compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying
value of the reporting unit exceeds its fair value, an impairment charge is recorded for the difference (not to exceed the
carrying value of goodwill). Judgments and assumptions are inherent in our management’s estimates of fair value.
Other intangible assets
Our identifiable intangible assets included within Intangible assets – net of accumulated amortization in the
Consolidated Balance Sheet are primarily related to gas gathering, processing, and fractionation contractual customer
relationships. Our intangible assets are amortized on a straight-line basis over the period in which these assets contribute
to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any
changes prospectively through amortization over the revised remaining useful life.
Impairment of property, plant, and equipment, other identifiable intangible assets, and investments
We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events
or changes in circumstances indicate, in our judgment, that the carrying value of such assets may not be recoverable.
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.
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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 15 – Debt and Banking Arrangements.)
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, at cost in the Consolidated Balance Sheet. Gains and losses on the subsequent reissuance
of shares are credited or charged to Capital in excess of par value in the Consolidated Balance Sheet using the average-
cost method.
Derivative instruments and hedging activities
We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily
of swaps, futures, and forward contracts involving short- and long-term purchases and sales of energy commodities.
We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has
been elected, in Other current assets and deferred charges; Regulatory assets, deferred charges, and other; Accrued
liabilities; or Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet. We determine the
current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report
these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties
on a gross basis. (See Note 18 – 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.
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Notes to Consolidated Financial Statements – (Continued)
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
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 effective January 1, 2018)
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.
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, in our judgment, 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
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Notes to Consolidated Financial Statements – (Continued)
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
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
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Notes to Consolidated Financial Statements – (Continued)
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
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 in the Consolidated Statement of Operations 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.
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Notes to Consolidated Financial Statements – (Continued)
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.
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.
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Notes to Consolidated Financial Statements – (Continued)
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 MVCs. If a customer under such an agreement
fails to meet its MVC 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 MVC for that
period. The revenue associated with MVCs 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.
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.
Leases (subsequent to the adoption of ASU 2016-02 effective January 1, 2019)
We recognize a lease liability with an offsetting right-of-use asset in our Consolidated Balance Sheet for operating
leases based on the present value of the future lease payments. We have elected to combine lease and nonlease
components for all classes of leased assets in our calculation of the lease liability and the offsetting right-of-use asset.
Our lease agreements require both fixed and variable periodic payments, with initial terms typically ranging from
one year to 15 years, but a certain land lease has a term of 108 years. Payment provisions in certain of our lease
agreements contain escalation factors which may be based on stated rates or a change in a published index at a future
time. The amount by which a lease escalates based on the change in a published index, which is not known at lease
commencement, is considered a variable payment and is not included in the present value of the future lease payments,
which only includes those that are stated or can be calculated based on the lease agreement at lease commencement.
In addition to the noncancellable periods, many of our lease agreements provide for one or more extensions of the lease
agreement for periods ranging from one year in length to an indefinite number of times following the specified contract
term. Other lease agreements provide for extension terms that allow us to utilize the identified leased asset for an
indefinite period of time so long as the asset continues to be utilized in our operations. In consideration of these renewal
features, we assess the term of the lease agreements, which includes using judgment in the determination of which
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Notes to Consolidated Financial Statements – (Continued)
renewal periods and termination provisions, when at our sole election, will be reasonably certain of being exercised.
Periods after the initial term or extension terms that allow for either party to the lease to cancel the lease are not
considered in the assessment of the lease term. Additionally, we have elected to exclude leases with an original term
of one year or less, including renewal periods, from the calculation of the lease liability and the offsetting right-of-use
asset.
We use judgment in determining the discount rate upon which the present value of the future lease payments is
determined. This rate is based on a collateralized interest rate corresponding to the term of the lease agreement using
company, industry, and market information available.
When permitted under our lease agreements, we may sublease certain unused office space for fixed periods that
could extend up to the length of the original lease agreement.
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 17 – 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.
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 plan.
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
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Notes to Consolidated Financial Statements – (Continued)
value of plan assets for our other postretirement benefit plan 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
In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update
(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 prior
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 are 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.”
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 nonlease 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. We prospectively adopted ASU 2016-02 effective January 1, 2019, and did not adjust prior periods as permitted
by ASU 2018-11 (see Note 11 – Leases).
We completed our review of contracts to identify leases based on the modified definition of a lease and implemented
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. The most significant changes to our financial statements as a result of adopting ASU 2016-02
relate to the recognition of a $225 million lease liability and offsetting right-of-use asset in our Consolidated Balance
Sheet for operating leases. We also evaluated ASU 2016-02’s available practical expedients on adoption and have
generally elected to adopt the practical expedients, which includes the practical expedient to not separate lease and
nonlease components by both lessees and lessors by class of underlying assets and the land easements practical expedient.
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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 us for interim and annual periods beginning after December 15, 2019. We are adopting ASU 2016-13
effective January 1, 2020. We anticipate that ASU 2016-13 will primarily apply to our trade receivables. While we do
not expect a significant financial impact, we have analyzed our historical credit loss experience, and considered current
conditions and reasonable forecasts, in developing our expected credit loss rate, and continue to develop and implement
processes, procedures, and internal controls in order to make the necessary credit loss assessments and required
disclosures upon adoption.
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Notes to Consolidated Financial Statements – (Continued)
Note 2 – Revenue Recognition
Revenue by Category
The following table presents our revenue disaggregated by major service line:
Transco
Northwest
Pipeline
Atlantic-
Gulf
Midstream
Northeast
Midstream
West
Midstream
(Millions)
Other
Eliminations
Total
2019
Revenues from contracts with
customers:
Service revenues:
Non-regulated gathering,
processing, transportation,
and storage:
Monetary consideration ....... $
Commodity consideration ...
— $
—
— $
—
Regulated interstate natural
gas transportation and
storage .................................
Other ......................................
Total service revenues ........
Product Sales:
2,336
11
2,347
NGL and natural gas ..............
106
Total revenues from contracts with
customers ..................................
Other revenues (1) ........................
Total revenues..................... $
2,453
1
2,454
$
450
—
450
—
450
—
450
$
2018
Revenues from contracts with
customers:
Service revenues:
Non-regulated gathering,
processing, transportation,
and storage:
Monetary consideration ....... $
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) ........................
Total revenues ..................... $
______________________________
1,921
2
1,923
127
—
127
2,050
11
2,061
$
443
—
443
—
—
—
443
—
443
$
479
41
—
26
546
185
731
8
739
541
59
—
17
617
307
—
307
924
18
942
$
$
1,171
12
$
1,309
150
— $
—
(75) $
—
$
$
—
147
1,330
150
1,480
20
1,500
861
20
—
94
975
287
—
287
1,262
21
1,283
$
—
42
1,501
1,795
3,296
14
3,310
$
$
1,590
321
—
46
1,957
2,421
21
2,442
4,399
12
4,411
$
—
—
—
—
—
30
30
2
—
—
—
2
—
—
—
2
32
34
$
$
$
$
$
(6)
(16)
(97)
(173)
(270)
(12)
(282) $
(73) $
—
(2)
(15)
(90)
(382)
(4)
(386)
(476)
(12)
(488) $
$
2,884
203
2,780
210
6,077
2,063
8,140
61
8,201
2,921
400
2,362
144
5,827
2,760
17
2,777
8,604
82
8,686
(1) Revenues not within the scope of ASC 606, “Revenue from Contracts with Customers,” consist of leasing revenues
associated with our headquarters building and management fees that we receive for certain services we provide to
operated equity-method investments, which are reported in Service revenues in our Consolidated Statement of
Operations, and amounts associated with our derivative contracts, which are reported in Product sales in our
Consolidated Statement of Operations.
96
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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.............................................................................................. $
Contract Liabilities
The following table presents a reconciliation of our contract liabilities:
Year Ended December 31,
2019
2018
(Millions)
4
62
(58)
8
$
$
4
66
(66)
4
Year Ended December 31,
2019
2018
(Millions)
Balance at beginning of period ................................................................................... $
Payments received and deferred ............................................................................
Significant financing component...........................................................................
Deconsolidation of Jackalope interest (Note 6).....................................................
Deconsolidation of certain Permian assets (Note 6)..............................................
Recognized in revenue...........................................................................................
Balance at end of period.............................................................................................. $
1,397
157
13
—
—
(352)
1,215
$
$
1,596
314
16
(52)
(26)
(451)
1,397
Remaining Performance Obligations
Remaining performance obligations primarily include reservation charges on contracted capacity for our gas
pipeline firm transportation contracts with customers, storage capacity contracts, long-term contracts containing
minimum volume commitments associated with our midstream businesses, and fixed payments associated with offshore
production handling. For our interstate natural gas pipeline businesses, remaining performance obligations 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 are not currently known.
Our remaining performance obligations exclude variable consideration, including contracts with variable
consideration for which we have elected the practical expedient for consideration recognized in revenue as billed.
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, 2019, do not consider potential future
performance obligations for which the renewal has not been exercised and excludes contracts with customers for which
the underlying facilities have not received FERC authorization to be placed into service. Consideration received prior
to December 31, 2019, that will be recognized in future periods is also excluded from our remaining performance
obligations and is instead reflected in contract liabilities.
The following table presents the amount of the contract liabilities balance expected to be recognized as revenue
when performance obligations are satisfied and the transaction price allocated to the remaining performance obligations
under certain contracts as of December 31, 2019.
97
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Contract
Liabilities
Remaining
Performance
Obligations
2020................................................................................................................................. $
2021.................................................................................................................................
2022.................................................................................................................................
2023.................................................................................................................................
2024.................................................................................................................................
Thereafter ........................................................................................................................
Total.............................................................................................................................. $
Note 3 – Acquisitions and Divestitures
UEOM
$
(Millions)
160
121
113
101
91
629
1,215
$
3,418
3,241
3,117
2,524
2,339
18,815
33,454
As of December 31, 2018, we owned a 62 percent interest in UEOM which we accounted for as an equity-method
investment. On March 18, 2019, we signed and closed the acquisition of the remaining 38 percent interest in UEOM.
Total consideration paid, including post-closing adjustments, was $741 million in cash funded through credit facility
borrowings and cash on hand. As a result of acquiring this additional interest, we obtained control of and now consolidate
UEOM.
UEOM is involved primarily in the processing and fractionation of natural gas and natural gas liquids in the Utica
Shale play in eastern Ohio. The purpose of the acquisition was to enhance our position in the region. We expect synergies
through common ownership of UEOM and our Ohio Valley midstream systems to create a more efficient platform for
capital spending in the region, resulting in reduced operating and maintenance expenses and creating enhanced
capabilities and benefits for producers in the area.
The acquisition of UEOM was accounted for as a business combination, which requires, among other things, that
identifiable assets acquired and liabilities assumed be recognized at their acquisition date fair values. In March 2019,
based on the transaction price for our purchase of the remaining interest in UEOM as finalized just prior to the acquisition,
we recognized a $74 million noncash impairment loss related to our existing 62 percent interest (see Note 18 – Fair
Value Measurements, Guarantees, and Concentration of Credit Risk). Thus, there was no gain or loss on remeasuring
our existing equity-method investment to fair value due to the impairment recognized just prior to closing the acquisition
of the additional interest.
The valuation techniques used to measure the acquisition date fair value of the UEOM acquisition consisted of the
market approach for our previous equity-method investment in UEOM and the income approach (excess earnings
method) for valuation of intangible assets and depreciated replacement costs for property, plant, and equipment.
The following table presents the allocation of the acquisition date fair value of the major classes of the assets
acquired, which are presented in the Northeast G&P segment, and liabilities assumed at March 18, 2019. The net assets
acquired reflect the sum of the consideration transferred and the noncash elimination of the fair value of our existing
equity-method investment upon our acquisition of the additional interest. The fair value of accounts receivable acquired,
presented in current assets in the table, equals contractual amounts receivable. After the March 31, 2019 financial
statements were issued, we received an updated valuation report from a third-party valuation firm. Significant changes
from the preliminary allocation disclosed in the first quarter to the final allocation, which were recorded in the second
quarter of 2019, reflect an increase of $169 million in goodwill, and decreases of $106 million in property, plant, and
equipment and $61 million in other intangible assets.
98
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Current assets, including $13 million cash acquired ................................................................................ $
Property, plant, and equipment .................................................................................................................
Other intangible assets..............................................................................................................................
Total identifiable assets acquired ..........................................................................................................
Current liabilities ......................................................................................................................................
Total liabilities assumed........................................................................................................................
(Millions)
55
1,387
328
1,770
7
7
Net identifiable assets acquired.............................................................................................................
1,763
Goodwill ...................................................................................................................................................
Net assets acquired................................................................................................................................ $
188
1,951
The goodwill recognized in the acquisition relates primarily to enhancing and diversifying our basin positions and
is reported within the Northeast G&P segment. Substantially all of the goodwill is expected to be deductible for tax
purposes. Goodwill is included within Intangible assets – net of accumulated amortization in the Consolidated Balance
Sheet and represents the excess of the consideration, plus the fair value of any previously held equity interest, over the
fair value of the net assets acquired.
Other intangible assets recognized in the acquisition are related to contractual customer relationships from gas
gathering, processing, and fractionation agreements with our customers. The basis for determining the value of these
intangible assets is estimated future net cash flows to be derived from acquired contractual customer relationships
discounted using a risk-adjusted discount rate. These intangible assets are being amortized on a straight-line basis over
a period of 20 years which represents the term over which the contractual customer relationships are expected to
contribute to our cash flows. Approximately 49 percent of the expected future revenues from these contractual customer
relationships are impacted by our ability and intent to renew or renegotiate existing customer contracts. 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 current contract periods (as estimated at the time of the acquisition),
the weighted-average period prior to the next renewal or extension of the existing contractual customer relationships
was approximately 10 years.
The following unaudited pro forma Revenues and Net income (loss) attributable to The Williams Companies, Inc.
for the years ended December 31, 2019 and 2018, respectively, are presented as if the UEOM acquisition had been
completed on January 1, 2018. These pro forma amounts are not necessarily indicative of what the actual results would
have been if the acquisition had in fact occurred on the date or for the periods indicated, nor do they purport to project
Revenues or Net income (loss) attributable to The Williams Companies, Inc. for any future periods or as of any date.
These amounts do not give effect to any potential cost savings, operating synergies, or revenue enhancements to result
from the transaction or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements.
Revenues................................................................................................................................. $
Net income (loss) attributable to The Williams Companies, Inc............................................
(Millions)
8,233
$
928
8,836
(128)
Adjustments to pro forma Net income (loss) attributable to The Williams Companies, Inc. include the removal of
the previously described $74 million impairment loss recognized in March 2019 just prior to the acquisition.
Year Ended December 31,
2019
2018
99
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
During the period from the acquisition date of March 18, 2019 to December 31, 2019, UEOM contributed Revenues
of $179 million and Net income (loss) attributable to The Williams Companies, Inc. of $53 million.
Costs related to this acquisition are $4 million and are reported within our Northeast G&P segment and included
in Selling, general, and administrative expenses in our Consolidated Statement of Operations.
Northeast JV
Concurrent with the UEOM acquisition, we executed an agreement whereby we contributed our consolidated
interests in UEOM and our Ohio Valley midstream business to a newly formed partnership. In June 2019, our partner
invested approximately $1.33 billion for a 35 percent ownership interest, and we retained 65 percent ownership of, as
well as operate and consolidate, the Northeast JV business. The change in ownership due to this transaction increased
Noncontrolling interests in consolidated subsidiaries by $567 million, and decreased Capital in excess of par value by
$426 million and Deferred income tax liabilities by $141 million in the Consolidated Balance Sheet. Costs related to
this transaction are $6 million and are reported within our Northeast G&P segment and included in Selling, general,
and administrative expenses in our Consolidated Statement of Operations.
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. 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 18 – 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. 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:
Year Ended December 31,
2018
2017
Income (loss) before income taxes of Four Corners area ....................................................... $
Income (loss) before income taxes of Four Corners area attributable to The Williams
Companies, Inc....................................................................................................................
(Millions)
52
$
43
47
35
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.
100
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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. .....
26
19
Year Ended
December 31,
2017
(Millions)
Note 4 – Variable Interest Entities
Consolidated VIEs
As of December 31, 2019, 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.
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.
Northeast JV
As a result of the June 2019 sale of a 35 percent interest in the Northeast JV (Note 3 – Acquisitions and Divestitures),
we now own a 65 percent interest in the Northeast JV, a subsidiary that is a VIE due to certain of our voting rights being
disproportionate to our obligation to absorb losses and substantially all of the Northeast JV’s activities being performed
on our behalf. We are the primary beneficiary because we have the power to direct the activities that most significantly
impact the Northeast JV’s economic performance. The Northeast JV provides midstream services for producers in the
Marcellus Shale and Utica Shale regions. Future expansion activity is expected to be funded with capital contributions
from us and the other equity partner on a proportional basis.
101
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The following table presents amounts included in our Consolidated Balance Sheet that are only for the use or
obligation of our consolidated VIEs:
December 31,
2019
2018
(Millions)
Assets (liabilities):
Cash and cash equivalents............................................................................................. $
Trade accounts and other receivables – net...................................................................
Other current assets and deferred charges ....................................................................
Property, plant, and equipment – net.............................................................................
Intangible assets – net of accumulated amortization.....................................................
Regulatory assets, deferred charges, and other.............................................................
Accounts payable ...........................................................................................................
Accrued liabilities ..........................................................................................................
Regulatory liabilities, deferred income, and other ........................................................
$
102
167
5
5,745
2,669
13
(58)
(66)
(283)
33
62
2
2,363
1,177
—
(15)
(115)
(264)
Nonconsolidated VIEs
Jackalope
At December 31, 2018, we owned a 50 percent interest in Jackalope, which provides gathering and processing
services for the Powder River basin and was a VIE due to certain risks shared with customers. In April 2019, we sold
our interest in Jackalope for $485 million in cash (see Note 6 – Investing Activities).
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, 2019, the carrying value of our investment in Brazos Permian II was $194
million. Our maximum exposure to loss is limited to the carrying value of our investment.
Constitution
As of December 31, 2019, we own a 41 percent interest in Constitution, a subsidiary which proposed a pipeline
project extending from Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas
Pipeline systems in New York. Constitution was considered a VIE due to shipper fixed-payment commitments under
its long-term firm transportation contracts, and we were the primary beneficiary because we had the power to direct
the activities that most significantly impacted Constitution’s economic performance during its construction phase. Thus,
prior to December 31, 2019, we consolidated Constitution.
Although Constitution received a certificate of public convenience and necessity from the FERC to construct and
operate the proposed pipeline and obtained, among other approvals, a waiver of the water quality certification under
Section 401 of the Clean Water Act for the New York portion of the project, the members of Constitution, following
extensive evaluation and discussion, recently determined that the underlying risk-adjusted return for this greenfield
pipeline project has diminished in such a way that further development is no longer supported. Accordingly, we
recognized a $354 million impairment of the consolidated capitalized project costs in the fourth quarter of 2019, which
considered our estimate of the fair value of the disposal group under various probability-weighted disposal alternatives.
(See Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) Our partners’ $209 million
share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in the Consolidated
Statement of Operations.
102
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Constitution is still considered a VIE due to insufficient equity at risk, but we are no longer the primary beneficiary.
As a result, we deconsolidated Constitution as of December 31, 2019, recognizing a loss on deconsolidation of $27
million in the fourth quarter of 2019, which is included in Other investing income (loss) - net in the Consolidated
Statement of Operations.
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 $304 million, $236 million, and $226 million for the years ended 2019, 2018, and 2017, respectively.
We have $36 million and $18 million included in Accounts payable in the Consolidated Balance Sheet with our equity-
method investees at December 31, 2019 and 2018, 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
$103 million, $75 million, and $67 million for the years ended 2019, 2018, and 2017, respectively.
Note 6 – Investing Activities
Other investing income (loss) – net
The following table presents certain items reflected in Other investing income (loss) – net in the Consolidated
Statement of Operations:
Year Ended December 31,
2019
2018
2017
(Millions)
Impairment of equity-method investments (Note 18) .................................... $
Gain (loss) on deconsolidation of businesses .................................................
Gain on disposition of equity-method investments ........................................
Other ...............................................................................................................
Other investing income (loss) – net ................................................................ $
(186) $
(29)
122
14
(79) $
(32) $
203
—
16
187
$
—
—
269
13
282
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, but
increased to 50 percent at December 31, 2018, based on additional capital contributions made after the initial purchase.
103
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Jackalope Deconsolidation
During the second quarter of 2018, we deconsolidated our 50 percent 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 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.
Sale of Jackalope
In April 2019, we sold our 50 percent equity-method interest in Jackalope for $485 million in cash, resulting in a
gain on the disposition of $122 million, reflected in Other investing income (loss) – net in the Consolidated Statement
of Operations.
Constitution Deconsolidation
We deconsolidated our interest in Constitution as of December 31, 2019, recognizing a loss on deconsolidation of
$27 million. See Note 4 – Variable Interest Entities for further discussion.
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.
104
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Equity-Method Investments
Ownership
Interest at
December 31,
2019
Appalachia Midstream Investments .....................................................................
RMM ....................................................................................................................
Discovery .............................................................................................................
Caiman II .............................................................................................................
OPPL ....................................................................................................................
Laurel Mountain ...................................................................................................
Gulfstream ............................................................................................................
Brazos Permian II .................................................................................................
UEOM ..................................................................................................................
Jackalope ..............................................................................................................
Other ....................................................................................................................
(1)
50%
60%
58%
50%
69%
50%
15%
(2)
(3)
Various
December 31,
2019
2018
(Millions)
3,236
881
472
428
403
249
217
194
—
—
155
6,235
$
$
3,218
776
507
412
415
314
225
191
1,293
343
127
7,821
$
$
___________
(1) Includes equity-method investments in multiple gathering systems in the Marcellus Shale with an approximate
average 66 percent interest.
(2) At December 31, 2018, we owned a 62 percent interest in UEOM. On March 18, 2019, we acquired the
remaining 38 percent interest. As a result of acquiring this additional interest, we obtained control of and now
consolidate UEOM.
(3) At December 31, 2018, we owned a 50 percent interest in Jackalope. In April 2019, we sold our interest in
Jackalope.
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 billion at December 31, 2019 and $1.8 billion at December 31, 2018. These
differences primarily relate to our investments in Appalachia Midstream Investments (and UEOM at December 31,
2018), 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 ................................................................
Laurel Mountain ..............................................................................................
Caiman II .........................................................................................................
Jackalope .........................................................................................................
Brazos Permian II ............................................................................................
Discovery.........................................................................................................
DBJV ...............................................................................................................
Other ................................................................................................................
$
Year Ended December 31,
2019
2018
(Millions)
2017
145
140
36
28
24
18
—
—
62
453
$
$
795
246
16
—
42
27
5
—
1
1,132
$
$
—
70
—
24
—
—
1
32
5
132
105
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 ...............................................................................................................
Caiman II .........................................................................................................
Discovery.........................................................................................................
RMM ...............................................................................................................
Laurel Mountain ..............................................................................................
UEOM .............................................................................................................
DBJV ...............................................................................................................
Other ................................................................................................................
$
Year Ended December 31,
2019
2018
(Millions)
2017
293
86
77
42
41
38
30
13
—
37
657
$
$
297
93
73
46
45
—
23
70
—
46
693
$
$
270
92
68
49
127
—
32
80
39
27
784
Summarized Financial Position and Results of Operations of All Equity-Method Investments
December 31,
2019
2018
(Millions)
Assets (liabilities):
Current assets..................................................................................................................... $
Noncurrent assets...............................................................................................................
Current liabilities ...............................................................................................................
Noncurrent liabilities .........................................................................................................
$
581
11,966
(341)
(2,532)
834
13,199
(605)
(2,491)
Gross revenue .................................................................................................. $
Operating income ............................................................................................
Net income.......................................................................................................
$
2,490
685
598
$
2,411
804
795
1,961
871
806
Year Ended December 31,
2019
2018
(Millions)
2017
106
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Note 7 – Other Income and Expenses
The following tables present by segment, certain other items included in our Consolidated Statement of Operations:
Year Ended December 31,
2019
2018
2017
(Millions)
Other (income) expense – net within Costs and expenses
Atlantic-Gulf
Amortization of regulatory assets associated with asset retirement obligations ...... $
21
$
33
$
33
22
16
—
—
—
—
(15)
22
4
—
(12)
24
12
—
(37)
—
—
(12)
Net accrual (amortization) of regulatory liability related to overcollection of
certain employee expenses ...................................................................................
Project development costs related to Constitution (see Note 4) ..............................
Amortization of regulatory liability associated with Tax Reform............................
Gains on asset retirements .......................................................................................
West
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......
Gains on contract settlements and terminations ......................................................
Other
Change to (benefit of) regulatory asset associated with Transco’s estimated
deferred state income tax rate following WPZ Merger ........................................
Gain on sale of refinery grade propylene splitter ....................................................
(17)
3
(26)
—
24
—
—
12
—
107
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Year Ended December 31,
2019
2018
2017
(Millions)
Other income (expense) – net below Operating income (loss)
Atlantic-Gulf
Allowance for equity funds used during construction ............................................. $
Settlement charge from pension early payout program ...........................................
Regulatory adjustments resulting from Tax Reform ...............................................
29
—
—
$
87
$
(7)
—
70
(15)
(33)
Northeast G&P
Settlement charge from pension early payout program ...........................................
—
(4)
(7)
West
Settlement charge from pension early payout program ...........................................
Regulatory adjustments resulting from Tax Reform ...............................................
Other
Income associated with a regulatory asset related to deferred taxes on equity
funds used during construction ............................................................................
Net gain (loss) associated with early retirement of debt .........................................
Settlement charge from pension early payout program ...........................................
Regulatory adjustments resulting from Tax Reform ...............................................
—
—
9
—
—
—
(6)
—
35
(7)
(5)
(1)
(13)
(6)
52
27
(35)
(63)
Severance and other related costs included within Operating and maintenance expenses and Selling, general, and
administrative expenses are as follows:
Atlantic-Gulf ............................................................................................................. $
Northeast G&P ..........................................................................................................
West ...........................................................................................................................
Other ..........................................................................................................................
Year Ended December 31,
2019
2018
2017
(Millions)
$ — $ —
—
—
—
—
—
22
32
7
17
1
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 16 – Stockholders' Equity) and $20 million for WPZ Merger related
costs within the Other segment.
108
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............................................................................................................
Provision (benefit) for income taxes............................................................... $
Year Ended December 31,
2019
2018
(Millions)
2017
(41) $
(5)
2
(44)
280
99
379
335
$
(83) $
1
—
(82)
183
37
220
138
$
15
23
—
38
(2,004)
(8)
(2,012)
(1,974)
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).....
Federal valuation allowance..............................................................
Other – net.........................................................................................
Provision (benefit) for income taxes..................................................... $
Year Ended December 31,
2019
2018
(Millions)
2017
224
$
69
$
187
29
—
74
—
2
3
3
335
$
(73)
—
(10)
38
—
105
9
138
$
(117)
(1,932)
(17)
26
(127)
—
6
(1,974)
Income (loss) from continuing operations before income taxes includes $6 million, $3 million, and $7 million of
foreign loss in 2019, 2018, and 2017, respectively.
Foreign operations – net (including tax effect of Canadian Sale) in 2017 reflects the release of a valuation allowance
associated with impairments and losses on the sale of our Canadian operations.
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
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.
109
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Significant components of Deferred income tax liabilities and Deferred income tax assets are as follows:
Deferred income tax liabilities:
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,
2019
2018
(Millions)
1,921
1,411
82
3,414
729
29
140
544
362
147
1,951
319
1,632
1,782
$
$
2,317
295
30
2,642
667
71
140
147
319
94
1,438
320
1,118
1,524
The valuation allowance at December 31, 2019 and 2018, serves to reduce the available deferred income tax assets
to an amount that will, more likely than not, be realized. We considered 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 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 was recorded in 2018. 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 in 2018 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 $29 million will be refunded/utilized no later than
2021.
Federal loss carryovers include deferred tax assets of $5 million at the end of 2019 that are expected to be utilized
by us prior to expiration between 2020 and 2023. Deferred tax assets on net operating loss carryovers of $539 million
have no expiration date.
Cash refunds for income taxes (net of payments) were $86 million in 2019. Cash payments for income taxes (net
of refunds) were $11 million, and $28 million in 2018 and 2017, respectively.
As of December 31, 2019, we had approximately $51 million of unrecognized tax benefits. If recognized, income
tax expense would be reduced by $51 million for each of the years 2019 and 2018, 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:
110
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
2019
2018
Balance at beginning of period ............................................................................................. $
Additions for tax positions of prior years .............................................................................
Balance at end of period........................................................................................................ $
$
(Millions)
51
—
51
$
50
1
51
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 $500 thousand and $800 thousand for 2019
and 2018, respectively. Approximately $3 million of interest and penalties primarily relating to uncertain tax positions
have been accrued as of both December 31, 2019 and 2018.
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, excluding 2015, for which the statute expired on August 31, 2019. As of December 31, 2019, examinations
of tax returns for 2011 through 2013 are currently in process. We do not expect material changes in our financial position
resulting from these examinations. The statute of limitations for most states expires one year after expiration of the IRS
statute. Generally, tax returns for our previously owned Canadian entities are open to audit for tax years after 2012.
Tax years 2013 and 2014 are currently under income tax examination, while tax year 2016 is under Goods and Services
Tax (GST) examination. In September 2016, we sold the majority of our Canadian operations and, as part of the sale,
indemnified the purchaser for any increases in Canadian tax due to an audit of any tax periods prior to the sale.
Note 9 – Earnings (Loss) Per Common Share from Continuing Operations
Year Ended December 31,
2019
2018
2017
(Dollars in millions, except per-share
amounts; shares in thousands)
Income (loss) from continuing operations available to common stockholders ..... $
862
Basic weighted-average shares........................................................................ 1,212,037
Effect of dilutive securities:
(156) $
973,626
$
2,174
826,177
Nonvested restricted stock units...................................................................
Stock options ................................................................................................
1,811
163
Diluted weighted-average shares (1) ............................................................... 1,214,011
Earnings (loss) per common share from continuing operations:
—
—
973,626
1,704
637
828,518
Basic ............................................................................................................. $
Diluted .......................................................................................................... $
.71
.71
$
$
(.16) $
(.16) $
2.63
2.62
________________
(1) For the year ended December 31, 2018, 2.0 million weighted-average nonvested restricted stock units and 0.5
million weighted-average stock options have been excluded from the computation of diluted earnings (loss) per
common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to
The Williams Companies, Inc.
Note 10 – Employee Benefit Plans
We have noncontributory defined benefit pension plans in which 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
111
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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 2018, our defined benefit pension and our defined contribution plans were amended. Eligible employees hired
or rehired on or after January 1, 2019, are not eligible to participate in the pension plan, but are 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 no longer receive future compensation credits under the defined benefit pension plan, but are 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 continue to receive compensation credits under the defined benefit pension plans and
these employees are not 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). These amounts 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 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 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 net periodic benefit cost (credit)
and other changes in plan assets and benefit obligations recognized in other comprehensive income (loss) before taxes.
112
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
2019
2018
2019
2018
(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................................................. $
1,187
45
50
—
(111)
69
(3)
50
1,237
1,132
218
63
—
(111)
(3)
167
1,299
62
1,221
$
$
1,319
50
46
—
(35)
(90)
(103)
(132)
1,187
1,227
(45)
88
—
(35)
(103)
(95)
1,132
$
$
(55) $
1,171
186
1
8
2
(12)
30
—
29
215
214
38
5
2
(12)
—
33
247
32
$
$
206
1
7
2
(13)
(17)
—
(20)
186
227
(7)
5
2
(13)
—
(13)
214
28
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,
2019
2018
(Millions)
Overfunded (underfunded) pension plans:
Noncurrent assets ........................................................................................................... $
Current liabilities............................................................................................................
Noncurrent liabilities......................................................................................................
$
92
(3)
(27)
Overfunded (underfunded) other postretirement benefit plan:
Noncurrent assets ...........................................................................................................
Current liabilities............................................................................................................
38
(6)
—
(2)
(53)
34
(6)
The plan assets within our other postretirement benefit plan are 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.
113
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The pension plans’ benefit obligation Net actuarial loss (gain) of $69 million in 2019 is primarily due to the impact
of a decrease in the discount rates utilized to calculate the benefit obligation, partially offset by the impact of a decrease
in the cash balance interest crediting rate assumption. 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 2019 benefit obligation Net actuarial loss (gain) of $30 million for our other postretirement benefit plan is
primarily due a decrease in the discount rate used to calculate the benefit obligation and other assumption changes,
partially offset by the impact of benefit payment experience and tax law changes. 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 following table summarizes information for pension plans with obligations in excess of plan assets.
December 31,
2019
2018
(Millions)
Plans with a projected benefit obligation in excess of plan assets:
Projected benefit obligation ........................................................................................... $
Fair value of plan assets.................................................................................................
$
29
—
1,187
1,132
Plans with an accumulated benefit obligation in excess of plan assets:
Accumulated benefit obligation.....................................................................................
Fair value of plan assets.................................................................................................
26
—
367
326
Pre-tax amounts not yet recognized in Net periodic benefit cost (credit) at December 31 are as follows:
Pension Benefits
Other
Postretirement
Benefits
2019
2018
2019
2018
(Millions)
Amounts included in Accumulated other comprehensive
income (loss):
Net actuarial loss................................................................. $
(243) $
(347) $
(21) $
(12)
Amounts included in regulatory liabilities associated with
Transco and Northwest Pipeline:
Net actuarial gain................................................................
N/A
N/A $
11
$
4
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 $106 million at December 31, 2019 and $116 million at December 31, 2018, 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, 2019 and 2018, these regulatory liabilities were $43 million and
$49 million, respectively. These pension and other postretirement plans amounts will be reflected in rates based on the
rate structures of these gas pipelines.
114
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
2019
2018
2017
Other
Postretirement Benefits
2018
2019
2017
(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) ................................... $
45
50
(61)
—
15
1
—
50
$
$
50
46
(63)
—
23
23
—
79
$
$
50
59
(82)
—
27
71
—
125
$
$
1
8
(10)
—
—
—
1
$ — $
$
1
7
(11)
(2)
—
—
2
(3) $
1
8
(11)
(13)
—
—
3
(12)
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
2019
2018
2017
2019
2018
2017
(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..............................
88
—
15
1
$
(18) $
—
23
23
62
—
27
71
$
(9) $
—
—
—
9
—
—
—
$
(3)
(5)
—
—
Other changes in plan assets and benefit obligations
recognized in Other comprehensive income (loss) ......... $ 104
$
28
$ 160
$
(9) $
9
$
(8)
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 .......................................................
$
$
7
—
(10) $
(2)
6
(8)
2019
2018
2017
(Millions)
115
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
2019
2018
2019
2018
Discount rate ..............................................................................
Rate of compensation increase...................................................
Cash balance interest crediting rate ...........................................
3.19%
3.68
3.50
4.34%
4.83
4.25
3.27%
N/A
N/A
4.39%
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
2019
2018
2017
2019
2018
2017
4.33%
3.67%
4.17%
4.39%
3.71%
4.27%
5.26
4.83
4.25
5.34
4.93
4.25
6.45
4.87
4.25
5.01
N/A
N/A
4.95
N/A
N/A
5.53
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 2020 is 7.2 percent. This rate decreases to 4.5 percent by 2028.
Plan Assets
Plan assets for our pension and other postretirement benefit plans consist primarily of equity and fixed income
securities including mutual funds and commingled investment funds invested in equity and fixed income securities.
The plans’ investment policy provides for a strategy in accordance with the Employee Retirement Income Security Act
(ERISA), which governs the investment of the assets in a diversified portfolio. The plans follow a policy of diversifying
the investments across various asset classes and investment managers. Additionally, the investment returns on
approximately 37 percent of the other postretirement benefit plan assets are subject to income tax; therefore, certain
investments are managed in a tax efficient manner.
The investment policy for the pension plans includes a general target asset allocation at December 31, 2019, 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.
Equity securities may include U.S. equities and non-U.S. equities. Investment in Williams’ securities or an entity
in which Williams has a majority ownership is prohibited except where these securities may be owned in a commingled
investment fund in which the plans’ trusts invest. No more than 5 percent of the total stock portfolio valued at market
may be invested in the common stock of any one corporation.
Fixed income securities may consist of U.S. as well as international instruments, including emerging markets. The
fixed income strategies may invest in government, corporate, asset-backed securities, and mortgage-backed obligations.
The weighted-average credit rating of the fixed income strategies must be at least “investment grade” including ratings
by Moody’s and/or Standard & Poor’s. No more than 5 percent of the total fixed income portfolio may be invested in
the fixed income securities of any one issuer with the exception of bond index funds and U.S. government guaranteed
and agency securities.
116
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The following securities and transactions are not authorized: unregistered securities, commodities or commodity
contracts, short sales or margin transactions, or other leveraging strategies. Additionally, real estate equity, natural
resource property, venture capital, leveraged buyouts, and other high-return, high-risk investments are generally
restricted. Use of derivative securities in mutual funds and commingled investment funds held by the plans’ trusts is
allowed. However, direct investment in derivative securities requires approval. Currently, investment managers are
approved to enter into U.S. Treasury futures contracts on behalf of the plans to implement and manage duration and
yield curve strategy in the fixed income portfolio.
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, 2019 and 2018 by asset class are as follows:
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
2019
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
(Millions)
Total
Pension assets:
Cash management fund ................................................... $
Equity securities ..............................................................
Fixed income securities (1):
U.S. Treasury securities...............................................
Governments and municipal bonds .............................
Mortgage and asset-backed securities .........................
Corporate bonds...........................................................
Other ..............................................................................
$
Commingled investment funds measured at net asset
value practical expedient (2):
Equities — U.S. large cap ...........................................
Equities — Global large and mid cap..........................
Equities — International emerging markets................
Fixed income — U.S. long and intermediate duration
Fixed income — Corporate bonds...............................
Total assets at fair value at December 31, 2019.......
$
11
41
— $
22
— $
—
62
—
—
—
5
119
$
—
35
11
360
4
432
$
—
—
—
—
—
—
$
11
63
62
35
11
360
9
551
133
100
26
380
109
1,299
117
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
2018
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Total
Pension assets:
Cash management fund ............................................... $
Equity securities ..........................................................
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...
(Millions)
— $
—
—
21
48
210
6
285
$
$
10
52
157
—
—
—
—
219
$
— $
—
—
—
—
—
—
—
$
10
52
157
21
48
210
6
504
123
8
19
51
335
92
1,132
118
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The fair values of our other postretirement benefits plan assets at December 31, 2019 and 2018 by asset class are
as follows:
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
2019
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
(Millions)
Total
Other postretirement benefit assets:
Cash management funds ................................................. $
Equity securities ..............................................................
Fixed income securities (1):
U.S. Treasury securities...............................................
Governments 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 — Global large and mid cap..........................
Equities — International emerging markets................
Fixed income — U.S. long and intermediate duration
Fixed income — Corporate bonds...............................
Total assets at fair value at December 31, 2019.......
$
11
35
— $
9
— $
—
8
—
—
—
46
100
$
—
4
1
43
—
57
$
—
—
—
—
—
—
$
11
44
8
4
1
43
46
157
16
12
3
46
13
247
119
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
2018
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Total
Other postretirement benefit assets:
Cash management funds............................................... $
Equity securities ...........................................................
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....
(Millions)
— $
5
—
2
6
25
—
38
$
$
11
29
19
—
—
—
43
102
$
— $
—
—
—
—
—
—
—
$
11
34
19
2
6
25
43
140
14
1
2
6
40
11
214
____________
(1) The weighted-average credit quality rating of the fixed income security portfolio is investment grade with a
weighted-average duration of approximately 14 years for 2019 and 13 years for 2018.
(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 1 day 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.
120
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, 2019 and
2018. Additionally, there were no transfers or reclassifications of investments between Level 1 and Level 2 from
December 2018 to December 2019. 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.
2020........................................................................................................................... $
2021...........................................................................................................................
2022...........................................................................................................................
2023...........................................................................................................................
2024...........................................................................................................................
2025-2029 .................................................................................................................
Pension
Benefits
Other
Postretirement
Benefits
$
(Millions)
100
99
97
93
90
433
14
14
14
14
14
62
In 2020, we expect to contribute approximately $10 million to our tax-qualified pension plans and approximately
$3 million to our nonqualified pension plans, for a total of approximately $13 million, and approximately $6 million
to our other postretirement benefit plan.
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 contributions charged to expense were
$36 million in 2019, $35 million in 2018, and $34 million in 2017.
121
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Note 11 – Leases
We are a lessee through noncancellable lease agreements for property and equipment consisting primarily of
buildings, land, vehicles, and equipment used in both our operations and administrative functions.
Year Ended
December 31,
2019
(Millions)
Lease Cost:
Operating lease cost................................................................................................................................ $
Short-term lease cost...............................................................................................................................
Variable lease cost...................................................................................................................................
Sublease income .....................................................................................................................................
Total lease cost .................................................................................................................................... $
Cash paid for amounts included in the measurement of operating lease liabilities................................ $
40
—
27
(2)
65
39
December 31,
2019
(Millions)
Other Information:
Right-of-use asset (included in Regulatory assets, deferred charges, and other in our Consolidated
Balance Sheet)..................................................................................................................................... $
Operating lease liabilities:
Current (included in Accrued liabilities in our Consolidated Balance Sheet) .................................... $
Noncurrent (included in Regulatory liabilities, deferred income, and other in our Consolidated
Balance Sheet) ................................................................................................................................. $
207
21
188
Weighted-average remaining lease term – operating leases (years) .......................................................
Weighted-average discount rate – operating leases ................................................................................
13
4.61%
Prior to adopting ASU 2016-02, which was effective January 1, 2019 (see Note 1 – General, Description of Business,
Basis of Presentation, and Summary of Significant Accounting Policies), total rent expense was $73 million in 2018
and $62 million in 2017 and primarily included in Operating and maintenance expenses and Selling, general, and
administrative expenses in the Consolidated Statement of Operations.
122
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
As of December 31, 2019, the following table represents our operating lease maturities, including renewal
provisions that we have assessed as being reasonably certain of exercise, for each of the years ended December 31:
2020 ................................................................................................................................................... $
2021 ...................................................................................................................................................
2022 ...................................................................................................................................................
2023 ...................................................................................................................................................
2024 ...................................................................................................................................................
Thereafter ..........................................................................................................................................
Total future lease payments ...........................................................................................................
Less amount representing interest .....................................................................................................
Total obligations under operating leases........................................................................................ $
(Millions)
29
33
28
22
19
157
288
79
209
We are the lessor to certain lease agreements for office space in our headquarters building, which are insignificant
to our financial statements.
Note 12 – 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,
2019
2018
(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 .......................
0.00 - 33.33
1.25 - 7.13
5 - 45
$
$
$
17,593
354
2,519
15,324
778
2,356
18,076
586
2,382
41,510
(12,310)
29,200
$
17,312
965
1,926
38,661
(11,157)
27,504
__________
(1) Estimated useful life and depreciation rates are presented as of December 31, 2019. 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 $1.390 billion, $1.392 billion,
and $1.389 billion in 2019, 2018, and 2017, respectively.
Regulated Property, plant, and equipment – net includes approximately $547 million and $586 million at
December 31, 2019 and 2018, 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.
123
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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.
The following table presents the significant changes to our ARO, of which $1.117 billion and $968 million are
included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued liabilities
at December 31, 2019 and 2018, respectively.
December 31,
2019
2018
(Millions)
$
Beginning balance ......................................................................................................... $
Liabilities incurred.........................................................................................................
Liabilities settled ...........................................................................................................
Accretion expense .........................................................................................................
Revisions (1)..................................................................................................................
Ending balance .............................................................................................................. $
___________
(1) 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 2019 revisions
reflect changes in removal cost estimates, decreases in the estimated remaining useful life of certain assets, increases
in inflation rates, and decreases in the discount rates used in the annual review process. 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.
998
21
(19)
71
(39)
1,032
1,032
15
(8)
59
67
1,165
$
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 18 – 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 13 – Goodwill and Other Intangible Assets
Goodwill
Changes in the carrying amount of goodwill, included in Intangible assets – net of accumulated amortization in
the Consolidated Balance Sheet, by reportable segment for the periods indicated are as follows:
Northeast G&P
West
Total
December 31, 2017 ................................................................................... $
Jackalope Deconsolidation (see Note 6) ..............................................
December 31, 2018 ...................................................................................
UEOM Acquisition (see Note 3) .........................................................
December 31, 2019 ................................................................................... $
124
(Millions)
$
47
(47)
—
$
— $
— $
—
188
188
47
(47)
—
188
188
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Our goodwill is not subject to amortization, but is evaluated at least annually for impairment or more frequently
if impairment indicators are present. We did not identify or recognize any impairments to goodwill in connection with
our evaluation of goodwill for impairment during the years ended December 31, 2019, 2018, and 2017, respectively.
Other Intangible Assets
The gross carrying amount and accumulated amortization of other intangible assets, included in Intangible assets
– net of accumulated amortization in the Consolidated Balance Sheet, at December 31 are as follows:
2019
2018
Gross
Carrying
Amount
Accumulated
Amortization
Gross
Carrying
Amount
Accumulated
Amortization
(Millions)
Contractual customer relationships......................................... $
9,560
$
(1,789) $
9,232
$
(1,465)
Other intangible assets primarily relate to gas gathering, processing, and fractionation contractual customer
relationships recognized in acquisitions. The increase in the gross carrying amount of other intangible assets during
2019 is primarily related to the acquisition of UEOM (see Note 3 – Acquisitions and Divestitures). Other intangible
assets are being amortized on a straight-line basis over a period of 20 years for the acquisition of UEOM and 30 years
for other acquisitions, which represents a portion of the term over which the contractual customer relationships are
expected to contribute to our cash flows.
We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts
with customers. Based on the estimated future revenues during the contract periods (as estimated at the time of the
acquisition), the weighted-average period prior to the next renewal or extension of the contractual customer relationships
associated with the UEOM acquisition was approximately 10 years. Although a significant portion of the expected
future cash flows associated with these contractual customer relationships are dependent on our ability to renew or
extend the arrangements beyond the initial contract periods, these expected future cash flows are significantly influenced
by the scope and pace of our producer customers’ drilling programs. Once producer customers’ wells are connected to
our gathering infrastructure, their likelihood of switching to another provider before the wells are abandoned is reduced
due to the significant capital investment required.
The amortization expense related to other intangible assets was $324 million, $333 million, and $347 million in
2019, 2018, and 2017, respectively. The estimated amortization expense for each of the next five succeeding fiscal
years is approximately $328 million.
Note 14 – Accrued Liabilities
December 31,
2019
2018
Interest on debt.............................................................................................................. $
Employee costs .............................................................................................................
Estimated rate refund liabilities (Note 19) ....................................................................
Contract liabilities (Note 2)...........................................................................................
Asset retirement obligation (Note 12)...........................................................................
Operating lease liabilities (Note 11)..............................................................................
Other, including other loss contingencies .....................................................................
$
125
$
(Millions)
288
226
189
158
48
21
346
1,276
$
282
205
—
244
64
—
307
1,102
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Note 15 – Debt and Banking Arrangements
Long-Term Debt
Transco:
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 obligation - Atlantic Sunrise ......................................................
Other financing obligation - Dalton ....................................................................
Northwest Pipeline:
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 ........................................................................................
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,
2019
2018
(Millions)
8
200
1,000
400
375
400
600
857
259
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
24
—
(119)
(58)
22,288
(2,140)
20,148
$
$
8
200
1,000
400
375
400
600
807
260
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
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.
126
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,
2019
(Millions)
2020 .................................................................................................................................................... $
2021 ....................................................................................................................................................
2022 ....................................................................................................................................................
2023 ....................................................................................................................................................
2024 ....................................................................................................................................................
2,141
893
2,025
1,477
2,279
Issuances and retirements
We retired $14 million of 8.75 percent senior unsecured notes that matured on January 15, 2020.
We retired $32 million of 7.625 percent senior unsecured notes that matured on July 15, 2019.
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.
Other financing obligations
During the construction of the Atlantic Sunrise and Dalton projects, Transco received funding from its partners
for their proportionate share of construction costs. Amounts received were recorded within noncurrent liabilities and
the costs associated with construction were capitalized in our Consolidated Balance Sheet. Upon placing these projects
into service Transco began utilizing the partners’ undivided interest in the assets, including the associated pipeline
capacity, and reclassified the funding previously received from its partners from noncurrent liabilities to debt. The
obligations, which mature in 2038 and 2052, respectively, require monthly interest and principal payments and both
bear an interest rate of approximately 9 percent.
127
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Credit Facilities
Long-term credit facility (1) ....................................................................................... $
Letters of credit under certain bilateral bank agreements ...........................................
(Millions)
4,500
$
—
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, 2019
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 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. The maturity
date of the 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 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.
• 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.
128
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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, 2019, we are in compliance with these covenants.
Commercial Paper Program
On August 10, 2018, following the consummation of the WPZ Merger, we entered into a $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, 2019 and 2018, no commercial paper was outstanding.
Cash Payments for Interest (Net of Amounts Capitalized)
Cash payments for interest (net of amounts capitalized) were $1.153 billion in 2019, $1.064 billion in 2018, and
$1.110 billion in 2017.
Note 16 – Stockholders' Equity
On January 28, 2020, our board of directors approved a regular quarterly dividend to common stockholders of
$0.40 per share payable on March 30, 2020.
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.
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, 2018 .................................. $
(2) $
Other comprehensive income (loss) before
reclassifications ..................................................
Amounts reclassified from accumulated other
comprehensive income (loss) .............................
Other comprehensive income (loss)...........................
Balance at December 31, 2019 .................................. $
—
—
—
(2) $
(Millions)
(1) $
—
—
—
(1) $
(267) $
(270)
59
12
71
(196) $
59
12
71
(199)
129
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,
2019:
Component
Reclassifications
(Millions)
Classification
Pension and other postretirement benefits:
Amortization of actuarial (gain) loss and net
actuarial loss from settlements included in net
periodic benefit cost (credit) ..................................
Income tax benefit ...........................................................
Reclassifications during the period .................................
$
$
Note 17 – Equity-Based Compensation
Williams’ Plan Information
Other income (expense) – net below
Operating income (loss)
16
(4) Provision (benefit) for income taxes
12
The Williams Companies, Inc. 2007 Incentive Plan (the Plan) provides common-stock-based awards to both
employees and nonmanagement directors. To date, 40 million new shares have been authorized for making awards
under the Plan. The Plan permits the granting of various types of awards including, but not limited to, restricted stock
units and stock options. At December 31, 2019, 23 million shares of our common stock were reserved for issuance
pursuant to existing and future stock awards, of which 11 million shares were available for future grants.
Additionally, up to 3.6 million new shares of our common stock have been authorized to date to be available for
sale under our Employee Stock Purchase Plan (ESPP). Employees purchased 322 thousand shares at a weighted-average
price of $19.55 per share during 2019. Approximately 424 thousand shares were available for purchase under the ESPP
at December 31, 2019.
Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated
Statement of Operations include equity-based compensation expense for the years ended December 31, 2019, 2018,
and 2017 of $57 million, $54 million, and $70 million, respectively. Income tax benefit recognized related to the stock-
based compensation expense for the years ended December 31, 2019, 2018, and 2017 was $14 million, $14 million,
and $17 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2019,
was $60 million, comprised of $2 million related to stock options and $58 million related to restricted stock units. These
amounts are expected to be recognized over a weighted-average period of 2.8 years.
Stock Options
The following summary reflects stock option activity and related information for the year ended December 31,
2019:
Stock Options
Weighted-
Average
Exercise
Price
Aggregate
Intrinsic
Value
(Millions)
Options
(Millions)
Outstanding at December 31, 2018 ...............................................
Granted ..........................................................................................
Exercised .......................................................................................
Cancelled .......................................................................................
Outstanding at December 31, 2019 ...............................................
Exercisable at December 31, 2019 ................................................
7.3
$
— $
(0.4) $
(0.1) $
$
6.8
$
5.8
31.55
—
11.31
35.62
32.64
33.22
$
$
2
2
130
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The following table summarizes additional information related to stock option activity during each of the last three
years:
Year Ended December 31,
2019
2018
(Millions)
2017
Total intrinsic value of options exercised........................................................ $
Tax benefits realized on options exercised...................................................... $
Cash received from the exercise of options..................................................... $
6
1
4
$
$
$
3
$
— $
$
9
4
1
7
The weighted-average remaining contractual lives for stock options outstanding and exercisable at December 31,
2019, were 4.2 years and 3.6 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
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
2018
2017
There were no stock options granted in 2019. The expected dividend yield for each respective year is based on the
dividend forecast for that year and the grant-date market price of our stock. Our expected future volatility is determined
using the historical volatility of our stock and implied volatility on our traded options. Historical volatility is based on
the blended 10-year historical volatility of our stock and certain peer companies. The risk-free interest rate is based on
the U.S. Treasury Constant Maturity rates as of the grant date. The expected life of the option is based on historical
exercise behavior and expected future experience.
Nonvested Restricted Stock Units
The following summary reflects nonvested restricted stock unit activity and related information for the year ended
December 31, 2019:
Restricted Stock Units Outstanding
Weighted-
Average
Fair Value (1)
Shares
(Millions)
Nonvested at December 31, 2018 .............................................................................
Granted......................................................................................................................
Forfeited ....................................................................................................................
Vested........................................................................................................................
Nonvested at December 31, 2019 .............................................................................
______________
(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.
4.5
$
$
2.5
(0.5) $
(1.1) $
$
5.4
28.96
25.87
28.48
26.25
28.11
131
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Value of Restricted Stock Units
Weighted-average grant date fair value of restricted stock units granted
2019
2018
2017
during the year, per share ............................................................................... $
Total fair value of restricted stock units vested during the year (in millions) ... $
25.87
29
$
$
30.48
35
$
$
29.47
33
Performance-based restricted stock units granted under the Plan represent 39 percent of nonvested restricted stock
units outstanding at December 31, 2019. 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.
Note 18 – 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.
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, 2019:
Measured on a recurring basis:
ARO Trust investments ........................................... $
201
$
201
$
201
$
— $
Energy derivative assets not designated as hedging
instruments ..........................................................
Energy derivative liabilities not designated as
hedging instruments ............................................
Additional disclosures:
1
(3)
1
(3)
Long-term debt, including current portion ..............
Guarantees ...............................................................
(22,288)
(41)
(25,319)
(27)
1
(1)
—
—
—
—
(25,319)
(11)
Assets (liabilities) at December 31, 2018:
Measured on a recurring basis:
ARO Trust investments ........................................... $
Energy derivative assets not designated as hedging
instruments ..........................................................
Energy derivative liabilities not designated as
hedging instruments ............................................
Additional disclosures:
Long-term debt, including current portion ..............
Guarantees ...............................................................
(22,414)
(43)
(23,330)
(30)
132
150
$
150
$
150
$
— $
3
(7)
3
(7)
3
(4)
—
—
—
—
(23,330)
(14)
—
—
(2)
—
(16)
—
—
(3)
—
(16)
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Fair Value Methods
We use the following methods and assumptions in estimating the fair value of our financial instruments:
Assets and liabilities measured at fair value on a recurring basis
ARO Trust investments: Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into
an external trust that is specifically designated to fund future ARO’s. 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 derivative
assets are reported in Other current assets and deferred charges and Regulatory assets, deferred charges, and other in
the Consolidated Balance Sheet. Energy derivative liabilities are reported in Accrued liabilities and Regulatory
liabilities, deferred income, and other in the Consolidated Balance Sheet.
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are
made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the years ended December 31,
2019 or 2018.
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 15 – Debt and Banking Arrangements).
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 $28 million at December 31, 2019. 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
133
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax
regulations and have no carrying value. We have never been called upon to perform under these indemnifications and
have no current expectation of a future claim.
Nonrecurring fair value measurements
The following table presents impairments of assets and equity-method investments associated with certain
nonrecurring fair value measurements within Level 3 of the fair value hierarchy, except as specifically noted.
Impairments of equity-method investments are reported in Other investing income (loss) – net in the Consolidated
Statement of Operations.
Segment
Date of
Measurement
Fair
Value
Impairments
Year Ended December 31,
2019
2018
2017
(Millions)
Impairment of certain assets:
Certain pipeline project (1) ...................................... Atlantic-Gulf
Certain gathering assets (2)......................................
Certain gathering assets (2)......................................
Certain idle gathering assets (3)...............................
Certain gathering assets (4)......................................
Certain idle pipeline assets (5) .................................
West
West
West
West
Other
Certain gathering assets (6)......................................
West
Certain gathering assets (7)......................................
Certain NGL pipeline (8) .........................................
Certain olefins pipeline project (9) ..........................
Other impairments and write-downs (10) ................
Impairment of certain assets .......................................
Impairment of equity-method investments:
Laurel Mountain (11) ...............................................
Appalachia Midstream Investments (12) .................
Pennant (13) .............................................................
UEOM (14) ..............................................................
UEOM (14) ..............................................................
Other.........................................................................
Impairment of equity-method investments .................
Northeast
G&P
Other
Other
Northeast
G&P
Northeast
G&P
Northeast
G&P
Northeast
G&P
Northeast
G&P
December 31,
2019
December 31,
2019
June 30, 2019
March 31,
2019
December 31,
2018
June 30, 2018
September 30,
2017
September 30,
2017
September 30,
2017
June 30, 2017
September 30,
2019
September 30,
2019
August 31,
2019
March 17,
2019
December 31,
2018
$
22
$ 354
25
40
—
470
25
439
21
32
18
20
59
12
$1,849
66
$ 1,019
115
68
23
23
$ 1,248
19
$ 464
—
$1,915
79
17
17
74
$ 242
$
102
11
1,210
1,293
$
$
32
32
(1)
$ 186
______________
(1) Relates to the Constitution development project. The estimated fair value of the Property, plant, and equipment
– net was based on probability-weighted third-party quotes. See Note 4 – Variable Interest Entities for further
discussion.
134
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
(2) Relates to a gas gathering system in the Eagle Ford region with expected declines in asset utilization and possible
idling of the gathering system. We designated these operations as held for sale, included in Other current assets
and deferred charges, as of December 31, 2019. As a result, we measured the fair value of the disposal group
using the expected sales price under a contract with a third party. These inputs resulted in a fair value measurement
within Level 2 of the fair value hierarchy. The estimated fair value of the Property, plant, and equipment – net at
June 30, 2019, was determined using a market approach, which incorporated indications of interest from third
parties.
(3) Reflects impairment of Property, plant, and equipment – net that is no longer in use for which the fair value was
determined to be lower than the carrying value.
(4) 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 the Property, plant, and equipment – net and Intangible assets – net of accumulated
amortization. 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.
(5) Relates to certain idle pipelines. The estimated fair value of the Property, plant, and equipment – net 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 – Acquisitions
and Divestitures.)
(6) 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 of the Property, plant, and equipment – net and Intangible assets – net of
accumulated amortization 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.
(7) 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 of the
Property, plant, and equipment – net and Intangible assets – net of accumulated amortization 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.
(8) 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 of the Property, plant, and equipment – net 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 – Acquisitions and Divestitures.)
(9) Relates primarily to project development costs associated with an olefins pipeline project in the Gulf Coast region,
where we consider the likelihood of completion to be remote. The estimated fair value of the remaining Property,
plant, and equipment – net considered a market approach based on our analysis of observable inputs in the principal
135
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
market, as well as an estimate of replacement cost. We sold these assets in the fourth quarter of 2018. (See
Note 3 – Acquisitions and Divestitures.)
(10) Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no
longer be in use or are surplus in nature for which the fair value was determined to be lower than the carrying
value.
(11) Relates to a gas gathering system in the Marcellus region that was adversely impacted by lower sustained forward
natural gas price expectations and changes in expected producer activity. The estimated fair value was determined
using an income approach. We utilized a discount rate of 10.2 percent in our analysis.
(12) Relates to a certain gathering system held in Appalachia Midstream Investments that was adversely impacted by
changes in the timing of expected producer activity. The estimated fair value was determined using an income
approach. We utilized a discount rate of 9.0 percent in our analysis.
(13) The estimated fair value of Pennant Midstream, LLC (“Pennant”) was determined by a market approach based
on recent observable third-party transactions. These inputs resulted in a fair value measurement within Level 2
of the fair value hierarchy.
(14) The estimated fair value at March 17, 2019, was determined by a market approach based on the transaction price
for the purchase of the remaining interest in UEOM as finalized just prior to the signing and closing of the
acquisition in March 2019 (see Note 3 – Acquisitions and Divestitures). These inputs resulted in a fair value
measurement within Level 2 of the fair value hierarchy. The estimated fair value at December 31, 2018, was
determined by a market approach based on our analysis of inputs in the principal market.
Concentration of Credit Risk
The following table summarizes concentration of receivables, net of allowances:
December 31,
2019
2018
NGLs, natural gas, and related products and services .............................................. $
Transportation of natural gas and related products ...................................................
Accounts Receivable related to revenues from contracts with customers ............
Other..........................................................................................................................
Trade accounts and other receivables ................................................................... $
$
(Millions)
613
277
890
106
996
$
626
232
858
134
992
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.
In 2019, 2018, and 2017, Chesapeake Energy Corporation, and its affiliates, a customer currently primarily within
our West segment, accounted for approximately 6 percent, 8 percent, and 10 percent, respectively, of our consolidated
revenues, and as of December 31, 2019, accounted for $78 million of the consolidated Trade accounts and other
receivables balance.
136
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Note 19 – 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 was remanded to the Nevada
federal district court and subsequently has been remanded to its originally filed court, the Kansas 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.
We reached an agreement to settle two of the actions, and on April 22, 2019, the Nevada federal district court
preliminarily approved the settlements, which are on behalf of Kansas and Missouri class members. The final fairness
hearing on the settlement occurred August 5, 2019, and a final judgment of dismissal with prejudice was entered the
same day.
Two putative class actions remain unresolved, and they have been remanded to their originally filed court, the
Wisconsin 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 primarily 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 were remanded to the Alaska Superior Court. The State of Alaska filed its action in March 2014,
seeking damages. The City of North Pole (North Pole) filed its lawsuit in November 2014, seeking past and future
damages, as well as punitive damages. Both we and WAPI asserted counterclaims against the State of Alaska and North
Pole, and cross-claims against FHRA. FHRA has also filed cross-claims against us.
The underlying factual basis and claims in the cases are similar and may duplicate exposure. As such, in February
2017, the three cases were consolidated into one action in state court containing the remaining claims from the James
137
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
West case and those of the State of Alaska and North Pole. The State of Alaska later announced the discovery of
additional contaminants per- and polyfluoralkyl (PFOS and PFOA) offsite of the refinery, and the Court permitted the
State of Alaska to amend its complaint to add a claim for offsite PFOS/PFOA contamination. The Court subsequently
remanded the offsite PFOS/PFOA claims to the Alaska Department of Environmental Conservation for investigation
and stayed the claims pending their potential resolution at the administrative agency. Several trial dates encompassing
all three cases have been scheduled and stricken. In the summer of 2019, the Court deconsolidated the cases for purposes
of trial. A bench trial on all claims except North Pole’s claims began in October 2019.
In January 2020, the Alaska Superior Court issued its Memorandum of Decision finding in favor of the State of
Alaska and FHRA, with the total incurred and potential future damages estimated to be $86 million. The Court did not
award natural resource damages to the State of Alaska and also found that FHRA is not entitled to contractual
indemnification from us because FHRA contributed to the sulfolane contamination. A final judgment has not been
entered in the case. We expect to appeal the decision. We have recorded an additional charge in the fourth quarter of
2019, reported within Income (loss) from discontinued operations in the Consolidated Statement of Operations, adjusting
our accrued liability to our estimate of the probable loss. It is reasonably possible that we may not be successful on
appeal and could ultimately pay up to the amount of judgment.
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.
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
138
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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. The Court of Chancery previously scheduled trial for May 20
through May 24, 2019; the court struck the trial setting and has re-scheduled trial for June 8 through June 11 and June 15,
2020.
Former Olefins Business
SABIC Petrochemicals, the other interest owner in our former Geismar, Louisiana, olefins facility we sold in July
2017, is seeking recovery from us for losses it allegedly suffered, including its share of personal injury settlements in
which it was a co-defendant, as well as amounts related to lost income, defense costs, and property damage associated
with an explosion and fire at the plant in June 2013. Due to the complexity of the various claims and available defenses,
we are unable to reliably estimate any reasonably possible losses at this time. Trial began on October 14, 2019, as
scheduled, but on October 21, 2019, the Court declared a mistrial due to the conduct of an officer of SABIC
Petrochemicals and SABIC Petrochemicals’ expert witness. No new trial date has been set. We believe that certain
losses incurred arising directly from the explosion and fire will be covered by our general liability policy and any
uninsured losses are not expected to be material.
Other
On August 31, 2018, Transco submitted to the FERC a general rate filing principally designed to recover increased
costs and to comply with the terms of the settlement in its prior rate proceeding. The new rates became effective March 1,
2019, subject to refund and the outcome of a hearing. In October 2019, we reached an agreement on the terms of a
settlement with the participants that would resolve all issues in the rate case without the need for a hearing, and on
December 31, 2019, we filed a formal stipulation and agreement with the FERC setting forth such terms of settlement.
We anticipate FERC approval of the stipulation and agreement in the second quarter of 2020. As of December 31, 2019,
we have provided a $189 million reserve for rate refunds related to increased rates collected since March 2019, which
we believe is adequate for any refunds that may be required.
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, 2019, we have accrued liabilities totaling $31 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, 2019, certain assessment studies were still
139
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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 and combustion turbine 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
state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund
waste sites. At December 31, 2019, we have accrued liabilities of $4 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, 2019, 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, 2019, we have accrued environmental liabilities of $20 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
140
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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, 2019, other than as previously disclosed, we are not aware of any material claims against us
involving the indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to
have a material impact on our future financial position. Any claim for indemnity brought against us in the future may
have a material adverse effect on our results of operations in the period in which the claim is made.
In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations,
none of which are expected to be material to our expected future annual results of operations, liquidity, and financial
position.
Summary
We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as all
significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all
other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses
beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity, and financial
position. These calculations have been made without consideration of any potential recovery from third parties.
Commitments
Commitments for construction and acquisition of property, plant, and equipment are approximately $206 million
at December 31, 2019.
Note 20 – Segment Disclosures
Our reportable segments are Atlantic-Gulf, Northeast G&P, 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:
Income (loss) from discontinued operations;
Provision (benefit) for income taxes;
Interest incurred, net of interest capitalized;
Equity earnings (losses);
Other investing income (loss) – net;
141
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
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.
142
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:
Atlantic-
Gulf
Northeast
G&P
West
Other
Eliminations
Total
(Millions)
2019
Segment revenues:
Service revenues
External ............................................................................ $ 2,812
Internal .............................................................................
49
2,861
Total service revenues ..........................................................
41
Total service revenues – commodity consideration .............
Product sales
External ............................................................................
Internal .............................................................................
Total product sales ...............................................................
217
71
288
Total revenues ......................................................................... $ 3,190
$
$
1,291
47
1,338
12
115
35
150
1,500
$ 1,813
—
1,813
150
1,733
64
1,797
$ 3,760
Other financial information:
Additions to long-lived assets ............................................... $ 1,179
Proportional Modified EBITDA of equity-method
investments .......................................................................
177
2018
Segment revenues:
Service revenues
External ............................................................................ $ 2,460
Internal .............................................................................
49
2,509
Total service revenues ..........................................................
Total service revenues – commodity consideration
59
Product sales
External ............................................................................
Internal .............................................................................
Total product sales ...............................................................
174
261
435
Total revenues ......................................................................... $ 3,003
Other financial information:
Additions to long-lived assets ............................................... $ 2,297
Proportional Modified EBITDA of equity-method
investments .......................................................................
183
2017
Segment revenues:
Service revenues
External .......................................................................... $ 2,202
37
Internal ...........................................................................
Total service revenues ..........................................................
2,239
Product sales
External ..........................................................................
Internal ...........................................................................
Total product sales ...............................................................
257
227
484
Total revenues ......................................................................... $ 2,723
Other financial information:
Additions to long-lived assets ............................................... $ 2,001
Proportional Modified EBITDA of equity-method
investments .......................................................................
264
143
$
1,245
$
466
454
115
$
$
$
$
$
$
935
41
976
20
$ 2,085
—
2,085
321
245
42
287
1,283
2,365
83
2,448
$ 4,854
477
$
361
493
94
837
35
872
$ 2,246
—
2,246
264
27
291
1,163
1,840
173
2,013
$ 4,259
460
$
321
452
79
$
$
$
$
$
$
$
$
$
17
13
30
—
—
—
—
30
21
—
22
12
34
—
—
—
—
34
36
—
27
11
38
358
8
366
404
32
—
$
$
$
$
$
$
$
$
— $
$
— $
(109)
(109)
—
—
(170)
(170)
(279) $
5,933
—
5,933
203
2,065
—
2,065
8,201
— $
2,911
—
746
(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
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:
Atlantic-Gulf.................................................................................................... $
Northeast G&P ................................................................................................
West .................................................................................................................
Other ................................................................................................................
Accretion expense associated with asset retirement obligations for
nonregulated operations....................................................................................
Depreciation and amortization expenses..............................................................
Equity earnings (losses) .......................................................................................
Other investing income (loss) – net......................................................................
Proportional Modified EBITDA of equity-method investments..........................
Interest expense ....................................................................................................
(Provision) benefit for income taxes ....................................................................
Income (loss) from discontinued operations ........................................................
Net income (loss)............................................................................................. $
Year Ended December 31,
2019
2018
(Millions)
2017
1,895
1,314
1,232
6
4,447
(33)
(1,714)
375
(79)
(746)
(1,186)
(335)
(15)
714
$
$
2,023
1,086
308
(29)
3,388
(33)
(1,725)
396
187
(770)
(1,112)
(138)
—
193
$
$
1,238
819
412
997
3,466
(33)
(1,736)
434
282
(795)
(1,083)
1,974
—
2,509
The following table reflects Total assets and Equity-method investments by reportable segments:
Total Assets
December 31,
2019
December 31,
2018
Equity-Method Investments
December 31,
December 31,
2018
2019
Atlantic-Gulf .........................................................
Northeast G&P ......................................................
West.......................................................................
Other......................................................................
Eliminations (1).....................................................
Total .................................................................
$
$
16,575
15,399
13,487
1,151
(572)
46,040
$
$
(Millions)
16,346
14,526
13,948
849
(367)
45,302
$
$
741
3,973
1,521
—
—
6,235
$
$
776
5,319
1,726
—
—
7,821
______________
(1) Eliminations primarily relate to the intercompany notes and accounts receivable generated by our cash management
program.
144
The Williams Companies Inc.
Quarterly Financial Data
(Unaudited)
Summarized quarterly financial data are as follows:
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
(Millions, except per-share amounts)
2019
Revenues ......................................................................................................... $ 2,054
565
Product costs and processing commodity expenses ........................................
214
Income (loss) from continuing operations .......................................................
—
Income (loss) from discontinued operations ...................................................
214
Net income (loss) ............................................................................................
Amounts attributable to The Williams Companies, Inc. available to
common stockholders:
Income (loss) from continuing operations ...............................................
Income (loss) from discontinued operations ............................................
Net income (loss) .....................................................................................
Basic and diluted income (loss) from continuing operations per
common share ......................................................................................
Basic and diluted income (loss) from discontinued operations per
common share ......................................................................................
Basic and diluted net income (loss) per common share ...........................
194
—
194
.16
—
.16
2018
Revenues ......................................................................................................... $ 2,088
648
Product costs and processing commodity expenses ........................................
270
Income (loss) from continuing operations .......................................................
Net income (loss) ............................................................................................
270
Amounts attributable to The Williams Companies, Inc. available to
common stockholders:
$ 2,041
507
324
—
324
$ 1,999
453
242
—
242
$ 2,107
541
(51)
(15)
(66)
310
—
310
.26
—
.26
220
—
220
.18
—
.18
138
(15)
123
.11
(.01)
.10
$ 2,091
662
269
269
$ 2,303
820
200
200
$ 2,204
714
(546)
(546)
Income (loss) from continuing operations ...............................................
Net income (loss) .....................................................................................
Basic and diluted net income (loss) per common share ...........................
152
152
.18
135
135
.16
129
129
.13
(572)
(572)
(.47)
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.
2019
Net income (loss) for fourth-quarter 2019 includes $354 million of impairment of Constitution’s capitalized project
costs (see Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements).
Net income (loss) for third-quarter 2019 includes $114 million of impairment of certain equity-method investments
(see Note 18 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated
Financial Statements).
Net income (loss) for second-quarter 2019 includes a $122 million gain on sale of our equity-method investment
in Jackalope (see Note 6 – Investing Activities of Notes to Consolidated Financial Statements).
2018
Net income (loss) for fourth-quarter 2018 includes:
•
$1.849 billion impairment of certain assets in the Barnett Shale region (see Note 18 – Fair Value Measurements,
Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements);
145
The Williams Companies Inc.
Quarterly Financial Data – (Continued)
(Unaudited)
•
•
•
$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 – Acquisitions and Divestitures of Notes to Consolidated Financial
Statements);
$141 million deconsolidation gain associated with our investment in the Brazos Permian II joint venture (see
Note 6 – Investing Activities of Notes to Consolidated Financial Statements);
$101 million gain on the sale of certain assets and operations located in the Gulf Coast area (see Note 3 –
Acquisitions and Divestitures of Notes to Consolidated Financial Statements).
146
The Williams Companies, Inc.
Schedule II — Valuation and Qualifying Accounts
Additions
Charged
(Credited)
To Costs and
Expenses
Beginning
Balance
Other
Deductions
Ending
Balance
(Millions)
2019
Deferred tax asset valuation allowance (1) ................ $
320
$
(1) $
— $
— $
319
2018
Deferred tax asset valuation allowance (1) ................
2017
Deferred tax asset valuation allowance (1) ................
224
334
96
(110)
—
—
—
—
320
224
__________
(1) Deducted from related assets.
147
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 2019 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.
148
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,
2019, 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, 2019, 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.
149
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, 2019, 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, 2019,
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, 2019 and 2018, 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, 2019, and the related notes and the financial statement schedule listed in the index at Item 15(a)
and our report dated February 24, 2020, 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 24, 2020
150
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 April 28, 2020, which shall be filed no
later than March 19, 2020 (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 “Information About Our Executive Officers,” as permitted by General Instruction G(3) to
and Instruction 3 to Item 401(b) of Regulation S-K.
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.
Our Code of Business Conduct, together with our Corporate Governance Guidelines, the charters for each of our
board committees, and our Code of Business Conduct applicable to all employees, including our Chief Executive
Officer, Chief Financial Officer, and Chief Accounting Officer, or persons performing similar functions, are available
on our Internet website at www.williams.com. We will provide, free of charge, a copy of our Code of Business Conduct
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, in each
case, of the Code of Business Conduct on behalf of our Chief Executive Officer, Chief Financial Officer, Chief
Accounting Officer, 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.
151
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.
152
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, 2019 ..
Consolidated statement of comprehensive income (loss) for each year in the three-year period ended
December 31, 2019 ..................................................................................................................................
Consolidated balance sheet at December 31, 2019 and 2018 .....................................................................
Consolidated statement of changes in equity for each year in the three-year period ended December 31,
2019..........................................................................................................................................................
Consolidated statement of cash flows for each year in the three-year period ended December 31, 2019 ..
Notes to consolidated financial statements .....................................................................................................
Schedule for each year in the three-year period ended December 31, 2019:
II — Valuation and qualifying accounts ....................................................................................................
Not covered by report of independent auditors:
Quarterly financial data (unaudited) ...............................................................................................................
Page
76
77
78
79
80
81
147
145
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
2.4
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).
— Agreement and Plan of Merger dated as of May 16, 2018, by and among The Williams Companies,
Inc., SCMS LLC, Williams Partners L.P., and WPZ GP LLC (filed on May 17, 2018 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).
153
Exhibit
No.
2.5
2.6
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. 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).
— 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).
154
Exhibit
No.
Description
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
— 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 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).
— 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).
155
Exhibit
No.
4.18
4.19
4.20
4.21
4.22
4.23
4.24
4.25
4.26
4.27
4.28
4.29
Description
— 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).
— 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).
156
Exhibit
No.
4.30
4.31
4.32
4.33
Description
— 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 herein by reference).
4.34* — Description of Securities.
10.1§ — 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).
10.2§ — 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).
10.3§ — 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).
10.4§ — 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).
10.5§ — Form of 2014 Restricted Stock Unit Agreement among Williams and certain nonmanagement
directors (filed on February 25, 2015, as Exhibit 10.12 to The Williams Companies, Inc. annual
report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.6§ — 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).
10.7§ — 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).
10.8§ — 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).
10.9§ — 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).
157
Exhibit
No.
Description
10.10§ — 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).
10.11§ — 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).
10.12§ — 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).
10.13§ — 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).
10.14§ — 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).
10.15§ — 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).
10.16§ — Form of 2017 Performance-Based Restricted Stock Unit Agreement among Williams and certain
employees and officers (filed on May 4, 2017, as Exhibit 10.10 to The Williams Companies, Inc.’s
quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.17§ — 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).
10.18§ — 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).
10.19§ — 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).
10.20§ — 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).
10.21§ — Form of 2019 Executive Performance-Based Restricted Stock Unit Agreement among Williams and
certain employees and officers (filed on May 2, 2019, 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).
10.22§ — Form of 2019 Performance-Based Restricted Stock Unit Agreement among Williams and certain
employees and officers (filed on May 2, 2019, 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).
158
Exhibit
No.
Description
10.23§ — Form of 2019 Time-Based Restricted Stock Unit Agreement among Williams and certain employees
and officers (filed on May 2, 2019, 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).
10.24§ — Form of 2019 Time-Based Restricted Stock Unit Agreement among Williams and certain non-
management directors (filed on May 2, 2019, 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).
10.25§ — 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).
10.26§ — 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).
10.27§ — 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).
10.28§ — 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).
10.29§* — Change in Control and Restrictive Covenant Agreement between certain executive officers (Tier
One Executives) and The Williams Companies, Inc.
10.30§* — Change in Control and Restrictive Covenant Agreement between certain executive officers (Tier
Two Executives) and The Williams Companies, Inc.
10.31§ — 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).
10.32§ — 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).
10.33§ — 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).
10.34 — 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).
10.35 — 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).
21*
— Subsidiaries of the registrant.
159
Exhibit
No.
Description
23.1* — Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP.
23.2* — Consent of Independent Registered Public Accounting Firm, PricewaterhouseCoopers LLP.
31.1* — Certification of the Chief Executive Officer pursuant to Rules 13a-l4(a) and 15d-14(a) promulgated
under the Securities Exchange Act of 1934, as amended, and Item 601(b)(3l) 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 l5d-l4(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. The instance document does not appear in the Interactive Data File
because its XBRL tags are embedded within the inline XBRL document.
101.SCH* — XBRL Taxonomy Extension Schema.
101.CAL* — XBRL Taxonomy Extension Calculation Linkbase.
101.DEF* — XBRL Taxonomy Extension Definition Linkbase.
101.LAB* — XBRL Taxonomy Extension Label Linkbase.
101.PRE* — XBRL Taxonomy Extension Presentation Linkbase.
104*
— Cover Page Interactive Data File. The cover page interactive data file does not appear in the
interactive data file because its XBRL tags are embedded within the inline XBRL document
(contained in Exhibit 101).
______________
* Filed herewith
** Furnished herewith
§ Management contract or compensatory plan or arrangement
160
Item 16. Form 10-K Summary
Not applicable.
161
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/ JOHN D. PORTER
John D. Porter
Vice President, Controller and
Chief Accounting Officer
Date: February 24, 2020
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 24, 2020
Alan S. Armstrong
(Principal Executive Officer)
/s/ JOHN D. CHANDLER
Senior Vice President and Chief Financial Officer
February 24, 2020
John D. Chandler
(Principal Financial Officer)
/s/ JOHN D. PORTER
John D. Porter
Vice President, Controller and Chief Accounting
Officer
(Principal Accounting Officer)
February 24, 2020
/s/ STEPHEN W. BERGSTROM
Chairman of the Board
February 24, 2020
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 24, 2020
February 24, 2020
February 24, 2020
/s/ KATHLEEN B. COOPER
Director
February 24, 2020
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 24, 2020
February 24, 2020
February 24, 2020
Director
Director
Director
162
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 24, 2020
February 24, 2020
February 24, 2020
163
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Corporate Data
ANNUAL MEETING
AUDITORS
Stockholders are invited to our annual
meeting at 2 p.m. Central Daylight Time
on April 28, 2020, 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
May 16, 2019.
We also filed with the Securities and
Exchange Commission on February
24, 2020, as Exhibits 31.1 and 31.2 to
our Annual Report on Form 10-K for
the year ended December 31, 2019,
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/sustainability.
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
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 40202
Contact our transfer agent for
information on registered share
accounts, dividend payments or
to receive information about our
Direct Stock Purchase Plan.
Stockholder Information
WILLIAMS SECURITIES
Williams common stock (WMB) is listed
on the New York Stock Exchange.
The market value on February 19, 2020,
was approximately $26.1 billion. On
that date, 6,512 stockholders of record
held 1,212,494,859 shares of Williams
common stock. The company’s common
stock traded at an average daily volume
of 8.2 million shares in 2019.
WMB COMMON STOCK ACTIVITY
(dividend/share)
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
2019
0.38
0.38
0.38
0.38
2018
0.34
0.34
0.34
0.34
WMB AVERAGE DAILY VOLUMES TRADED
(thousands of shares)
20,000
16,000
12,000
8,000
4,000
43214321432143214321
2015
2017
2018
2016
2019
WMB CLOSING PRICE RANGES
($/share)
High
Low
70
60
50
40
30
20
10
0
43214321432143214321
2017
2015
2018
2016
2019
WMB CLOSING PRICE RANGES
($/share)
2019
2018
High
Low
High
Low
1st Quarter
28.93
22.42
33.21
24.78
2nd Quarter
29.35
26.30
28.01
24.38
3rd Quarter
28.85
22.88
31.79
26.70
4th Quarter
23.94
21.95
27.98
20.58
(800) WILLIAMS l www.williams.com
© 2020 The Williams Companies, Inc.