0000107263 us-gaap:ConstructionInProgressMember us-gaap:RegulatedOperationMember 2019-12-31
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
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þ☑ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| | For the fiscal year ended | December 31, 20162019 |
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¨☐ | 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)
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| Delaware | | 73-0569878 |
(State or Other Jurisdiction of Incorporation or Organization) | | (IRS Employer Identification No.) |
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| One Williams Center | | |
| Tulsa | Oklahoma | | 74172 |
| (Address of Principal Executive Offices) | | (Zip Code) |
918-573-2000918-573-2000
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
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| Title of Each Class | Trading Symbol(s) | Name of Each Exchange on Which Registered |
| Common Stock, $1.00 par value | WMB | 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. Yesþ☑ 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 ¨☐Noþ☑
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. Yesþ☑ No ¨☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yesþ☑ No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”filer,” “smaller reporting company,” and “smaller reporting“emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
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| Large accelerated filerþ | ☑ | | Accelerated filer¨ | ☐ | | | Non-accelerated filer¨ | ☐ | | Smaller reporting company¨ | |
| ☐ | | Emerging growth company | | | (Do not check if a smaller reporting company) | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨☐ No þ☑
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 $16,207,908,251.$32,986,794,536.
The number of shares outstanding of the registrant’s common stock outstanding at February 17, 201719, 2020 was 825,823,9181,212,494,859.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s Definitive Proxy Statement for the Registrant’s Annual Meeting of Stockholders to be held on May 18, 2017,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
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| PART I | |
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| Item 1. | | |
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| Item 1A. | | |
| Item 1B. | | |
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Item 2. | | |
Item 3. | | |
Item 4. | | |
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| PART II | |
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| Item 5. | | |
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| Item 7A. | | |
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| PART III | |
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| PART IV | |
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| Item 15. | | |
| Item 16. | | |
DEFINITIONS
The following is a listing of certain abbreviations, acronyms, and other industry terminology that may be used throughout this Annual Report.
Measurements:
Barrel: One barrel of petroleum products that equals 42 U.S. gallons
Bcf : One billion cubic feet of natural gas
Bcf/d: One billion cubic feet of natural gas per day
British Thermal Unit (Btu): A unit of energy needed to raise the temperature of one pound of water by one degree
Fahrenheit
Dekatherms (Dth): A unit of energy equal to one million British thermal units
Mbbls/d: One thousand barrels per day
Mdth/d: One thousand dekatherms per day
MMcf/d: One million cubic feet per day
MMdth: One million dekatherms or approximately one trillion British thermal units
MMdth/d: One million dekatherms per day
Tbtu: One trillion British thermal units
Consolidated Entities:
ACMP: Access Midstream Partners, L.P. prior to its merger with Pre-Merger WPZ
Cardinal: Cardinal Gas Services, L.L.C.
Constitution: Constitution Pipeline Company, LLC
Gulfstar One: Gulfstar One LLC
Jackalope: Jackalope Gas Gathering Services, L.L.C.
Northwest Pipeline: Northwest Pipeline LLC
Pre-merger WPZ: Williams Partners L.P. prior to its merger with ACMP
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, 2016,2019, we account for as an equity-method investment, including principally the following:
Aux Sable: Aux Sable Liquid Products LP
Bluegrass: Bluegrass Pipeline CompanyBrazos 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
Laurel Mountain: Laurel Mountain Midstream, LLC
Moss Lake: Moss Lake Fractionation LLC and Moss Lake LPG Terminal LLC
OPPL: Overland Pass Pipeline Company LLC
UEOM: Utica East OhioRMM: Rocky Mountain Midstream Holdings LLC
Government and Regulatory:
EPA: Environmental Protection Agency
Exchange Act, the: Securities and Exchange Act of 1934, as amended
FERC: FERC: Federal Energy Regulatory Commission
GAAP: Generally accepted accounting principles
IRS: Internal Revenue Service
SEC: Securities and Exchange Commission
Other:
DRIP: Distribution reinvestment program
Energy Transfer: Energy Transfer Equity, L.P.
ETC: Energy Transfer Corp LP
ETC Merger: Merger wherein Williams would have been merged into ETC
Fractionation: The process by which a mixed stream of natural gas liquids is separated into its constituent products,
such as ethane, propane, and butane
IDR: Incentive distribution rightGAAP: 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
Merger Agreement: Merger Agreement and Plan of Merger of Williams with Energy Transfer and certain of its
affiliates
MVC: Minimum volume commitment
NGLs: Natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are
used as petrochemical feedstocks, heating fuels, and gasoline additives, among other applications
NGL margins:NGL revenues less Btu replacement cost, plant fuel, transportation, and fractionation
PDH facility:Propane dehydrogenation facilityWPZ 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.
RGP Splitter:Refinery grade propylene splitter
Throughput:The volumestatements in this Annual Report that are not historical information, including statements concerning plans and objectives of product transportedmanagement for future operations, economic performance or passing through a pipeline, plant, terminal,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 facilitysimilar 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.
PART I
Item 1.Business
In this report, Williams (which includes The Williams Companies, Inc. and, unless the context otherwise indicates, all of our subsidiaries) is at times referred to in the first person as “we,” “us” or “our.” We also sometimes refer to Williams as the “Company.”
WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION
We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and other documents electronically with the SEC under the Exchange Act. You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also obtain such reports from the SEC’s Internet website at www.sec.gov.
Our Internet website is www.williams.com. We make available, free of charge, through the Investor tab of our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our Corporate Governance Guidelines, Code of Ethics for Senior Officers, Board committee charters, and the Williams Code of Business Conduct are also available on our Internet website. We will also provide, free of charge, a copy of any of our corporate documents listed above upon written request to our Corporate Secretary, One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.
GENERAL
We are primarily an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource playscommitted to markets forbe the leader in providing infrastructure that safely delivers natural gas NGLs,products to reliably fuel the clean energy economy. We have operations in 15 supply areas that provide natural gas gathering, processing, and olefins. Our operations are located principally in the United States.
As of December 31, 2016, our interstatetransmission services and natural gas pipelines, midstream,liquids fractionation, transportation, and olefins production interests were largely held through our significant investment in Williams Partners L.P. (WPZ).storage services to more than 600 customers. We owned the general partner interest and a 58 percent limited-partnerown an interest in WPZ. Seeand 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 Financial Repositioning discussion below for recent changes to our interest in WPZ.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; Oklahoma City, Oklahoma;and Pittsburgh, Pennsylvania; and the Four Corners Area.Pennsylvania. Our telephone number is 918-573-2000.
FINANCIAL REPOSITIONING
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 ofnatural gas gathered and/or treated, generally measured in the Btu heating value.
In January 2017,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 announcedreceive 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 WPZ, wherein we permanently waivedterms ranging from month-to-month to the general partner’s incentive distribution rightslife 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 convertedallow our 2gathering 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 general partner interest in WPZ to a non-economic 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 proceedsour gathering and processing fee revenues and NGL margins from our equity offering (see Note 15 - Stockholders’ Equitynoncash commodity-based agreements.
Crude Oil Transportation and Production Handling Assets
Our crude oil transportation operations, which are presented in our Transmission & Gulf of Notes to Consolidated Financial Statements). Following these transactions, we ownMexico segment as described under the heading “Business Segments,” earn revenues typically by volumetric-based fee arrangements. Revenue sources have historically included a 74 percent limited partner interest in WPZ. It is anticipated that the combination of these measures will improve WPZ’sfixed-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 capital, provide for debt reduction, and eliminate WPZ’s need to access the public equity markets for several years.
In additionOperations subsequent to the previously announced Geismar monetization process, we have announced plansadoption 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 monetize other select assets that are not corebe:
Obstacles to our strategy. We expectexpansion efforts, including delays or denials of necessary permits and opposition to raise more than $2 billion in after-tax proceeds from the monetization process of Geismarhydrocarbon-based energy development;
Producer drilling activities impacting natural gas supplies supporting our gathering and the other select assets.processing volumes;
Retaining and attracting customers by continuing to provide reliable services;
SALE OF OUR CANADIAN OPERATIONSRevenue growth associated with additional infrastructure either completed or currently under construction;
In September 2016, we completed the sale ofPrices impacting our Canadian operations. Consideration received to date totaled $1.020 billion, net of $31 million of cash divested and subject to customary working capital adjustments. We recognized an impairment charge of $747 million during the second quarter of 2016 related to these operations and an additional loss of $66 million upon completion of the sale. (See Note 3 – Divestiture of Notes to Consolidated Financial Statements.)commodity-based activities;
ENERGY TRANSFER MERGER AGREEMENT
On September 28, 2015, we publicly announced in a press release that we had entered into a Merger Agreement with Energy Transfer and certain of its affiliates. The Merger Agreement provided that, subject to the satisfaction of customary closing conditions, we would merge with and into the newly formed ETC, with ETC surviving the ETC Merger.
On June 29, 2016, Energy Transfer provided us written notice terminating the Merger Agreement, citing the alleged failure of certain conditions under the Merger Agreement.
ORGANIZATIONAL REALIGNMENT
In September 2016, we announced organizational changes aiming to simplify our structure, increase direct operational alignment to advance our natural gas-focused strategy, and drive continued focus on customer service and execution. Effective January 1, 2017, we implemented these changes, which combined the management of certain of our operations and reduced the overall number of operating areas managed within our business.
Information in this report has generally been prepared to be consistent with the reportable segment presentationDisciplined growth in our consolidated financial statements in Part II, Item 8 of this document. These segments are discussed in further detail in the following sections.
FINANCIAL INFORMATION ABOUT SEGMENTS
See “Item 8 — Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements — Note 19 – Segment Disclosures.”service areas.
BUSINESS SEGMENTS
Substantially allEffective 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, through our subsidiaries. Our activitiesmanaged, and presented in 2016 were operated throughPart I of this Annual Report within the following reportingreportable segments: Transmission & Gulf of Mexico, Northeast G&P, and West.
Pursuant to the organizational realignment, our reportable segments as presented in the accompanying financial statements and management’s discussion and analysis.
Williams Partners —are comprised of our consolidated master limited partnership, WPZ, which includes gas pipeline and midstream businesses. The gas pipelinethe following business includesactivities:
Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco and pipeline joint project investments. The midstream business providesNorthwest Pipeline, as well as natural gas gathering, treating, processing, and compression services; NGL production, fractionation, storage, marketingtreating assets and transportation; deepwatercrude oil production handling and crude oil transportation services; an olefinassets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated variable interest entity), which is a proprietary floating production businesssystem, 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 several wholly ownedour midstream gathering, processing, and partially owned subsidiaries and joint project investments.
Prior to September 2016, this reporting segment also included our Canadian midstream operations comprised of an oil sands offgas processing plant near Fort McMurray, Alberta, an NGL/olefin fractionation facility,businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and the Boreal PipelineUtica Shale region of eastern Ohio, as well as a 65 percent interest in our Northeast JV (a consolidated variable interest entity) which were subsequently sold.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).
Williams NGL & Petchem Services —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, Belle pipelinethe Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and certain other domestic olefins pipeline assets. Prior to September 2016, this reportingthe Mid-Continent region which includes the Anadarko, Arkoma, and Permian basins. This segment also included certain Canadian growth projects under development, includingincludes our NGL and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a propane dehydrogenation facility50 percent equity-method investment in OPPL, a 50 percent equity-method investment in RMM, and a recently completed liquids extraction plant which were subsequently sold.
15 percent equity-method investment in Brazos Permian II.Other — primarily comprised of includes minor business activities that are not operating segments, as well as corporate operations and our Canadian construction services company.
As previously discussed, in September 2016 we announced organizational changes aiming to simplify our structure, increase direct operational alignment to advance our natural gas-focused strategy, and drive continued focus on customer service and execution. Effective January 1, 2017, we implemented these changes, which combined the management of certain of our operations and reduced the overall number of operating areas managed within our business. As a result of this realignment and the sale of our Canadian operations, the Williams NGL & Petchem Services reporting segment will be eliminated and the remaining assets will be reported with Other.operations.
Detailed discussion of each of our reporting segments follows. For a discussion of our ongoing expansion projects, seePart II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.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.
Williams PartnersTransmission & Gulf of Mexico
Gas Pipeline Business
Williams Partners' gas pipeline businesses consist primarily ofThis segment includes the Transco and Northwest Pipeline. Our gas pipeline business also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent equity-method investment in Gulfstream and a 41 percent interest in Constitution (a consolidated entity), which is under development. Transco andthat extends from the Gulf of Mexico to the eastern seaboard, the Northwest Pipeline own and operate a combined total of approximately 13,600 miles of pipelines with a total annual throughput of approximately 4,230 TBtu ofinterstate natural gas pipeline, as well as natural gas gathering, processing and peak-day delivery capacitytreating, crude oil production handling, and NGL fractionation assets within the onshore, offshore shelf, and
deepwater areas in and around the Gulf Coast states of approximately 15.5 MMdth of natural gas.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 9,700-mile9,800-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.
Pipeline system and customers
At December 31, 2016,2019, Transco’s system, had a mainline delivery capacity of approximately 6.6 MMdth of natural gas per daywhich extends from its production areasTexas to its primary markets, including delivery capacity from the mainline to locations on its Mobile Bay Lateral. Using its Leidy Line along with market-area storage and transportation capacity, Transco can deliver an additional 5.1 MMdth of natural gas per day forNew York, had a system-wide delivery capacity total oftotaling approximately 11.717.4 MMdth/d. During 2019, Transco completed four fully-contracted expansions, which added more than 0.6 MMdth of natural gasfirm transportation capacity per day.day to our pipeline. Transco’s system includes 4757 compressor stations, four underground storage fields, and anone LNG storage facility. Compression facilities at sea level-rated capacity total approximately 1.82.3 million horsepower.
Transco’s major natural gas transportation customers are public utilities and municipalities that provide service to residential, commercial, industrial and electric generation end users. Shippers on Transco’s system include public utilities, municipalities, direct industrial users, electric power generators, and natural gas marketers and producers. Transco’s firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of Transco’s business. Additionally, Transco offers interruptible transportation services under shorter-term agreements.
Transco has natural gas storage capacity in four underground storage fields located on or near its pipeline system or market areas and operates two of these storage fields. Transco also has storage capacity in an LNG storage facility that it owns and operates. The total usable gas storage capacity available to Transco and its customers in such underground storage fields and LNG storage facility and through storage service contracts is approximately 200 198 Bcf of natural gas. At December 31, 2016,2019, Transco’s customers had stored in its facilities approximately 151 140 Bcf of natural gas. In addition, wholly owned subsidiaries of Transco operate and hold a 35 percent equity-method investment in Pine Needle LNG Company, LLC, an LNG storage facility with 4 Bcf of storage capacity. Storage capacity permits Transco’sour 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.
Pipeline system and customers
At December 31, 2016,2019, Northwest Pipeline’s system, having long-term firm transportation and storage redelivery agreements with aggregate capacity reservations of approximately 3.83.9 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 transports and stores 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. Northwest Pipeline’s firm transportation and storage redelivery contracts are generally long-term contracts with various expiration dates and account for the major portion of Northwest Pipeline’s business. Additionally, Northwest Pipeline offers interruptible and short-term firm transportation service.
Northwest Pipeline owns a one-third 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-partythird-
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 | | | | |
| | | | | Pipeline | | Capacity | | Ownership | | |
| | | Location | | Miles | | (Bcf/d) | | Interest | | Supply Basins |
| | | | | | | | | | | |
| Consolidated: | | | | | | | | | | |
| Canyon Chief, including Blind Faith and Gulfstar extensions | | Deepwater Gulf of Mexico | | 156 | | 0.5 | | 100% | | Eastern Gulf of Mexico |
| Other Eastern Gulf | | Offshore shelf and other | | 46 | | 0.2 | | 100% | | Eastern Gulf of Mexico |
| Seahawk | | Deepwater Gulf of Mexico | | 115 | | 0.4 | | 100% | | Western Gulf of Mexico |
| Perdido Norte | | Deepwater Gulf of Mexico | | 105 | | 0.3 | | 100% | | Western Gulf of Mexico |
| Norphlet | | Deepwater Gulf of Mexico | | 58 | | 0.3 | | 100% | | Eastern Gulf of Mexico |
| Other Western Gulf | | Offshore shelf and other | | 103 | | 0.4 | | 100% | | Western Gulf of Mexico |
| Non-consolidated: (1) | | | | | | | | | | |
| Discovery | | Central Gulf of Mexico | | 594 | | 0.6 | | 60% | | Western Gulf of Mexico |
|
| | | | | | | | | | |
| | | Natural Gas Processing Facilities |
| | | | | | | NGL | | | | |
| | | | | Inlet | | Production | | | | |
| | | | | Capacity | | Capacity | | Ownership | | |
| | | Location | | (Bcf/d) | | (Mbbls/d) | | Interest | | Supply Basins |
| | | | | | | | | | | |
| Consolidated: | | | | | | | | | | |
| Markham | | Markham, TX | | 0.5 | | 45 | | 100% | | Western Gulf of Mexico |
| Mobile Bay | | Coden, AL | | 0.7 | | 35 | | 100% | | Eastern Gulf of Mexico |
| Non-consolidated: (1) | | | | | | | | | | |
| Discovery | | Larose, LA | | 0.6 | | 32 | | 60% | | Western Gulf of Mexico |
_____________
| |
| (1) | Includes 100 percent of the statistics associated with operated equity-method investments. |
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 | | Capacity | | Ownership | | |
| | | | | | Miles | | (Mbbls/d) | | Interest | | Supply Basins |
| | | | | | | | | | | | |
| Consolidated: | | |
| Mountaineer, including Blind Faith and Gulfstar extensions | | 155 | | 150 | | 100% | | Eastern Gulf of Mexico |
| BANJO | | 57 | | 90 | | 100% | | Western Gulf of Mexico |
| Alpine | | 96 | | 85 | | 100% | | Western Gulf of Mexico |
| Perdido Norte | | 74 | | 150 | | 100% | | Western Gulf of Mexico |
|
| | | | | | | | | | | |
| | | | | Production Handling Platforms |
| | | | | | | | | | | | |
| | | | | | | | Crude/NGL | | | | |
| | | | | | Gas Inlet | | Handling | | | | |
| | | | | | Capacity | | Capacity | | Ownership | | |
| | | | | | (MMcf/d) | | (Mbbls/d) | | Interest | | Supply Basins |
| | | | | | | | | | | |
| Consolidated: | | | | | | | | |
| Devils Tower | | 110 | | 60 | | 100% | | Eastern Gulf of Mexico |
| Gulfstar I FPS (1) | | 172 | | 80 | | 51% | | Eastern Gulf of Mexico |
| | | | | | | | | | | | |
| Non-consolidated: (2) | | | | | | | | |
| Discovery | | 75 | | 10 | | 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. |
Transmission & Gulf of Mexico Operating Statistics |
| | | | | | | | |
| | 2019 | | 2018 | | 2017 |
| | | | | | |
Volumes: | | | | | |
| Interstate natural gas pipeline throughput (Tbtu) | 5,593 |
| | 5,129 |
| | 4,533 |
|
| Gathering volumes (Bcf/d) - Consolidated | 0.25 |
| | 0.26 |
| | 0.31 |
|
| Gathering volumes (Bcf/d) - Non-consolidated (1) | 0.36 |
| | 0.26 |
| | 0.44 |
|
| Plant inlet natural gas volumes (Bcf/d) - Consolidated | 0.54 |
| | 0.50 |
| | 0.55 |
|
| Plant inlet natural gas volumes (Bcf/d) - Non-consolidated (1) | 0.36 |
| | 0.27 |
| | 0.43 |
|
| NGL production (Mbbls/d) - Consolidated (2) | 32 |
| | 32 |
| | 33 |
|
| NGL production (Mbbls/d) - Non-consolidated (1) (2) | 25 |
| | 20 |
| | 21 |
|
| NGL equity sales (Mbbls/d) - Consolidated (2) | 7 |
| | 6 |
| | 9 |
|
| NGL equity sales (Mbbls/d) - Non-consolidated (1) (2) | 6 |
| | 4 |
| | 5 |
|
| Crude oil transportation (Mbbls/d) - Consolidated (2) | 136 |
| | 140 |
| | 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. Williams Partners owns,We own, through a subsidiary, a 50 percent equity-method investment in Gulfstream. Williams Partners sharesWe share operating responsibilities for Gulfstream with the other 50 percent owner.
Williams Partners’ midstream business, one of the nation’s largestNortheast G&P
This segment includes our natural gas gatherersgathering, compression, processing, and processors, has primary service areas concentratedNGL fractionation businesses in major producing basinsthe Marcellus and Utica Shale regions in Arkansas, Colorado, New Mexico, Oklahoma, Texas, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio. The primary businesses are: (1) natural gas gathering, treating,
Acquisition of UEOM and processing; (2) NGL fractionation, storageformation 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 transportation; (3) crude oil transportation; and (4) olefins production. These fall withinclosed the middleacquisition of the processremaining 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 taking raw natural gasacquiring this additional interest, we obtained control of and crude oil fromnow consolidate UEOM. (See Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).
Concurrent with the producing fieldsUEOM 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 consumer. We also own and operate gas gathering and processing assets and pipelines primarily within the onshore, offshore shelf, and deepwater areas in and around the Gulf Coast states of Texas, Louisiana, Mississippi, and Alabama.Northeast JV business.
Key variables for this business will continue to be:
Producer drilling activities impacting natural gas supplies supporting our gathering and processing volumes;
Prices impacting commodity-based activities;
Retaining and attracting customers by continuing to provide reliable services;
Revenue growth associated with additional infrastructure either completed or currently under construction;
Disciplined growth in core service areas and new step-out areas.
Gathering, Processing, and Treating
Williams Partners’ gathering systems receive natural gas from producers’ oil and natural gas wells and gather these volumes to gas processing, treating or redelivery facilities. Typically, natural gas, in its raw form, is not acceptable for transportation in major interstate natural gas pipelines or for commercial use as a fuel. Williams Partners’ treating facilities remove water vapor, carbon dioxide, and other contaminants and collect condensate, but do not extract NGLs. Williams Partners’ is generally paid a fee based on the volume of natural gas gathered and/or treated, generally measured in the Btu heating value.
In addition, natural gas contains various amounts of NGLs, which generally have a higher value when separated from the natural gas stream. Our processing plants extract the NGLs in addition to removing water vapor, carbon dioxide, and other contaminants. NGL products include:
Ethane, primarily used in the petrochemical industry as a feedstock for ethylene production, one of the basic building blocks for plastics;
Propane, used for heating, fuel and as a petrochemical feedstock in the production of ethylene and propylene, another building block for petrochemical-based products such as carpets, packing materials, and molded plastic parts;
Normal butane, isobutane and natural gasoline, primarily used by the refining industry as blending stocks for motor gasoline or as a petrochemical feedstock.
Our gas processing services generate revenues primarily from the following three types of contracts:
Fee-based: We are paid a fee based on the volume of natural gas processed, generally measured in the Btu heating value. Our customers are entitled to the NGLs produced in connection with this type of processing agreement. A portion of our fee-based processing revenues includes a share of the margins on the NGLs produced. For the year ended December 31, 2016, 69 percent of the domestic NGL production volumes were under fee-based contracts.
Keep-whole: Under keep-whole contracts, we (1) process natural gas produced by customers, (2) retain some or all of the extracted NGLs as compensation for our services, (3) replace the Btu content of the retained NGLs that were extracted during processing with natural gas purchases, also known as shrink replacement gas, and (4) deliver an equivalent Btu content of natural gas for customers at the plant outlet. NGLs we retain in connection with this type of processing agreement are referred to as our equity NGL production. Under these agreements, we have commodity price exposure on the difference between NGL and natural gas prices. For the year ended December 31, 2016, 26 percent of the domestic NGL production volumes were under keep-whole contracts.
Percent-of-Liquids: Under percent-of-liquids processing contracts, we (1) process natural gas produced by customers, (2) deliver to customers an agreed-upon percentage of the extracted NGLs, (3) retain a portion of the extracted NGLs as compensation for our services, and (4) deliver natural gas to customers at the plant outlet. Under this type of contract, we are not required to replace the Btu content of the retained NGLs that were extracted during processing, and are therefore only exposed to NGL price movements. NGLs we retain in connection with this type of processing agreement are also referred to as our equity NGL production. For the year ended December 31, 2016, 5 percent of the domestic NGL production volumes were under percent-of-liquids contracts.
Our gathering and processing agreements have terms ranging from month-to-month to the life of the producing lease. Generally, our gathering and processing agreements are long-term agreements. Some contracts have price escalators which annually increase our gathering rates. In addition, certain contracts include fee redetermination or cost of service mechanisms that are designed to support a return on invested capital and allow our gathering rates to be
adjusted, subject to specified caps in certain cases, to account for variability in volume, capital expenditures, commodity price fluctuations, compression and other expenses. Certain of our gas gathering agreements include MVCs. If the minimum annual or semi-annual volume commitment is not met, these customers are obligated to pay a fee equal to the applicable fee for each Mcf by which the applicable customer’s minimum annual or semi-annual volume commitment exceeds the actual volume gathered. The revenue associated with such shortfall fees is generally recognized in the fourth quarter of each year.
Demand for gas gathering and processing services is dependent on producers’ drilling activities, which is impacted by the strength of the economy, natural gas prices, and the resulting demand for natural gas by manufacturing and industrial companies and consumers. Williams Partners’ gas gathering and processing customers are generally natural gas producers who have proved and/or producing natural gas fields in the areas surrounding its infrastructure. During 2016, Williams Partners’ facilities gathered and processed gas for approximately 200 customers. Williams Partners’ top eight gathering and processing customers accounted for approximately 78 percent of our gathering and processing fee revenues and NGL margins from our keep-whole and percent-of-liquids agreements.
Demand for our equity NGLs is affected by economic conditions and the resulting demand from industries using these commodities to produce petrochemical-based products such as plastics, carpets, packing materials and blending stocks for motor gasoline and the demand from consumers using these commodities for heating and fuel. NGL products are currently the preferred feedstock for ethylene and propylene production, which has shifted away from the more expensive crude-based feedstocks.
Geographically, the midstream natural gas assets are positioned to maximize commercial and operational synergies with our other assets. For example, most of the offshore gathering and processing assets attach and process or condition natural gas supplies delivered to the Transco pipeline. Our San Juan basin, southwest Wyoming, and Piceance systems are capable of delivering residue gas volumes into Northwest Pipeline’s interstate system in addition to third-party interstate systems. Our gathering systems in Pennsylvania delivers residue gas volumes into Transco’s pipeline in addition to third-party interstate systems.
The following table summarizes ourtables summarize the significant consolidated natural gas gathering assets:operated assets of this segment:
|
| | | | | | | | | |
| | Natural Gas Gathering Assets |
| | Location | | Pipeline Miles | | Inlet Capacity (Bcf/d) | | Ownership Interest | | Supply Basins/Shale Formations |
| Northeast | | | | | | | | | |
| Ohio Valley | West Virginia & Pennsylvania | | 210 | | 0.8 | | 100% | | Appalachian |
| Susquehanna Supply Hub | Pennsylvania & New York | | 399 | | 2.9 | | 100% | | Appalachian |
| Cardinal (1) | Ohio | | 352 | | 1.0 | | 66% | | Appalachian |
| Flint | Ohio | | 33 | | 0.2 | | 100% | | Appalachian |
| Marcellus South (2) | West Virginia & Pennsylvania | | 41 | | 0.1 | | 100% | | Appalachian |
| Atlantic-Gulf | | | | | | | | | |
| Canyon Chief, including Blind Faith and Gulfstar extensions | Deepwater Gulf of Mexico | | 156 | | 0.5 | | 100% | | Eastern Gulf of Mexico |
| Other Eastern Gulf | Offshore shelf and other | | 46 | | 0.2 | | 100% | | Eastern Gulf of Mexico |
| Seahawk | Deepwater Gulf of Mexico | | 115 | | 0.4 | | 100% | | Western Gulf of Mexico |
| Perdido Norte | Deepwater Gulf of Mexico | | 105 | | 0.3 | | 100% | | Western Gulf of Mexico |
| Other Western Gulf | Offshore shelf and other | | 120 | | 0.9 | | 100% | | Western Gulf of Mexico |
| West | | | | | | | | | |
| Four Corners | Colorado & New Mexico | | 3,743 | | 1.8 | | 100% | | San Juan |
| Wamsutter | Wyoming | | 1,973 | | 0.6 | | 100% | | Wamsutter |
| Southwest Wyoming | Wyoming | | 1,614 | | 0.5 | | 100% | | Southwest Wyoming |
| Piceance | Colorado | | 336 | | 1.5 | | (3) | | Piceance |
| Niobrara | Wyoming | | 184 | | 0.2 | | (4) | | Powder River |
| Barnett Shale | Texas | | 858 | | 0.9 | | 100% | | Barnett Shale |
| Eagle Ford Shale | Texas | | 1,010 | | 0.7 | | 100% | | Eagle Ford Shale |
| Haynesville Shale | Louisiana | | 598 | | 1.7 | | 100% | | Haynesville Shale |
| Permian | Texas | | 346 | | 0.1 | | 100% | | Permian |
| Mid-Continent | Oklahoma & Kansas | | 2,112 | | 0.9 | | 100% | | Miss-Lime, Granite Wash, Colony Wash |
|
| | | | | | | | | | |
| | | Natural Gas Gathering Assets |
| | | | | | | | | | | |
| | | | | | | Inlet | | | | |
| | | | | Pipeline | | Capacity | | Ownership | | |
| | | Location | | Miles | | (Bcf/d) | | Interest | | Supply Basins |
| | | | | | | | | | | |
| Consolidated: | | | | | | | | | | |
| Ohio Valley Midstream (1) | | Ohio, West Virginia, & Pennsylvania | | 216 | | 0.8 | | 65% | | Appalachian |
| Utica East Ohio Midstream (1) | | Ohio | | 53 | | 0.4 | | 65% | | Appalachian |
| Susquehanna Supply Hub | | Pennsylvania & New York | | 451 | | 4.3 | | 100% | | Appalachian |
| Cardinal (1) | | Ohio | | 365 | | 0.9 | | 66% | | Appalachian |
| Flint | | Ohio | | 95 | | 0.5 | | 100% | | Appalachian |
| Beaver Creek | | Pennsylvania | | 41 | | 0.1 | | 100% | | Appalachian |
| | | | | | | | | | | |
| Non-consolidated: (2) | | | | | | | | | | |
| Bradford Supply Hub | | Pennsylvania | | 726 | | 3.7 | | 66% | | Appalachian |
| Marcellus South | | Pennsylvania & West Virginia | | 306 | | 0.9 | | 68% | | Appalachian |
| Laurel Mountain | | Pennsylvania | | 2,053 | | 0.7 | | 69% | | Appalachian |
__________
|
| | | | | | | | | | |
| | | Natural Gas Processing Facilities |
| | | | | | | | | | | |
| | | | | | | NGL | | | | |
| | | | | Inlet | | Production | | | | |
| | | | | Capacity | | Capacity | | Ownership | | |
| | | Location | | (Bcf/d) | | (Mbbls/d) | | Interest | | Supply Basins |
| | | | | | | | | | | |
| Consolidated: | | | | | | | | | | |
| Fort Beeler | | Marshall County, WV | | 0.5 | | 62 | | 65% | | Appalachian |
| Oak Grove | | Marshall County, WV | | 0.4 | | 50 | | 65% | | Appalachian |
| Kensington | | Columbiana Co., OH | | 0.6 | | 68 | | 65% | | Appalachian |
| Leesville | | Carroll Co., OH | | 0.2 | | 18 | | 65% | | Appalachian |
_____________
| |
| (1) | Statistics reflect 100 percent of the assets from our 65 percent ownership in our Northeast JV and 66 percent ownership of Cardinal gathering system. |
| |
| (2) | Statistics reflectIncludes 100 percent of the Beaver Creek assets from our 67statistics 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.
Northeast G&P Operating Statistics
|
| | | | | | | | |
| | | 2019 | | 2018 | | 2017 |
| | | | | | | |
| Volumes: | | | | | | |
| Gathering (Bcf/d) - Consolidated (1) | | 4.24 |
| | 3.63 |
| | 3.31 |
| Gathering (Bcf/d) - Non-consolidated (2) | | 4.29 |
| | 3.76 |
| | 3.55 |
| Plant inlet natural gas (Bcf/d) - Consolidated (1) | | 1.04 |
| | 0.52 |
| | 0.43 |
| NGL production (Mbbls/d) (3) | | 76 |
| | 46 |
| | 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 ownership inof 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 gathering system.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.)
West
Gas Gathering, Processing, and Treating Assets
The following tables summarize the significant operated assets of this segment:
|
| | | | | | | | | | | |
| | | | Natural Gas Gathering Assets |
| | | | | | | | | | | | |
| | | | Location | | Pipeline Miles | | Inlet Capacity (Bcf/d) | | Ownership Interest | | Supply Basins/Shale Formations |
| | | | | | | | | | | | |
| Consolidated: | | | | | | | | | | |
| Wamsutter | | Wyoming | | 2,265 | | 0.7 | | 100% | | Wamsutter |
| Southwest Wyoming | | Wyoming | | 1,614 | | 0.5 | | 100% | | Southwest Wyoming |
| Piceance | | Colorado | | 352 | | 1.8 | | (2) | | Piceance |
| Barnett Shale | | Texas | | 845 | | 0.8 | | 100% | | Barnett Shale |
| Eagle Ford Shale | | Texas | | 1,275 | | 0.6 | | 100% | | Eagle Ford Shale |
| Haynesville Shale | | Louisiana | | 626 | | 1.8 | | 100% | | Haynesville Shale |
| Permian | | Texas | | 100 | | 0.1 | | 100% | | Permian |
| Mid-Continent | | Oklahoma & Texas | | 2,248 | | 0.9 | | 100% | | Miss-Lime, Granite Wash, Colony Wash, Arkoma |
| | | | | | | | | | | | |
| 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. |
| |
(4) | Includes our 50 percent ownership of the Jackalope gathering system. |
The following table summarizes our significant consolidated natural gas processing facilities:
|
| | | | | | | | | |
| | Natural Gas Processing Facilities |
| | Location | | Inlet Capacity (Bcf/d) | | NGL Production Capacity (Mbbls/d) | | Ownership Interest | | Supply Basins |
| Northeast | | | | | | | | | |
| Fort Beeler | Marshall County, WV | | 0.5 | | 62 | | 100% | | Appalachian |
| Oak Grove | Marshall County, WV | | 0.2 | | 25 | | 100% | | Appalachian |
| Atlantic-Gulf | | | | | | | | | |
| Markham | Markham, TX | | 0.5 | | 45 | | 100% | | Western Gulf of Mexico |
| Mobile Bay | Coden, AL | | 0.7 | | 30 | | 100% | | Eastern Gulf of Mexico |
| West | | | | | | | | | |
| Echo Springs | Echo Springs, WY | | 0.7 | | 58 | | 100% | | Wamsutter |
| Opal | Opal, WY | | 1.1 | | 47 | | 100% | | Southwest Wyoming |
| Bucking Horse (1) | Converse County, WY | | 0.1 | | 7 | | 50% | | Powder River |
| Willow Creek | Rio Blanco County, CO | | 0.5 | | 30 | | 100% | | Piceance |
| Parachute | Garfield County, CO | | 1.1 | | 6 | | 100% | | Piceance |
| Ignacio | Ignacio, CO | | 0.5 | | 29 | | 100% | | San Juan |
| Kutz | Bloomfield, NM | | 0.2 | | 12 | | 100% | | San Juan |
|
| | | | | | | | | | | |
| | | | Natural Gas Processing Facilities |
| | | | | | | | | | | | |
| | | | | | | | NGL | | | | |
| | | | | | Inlet | | Production | | | | |
| | | | | | Capacity | | Capacity | | Ownership | | |
| | | | Location | | (Bcf/d) | | (Mbbls/d) | | Interest | | Supply Basins |
| | | | | | | | | | | | |
| Consolidated: | | | | | | | | | | |
| Echo Springs | | Echo Springs, WY | | 0.7 | | 58 | | 100% | | Wamsutter |
| Opal | | Opal, WY | | 1.1 | | 47 | | 100% | | Southwest Wyoming |
| Willow Creek | | Rio Blanco County, CO | | 0.5 | | 30 | | 100% | | Piceance |
| Parachute | | Garfield County, CO | | 1.1 | | 6 | | 100% | | Piceance |
| | | | | | | | | | | | |
| Non-consolidated: (1) | | | | | | | | | | |
| Fort Lupton | | Colorado | | 0.2 | | 50 | | 50% | | Denver-Julesburg |
| Keenesburg I | | Colorado | | 0.2 | | 40 | | 50% | | Denver-Julesburg |
______________________
| |
| (1) | Statistics reflectIncludes 100 percent of the assets from our 50 percent ownership of Bucking Horse gas processing facility.statistics associated with operated equity-method investments. |
In addition, we own and operate several natural gas treating facilities in New Mexico, Colorado, Texas, and Louisiana which bring natural gas to specifications allowable by major interstate pipelines.
We also own and operate fractionation facilities at Moundsville, de-ethanization and condensate facilities at our Oak Grove processing plant, another condensate stabilization facility near our Oak Grove plant, and an ethane transportation pipeline. Our two condensate stabilizers are capable of handling 17 Mbbls/d of field condensate. NGLs are extracted from the natural gas stream in our cryogenic processing plants. Our Oak Grove de-ethanizer is capable of handling up to approximately 80 Mbbls/d of mixed NGLs to extract up to approximately 40 Mbbls/d of ethane. The remaining mixed NGL stream from the de-ethanizer is then transported and fractionated at our Moundsville facilities, which are capable of handling more than 42 Mbbls/d of mixed NGLs. Ethane produced at our de-ethanizer is transported to markets via our 50-mile ethane pipeline from Oak Grove to Houston, Pennsylvania.
Our gathering business in the Northeast also provides multiple takeaway options to its customers. Ohio Valley Midstream makes customer deliveries with interconnections to two pipelines. Susquehanna Supply Hub makes deliveries for its customers with interconnections to Transco, as well as five other pipelines, while our Cardinal system utilizes interconnections with Blue Racer and UEOM. In addition, our NGL processing business utilizes connections with multiple pipelines, as well as truck and rail transportation to local and regional markets.
Crude Oil Transportation and Production Handling Assets
In addition to our natural gas assets, we own and operate four deepwater crude oil pipelines and own production platforms serving the deepwater in the Gulf of Mexico. Our crude oil transportation revenues are typically volumetric-based fee arrangements. However, a portion of our marketing revenues are recognized from purchase and sale arrangements whereby the oil that we transport is purchased and sold as a function of the same index-based price. Our offshore floating production platforms provide centralized services to deepwater producers such as compression, separation, production handling, water removal, and pipeline landings. Revenue sources have historically included a combination of fixed-fee, volumetric-based fee and cost reimbursement arrangements. Fixed fees associated with the resident production at our Devils Tower facility are recognized on a units-of-production basis. Fixed fees associated with the resident production at our Gulfstar One facility are recognized as the guaranteed capacity is made available.
The following tables summarize our significant crude oil transportation pipelines and production handling platforms:
|
| | | | | | | |
| | Crude Oil Pipelines |
| | Pipeline Miles | | Capacity (Mbbls/d) | | Ownership Interest | | Supply Basins |
| Mountaineer, including Blind Faith and Gulfstar extensions | 172 | | 150 | | 100% | | Eastern Gulf of Mexico |
| BANJO | 57 | | 90 | | 100% | | Western Gulf of Mexico |
| Alpine | 96 | | 85 | | 100% | | Western Gulf of Mexico |
| Perdido Norte | 74 | | 150 | | 100% | | Western Gulf of Mexico |
|
| | | | | | | |
| | Production Handling Platforms |
| | Gas Inlet Capacity (MMcf/d) | | Crude/NGL Handling Capacity (Mbbls/d) | | Ownership Interest | | Supply Basins |
| Devils Tower | 210 | | 60 | | 100% | | Eastern Gulf of Mexico |
| Gulfstar I FPS (1) | 172 | | 80 | | 51% | | Eastern Gulf of Mexico |
__________
| |
(1) | Statistics reflect 100 percent of the assets from our 51 percent interest in Gulfstar One. |
Canadian Operations
Williams Partners completed the sale of its Canadian operations in September 2016. This business included an oil sands offgas processing plant located near Fort McMurray, Alberta, and an NGL/olefin fractionation facility located at Redwater, Alberta, which is near Edmonton, Alberta, and the Boreal Pipeline which transported NGLs and associated olefins from the Fort McMurray plant to the Redwater fractionation facility. This business allowed us to extract, fractionate, treat, store, terminal and sell the ethane/ethylene, propane, propylene, normal butane (butane), iso-butane, alky feedstock, and condensate recovered from a third-party oil sands bitumen upgrader. The commodity price exposure of this asset was the spread between the price for natural gas and the NGL and olefin products we produce. These products were sold within Canada and the United States.
Operating statistics
The following table summarizes our significant operating statistics:
|
| | | | | | | | |
| | 2016 | | 2015 | | 2014 |
| Volumes: | | | | | |
| Canadian propylene sales (millions of pounds) | 87 |
| | 161 |
| | 143 |
|
| Canadian NGL sales (millions of gallons) | 141 |
| | 284 |
| | 218 |
|
Gulf Olefins
We have an 88.5 percent undivided interest and operatorship of an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf region. Our olefins business also operates an ethylene storage hub at Mont Belvieu using leased third-party underground storage caverns.
In 2015, we placed in service an expansion of the olefins production facility that increased its ethylene production capacity by 600 million pounds per year, for a total production capacity of 1.95 billion pounds of ethylene and 114 million pounds of propylene per year. Our feedstocks for the cracker are ethane and propane; as a result, these assets are primarily exposed to the price spread between ethane and propane, and ethylene and propylene, respectively. Ethane and propane are available for purchase from third parties and from affiliates. Following an explosion and fire that occurred in 2013, the Geismar plant resumed consistent operations in late March 2015 and reached full production capacity in the third quarter of 2015.
Our refinery grade propylene splitter has a production capacity of approximately 500 million pounds per year of propylene. At our propylene splitter, we purchase refinery grade propylene and fractionate it into polymer grade propylene and propane; as a result, this asset is exposed to the price spread between those commodities.
We own 283 miles of pipeline systems in Louisiana and Texas that provide feedstock transportation to the Geismar olefins plant, the RPG Splitter, and other third-party crackers. These systems include the Bayou ethane pipeline, which provides ethane transportation from fractionation and storage facilities in Mont Belvieu, Texas, to the Geismar olefins plant in south Louisiana and serves customers along the way; as well as the Geismar ethane and propane systems in Louisiana, which provide feedstock transportation to the Geismar olefins plant and other customers. We also own a pipeline that has the capacity to supply 12 Mbbls/d of ethane from Discovery’s Paradis fractionator to the Geismar olefins plant.
As a merchant producer of ethylene and propylene, our product sales are to customers for use in making plastics and other downstream petrochemical products destined for both domestic and export markets. We are currently seeking to monetize our ownership interest in the Geismar, Louisiana, olefins plant and complex (see Overview within Management’s Discussion and Analysis of Financial Condition and Results of Operations).
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.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 than a long-term agreement to sell our equity NGLs transported on OPPL, the majority of sales are based on supply contracts of one year or less in duration.
In certain situations to facilitate our gas gathering and processing activities, we buy natural gas from our producer customers for resale.
We also market olefin products to a wide range of users in the energy and petrochemical industries. In order to meet sales contract obligations, we may purchase olefin products for resale.
Other NGL & Petchem Operations
We own interests in and/or operate NGL fractionation and storage assets in central Kansas near Conway. These assets include a 50 percent interest in an NGL fractionation facility with capacity of slightly more than 100 Mbbls/d and we own approximately 20 million barrels of NGL storage capacity.
We own 114 milesWest Operating Statistics
|
| | | | | | | | | |
| | | 2019 | | 2018 | | 2017 |
| | | | | | | |
| Volumes: | | | | | | |
| Gathering (Bcf/d) - Consolidated | | 3.52 |
| | 4.27 |
| | 4.53 |
|
| Gathering (Bcf/d) - Non-consolidated (1) | | 0.20 |
| | 0.08 |
| | — |
|
| Plant inlet natural gas (Bcf/d) - Consolidated | | 1.48 |
| | 2.01 |
| | 2.07 |
|
| Plant inlet natural gas (Bcf/d) - Non-consolidated (1) | | 0.08 |
| | 0.08 |
| | — |
|
| NGL production (Mbbls/d) - Consolidated (2) | | 54 |
| | 84 |
| | 77 |
|
| NGL production (Mbbls/d) - Non-consolidated (1) (2) | | 12 |
| | 3 |
| | — |
|
| NGL equity sales (Mbbls/d) - Consolidated (2) | | 22 |
| | 33 |
| | 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 pipelines inFour Corners Assets
In October 2018, we completed the Houston Ship Channel area which transport a varietysale of products including ethane, propane, ammonia, tertiary butyl alcohol, and other industrial products used in the petrochemical industry. We also own a tunnel crossing pipeline under the Houston Ship Channel. A portion of these pipelines are leased to third parties.
WPZ Operating Areas
Effective January 1, 2017, WPZ organizes these businesses into the following operating areas:
Northeast G&P is comprised ofour natural gas gathering and processing compression, and NGL fractionation businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern Ohio, as well as a 66 percent interest in Cardinal (a consolidated entity), a 62 percent equity-method investment in UEOM, a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, and Appalachia Midstream Services, LLC, which owns an approximate average 41 percent equity-method investment in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).
Atlantic-Gulf is comprised of an interstate natural gas pipeline, Transco, and significant natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated entity) which is a proprietary floating productionFour Corners area of New Mexico and Colorado. The system and various petrochemical and feedstock pipelines in the Gulf Coast region, as well as a 50 percent equity-method investment in Gulfstream, a 41 percent interest in Constitution (a consolidated entity) which is under development, and a 60 percent equity-method investment in Discovery.
West iswas comprised of an interstate3,742 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 pipeline, Northwest Pipeline,processing inlet capacity and natural gas gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming, as well as the Barnett Shale region41 Mbbls/d of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware, and Permian basins. West also includes an NGL and natural gas marketing business, storage facilities, and an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, as well as a 50 percent equity-method investment in the Delaware basin gas gathering system in the Permian basin, and a 50 percent equity-method investment in OPPL.
NGL & Petchem Services is comprised of our 88.5 percent undivided interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter. Prior to September 2016, this operating area also included an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility which were subsequently sold.capacity.
Certain Equity-Method Investments
DiscoveryBrazos Permian II
We ownacquired a 60non-operated 15 percent interest in Brazos Permian II in December 2018 by contributing cash and operate the facilitiesour existing Delaware basin assets. This partnership consists of Discovery. Discovery’s assets include a 600725 miles of gas gathering pipelines, 460 MMcf/d cryogenicof natural gas processing plant near Larose, Louisiana,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 32 Mbbls/d NGL fractionator plant near Paradis, Louisiana, and a 614-mile offshore natural gas gathering and transportation system in the Gulf of Mexico with an inlet capacity of 1,350 MMcf/d, including the Keathley Canyon Connector, a 209-mile deepwater lateral pipeline in the central deepwater Gulf of Mexico that contributes 400 MMcf/d of inlet capacity. Discovery’s assets also include a crude oil production handling platform with a crude oil/NGL handling capacity of 10 Mbbls/dgathering and natural gas processing capacitybusiness in Colorado’s Denver-Julesburg basin. As of 75 MMcf/d.
Laurel Mountain
We own a 69 percent interest in a joint venture, Laurel Mountain, that includes a 2,053-mile gathering system thatDecember 31, 2019, 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
Weand own a 58 percent interest in Caiman II, which owns a 50 percent interest in Blue Racer, a joint project to own, operate, develop and acquire midstream assets in the Utica Shale and certain adjacent areas in the Marcellus Shale. Blue Racer’s assets include 688 miles of natural gasRMM. RMM includes an approximate 80-mile crude oil gathering pipelines, including 422 miles of large-diameter pipelines, and the Natrium complex in Marshall County, West Virginia, with a cryogenic processing capacity of 400 MMcf/d and fractionation capacity of approximately 123,000 Bbls/d. Blue Racer also owns the Berne complex in Monroe County, Ohio, with a cryogenic processing capacity of 400 MMcf/d, and NGL and condensate pipelines connecting Natrium to Berne.system.
Utica East Ohio Midstream
We own a 62 percent interest in UEOM, a joint project to develop infrastructure for the gathering, processing and fractionation of natural gas and NGLs in the Utica Shale play in eastern Ohio. We, along with other equity owners, operate the infrastructure complex which consists of natural gas gathering and compression facilities, four processing plants with a total capacity of 800 MMcf/d, 41 Mbbls/d of condensate stabilization capacity, a 135 Mbbls/d NGL fractionation facility, approximately 950,000 barrels of NGL storage capacity and other ancillary assets, including
loading and terminal facilities that are operated by our partner. These assets earn a fixed fee that escalates annually within a specified range.
Aux Sable
We own a 14.6 percent interest in Aux Sable and its Channahon, Illinois, gas processing and NGL fractionation facility near Chicago. The facility is capable of processing up to 2.1 Bcf/d of natural gas from the Alliance Pipeline system and fractionating approximately 107 Mbbls/d of extracted liquids into NGL products. Additionally, Aux Sable owns an 80 MMcf/d gas conditioning plant and a 12-inch, 83-mile gas pipeline infrastructure in North Dakota that provides additional NGLs to Channahon from the Bakken Shale in the Williston basin.
Appalachia Midstream Investments
Through our Appalachia Midstream Investments, we operate 100 percent of and own an approximate average 41 percent interest in multiple natural gas gathering systems that consist of approximately 979 miles of gathering pipeline in the Marcellus Shale region. The majority of our volumes in the region are gathered from northern Pennsylvania, southwestern Pennsylvania and the northwestern panhandle of West Virginia in core areas of the Marcellus Shale. Appalachia Midstream Investments operates the assets under long-term, 100 percent fixed-fee gathering agreements that include significant acreage dedications and cost of service mechanisms.
Delaware basin gas gathering system
We own a non-operated 50 percent interest in the Delaware basin gas gathering system (DBJV) in the Permian basin. The system is comprised of more than 450 miles of gathering pipeline, located in west Texas.
Acquisition of Additional Interests in Appalachia Midstream Investments
In February 2017, we announced agreements to acquire additional interests in two Marcellus Shale gathering systems within Appalachia Midstream Investments in exchange for equity-method investment interests in DBJV and the Ranch Westex gas processing plant. We also expect to receive a total of $200 million in cash as part of the agreements, subject to customary closing conditions and purchase price adjustments. The transactions are expected to close in late first-quarter or early second-quarter 2017.
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 1,0961,035 miles of NGL pipeline extending from Opal, Wyoming, to the Mid-Continent NGL market center near Conway, Kansas, along with extensions into the Piceance and Denver-Julesberg basins in Colorado and the Bakken Shale in the Williston basin in North Dakota. Our equity NGL volumes from two of our three Wyoming plants and our Willow Creek facility in Colorado are dedicated for transport on OPPL under a long-term transportation agreement. NGL volumes from our RMM equity-method investment are also transported on OPPL.
Operating StatisticsJackalope
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 following table summarizes our significant operating statistics for Williams Partners’ domestic midstream business:system was comprised of more than 450milesof gathering pipeline, located in west Texas.
|
| | | | | | | | |
| | 2016 | | 2015 | | 2014 |
| Volumes: (1) | | | | | |
| Gathering (Bcf/d) | 8.25 |
| | 8.34 |
| | 8.90 |
|
| Plant inlet natural gas (Bcf/d) | 3.50 |
| | 3.52 |
| | 3.82 |
|
| NGL production (Mbbls/d) (2) | 151 |
| | 131 |
| | 128 |
|
| NGL equity sales (Mbbls/d) (2) | 46 |
| | 31 |
| | 27 |
|
| Crude oil transportation (Mbbls/d) (2) | 113 |
| | 126 |
| | 105 |
|
| Geismar ethylene sales (millions of pounds) | 1,638 |
| | 1,066 |
| | — |
|
__________
| |
(1) | Excludes volumes associated with equity-method investments. |
| |
(2) | Annual average Mbbls/d. |
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 NGL & Petchem Services
The Williams NGL & Petchem Services segment is comprised ofOlefins, L.L.C, a wholly owned subsidiary which owned our Texas Belle88.5 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 and certain other domestic olefins pipeline assets. Prior to its sale in September 2016, this reporting segment also included the Horizon liquids extraction plant which was placed in service in March 2016 and a propane dehydrogenation facility which was under development. As this segment is currently comprised primarily of projects under development, reported revenues to-date are nominal. Effective January 1, 2017, these assets will be reported in Other.system.
Additional Business Segment Information
Our ongoing business segmentsRevenues by service that exceeded 10 percent of consolidated revenues are presented as continuing operations in the accompanying financial statements andNote 2 – Revenue Recognition of Notes to Consolidated Financial Statements included in Part II.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 distributions, and advances from our subsidiaries, investments, payments by subsidiaries for services rendered, and, if needed, external financings, and net proceeds from asset sales.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.
Revenues by service within our Williams Partners segment that exceeded 10 percent of consolidated revenue include:
|
| | | |
| | Total |
| | (Millions) |
| 2016 | |
| Service: |
|
|
| Regulated natural gas transportation and storage | $ | 2,001 |
|
| Gathering, processing, and production handling | 2,729 |
|
| 2015 | |
| Service: | |
| Regulated natural gas transportation and storage | $ | 1,938 |
|
| Gathering, processing, and production handling | 2,804 |
|
| 2014 | |
| Service: | |
| Regulated natural gas transportation and storage | $ | 1,781 |
|
| Gathering, processing and production handling | 1,838 |
|
We have one customer, Chesapeake Energy Corporation, and its affiliates, that accounts for 14 percent of our total revenue in 2016. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements for additional details.)
REGULATORY MATTERS
FERC
Our gas pipeline interstate transmission and storage activities are subject to FERC regulation under the Natural Gas Act of 1938 (NGA) and under the Natural Gas Policy Act of 1978, and, as such, 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 companycompanies 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. Each of ourOur interstate natural gas pipeline companies establishes itsestablish rates primarily 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 are:include:
Costs of providing service, including depreciation expense;
Allowed rate of return, including the equity component of the capital structure and related income taxes;
Contract and volume throughput assumptions.
The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the reservation and commodity rates also impact profitability. As a result of these proceedings, certain revenues previously collected may be subject to refund.
We also own interests in and operate two offshore transmissionnatural gas liquids pipelines that are regulated by the FERC because they are deemed to transport gas in interstate commerce. Black Marlin Pipeline Company provides transportation service for offshore Texas production in the High Island areavarious federal and redelivers that gas to intrastate pipeline interconnects near Texas City. Discovery provides transportation service for offshore Louisiana production from the South Timbalier, Grand Isle, Ewing Bank, and Green Canyon (deepwater) areas to an onshore processing facility and downstream interconnect points with major interstate pipelines. In addition, Williams Partners owns a 50 percent equity-method investment in and is the operator of OPPL, which is anstate governmental agencies. Services provided on our interstate natural gas liquids pipeline regulatedpipelines are subject to regulation under the Interstate Commerce Act by the FERC, pursuantwhich 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 the Interstate Commerce Act. OPPL provides transportation service pursuant to tariffs filed with the FERC.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. However, PHMSA is completing a congressionally-mandated review of the adequacy of the existing federal and state regulations for gathering lines and has indicated that it may apply additional safety standards to rural gas gathering lines in the future.
States are largely preempted by federal law from regulating pipeline safety for interstate pipelines but most are certified by PHMSA to assume responsibility for enforcing intrastate pipeline safety regulations and inspecting intrastate
pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, they vary considerably in their authority and capacity to address pipeline safety.
On January 3, 2012, the Pipeline Safety Act was enacted. The Pipeline Safety Act requires PHMSA to complete a number of reports in preparation for potential rulemakings. The issues addressed in these rulemaking provisions include, but are not limited to, the use of automatic or remotely controlled shut-off valves on new or replaced transmission line facilities, modifying the requirements for pipeline leak detection systems, and expanding the scope of the pipeline integrity management requirements for both gas and liquid pipeline systems. On June 22, 2016, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 was enacted, further strengthening PHMSA’s safety authority.
Pipeline Integrity Regulations
We have developed 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 20172020 associated with this program to be approximately $57$133 million. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through Northwest Pipeline’s and Transco’s rates.
We developed ahave 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 20172020 associated with this program will be approximately $7$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 RegulationRegulations
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 midstream gathering isgas and liquids pipelines located on the outer continental shelf are subject to the Outer Continental Shelf Lands Act, (OCSLA). Although offshore gathering facilities are not subject to the NGA, offshore transmission pipelines are subject to the NGA, and in recent years the FERC has taken a broad view of offshore transmission, finding many shallow-water pipelines to be jurisdictional transmission. Most offshore gathering facilities are subject to the OCSLA, which provides in part that outer continental shelf pipelines “must provide open and nondiscriminatory access to both owner and nonowner shippers.”
Olefins
Our olefins assets are regulated by the Louisiana Department of Environmental Quality, the Texas Railroad Commission,See Part II, Item 8. Financial Statements and various other state and federal entities regarding our liquids pipelines.
These olefins assets are also subject to the liquid pipeline safety and integrity regulations previously discussed above since both Louisiana and Texas have adopted the integrity management regulations defined by PHMSA.
SeeSupplementary Data — Note 1819 – 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 FactorsFactors” — The “The operation of our businesses might also be adversely affected by regulatory proceedings, changes in government regulations or in their
interpretation or implementation, or the introduction of new laws or regulations applicable to our businesses or our customers,” and “The natural gas sales, transportation, and storage operations of our gas pipelines are subject to regulation by the FERC, which could have an adverse impact on their ability to establish transportation and storage rates that would allow them to recover the full cost of operating their respective pipelines, including a reasonable rate of return."”
ENVIRONMENTAL MATTERS
Our operations are subject to federal environmental laws and regulations as well as the state, local, and tribal laws and regulations adopted by the jurisdictions in which we operate. We could incur liability to governments or third parties for any unlawful discharge of pollutants into the air, soil, or water, as well as liability for cleanup costs. Materials could be released into the environment in several ways including, but not limited to:
Leakage from gathering systems, underground gas storage caverns, pipelines, processing or treating facilities, transportation facilities, and storage tanks;
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 FactorsFactors” — “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 currentour 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 1819 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements.
COMPETITION
Gas Pipeline Business
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 haullong-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
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. We primarily face competition to the extent these agreements approach renewal and new volume opportunities arise. Competition for natural gas volumes is primarily based on reputation, commercial terms (products retained or fees charged), array of services provided, efficiency and reliability of services, location of gathering facilities, available capacity, downstream interconnects, and latent capacity. We believe our significant presence in traditional prolific supply basins, our solid positions in growing shale plays, our expertise and reputation as a reliable operator, and our ability to offer integrated packages of services position us well against our competition.
Our olefins business (primarily ethylene and propylene production), competes in a worldwide market place. However, the majority of North American olefins producers have significant downstream petrochemical manufacturing for plastics and other petrochemical products. We participate as a merchant seller of olefins with no downstream petrochemical manufacturing; therefore, at any time we can be either a supplier or a competitor to these companies. We compete on the basis of service, price, and availability of products that we produce.
For additional information regarding competition for our services or otherwise affecting our business, please refer to Part 1, Item 1A. “Risk FactorsFactors” - “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.”
EMPLOYEES
At February 1, 2017,2020, we had approximately 5,6044,812 full-time employees.
FINANCIALWEBSITE ACCESS TO REPORTS AND OTHER INFORMATION ABOUT GEOGRAPHIC AREAS
See Note 19 – Segment DisclosuresWe 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 Notescharge, 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 Consolidated Financial Statements for amountsthose reports filed or furnished pursuant to Section 13(a) or 15(d) of revenues during the last three fiscal years from external customers attributableExchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the United StatesSEC. Our Corporate Governance Guidelines, Sustainability Report, Code of Ethics for Senior Officers, Board committee charters, and all foreign countries. Also see Note 19 – Segment Disclosuresthe Williams Code of NotesBusiness 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 Consolidated Financial Statements for information relating to long-lived assets during the last three fiscal years, located in the United States and all foreign countries.our Corporate Secretary, One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.
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 The Williams Companies, Inc. (Williams) may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act).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.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 fact,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”“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 cash distributions by Williams Partners L.P. (WPZ) with respect to limited partner interests;
Levels of dividends to Williams stockholders;
Future credit ratings of Williams WPZ, and theirits 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 and olefins prices, supply, and demand;
Demand for our services.
Forward-looking statements are based on numerous assumptions, uncertainties, and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:
Whether WPZ will produce sufficient cash flows to provide the levelAvailability of cash distributions that we expect;supplies, market demand, and volatility of prices;
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 pay currentsuccessfully identify, evaluate, and expected levelstimely execute our capital projects and investment opportunities;
The strength and financial resources of dividends;our competitors and the effects of competition;
Whether WPZ elects to pay expected levelsThe amount of cash distributions from and capital requirements of our investments and joint ventures in which we elect to pay expected levels of dividends;participate;
Whether we will be able to effectively execute our financing planplan;
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 the receiptclimate conditions and physical damage to our facilities;
Acts of anticipated levels of proceeds from planned asset sales;terrorism, cybersecurity incidents, and related disruptions;
Whether we will be able to effectively manage the transitionOur costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;
Changes in our board of directorsmaintenance and managementconstruction costs, as well as successfully execute our business restructuring;ability to obtain sufficient construction related inputs including skilled labor;
Availability of supplies, including lower than anticipated volumes from third parties served by our midstream business, and market demand;
Volatility of pricing including the effect of lower than anticipated energy commodity prices and margins;
Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on customers and suppliers);
The strength and financial resources of our competitors and the effects of competition;
Whether we are able to successfully identify, evaluate, and timely execute our capital projects and other
investment opportunities in accordance with our forecasted capital expenditures budget;
Our ability to successfully expand our facilities and operations;
Development of alternative energy sources;
Availability of adequate insurance coverage and the impact of operational and developmental hazards and unforeseen interruptions;
The impact of existing and future laws, regulations, the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain permits and achieve favorable rate proceeding outcomes;
Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;
Changes in maintenance and construction costs;
Changes in the current geopolitical situation;
Our exposure to the credit risk of our customers and counterparties;
Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally-recognizednationally recognized credit rating agencies, and the availability and cost of capital;
The amountChanges in the current geopolitical situation;
Whether we are able to pay current and expected levels of cash distributions from and capital requirements of our investments and joint ventures in which we participate;dividends;
Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities;
Acts of terrorism, including cybersecurity threats and related disruptions;
Additional risks described in our filings with the Securities and Exchange Commission (SEC).Commission.
Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
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.
Litigation pertaining
Risks Related to the ETC Merger, including litigation related to Energy Transfer Equity, L.P.’s (ETE’s) termination of and failure to close the ETC Merger, may negatively impact our business and operations.Our Business
We have incurred and may continue to incur additional costs in connection with the prosecution, defense or settlement of the currently pending and any future litigation relating to the ETC Merger or ETE’s termination of and failure to close the ETC Merger. Such litigation includes, among other litigation matters, litigation brought by stockholders of us and unitholders of WPZ related to the ETC Merger and/or Williams’ termination of the merger agreement with WPZ. Such litigation also includes the on-going litigation against ETE and its affiliates a portion of which is on appeal in the Delaware Supreme Court and in which ETE has asserted counterclaims against us. We continue to believe that our lawsuit against ETE and its affiliates is an enforcement of our rights under the Merger Agreement and that this lawsuit is designed to deliver to our stockholders benefits under the Merger Agreement. We cannot predict the outcome of this litigation. Such litigation may also create a distraction for our management team and board of directors and require time and attention. In addition, any litigation relating to the ETC Merger or ETE’s termination of and failure to close the ETC Merger could, among other things, adversely affect our financial condition and results of operations.
We are exposed to the credit risk of our customers and counterparties, including Chesapeake Energy Corporation and its affiliates, and our credit risk management will not be able to completely eliminate such risk.
We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business. Generally, our customers are rated investment grade, are otherwise considered creditworthy or are required to make prepayments or provide security to satisfy credit concerns. However, our credit procedures and policies cannot completely eliminate customer and counterparty credit risk. Our customers and counterparties include industrial customers, local distribution companies, natural gas producers, and marketers whose creditworthiness may be suddenly and disparately impacted by, among other factors, commodity price volatility,
deteriorating energy market conditions, and public and regulatory opposition to energy producing activities. In a low commodity price environment certain of our customers could be negatively impacted, causing them significant economic stress including, in some cases, to file for bankruptcy protection or to renegotiate contracts. To the extent one or more of our key customers commences bankruptcy proceedings, our contracts with the customers may be subject to rejection under applicable provisions of the United States Bankruptcy Code, or may be renegotiated. Further, during any such bankruptcy proceeding, prior to assumption, rejection or renegotiation of such contracts, the bankruptcy court may temporarily authorize the payment of value for our services less than contractually required, which could have a material adverse effect on our business, results of operations, cash flows, and financial conditions. For example, Chesapeake Energy Corporation and its affiliates, which accounted for approximately 14 percent of our 2016 consolidated revenues, have experienced significant, negative financial results due to sustained low commodity prices. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties or otherwise do not take or are unable to take sufficient mitigating actions, including obtaining sufficient collateral, deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off accounts receivable. Such write-downs or write-offs could negatively affect our operating results in the periods in which they occur, and, if significant, could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
Prices for NGLs, olefins, natural gas, 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 NGLs, olefins, natural gas, oil, or other commodities, and the differences between prices of these commodities, and could be materially adversely affected by an extended period of current low commodity prices or a further decline in commodity prices. Price volatility 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 NGLs, olefins, natural gas, oil, and other commodities are likely to continue to be volatile. Wide fluctuations in prices might result from one or more factors beyond our control, including:
Worldwide and domestic supplies of and demand for natural gas, NGLs, olefins, oil, and related commodities;
Turmoil in the Middle East and other producing regions;
The activities of the Organization of Petroleum Exporting Countries;
The level of consumer demand;
The price and availability of other types of fuels or feedstocks;
The availability of pipeline capacity;
Supply disruptions, including plant outages and transportation disruptions;
The price and quantity of foreign imports of natural gas and oil;
Domestic and foreign governmental regulations and taxes;
The credit of participants in the markets where products are bought and sold.
Downgrades of our credit ratings, which are determined outside of our control by independent third parties, impact our liquidity, access to capital, and our costs of doing business.
Downgrades of our credit ratings increase our cost of borrowing and could require us to provide collateral to our counterparties, negatively impacting our available liquidity. In addition, our ability to access capital markets could continue to be limited by the downgrading of our credit ratings.
Credit rating agencies perform independent analysis when assigning credit ratings. This analysis includes a number of criteria such as, business composition, market, and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are subject to revision or withdrawal at any time by the ratings agencies. As of the date of the filing of this report, we have been assigned below investment-grade credit ratings by each of the three credit ratings agencies.
Our ability to obtain credit in the future could be affected by WPZ’s credit ratings.
A substantial portion of our operations are conducted through, and our cash flows are substantially derived from distributions paid to us by, WPZ. Due to our relationship with WPZ, our ability to obtain credit will be affected by WPZ’s credit ratings. If WPZ were to experience a deterioration in its credit standing or financial condition, our access to capital, and our ratings could be adversely affected. Any future downgrading of a WPZ credit rating could also result in a downgrading of our credit rating. A downgrading of a WPZ credit rating could limit our ability to obtain financing in the future upon favorable terms, if at all.
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 couldhave, 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 and thefacilities. The import and export of natural gas supplies. Localized lowsupplies 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.
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
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.
We also face all the Additional risks associated with construction including political opposition by landowners, environmental activists, and others resulting in the delay and/or denial of required governmental permits. Other construction risksmay include the inability to obtain rights-of-way, skilled labor, equipment, materials, and other required inputs in a timely manner such that projects are completed, on time or at all, and the risk that construction cost overruns could cause total project costs to exceed budgeted costs. Additional risks associated with growing our business include, among others, that:
Changing circumstances and deviations in variables could negatively impact our investment analysis, including our projections of revenues, earnings, and cash flow relating to potential investment targets, resulting in outcomes which are materially different than anticipated;
We could be required to contribute additional capital to support acquired businesses or assets;
We may assume liabilities that were not disclosed to us, that exceed our estimates and for which contractual protections are either unavailable or prove inadequate;
Acquisitions could disrupt our ongoing business, distract management, divert financial and operational resources from existing operations and make it difficult to maintain our current business standards, controls, and procedures;
Acquisitions and capital projects may require substantial new capital, including proceeds from the issuance of debt or equity, and we may not be able to access capital markets or obtain acceptable terms.
If realized, any of these risks could have an adverse impact on our financial condition, results of operations, including the possible impairment of our assets, or cash flows.
We do not own all of the interests in the Partially Owned Entities, which could adversely affect our ability to operate and control these assets in a manner beneficial to us.
Because we do not control the Partially Owned Entities, we may have limited flexibility to control the operation of or cash distributions received from these entities. The Partially Owned Entities’ organizational documents generally require distribution of their available cash to their members on a quarterly basis; however, in each case, available cash is reduced, in part, by reserves appropriate for operating the businesses. As of December 31, 2016, our investments in the Partially Owned Entities accounted for approximately 8 percent of our total consolidated assets. Conflicts of interest may arise in the future between us, on the one hand, and our Partially Owned Entities, on the other hand, with regard to our Partially Owned Entities’ governance, business, or operations. If a conflict of interest arises between us and a Partially Owned Entity, other owners may control the Partially Owned Entity’s actions with respect to such matter (subject to certain limitations), which could be detrimental to our business. Any future disagreements with the other co-owners of these assets could adversely affect our ability to respond to changing economic or industry conditions, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
Holders of our common stock may not receive dividends in the amount expected or any dividends.
We may not have sufficient cash each quarter to pay dividends or maintain current or expected levels of dividends. The actual amount of cash we dividend may fluctuate from quarter to quarter and will depend on various factors, some of which are beyond our control, including:
The amount of cash that WPZ and our other subsidiaries distribute to us;
The amount of cash we generate from our operations, our working capital needs, our level of capital expenditures, and our ability to borrow;
The restrictions contained in our indentures and credit facility and our debt service requirements;
The cost of acquisitions, if any.
A failure either to pay dividends or to pay dividends at expected levels could result in a loss of investor confidence, reputational damage, and a decrease in the value of our stock price.
Our cash flow depends heavily on the earnings and distributions of WPZ.
Our partnership interest in WPZ is currently our largest cash-generating asset. Therefore, we are, at the least, indirectly exposed to all the risks to which WPZ is subject and our cash flow is heavily dependent upon the ability of WPZ to make distributions to its partners. A significant decline in WPZ’s earnings and/or distributions would have a corresponding negative impact on us.
We may not be able to sell assets or, if we are able to sell assets, to raise a sufficient amount of capital from such asset sales. In addition, the timing to enter into and close any asset sales could be significantly different than our expected timeline.
We are planning to monetize certain assets held by our subsidiaries in 2017 (including without limitation the Geismar olefins facility owned by WPZ) to fund additional debt reduction and capital and investment expenditures. Given the commodity markets, financial markets, and other challenges currently facing the energy sector, our competitors may also engage in asset sales leading to lower demand for the assets we wish to sell. We may not be able to sell the assets we identify for sale on favorable terms or at all. If we are able to sell assets, the timing of the receipt of the asset sale proceeds may not align with the timing of our capital requirements. A failure to raise sufficient capital from asset sales or a misalignment of the timing of capital raised and capital funding needs could have an adverse impact on our business, financial condition, results of operations, and cash flows.
An impairment of our assets, including goodwill, property, plant, and equipment, intangible assets, and/or equity-method investments, could reduce our earnings.
GAAP requires us to test certain assets for impairment on either an annual basis or when events or circumstances occur which indicate that the carrying value of such assets might be impaired. The outcome of such testing could result in impairments of our assets including our goodwill, property, plant, and equipment, intangible assets, and/or equity method investments. Additionally, any asset monetizations could result in impairments if any assets are sold or otherwise exchanged for amounts less than their carrying value. If we determine that an impairment has occurred, we would be required to take an immediate noncash charge to earnings.
Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results.
We have numerous competitors in all aspects of our businesses, and additional competitors may enter our markets. Some of our competitors are large oil,Any current or future competitor that delivers natural gas, and petrochemical companiesNGLs, or other commodities into the areas that have greater accesswe operate could offer transportation services that are more desirable to supplies
shippers than those we provide because of natural gas and NGLs than we do.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. Similarly, a highly-liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. As a result, pipeline capacity is being used more efficiently, and peaking and storage services are increasingly effective substitutes for annual pipeline capacity. Failure to successfully compete against current and future competitors could have a material adverse effect on our business, results of operations, financial condition, and cash flows.
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.
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 fuel sources, such as electricity, renewable resources, coal, fuel oils, or nuclear energy;
Natural gas NGL, and olefinsNGL 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. For instance, pursuant to a compression services agreement, one of our businesses receives a substantial portion of its compression capacity on certain gathering systems from EXLP Operating LLC (“Exterran Operating”). Exterran Operating has, until December 31, 2020, the exclusive right to provide compression services on certain gas gathering systems located in Wyoming, Texas, Oklahoma, Louisiana, and Arkansas, in return for the payment of specified monthly rates for the services provided, subject to an annual escalation provision. If a supplier on which one of our businesses depends were to fail to timely supply required goods and services, such business may not be able to replace such goods and services in a timely manner or otherwise on favorable terms or at all. If our business is unable to adequately diversify or otherwise mitigate such supplier concentration risks and such
risks were realized, such businesses could be subject to reduced revenues and increased expenses, which could have a material adverse effect on our financial condition, results of operation, and cash flows.
Failure of our service providers or disruptions to our outsourcing relationships might negatively impact our ability to conduct our business.
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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 will conduct certain operations through joint ventures thatface 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 limit our operational flexibility or require us to implement ESG procedures or standards in order to remain invested in us or before they may make additional capital contributions.
Some of our operations are conducted through joint venture arrangements, andfurther investments in us. Additionally, we may enter additional joint venturesface reputational challenges in the future. In a joint venture arrangement, weevent our ESG procedures or standards do not meet the standards set by certain constituencies. We have less operational flexibility,adopted certain practices as actions must be takenhighlighted in accordance with the applicable governing provisions of the joint venture. In certain cases:
We cannot control the amount of capital expenditures that we are required to fundour 2018 Sustainability Report, including with respect to these operations;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.
We are dependent
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 third parties to fund their required sharethe oil and gas industry could have a significant financial and operational adverse impact on our business.
The occurrence of capital expenditures;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 restrictions or limitations onphysical and financial risks associated with climate change.
The threat of global climate change may create physical and financial risks to our ability to sell or transfer our interests inbusiness. Energy needs vary with weather conditions. To the jointly owned assets;
Weextent weather conditions may be forcedaffected by climate change, energy use could increase or decrease depending on the duration and magnitude of any changes. Increased energy use due to offer rights of participationweather changes may require us to other joint venture participantsinvest in the area of mutual interest;
We have limited ability to influence or control certain day to day activities affecting the operations.
In addition, joint venture participants may have obligations that are important to the success of the joint venture, such as the obligation to pay substantial carried costs pertaining to the joint venture and to pay their share of capitalmore pipelines and other costs of the joint venture. The performance and ability of third partiesinfrastructure to satisfy their obligations under joint venture arrangements is outside our control. If these third parties do not satisfy their obligations under these arrangements, our businessserve increased demand. A decrease in energy use due to weather changes may be adversely affected. Joint venture partners may be in a position to take actions contrary to instructions or requests or contrary to our policies or objectives, and disputes between us and our joint venture partners may result in delays, litigation or operational impasses.
If we fail to make a required capital contribution under the applicable governing provisions of a joint venture arrangements, we could be deemed to be in default under the joint venture agreement. Joint venture partners may be permitted to fund any deficiency resulting from our failure to make such capital contribution, which would result in a dilution of our ownership interest, or such joint venture partners may have the option to purchase all of our existing interest in the subject joint venture.
The risks described above or the failure to continue joint ventures, or to resolve disagreements with joint venture partners could adversely affect our ability to conduct our operations that are the subject of any joint venture, which could in turn negatively affect our financial condition through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and resultscan contribute to increased system stresses, including service interruptions. Weather conditions outside of operations.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, the processing of olefins, and crude oil transportation and production handling, including:
Aging infrastructure and mechanical problems;
Damages to pipelines and pipeline blockages or other pipeline interruptions;
Uncontrolled releases of natural gas (including sour gas), NGLs, olefins products, brine,crude oil, or industrial chemicals;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;
Truck and rail loading and unloading;Security risks, including cybersecurity;
Operating in a marine environment.
Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations, loss of services to our customers, reputational damage, and substantial losses to us. The location of certain segments of our facilities in or near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks. An event such as those described above could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance.
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. We currently maintain excess liability insurance with limits of $820 million per occurrence and in the annual aggregate with a $2 million per occurrence deductible. This insurance covers us, our subsidiaries, and certain of our affiliates for legal and contractual liabilities arising out of bodily injury or property damage, including resulting loss of use to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability for full limits, with the first $135 million of insurance also providing gradual pollution liability coverage for natural gas and NGL operations.
Although we maintain property insurance on certain physical assets that we own, lease or are responsible to insure, the policy may not cover the full replacement cost of all damaged assets or the entire amount of business interruption loss we may experience. In addition, certain perils may be excluded from coverage or be sub-limited. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. We may elect to self-insure a portion of our risks. We do not insure our onshore underground pipelines for physical damage, except at certain locations such as river crossings and compressor stations. Offshore assets are covered for property damage when loss is due to a named windstorm event, but coverage for loss caused by a named windstorm is subject to a significant sub-limit and to a large deductible. All of our insurance is subject to deductibles.
In addition, to the insurance coverage described above, we are a member of Oil Insurance Limited (OIL), an energy industry mutual insurance company, which provides coverage for damage to our property. As an insured member of OIL, we share in the losses among other OIL members even if our property is not damaged.
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.
Acts
Our business could be negatively impacted by acts of terrorism could have a material adverse effect on our business, financial condition, results of operations, and cash flows.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.
Our business could be negatively impacted
A breach of our information technology infrastructure, including a breach caused by security threats, includinga cybersecurity threats,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 related disruptions.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. While we believe that we maintain appropriate information securityOur Board of Directors has oversightresponsibility 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 practices,to address cybersecurity threats. We have invested, and protocols, we face cybersecurityexpect to continue to invest, significant time, manpower and other security threats tocapital in our information technology infrastructure, which could include threats to our operational industrial control systems and safety systems that operate our pipelines, plants, and assets. We could face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists”, or private individuals. Theinfrastructure. 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 couldface 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
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, or the loss of contracts, the imposition of significant costs associated with remediation and havelitigation, heightened regulatory scrutiny, increased insurance costs, and a material adverse effect on our operations, financial condition, results of operations, and cash flows.
The natural gas sales, transportation, and storage operations of our gas pipelines are subject to regulation by the FERC, which could have an adverse impact on their ability to establish transportation and storage rates that would allow them to recover the full cost of operating their respective pipelines, including a reasonable rate of return.
In addition to regulation by other federal, state, and local regulatory authorities, under the Natural Gas Act of 1938, interstate pipeline transportation and storage service is subject to regulation by the FERC. Federal regulation extends to such matters as:
Transportation and sale for resale of natural gas in interstate commerce;
Rates, operating terms, types of services, and conditions of service;
Certification and construction of new interstate pipelines and storage facilities;
Acquisition, extension, disposition, or abandonment of existing interstate pipelines and storage facilities;
Accounts and records;
Depreciation and amortization policies;
Relationships with affiliated companies who are involved in marketing functions of the natural gas business;
Market manipulation in connection with interstate sales, purchases, or transportation of natural gas.
Regulatory or administrative actions in these areas, including successful complaints or protests against the rates of the gas pipelines, can affect our business in many ways, including decreasing tariff rates and revenues, decreasing volumes in our pipelines, increasing our costs, and otherwise altering the profitability of our pipeline business.
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 chemical and industrial facilities. Substantial costs, liabilities, delays, and other significant issues related to environmental laws and regulations are inherent in the gathering, transportation, storage, processing, and treating of natural gas, fractionation, transportation, and storage of NGLs, processing of olefins, and crude oil transportation and production handling as well as waste disposal practices and construction activities. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil and/or criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, and delays or denials in granting permits.
Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, for the remediation of contaminated areas and in connection with spills or releases of materials associated with natural gas, oil, and wastes on, under or from our properties and facilities. Private parties, including the owners of properties through which our pipeline and gathering systems pass and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third-party hydrocarbon storage and processing or oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours.
We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.
In addition, climate change regulations and the costs associated with the regulation of emissions of greenhouse gases (GHGs) have the potential to affect our business. Regulatory actions by the Environmental Protection Agency or the passage of new climate change laws or regulations could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, or (iii) administer and manage our GHG compliance program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Climate change and GHG regulation could also reduce demand for our services.
If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas and NGLs or to treat natural gas, our revenues 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.
The operation of our businesses might also be adversely affected by regulatory proceedings, changes in government regulations or in their interpretation or implementation, or the introduction of new laws or regulations applicable to our businesses or our customers.
Public and regulatory scrutiny of the energy industry has resulted in the proposal and/or implementation of increased regulations. Such scrutiny has also resulted in various inquiries, investigations, and court proceedings, including litigation of energy industry matters. Both the shippers on our pipelines and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.
Certain inquiries, investigations, and court proceedings are ongoing. Adverse effects may continue as a result of the uncertainty of ongoing inquiries, investigations, and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines and/or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our results of operations or increase our operating costs in other ways. Current legal proceedings or other matters, including environmental matters, suits, regulatory appeals, and similar matters might result in adverse decisions against us which, among other outcomes, could result in the imposition of substantial penalties and fines and could damage our reputation. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.
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.
Certain of our gas pipeline services are subject to long-term, fixed-price contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.
Our gas pipelines provide some services pursuant to long-term, fixed-price contracts. It is possible that costs to perform services under such contracts will exceed the revenues our pipelines collect for their services. Although most of the services are priced at cost-based rates that are subject to adjustment in rate cases, under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” that may be above or below the FERC regulated cost-based rate for that service. These “negotiated rate” contracts are not generally
subject to adjustment for increased costs that could be produced by inflation or other factors relating to the specific facilities being used to perform the services.
Our operating results for certain components of our business might fluctuate on a seasonal basis.
Revenues from certain components of our business can have seasonal characteristics. In many parts of the country, demand for natural gas and other fuels peaks during the winter. As a result, our overall operating results in the future might fluctuate substantially on a seasonal basis. Demand for natural gas and other fuels could vary significantly from our expectations depending on the nature and location of our facilities and pipeline systems and the terms of our natural gas transportation arrangements relative to demand created by unusual weather patterns.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and facilities have been constructed. As such, we are subject to the possibility of increased costs to retain necessary land use. In those instances in which we do not own the land on which our facilities are located, we obtain the rights to construct and operate our pipelines and gathering systems on land owned by third parties and governmental agencies for a specific period of time. In addition, some of our facilities cross Native American lands pursuant to rights-of-way of limited 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.
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, 2016, was $23.41 billion.
The agreements governing our indebtedness contain covenants that restrict our and our material subsidiaries’ ability to incur certain liens to support indebtedness and our ability to merge or consolidate or sell all or substantially all of our assets in certain circumstances. In addition, certain of our debt agreements contain various covenants that restrict or limit, among other things, our ability to make certain distributions during the continuation of an event of default, the ability of our subsidiaries to incur additional debt, and our and our material subsidiaries’ ability to enter into certain affiliate transactions and certain restrictive agreements. Certain of our debt agreements also contain, and those we enter into in the future may contain, financial covenants, and other limitations with which we will need to comply.
Our debt service obligations and the covenants described above could have important consequences. For example, they could:
Make it more difficult for us to satisfy our obligations with respect to our indebtedness, which could in turn result in an event of default on such indebtedness;
Impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes, or other purposes;
Diminish our ability to withstand a continued or future downturn in our business or the economy generally;
Require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, the payments of dividends, general corporate purposes, or other purposes;
Limit our flexibility in planning for, or reacting to, changes in our business, and the industry in which we operate, including limiting our ability to expand or pursue our business activities and preventing us from engaging in certain transactions that might otherwise be considered beneficial to us.
Our ability to comply with our debt covenants, to repay, extend, or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance. Our ability to refinance existing debt obligations or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to comply with these covenants, meet our debt service obligations, or obtain future credit on favorable terms, or at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.
Our failure to comply with the covenants in the documents governing our indebtedness could result in events of default, which could render such indebtedness due and payable. We may not have sufficient liquidity to repay our indebtedness in such circumstances. In addition, cross-default or cross-acceleration provisions in our debt agreements could cause a default or acceleration to have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. For more information regarding our debt agreements, please read Note 14 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.
The Company’s 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 the Company. During the latter part of fiscal year 2016, the Company wasours.
We were the target of a proxy contest from a stockholder activist, which resulted in our incurring significant costs to the Company.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 the Company’sour business or financial results. Stockholder activists may also seek to involve themselves in the governance, strategic direction, and operations of the Company. Such proposals may disrupt the Company’s business and divert the attention of the Company’s management and employees; and any perceived uncertainties as to the Company’s future direction resulting from such a situation could result in the loss of potential business opportunities, the perception that the Company needs a change in the direction of its business, or the perception that the Company is unstable or lacks continuity, any or all of which may be exploited by our competitors, cause concern to our current or potential customers, and may make it more difficult for the Company to attract and retain qualified personnel and business partners, which could adversely affect the Company’s business. In addition, actions
of activist stockholders may cause significant fluctuations in our stock price based on temporary or speculative market perceptions or other factors that do not necessarily reflect the underlying fundamentals and prospects of our business.
We are experiencing significant change in the composition of our Board of Directors and senior management.
On June 30, 2016, Frank T. MacInnis stepped down as Chairman of the Board and Kathleen B. Cooper was appointed as Chairman of the Board. Also on June 30, 2016, each of Ralph Izzo, Frank T. MacInnis, Eric W. Mandelblatt, Keith A. Meister, Steven W. Nance, and Laura A. Sugg resigned from the Board. On August 28, 2016, the Board appointed three new independent directors to the Board: Stephen W. Bergstrom, Scott D. Sheffield, and William H. Spence; on September 23, 2016, the Board appointed two additional new independent directors to the Board: Stephen I. Chazen and Peter A. Ragauss; and on December 5, 2016, the Board appointed two more additional new independent
directors to the Board: Charles “Casey” Cogut and Michael A. Creel. Three of Williams former directors, Joseph R. Cleveland, John A. Hagg, and Juanita H. Hinshaw, determined not to stand for re-election at the Company’s November 23, 2016 annual meeting. Thus, the Board is now composed of eleven directors, seven of whom were appointed in the second half of 2016.
On December 13, 2016, the Company announced the retirement of Senior Vice President Robert S. Purgason, effective January 31, 2017. The Company is also executing on a restructuring process, shifting from five operating areas to three, and on February 14, 2017 the Company announced the appointment of Micheal Dunn as Executive Vice President and Chief Operating Officer.
The changes in composition of the Company’s board and management impose an additional demand for attention, time and energy of board members and management in connection with orientation and education of new members about the Company, including with regard to its business strategies and objectives, assets and operations, and policies and practices, which could distract the board and management from execution of the Company’s strategy and objectives. Additionally, such changes invite new analysis of our business as the new members contribute to the formulation of our business strategies and objectives, which could implicate changes to such strategy and objectives. It is possible that changes to the composition of our board and management could have a negative impact on our business, financial condition, and results of operations.
Institutional knowledge residing with current employees nearing retirement eligibility or with our former employees might not be adequately preserved.
We expect that a significant percentage of employees will become eligible for retirement over the next several years. In addition, as part of an internal restructuring, we recently announced the reduction of five operating areas into three and the closing of our Oklahoma City office and the consolidation of employee positions to Tulsa or other locations. As employees with significant institutional knowledge reach retirement age, choose not to relocate with us, or their services are otherwise no longer available to us, we may not be able to replace them with employees of comparable knowledge and experience. In addition, we may not be able to retain or recruit other qualified individuals, and our efforts at knowledge transfer could be inadequate. If knowledge transfer, recruiting, and retention efforts are inadequate, access to significant amounts of knowledge and expertise could become unavailable to us.
Our hedging activities might not be effective and could increase the volatility of our results.
In an effort to manage our financial exposure related to commodity price and market fluctuations, we have entered, and may in the future enter into, contracts to hedge certain risks associated with our assets and operations. In these hedging activities, we have used, and may in the future use, fixed-price, forward, physical purchase, and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. Nevertheless, no single hedging arrangement can adequately address all risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist. While we attempt to manage counterparty credit risk within guidelines established by our credit policy, we may not be able to successfully manage all credit risk and as such, future cash flows and results of operations could be impacted by counterparty default.
One of our subsidiaries acts as the general partner of a publicly traded limited partnership, Williams Partners L.P. As such, this subsidiary’s operations may involve a greater risk of liability than ordinary business operations.
One of our subsidiaries acts as the general partner of WPZ, a publicly traded limited partnership. This subsidiary may be deemed to have undertaken contractual obligations with respect to WPZ as the general partner and to the limited partners of WPZ. Activities, determined to involve such obligations to other persons or entities typically involve a higher standard of conduct than ordinary business operations and therefore may involve a greater risk of liability, particularly when a conflict of interest is found to exist. Our control of the general partner of WPZ may increase the possibility of claims of breach of such duties, including claims brought due to conflicts of interest (including conflicts
of interest that may arise between WPZ, on the one hand, and its general partner and that general partner’s affiliates, including us, on the other hand). Any liability resulting from such claims could be material.
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.
Our costs and funding obligations for our defined benefit pension plans and costs for our other postretirement benefit plans are affected by factors beyond our control.
We have defined benefit pension plans covering substantially all of our U.S. employees and other postretirement benefit plans covering certain eligible participants.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 (IRS) private letter ruling or a tax opinion are incorrect or for any other reason, then we and our stockholders could incur significant income tax liabilities.
In connection with our original separation plan that called for an initial public offering (IPO) of stock of WPX and a subsequent spin-off of our remaining shares of WPX to our stockholders, we obtained a private letter ruling from the IRS and an opinion of our outside tax advisor, to the effect that the distribution by us of WPX shares to our stockholders, and any related restructuring transaction undertaken by us, would not result in recognition for U.S. federal income tax purposes, of income, gain or loss to us or our stockholders under section 355 and section 368(a)(1)(D) of the U.S. Internal Revenue Code of 1986, as amended (Code), except for cash payments made to our stockholders in lieu of fractional shares of WPX common stock. In addition, we received an opinion from our outside tax advisor to the effect
that the spin-off pursuant to our revised separation plan which was ultimately consummated on December 31, 2011, which did not involve an IPO of WPX shares, would not result in the recognition, for federal income tax purposes, of income, gain, or loss to us or our stockholders under section 355 and section 368(a)(1)(D) of the Code, except for cash payments made to our stockholders in lieu of fractional shares of WPX. The private letter ruling and opinion have relied on or will rely on certain facts, representations, and undertakings from us and WPX regarding the past and future conduct of the companies’ respective businesses and other matters. If any of these facts, representations, or undertakings are, or become, incorrect or are not otherwise satisfied, including as a result of certain significant changes in the stock ownership of us or WPX after the spin-off, or if the IRS disagrees with any such facts and representations upon audit, we and our stockholders may not be able to rely on the private letter ruling or the opinion of our tax advisor and could be subject to significant income tax liabilities.
The spin-off may expose
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 liabilities arising outnegative 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 statebusiness 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 fraudulent conveyance lawsgovernment in response to these concerns, could significantly and legal dividend requirements that we did not assumeadversely 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 with WPX.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 spin-off is subjectagreements governing our indebtedness contain covenants that restrict our and our material subsidiaries’ ability to review underincur 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 statecovenants 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 federal fraudulent conveyance laws. A court could deemour, 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 spin-off or certain internal restructuring transactions undertaken by us in connectionfuture may contain, financial covenants, and other limitations with the separationwhich we will need to be a fraudulent conveyance or transfer. Fraudulent conveyances or transfers are defined to include transfers made or obligations incurred with the actual intent to hinder, delay, or defraud current or future creditors or transfers made or obligations incurred for less than reasonably equivalent value when the debtor was insolvent, or that rendered the debtorcomply.
insolvent, inadequately capitalizedOur 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 pay its debts as they become due. A courtcomply with these covenants, meet our debt service obligations, or obtain future credit on favorable terms, or at all, we could voidbe 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 transactions or impose substantial liabilities upon us,covenants in the documents governing our indebtedness could result in events of default, which could adversely affectrender such indebtedness due and payable. We may not have sufficient liquidity to repay our financial conditionindebtedness 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 our results Banking Arrangementsof operations. Whether a transaction is a fraudulent conveyanceNotes to Consolidated Financial Statements.
Changes to interest rates or transfer will vary depending upon the jurisdiction whose law is being applied. Under the separation and distribution agreement between us and WPX, from and after the spin-off, each of WPX and we are responsible for the debts, liabilities, and other obligations related to the business or businesses which each owns and operates. Although we do not expect to be liable for any such obligations not expressly assumed by us pursuant to the separation and distribution agreement, it is possible that a court would disregard the allocation agreed to between the parties, and require that we assume responsibility for obligations allocated to WPX, particularly if WPX were to refuse or were unable to pay or perform the subject allocated obligations.
Increasesincreases in interest rates could adversely impact our access to credit, share price, our ability to issue equitysecurities or incur debt for acquisitions or other purposes, and our ability to make cash dividends at our intended levels.
Interest rates may increase further 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 distributiondividend yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our shares, and a rising interest rate environment could have an adverse impact on our share price and our ability to issue equity or incur debt for acquisitions or other purposes and to pay cash dividends at our intended levels.
Our hedging activities might not be effective and could increase the volatility of our results.
In an effort to manage our financial exposure related to commodity price and market fluctuations, we have entered, and may in the future enter into contracts to hedge certain risks associated with our assets and operations. In these hedging activities, we have used, and may in the future use, fixed-price, forward, physical purchase, and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. Nevertheless, no single hedging arrangement can adequately address all risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty
credit or performance risk. Therefore, unhedged risks will always continue to exist. While we attempt to manage counterparty credit risk within guidelines established by our credit policy, we may not be able to successfully manage all credit risk and as such, future cash flows and results of operations could be impacted by counterparty default.
Risks Related to Regulations
The 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;
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.
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 21,19, 2016, we received a Compliance Order from the Pennsylvania DepartmentNotice of Environmental Protection requiring the correction of several alleged deficiencies arising out of the construction of the Springville Gathering Line, the Pennsylvania Mainline Gathering Line,Noncompliance with certain Leak Detection and the 2008 Core Zone Gathering Line. The original Order identified civil penalties in the amount of approximately $712,000. On December 28, 2016, we entered into an Order with the Pennsylvania Department of Environmental Protection to address the issues and paid the associated penalty of $581,477.
On February 21, 2017, we received notice from the Environmental Enforcement Section of the United States Department of Justice regarding certain alleged violations ofRepair (LDAR) regulations under the Clean Air Act at our Moundsville facility as set forth inFractionator 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 Noncompliance issued byViolation of certain LDAR regulations at our former Ignacio Gas Plant from the EPA, on January 14, 2016. The notice includesRegion 8, following an offeron-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 avoid further legal action ona common attorney at the Department of Justice (DOJ). We are exploring global resolution of the claims at these facilities, as well as alleged violations by paying $2,000,000. We are currently evaluatingat certain other facilities, with the communication and our response.DOJ. Global resolution would include both
Otherpayment 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.
The additional informationOther environmental matters called for by this item is providedItem are described under the caption “Environmental Matters” in Note 1819 – 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.
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.
Information About Our Executive Officers of the Registrant
The name, title, age, period of service, and titlerecent business experience of each of our executive officers as of February 22, 2017,24, 2020, are listed below. As previously discussed, Williams Partners L.P. merged with ACMP in February 2015 (the ACMP Merger). ACMP was the surviving entity in the ACMP Merger and changed its name to Williams Partners L.P. References in the biographical information below to (a) “Pre-merger WPZ” will mean Williams Partners L.P. prior to the ACMP Merger and (b) “ACMP/WPZ” will refer to both ACMP prior to and after the ACMP Merger, when it changed its name to Williams Partners L.P.
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| | | | | | |
| Name and Position | | Age | | Business Experience in Past Five Years |
| Alan S. Armstrong | | 57 | | 2011 to present | | Director, Chief Executive Officer, and President, The Williams Companies, Inc. |
| Director, Chief Executive Officer, and President | | | | 2015 to 2018 | | Chairman of the Board, WPZ |
| | Age: 54 | | | 2014 to 2018 | | Chief Executive Officer, WPZ |
| | Position held since 2011. |
| | From 2002 | 2012 to 2011, Mr. Armstrong served as Senior Vice President - Midstream and acted as President of our midstream business. From 1999 to 2002, Mr. Armstrong was Vice President, Gathering and Processing in our midstream business and from 1998 to 1999 was Vice President, Commercial Development. Mr. Armstrong has served as a director2018 | | Director of the general partner, of ACMP/WPZ since 2012, as Chief Executive Officer since December 31, 2014, and as Chairman |
| Walter J. Bennett | | 50 | | 2020 to present | | Senior Vice President Gathering & Processing, The Williams Companies, Inc. |
| Senior Vice President Gathering & Processing | | | | 2015 to 2019 | | Senior Vice President – West, The Williams Companies, Inc. |
| | | | 2013 to 2018 | | Senior Vice President – West of the Board since February 2, 2015. Mr. Armstrong has served as a director of BOK Financial Corporation, a financial services company, since 2013. Mr. Armstrong also served as Chairmangeneral partner, WPZ |
| | | | 2017 | | Director of the Boardgeneral partner, WPZ |
| John D. Chandler | | 50 | | 2017 to present | | Senior Vice President and Chief Financial Officer, The Williams Companies, Inc. |
| Senior Vice President and Chief Financial Officer | | | | 2017 to 2018 | | Director of the general partner, WPZ |
| | | | 2009 to 2014 | | Senior Vice President and Chief Financial Officer, Magellan GP, LLC |
| Debbie Cowan | | 42 | | 2018 to present | | Senior Vice President – Chief Human Resources Officer, The Williams Companies, Inc. |
| Senior Vice President – Chief Human Resources Officer | | | | 2013 to 2018 | | Global Vice President of Human Resources, Koch Chemical Technology Group, LLC |
| Micheal G. Dunn | | 54 | | 2017 to present | | Executive Vice President and Chief Operating Officer, The Williams Companies, Inc. |
| Executive Vice President and Chief Operating Officer | | | | 2017 to 2018 | | Director of the general partner, WPZ |
| | | | 2015 to 2016 | | President / Executive Vice President, Questar Pipeline / Questar Corporation |
| | | | 2010 to 2015 | | President and Chief Executive Officer, of the general partner of Pre-merger WPZ from 2011 until the ACMP Merger, as PacifiCorp Energy |
| Scott A. Hallam | | 43 | | 2020 to present | | Senior Vice President Transmission & Gulf of Mexico, The Williams Companies, Inc. |
| Senior Vice President Transmission & Gulf of Mexico | | | | 2019 | | Senior Vice President – Atlantic-Gulf, The Williams Companies, Inc. |
| | | | 2017 to 2019 | | Vice President GM Atlantic-Gulf, The Williams Companies, Inc. |
| | | | 2015 to 2017 | | Vice President Northeast OA, The Williams Companies, Inc. |
| | | | 2013 to 2015 | | 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 Williams Companies, Inc. |
| | | | 2017 | | Vice President – Commercial - Midstream from 2010West, The Williams Companies, Inc. |
| | | | 2015 to 2017 | | Vice President – Commercial & Business Development, The Williams Companies, Inc. |
| | | | 2011 and director and Chief Operating Officer from 2005 to 2010.2015 | | General Manager – Eagle Ford, ACMP |
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Walter J. Bennett | Senior Vice President — West |
| Age: 47 |
| Position held since January 2015. |
| Mr. Bennett was formerly Chief Operating Officer of Chesapeake Midstream Development and served as Senior Vice President-Operations at Boardwalk Pipeline Partners. Previously, Mr. Bennett served in a variety of senior positions at Gulf South Pipeline Company that included operations and commercial responsibilities. Mr. Bennett began his career at a subsidiary of Koch Industries. Mr. Bennett has served as Senior Vice President - West of the general partner of ACMP/WPZ since December 2013 and served as Senior Vice President - West of the general partner of Pre-merger WPZ from January 2015 until the ACMP Merger. He has served as a director of the general partner of ACMP/WPZ since February 2017. |
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| |
Francis (Frank) E. BillingsName and Position | Senior Vice President — Corporate Strategic Development |
| | Age: 54Age |
| | Position held since January 2014. |
| Mr. Billings served as Senior Vice President - Northeast G&P of us and Pre-merger WPZ from January 2013 to January 2014. Mr. Billings served as Vice President of our midstream gathering and processing business from 2011 until 2013 and as Vice President, Business Development from 2010 to 2011. Mr. Billings served as President of Cumberland Plateau Pipeline Company, a privately held company developing an ethane pipeline to serve the Marcellus Shale area, from 2009 until 2010. From 2008 to 2009, Mr. Billings served as Senior Vice President of Commercial for Crosstex Energy, Inc. and Crosstex Energy L.P., an independent midstream energy services master limited partnership and its parent corporation. In 1988, Mr. Billings joined MAPCO Inc., which merged with one of our subsidiariesExperience in 1998, serving in various management roles, including in 2008 as a Vice President in the midstream business. Mr. Billings served as Senior Vice President - Corporate Strategic Development of the general partner of Pre-merger WPZ from January 2014 until the ACMP Merger. He has served as Senior Vice President - Corporate Strategic Development since the ACMP Merger, and as a director of the general partner of ACMP/WPZ since the ACMP Merger until February 2017.
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Donald R. Chappel | Senior Vice President and Chief Financial Officer |
| Age: 65 |
| Position held since 2003. |
| Prior to joining us, Mr. Chappel held various financial, administrative and operational leadership positions. Mr. Chappel has served as a director of the general partner of ACMP/WPZ since 2012 and as Chief Financial Officer of the general partner of ACMP/WPZ since December 31, 2014. Mr. Chappel has also served as a member of the Management Committee of Northwest Pipeline since 2007. Mr. Chappel served as Chief Financial Officer and a director of the general partner of Pre-merger WPZ from 2005 until the ACMP Merger. Mr. Chappel was Chief Financial Officer from 2007 and a director from 2008 of the general partner of Williams Pipeline Partners L.P. (WMZ), until its merger with Pre-merger WPZ in 2010. Mr. Chappel is a director of SUPERVALU, Inc. (a grocery and pharmacy company). |
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John R. Dearborn | Senior Vice President — NGL & Petchem Services |
| Age: 59 |
| Position held since 2013. |
| Mr. Dearborn served as a senior leader for Saudi Basic Industries Corporation, a petrochemical company, from 2011 to 2013. From 2001 to 2011, Mr. Dearborn served in a variety of leadership positions with the Dow Chemical Company. Mr. Dearborn also worked for Union Carbide Corporation, prior to its merger with DOW, from 1981 to 2001 where he served in several leadership roles. Mr. Dearborn also served as Senior Vice President - NGL & Petchem Services of the general partner of Pre-merger WPZ from 2013 until the ACMP Merger and has served in that role for the general partner of ACMP/WPZ since the ACMP Merger. |
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Robyn L. Ewing | Senior Vice President and Chief Administrative Officer |
| Age: 61 |
| Position held since 2008. |
| From 2004 to 2008, Ms. Ewing was Vice President of Human Resources. Prior to joining Williams, Ms. Ewing worked at MAPCO, which merged with Williams in 1998. Ms. Ewing began her career with Cities Service Company in 1976. |
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Rory L. Miller | Senior Vice President — Atlantic - Gulf |
| Age: 56 |
| Position held since 2013. |
| From 2011 until 2013, Mr. Miller was Senior Vice President - Midstream of Williams and the general partner of Pre-merger WPZ, acting as President of Williams’ midstream business. Mr. Miller was a Vice President of Williams’ midstream business from 2004 until 2011. Mr. Miller served as a director and Senior Vice-President - Atlantic-Gulf of the general partner of Pre-merger WPZ from 2011 until the ACMP Merger and has served in those roles for the general partner of ACMP/WPZ since the ACMP Merger. Mr. Miller has also served as a member of the Management Committee of Transco, since 2013. |
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Sarah C. Miller | Senior Vice President and General Counsel |
| Age: 45 |
| Position held since 2015. |
| Ms. Miller joined Williams in 2000, where she has served in a variety of legal leadership positions, including Vice President, Corporate Secretary and Assistant General Counsel for the company’s corporate secretary team, Senior Counsel for the company’s midstream business, and as Senior Attorney for the legal department’s business development team. She was named Senior Vice President and General Counsel on June 20, 2015. Prior to joining Williams, Ms. Miller was a litigation associate at Crowe & Dunlevy. |
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James E. Scheel | Senior Vice President — Northeast G&P |
| Age: 52 |
| Position held since January 2014. |
| From 2012 to 2014, Mr. Scheel served as Senior Vice President - Corporate Strategic Development of us and the general partner of Pre-merger WPZ. From 2011 until 2012, Mr. Scheel served as Vice President of Business Development for our midstream business. Mr. Scheel joined Williams in 1988 and has served in leadership roles in business strategic development, engineering and operations, our NGL business, and international operations. Mr. Scheel has served as a director and Senior Vice President - Northeast G&P of the general partner of ACMP/WPZ since the ACMP Merger, having previously served as a director of the general partner of ACMP/WPZ from 2012 to February 2014. Mr. Scheel served as a director of the general partner of Pre-merger WPZ from 2012 until the ACMP Merger. |
|
| Past Five Years |
John D. SeldenrustPorter | Senior Vice President — Engineering Services |
| | Age: 5250 |
| | Position held since July 2015.2020 to present |
| | Mr. Seldenrust served as Senior Vice President - Eastern Operations for us from January 2015 to July 2015, and for ACMP/WPZ from 2013 to July 2015. Mr. Seldenrust also previously served in a variety of operations and engineering leadership roles at ACMP and Chesapeake Energy from 2004 to August 2013. Prior to joining Chesapeake, Mr. Seldenrust held reservoir, production and facilities engineering positions with ARCO Oil & Gas, Vastar Resources and BP America. |
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Ted T. Timmermans | 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 |
| | Age: 60 | | | 2013 to 2017 | | Director of Investor Relations & Enterprise Planning |
| T. Lane Wilson | Position held since 2005. | 53 | | 2017 to present | | Senior Vice President and General Counsel, The Williams Companies, Inc. |
| Mr. Timmermans served as Assistant Controller of Williams from 1998 to 2005. Mr. Timmermans served asSenior Vice President, Controller & Chief Accounting OfficerGeneral Counsel | | | | 2009 to 2017 | | United States Magistrate Judge for the Northern District of Oklahoma |
| Chad J. Zamarin | | 43 | | 2017 to present | | Senior Vice President – Corporate Strategic Development, The Williams Companies, Inc. |
| Senior Vice President – Corporate Strategic Development | | | | 2017 to 2018 | | Director of the general partner, of Pre-merger WPZ until the ACMP Merger |
| | | | 2014 to 2017 | | President – Pipeline and has served in those roles for the general partner of ACMP/WPZ since the ACMP Merger. Mr. Timmermans served as Chief Accounting Officer of the general partner of WMZ from 2008 until its merger with Pre-merger WPZ in 2010.Midstream, Cheniere Energy |
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 17, 2017,19, 2020, we had approximately 7,3766,512holders of record of our common stock. The high and low sales price ranges (New York Stock Exchange composite transactions) and dividends declared by quarter for each of the past two years are as follows:
|
| | | | | | | | | | | |
| | High | | Low | | Dividend |
| 2016 | | | | | |
| First Quarter | $ | 26.68 |
| | $ | 10.22 |
| | $ | 0.64 |
|
| Second Quarter | 23.89 |
| | 14.60 |
| | 0.64 |
|
| Third Quarter | 31.43 |
| | 19.68 |
| | 0.20 |
|
| Fourth Quarter | 32.21 |
| | 27.35 |
| | 0.20 |
|
| 2015 | | | | | |
| First Quarter | $ | 51.15 |
| | $ | 40.07 |
| | $ | 0.58 |
|
| Second Quarter | 61.38 |
| | 46.28 |
| | 0.59 |
|
| Third Quarter | 58.77 |
| | 34.64 |
| | 0.64 |
|
| Fourth Quarter | 44.51 |
| | 20.95 |
| | 0.64 |
|
Some of our subsidiaries’ borrowing arrangements may limit the transfer of funds to us. These terms have not impeded, nor are they expected to impede, our ability to pay dividends. On February 20, 2017, our board of directors approved a regular quarterly dividend of $0.30 per share payable on March 27, 2017, representing a 50 percent increase from our previous quarterly dividend.
Performance Graph
Set forth below is a line graph comparing our cumulative total stockholder return on our common stock (assuming reinvestment of dividends) with the cumulative total return of the S&P 500 Stock Index, and the Bloomberg Americas Pipelines Index, and the Arca Natural Gas Index for the period of five fiscal years commencing January 1, 2012.2015. The Bloomberg Americas Pipelines Index is composed of Enbridge Inc., Inter Pipeline Ltd., Kinder Morgan, Inc., TC Energy Corporation, ONEOK, Inc., Pembina Pipeline Corp, Plains GP Holdings LP, SpectraCorporation, Cheniere Energy, Corp, TransCanadaInc., Targa Resources Corp., Keyera Corp., AltaGasInter 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.
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| | | | | | | | | | | |
| | 2011 | | 2012 | | 2013 | | 2014 | | 2015 | | 2016 |
| The Williams Companies, Inc. | 100.0 | | 126.1 | | 154.5 | | 187.4 | | 114.2 | | 150.0 |
| S&P 500 Index | 100.0 | | 115.9 | | 153.4 | | 174.3 | | 176.8 | | 197.8 |
| Bloomberg Americas Pipelines Index | 100.0 | | 113.4 | | 125.9 | | 147.3 | | 81.5 | | 119.2 |
44 |
| | | | | | | | | | | |
| | 2014 | | 2015 | | 2016 | | 2017 | | 2018 | | 2019 |
| The Williams Companies, Inc. | 100.0 | | 60.8 | | 79.8 | | 81.5 | | 62.0 | | 70.8 |
| S&P 500 Index | 100.0 | | 101.4 | | 113.5 | | 138.3 | | 132.2 | | 173.8 |
| Bloomberg Americas Pipelines Index | 100.0 | | 55.0 | | 80.7 | | 80.5 | | 69.0 | | 93.4 |
| Arca Natural Gas Index | 100.0 | | 61.0 | | 89.7 | | 76.3 | | 52.1 | | 51.5 |
Item 6. Selected Financial Data
The following financial data at December 31, 20162019 and 2015,2018, and for each of the three preceding years in the period ended December 31, 2016,2019, 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, FinancialStatements and Supplementary Data of this Form 10-K. All other financial data has been prepared from our accounting records.
| | | | 2016 | | 2015 | | 2014 | | 2013 | | 2012 | Year Ended December 31, |
| | (Millions, except per-share amounts) | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| Revenues (1) | $ | 7,499 |
| | $ | 7,360 |
| | $ | 7,637 |
| | $ | 6,860 |
| | $ | 7,486 |
| |
| | | (Millions, except per-share amounts) |
| 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 operations (2) | (350 | ) | | (1,314 | ) | | 2,335 |
| | 679 |
| | 929 |
| 862 |
| | (156 | ) | | 2,174 |
| | (424 | ) | | (571 | ) |
| Amounts attributable to The Williams Companies, Inc.: | | | | | | | | | | |
| Income (loss) from continuing operations (2) | (424 | ) | | (571 | ) | | 2,110 |
| | 441 |
| | 723 |
| |
| Diluted earnings (loss) per common share: | | | | | | | | | | |
| Income (loss) from continuing operations (2) | (.57 | ) | | (.76 | ) | | 2.91 |
| | .64 |
| | 1.15 |
| |
| Diluted income (loss) from continuing operations per common share | | .71 |
| | (.16 | ) | | 2.62 |
| | (.57 | ) | | (.76 | ) |
Total assets at December 31 (3) | 46,835 |
| | 49,020 |
| | 50,455 |
| | 27,065 |
| | 24,248 |
| 46,040 |
| | 45,302 |
| | 46,352 |
| | 46,835 |
| | 49,020 |
|
| Commercial paper and long-term debt due within one year at December 31 (4) | 878 |
| | 675 |
| | 802 |
| | 226 |
| | 1 |
| |
| Long-term debt at December 31 (3) | 22,624 |
| | 23,812 |
| | 20,780 |
| | 11,276 |
| | 10,656 |
| |
| 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 31 (3) | 4,643 |
| | 6,148 |
| | 8,777 |
| | 4,864 |
| | 4,752 |
| 13,363 |
| | 14,660 |
| | 9,656 |
| | 4,643 |
| | 6,148 |
|
| Cash dividends declared per common share | 1.680 |
| | 2.450 |
| | 1.9575 |
| | 1.438 |
| | 1.196 |
| 1.52 |
| | 1.36 |
| | 1.20 |
| | 1.68 |
| | 2.45 |
|
| Diluted weighted-average shares outstanding (thousands) | | 1,214,011 |
| | 973,626 |
| | 828,518 |
| | 750,673 |
| | 749,271 |
|
| |
| (1) | Revenues for 2014 increased reflecting the consolidation of ACMP beginning in third quarter and new Canadian construction management services. |
| |
(2) | Income (loss) from continuing operations: |
For 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;goodwill.
| |
| (2) | Income (loss) from continuing operations attributable to the Williams Companies, Inc. available to common stockholders: |
For 20142019 includes $2.5 billion pretax gain recognized as a resultbenefit of remeasuring to fair value$209 million reflecting the equity-method investment we held before we acquired a controlling interest in ACMP, $246 millionnoncontrolling interests’ share of insurance recoveries related to the 2013 Geismar Incident, and $154 millionimpairment of cash received related to a contingency settlement. 2014 also includes $78 million of pretax equity losses from Bluegrass Pipeline and Moss Lake related primarily to the underlying write-off of previouslyConstitution’s capitalized project development costs and $76 million of pretax acquisition, merger, and transition expenses related to our acquisition of ACMP;costs.
For 2013 includes $99 million of deferred income tax expense incurred on undistributed earnings of our foreign operations that are no longer considered permanently reinvested.
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| (3) | The increases in 2014 reflect assets acquired and debt assumed primarily related to our acquisition of ACMP (see Note 2 – Acquisitions) in third quarter as well as $1.9 billion of related debt issuances and $2.8 billion of debt issuancesStockholders’ equity at WPZ. Additionally, we issued $3.4 billion of equity (see Note 15 – Stockholders' Equity).
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| |
(4) | The increases in 2014 and 2013 reflect borrowings under WPZ’s commercial paper program, which was initiated in 2013.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.
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 olefins.midstream business. Our operations are located principally in the United States and are organized into the Williams Partners and Williams NGL & Petchem Services reportable segments. All remaining business activities are included in Other.States.
Williams Partners
Williams Partners consists of our consolidated master limited partnership, WPZ, which includes gas pipeline and midstream businesses. The gas pipeline businesses includeOur interstate natural gas pipelines and pipeline joint project investments; andstrategy is to create value by maximizing the midstream businesses provide natural gas gathering, treating, and processing services; NGL production, fractionation, storage, marketing and transportation; deepwater production handling and crude oilutilization of our pipeline capacity by providing high quality, low cost transportation services; an olefin production business, and is comprised of several wholly owned and partially owned subsidiaries and joint project investments. As of December 31, 2016, we owned approximately 60 percent of the interests in WPZ, including the interests of the general partner, which were wholly owned by us, and IDRs.
Williams Partners’ gas pipeline businesses consist primarily of Transco and Northwest Pipeline. The gas pipeline business also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent equity-method investment in Gulfstream and a 41 percent interest in Constitution (a consolidated entity), which is under development. As of December 31, 2016, Transco and Northwest Pipeline own and operate a combined total of approximately 13,600 miles of pipelines with a total annual throughput of approximately 4,230 Tbtu of natural gas to large and peak-day delivery capacity of approximately 15.5 MMdth of natural gas.
Williams Partners' midstream businesses primarily consist of (1) naturalgrowing markets. Our gas gathering, treating, compression, and processing; (2) NGL fractionation, storage and transportation; (3) crude oil production handling and transportation; and (4) olefins production. (See Geismar Olefins Facility Monetization below.) The primary service areas are concentrated in major producing basins in Colorado, Texas, Oklahoma, Kansas, New Mexico, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio which include the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, and Utica Shale plays as well as the Mid-Continent region.
The midstream businesses include equity-method investments in natural gas gathering and processing assets and NGL fractionation and transportation assets, including a 62 percent equity-method investment in UEOM, a 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region, a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, a 60 percent equity-method investment in Discovery, a 50 percent equity-method investment in OPPL, and Appalachia Midstream Services, LLC, which owns an approximate average 41 percent equity-method investment interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).
The midstream businesses previously included our Canadian midstream operations, which were comprised of an oil sands offgas processing plant near Fort McMurray, Alberta and an NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, these Canadian operations were sold. (See Note 3 – Divestiture of Notes to Consolidated Financial Statements.)
Williams Partners’ ongoing strategy is to safely and reliably operate large-scale, interstate natural gas transmission and midstream infrastructures where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers and investing in growing markets, including the deepwater Gulf of Mexico, the Marcellus Shale, the Gulf Coast Region, and areas of increasing natural gas demand.
Williams Partners’pipeline businesses’ interstate transmission and related storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion
or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.
WilliamsThe 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 & Petchem Services
Williamsfractionation and transportation, crude oil production handling and transportation, marketing services for NGL, & Petchem Services includes certain domestic olefins pipeline assetscrude oil and natural gas, as well as storage facilities.
As of December 31, 2019, our operations are presented within the previously owned Canadianfollowing 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 includedis a liquids extraction plant near Fort McMurray, Alberta, that beganproprietary 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 March 2016the 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 propane dehydrogenation facility under development15 percent equity-method investment in Canada. In September 2016, these Canadian operationsBrazos 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. (Seesold during the fourth quarter of 2018 (see Note 3 – DivestitureAcquisitions and Divestitures of Notes to Consolidated Financial Statements.)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,
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).
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| • | 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),anda 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 2016,2019, we paid a regular quarterly dividend of $0.20$0.38 per share. On February 20, 2017,January 28, 2020, our board of directors approved a regular quarterly dividend of $0.30$0.40 per share payable on March 27, 2017, representing a 50 percent increase from our previous quarterly dividend.30, 2020.
Overview
Net income (loss) attributable to The Williams Companies, Inc., for the year ended December 31, 2016,2019, increased $147 million$1.005 billioncompared to the year ended December 31, 2015, reflecting the absence of certain goodwill impairments, lower impairments of equity-method investments, an increase in olefins margins associated with our Geismar plant, decreases in operating and maintenance expenses, and higher equity earnings. 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; |
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| • | 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 an unfavorable changeby:
| |
| • | 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 netprovision for income attributable to noncontrolling intereststaxes driven primarily by higher WPZpre-tax income, as well as the impact of reduced incentive distributions from WPZ associated with the termination of the WPZ Merger Agreement. The favorable changes were also partially offset by increased impairment charges and lossthe absence of a 2018 charge to establish a valuation allowance on sale associated with our Canadian operations, lower insurance recoveries, as well as higher interest incurred. See additional discussion in Results of Operations.deferred tax assets that may not be realized following the WPZ merger.
Acquisition of Additional InterestsUEOM
As of December 31, 2018, we owned a 62 percent interest in Appalachia Midstream Investments
In February, 2017,UEOM which we announced agreements to acquire additional interestsaccounted for as an equity-method investment. On March 18, 2019, we signed and closed the acquisition of the remaining 38 percent interest in two Marcellus Shale gathering systems within Williams Partners’ Appalachia Midstream Investments in exchange for equity-method investment interests in DBJV and the Ranch Westex gas processing plant, both currently reported within the Williams Partners segment. We also expect to receive a total of $200UEOM. Total consideration paid, including post-closing adjustments, was $741 million in cash as partfunded through credit facility borrowings and cash on hand. As a result of the agreements subject to customary closing conditionsacquiring this additional interest, we obtained control of and purchase price adjustments. The transactions are expected to close in late first-quarter or early second-quarter 2017.
Financial Repositioning
In January 2017, we announced agreements with WPZ, wherein we permanently waived the general partner’s incentive distribution rightsnow consolidate UEOM. (See Note 3 – Acquisitions and converted our 2 percent general partner interest in WPZ to a non-economic interest in exchange for 289 million newly issued WPZ common units. Pursuant to this agreement, we also purchased approximately 277 thousand WPZ common units for $10 million. Additionally, we purchased approximately 59 million common units of WPZ at a price of $36.08586 per unit in a private placement transaction, funded with proceeds from our equity offering (see Note 15 - Stockholders’ EquityDivestitures of Notes to Consolidated Financial Statements). Following these transactions,Statements.)
Northeast JV
Concurrent with the UEOM acquisition, we ownexecuted an agreement whereby we contributed our consolidated interests in UEOM and our Ohio Valley midstream business to a 74newly formed partnership. In June 2019, our partner invested approximately $1.33 billion for a 35 percent limited partnerownership 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 WPZ. It is anticipatedJackalope 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 combinationunderlying 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 measures will improve WPZ’s costagreements, we have expanded the inlet processing capacity of capital,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 debt reduction,NGLs. These expansions are supported by long-term, fee-based agreements and eliminate WPZ’s need to access the public equity markets for several years.volumetric commitments.
Susquehanna Supply Hub Expansion
In additionNovember 2019, we completed a 500 MMcf/d expansion of the gathering systems in the Susquehanna Supply Hub to bring the previously announced Geismar monetization process,capacity to approximately 4.3 Bcf/d.
Atlantic-Gulf
Rivervale South to Market
In August 2018, we have announced plansreceived approval from the FERC to monetizeexpand 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 select assets that are not core to our strategy. We expect to raise more than $2 billion in after-tax proceeds fromexisting Transco locations within New
Jersey. The project was placed into partial service in July 2019. The remaining portion of the monetization process of Geismar and the other select assets. Asproject was placed into service in September 2019. The full project increased capacity by 190 Mdth/d.
Norphlet Project
In March 2016, we pursue these other asset monetizations, it is possibleannounced that we may incur impairments of certain equity-method investments, property, plant, and equipment, and intangible assets. Such impairments could potentially be caused by indications of fair value implied throughreached an agreement to provide deepwater gas gathering services to the monetization process or,Appomattox development in the caseGulf of asset dispositions that are part of a broader asset group, the impact of the loss of future estimated cash flows.
Energy Transfer Merger Agreement
On September 28, 2015, we publicly announced in a press release that we had entered into a Merger Agreement with Energy Transfer and certain of its affiliates. The Merger Agreement provided that, subjectMexico. We completed modifications to the satisfaction of customary closing conditions, we would merge with and into the newly formed ETC, with ETC surviving the ETC Merger.
On June 29, 2016, Energy Transfer provided us written notice terminating the Merger Agreement, citing the alleged failure of certain conditions under the Merger Agreement.
Termination of WPZ Merger Agreement
On May 12, 2015, we entered intoinstall an agreement for a unit-for-stock transaction whereby we would have acquired all of the publicly held outstanding common units of WPZ in exchange for shares of our common stock (WPZ Merger Agreement).
On September 28, 2015, prioralternate delivery route to our entry into the Merger Agreement, we entered into a Termination Agreement and Release (Termination Agreement), terminating the WPZ Merger Agreement. Under the terms of the Termination Agreement, we were requiredMain Pass 261 Platform, as well as modifications to pay a $428 million termination fee to WPZ,our onshore Mobile Bay processing facility. The project went in service early in July 2019, at which time we owned approximately 60 percent, includingalso purchased a 54-mile-long, 16-inch-diameter pipeline (the Norphlet Pipeline) for $200 million. This pipeline transports gas from the interests of the general partner and IDRs. Such termination fee settled through a reduction of quarterly incentive distributions we were entitledAppomattox development to receive from WPZ (such reduction not to exceed $209 million per quarter). The distributions from WPZ in November 2015, February 2016, and May 2016 were reduced by $209 million, $209 million, and $10 million, respectively, related to this termination fee.our Main Pass 261 Platform.
Organizational RealignmentGateway
In September 2016,December 2018, we announced organizational changes aiming to simplify our structure, increase direct operational alignment to advance our natural gas-focused strategy, and drive continued focus on customer service and execution. Effective January 1, 2017, we implemented these changes, which combined the management of certain of our operations and reduced the overall number of operating areas managed within our business.
Information in this report has generally been prepared to be consistent with the reportable segment presentation in our consolidated financial statement in Part II, Item 8 of this document. These segments are discussed in further detail in the following sections.
Williams Partners
Northwest Pipeline rate case
On January 23, 2017, Northwest Pipeline filed a Stipulation and Settlement Agreement withreceived approval from the FERC for new rates.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 new rates become effective January 1, 2018,project was placed into service in December 2019 and are not expected to materially affect our trend of earnings. Pursuant to this agreement, Northwest Pipeline can file for new rates to be effective after October 1, 2018, and must file a general rate case for new rates to become effective no later than January 1, 2023.increased capacity by 65 Mdth/d.
Geismar olefins facility monetizationGulf Connector
In September 2016, Williams Partners announcedJanuary 2019, the initiation of an ongoing process to explore monetization of its ownership interest in the Geismar, Louisiana, olefins plant and complex, consistent with our strategy to narrow our focus and allocate capital to our natural gas–focused business.
Sale of Canadian operations
In September 2016, we completed the sale of our Canadian operations for total consideration of $1.02 billion. We recognized an impairment charge of $747 million during the second quarter of 2016 related to these operations and an additional loss of $66 million upon completion of the sale. (See Note 3 – Divestiture.)
Barnett Shale and Mid-Continent contract restructurings
In August 2016, Williams Partners conditionally committed to execute a new gas gathering agreement in the Barnett Shale. The agreement was executed in the fourth quarter of 2016, in conjunction with our existing customer, Chesapeake Energy Corporation, closing the sale of its Barnett Shale properties to another producer. That other producer, which has an investment grade credit rating, is now our customer under the new gas gathering agreement. The restructured agreement provided a $754 million up-front cash payment to us primarily in exchange for eliminating future minimum volume commitments. The restructured agreement also provides for revised gathering rates. Based on current commodity price assumptions at the time of the agreement, we generally expect the up-front cash proceeds and the ongoing cash flows generated by gathering services, to represent equivalent net present value of cash flows as compared to expected performance under the existing agreement. Additionally, Williams Partners agreed to a revised contract in the Mid-Continent region, also with Chesapeake Energy Corporation. The revised contract was executed in the third quarter of 2016 and provided an up-front cash payment to us of $66 million primarily in exchange for changing from a cost of service contract to fixed-fee terms. The majority of the up-front cash proceeds from both agreements were recognized as deferred revenue and will be amortized into income in future periods. In the near term, we do not expect that our trend of reported results will be significantly impacted by the effect of the discount associated with the up-front cash proceeds relative to the original minimum volume commitments and reduced gathering rates. It was anticipated that both agreements would reduce customer concentration risk and provide support to realize additional drilling and improved volumes in these regions.
Powder River basin contract restructuring
In October 2016, in conjunction with our partner in the Bucking Horse natural gas processing plant and Jackalope Gas Gathering System, we announced an agreement with Chesapeake Energy Corporation to restructure gathering and processing contracts in the Powder River basin. The restructured contracts became effective in January 2017 and replaced the previous cost-of-service arrangement with MVCs in the near-term such that we do not expect that our near-term trend of reported results will be significantly impacted by the restructured terms.
Rock Springs expansion
In August 2016, the Rock Springs expansionGulf Connector project was placed into service. TheThis project expanded Transco’s existing natural gas transmission system from New Jersey to a generation facility in Maryland and increased capacity by 192 Mdth/d.
Gulf Trace expansion
In February 2017, the Gulf Trace expansion was placed into service. The project expanded Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 65 in St. Helena Parish, Louisiana to a new interconnection with Sabine Pass Liquefactiondelivery points in Cameron Parish, Louisiana. It is expected to increaseWharton and San Patricio Counties, Texas. The project increased capacity by 1,200475 Mdth/d.
Redwater expansionWest
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 2016, we completed1, 2019, subject to refund and the expansion of our Redwater facilities in supportoutcome of a long-termhearing. 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 to provide gas processing services toon the terms of a second bitumen upgradersettlement with the participants that would resolve all issues in Canada’s oil sands near Fort McMurray, Alberta. The expanded Redwater facility receives NGL/olefins mixtures fromthe 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 bitumen upgrader and fractionates the mixtures into an ethane/ethylene mix, propane, polymer grade propylene, normal butane, an alkylation feed and condensate. We sold these operations in September 2016. (See Note 3 – Divestiturequarter of Notes2020. As of December 31, 2019, we have provided a $189 million reserve for rate refunds related to Consolidated Financial Statements.)increased rates collected since March 2019, which we believe is adequate for any refunds that may be required.
Williams NGL & Petchem Services
Horizon liquids extraction plant
In March 2016, we completed a new liquids extraction plant near Fort McMurray, Alberta. The Boreal pipeline was extended to enable transportation of the NGL/olefins mixture from the new liquids extraction plant to Williams Partners’ expanded Redwater facilities. The plant increased the amount of NGLs produced in Canada to a total of approximately 40 Mbbls/d. To mitigate ethane price risk associated with our processing services, we had a long-term agreement with a minimum price for ethane sales to a third-party customer. We sold these operations in September 2016. (See Note 3 – Divestiture of Notes to Consolidated Financial Statements.)
Commodity Prices
NGL per-unit margins were approximately 744 percent lower in 20162019 compared to the same period of 2015. Following2018 primarily due to a sharp decline31 percent and a 44 percent decrease in late 2014 to early 2015, total NGL margins have remained somewhat consistentper-unit non-ethane and ethane sales prices, respectively, slightly offset by an approximate 10 percent decrease in 2015 and 2016. While 2014 and 2015 reflect limited ethane recoveries, we have seen an increase in ethane production during 2016.per-unit natural gas feedstock prices.
NGL margins are defined as NGL revenues less any applicable Btu replacement cost, plant fuel, and third-party transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. Our equity volumes include NGLs where we own the rights to the value from NGLs recovered at our plants under both “keep-whole” processing agreements, where we have the obligation to replace the lost heating value with natural gas, and “percent-of-liquids” agreements whereby we receive a portion of the extracted liquids with no obligation to replace the lost heating value.
The following graph illustrates the NGL production and sales volumes, as well as the margin differential between ethane and non-ethane products and the relative mix of those products.
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 20172020 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 previously announced agreement with WPZpace of our capital growth spending in our gathering and processing business and remaining committed to permanently waiveoperating cost discipline.
In 2020, our incentive distribution rights in exchange for WPZ common units as well as our private purchase of $2.1 billion newly issued WPZ commits units. We expect to increase our dividend to $0.30 per share, or $1.20 annually, beginning in the first quarter of 2017. Our business plan also includes previously discussed asset monetizations, which include our ownership interest in the Geismar olefins facility as well as other select assets that are not core to our strategy. The monetizationsoperating results are expected to yield after-tax proceeds of greater than $2.0 billion. For WPZ, these transactionsinclude 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 improve its cost of capital, remove its needincrease from higher gathering and processing volumes.We expect decreases in the West primarily due to accesslower deferred revenue amortization in the public equity markets for the next several years, enhance growth,Barnett Shale and provide for debt reduction, solidifying WPZ as an attractive financing vehicle. The transactions are also expected to facilitate a reduction oflower revenues from our parent-level debtHaynesville operations, partially offset by increased results from our DJ Basin and provides for dividend growth flexibility, while retaining strategic and financing flexibility.Eagle Ford operations. Additionally, we expect our recently implemented organizational realignment will benefit our expenses.
Our growth capital and investment expenditures in 20172020 are expected to total $2.1be in a range from $1.1 billion to $2.8$1.3 billion. Approximately $1.4 billion to $1.9 billion of our growthGrowth capital funding needs includespending in 2020 primarily includes Transco expansions, and other interstate pipeline growth projects, mostall of which are fully contracted with firm transportation agreements. The remaining growth capital spending in 2017 primarily reflects investment in gatheringagreements, and processing systemsour Bluestem NGL pipeline project in the Northeast region limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project.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.
As a result of our significant continued capital and investment expenditures on Transco expansions and fee-based gathering and processing projects, as well as the previously discussed sale of our Canadian operations and the planned monetization of the Geismar olefins facility, fee-based businesses are becoming an even more significant component of our portfolio and serve to reduce the influence of commodity price fluctuations on our operating results and cash flows. We expect to benefit as continued growth in demand for low-cost natural gas is driven by increases in LNG exports, industrial demand and power generation. Current forward market prices indicate a slightly more favorable energy commodity price environment in 2017 as compared to 2016, including higher natural gas and NGL prices. However, some of our customers may continue to curtail or delay drilling plans until there is a more sustained recovery in prices, which may negatively impact our gathering volumes. Although there has been some improvement, the credit profiles of certain of our producer customers remain challenged. Unfavorable changes in energy commodity prices or the credit profile of our producer customers may also result in noncash impairments of our assets.
In 2017, our operating results will include increases from our fee-based businesses recently placed in service or expected to be placed in service in 2017 primarily along the Transco system, a full year benefit of expanded capacity on our Gulfstar FPS™, and lower general and administrative expenses due to cost reduction initiatives and asset monetizations. We expect overall gathering and processing volumes to remain steady in 2017 and increase thereafter to meet the growing demand for natural gas and natural gas products.
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;
Counterparty creditUnexpected changes in customer drilling and performance risk, including that of Chesapeake Energy Corporationproduction activities, which could negatively impact gathering and its affiliates;processing volumes;
Inability to execute or delay in completing planned asset monetizations;
Lower than anticipated demand for natural gas and natural gas products which could result in lower than expected volumes, energy commodity prices, and margins;
General economic, financial markets, or further industry downturn,downturns, including increased interest rates;
Physical damages to facilities, including damage to offshore facilities by named windstorms;
Reduced availability of insurance coverage;
Lower than expected distributions from WPZ.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:
Williams Partners
Eagle Ford
We plan to expand our gathering infrastructure in the Eagle Ford region in order to meet our customers’ production plans. The expansion of the gathering infrastructure includes the addition of new facilities, well connections, and gathering pipeline to the existing systems.
Oak Grove Expansion
We plan to expand our processing capacity at our Oak Grove facility by adding a second 200 MMcf/d cryogenic natural gas processing plant, which, based on our customers’ needs, is expected to be placed into service in 2020.
Gathering System Expansion
We will continue to expand the gathering systems in the Marcellus and Utica Shale regions that are needed to meet our customers’ production plans. The expansion of the gathering infrastructure includes additional compression and gathering pipeline to the existing system.
Constitution Pipeline
In December 2014, we received approval from the FERC to construct and operate the jointly owned Constitution pipeline, which will have an expected capacity of 650 Mdth/d. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied a necessary water quality certification for the New York portion of the pipeline. We remain steadfastly committed to the project, and in May 2016, Constitution appealed the NYSDEC’s denial of the certification and filed an action in federal court seeking a declaration that the State of New York’s authority to exercise permitting jurisdiction over certain other environmental matters is preempted by federal law. (See Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements.) We currently own 41 percent of Constitution with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We will be the operator of Constitution. The 126-mile Constitution pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York, as well as to a local distribution company serving New York and Pennsylvania. In light of the NYSDEC’s denial of the water quality certification and the actions taken to challenge the decision, the target in-service date has been revised to as early as the second half of 2018, which assumes that the legal challenge process is satisfactorily and promptly concluded.
Garden State
In April 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 210 in New Jersey to a new interconnection on our Trenton Woodbury Lateral in New Jersey. The project will be constructed in phases and is expected to increase capacity by 180 Mdth/d. We plan to place the initial phase of the project into service during the third quarter of 2017 and the remaining portion in the second quarter of 2018, assuming timely receipt of all necessary regulatory approvals.
Norphlet Project
In March 2016, we announced that we have reached an agreement to provide deepwater gas gathering services to the Appomattox development in the Gulf of Mexico. The project will provide offshore gas gathering services to our existing Transco lateral, which will provide transmission services onshore to our Mobile Bay processing facility. We also plan to make modifications to our Main Pass 261 Platform to install an alternate delivery route from the platform, as well as modifications to our Mobile Bay processing facility. The project is scheduled to go into service during the second quarter of 2020.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 proposed new interconnection with the Sabal Trail projectpipeline in Alabama. The project will beis being constructed in phases, and all of the project expansion capacity will be leasedis dedicated to Sabal Trail. We planTrail pursuant to place the initial phase of the project into service concurrent with the in-service date of the Sabal Trail project, which is planned to occur as early as the second quarter of 2017.a capacity lease agreement. Phase I was completed in 2017 and it increased capacity by 818 Mdth/d. The in-service date of the second phase of the projectPhase II is planned for the second quarter of 2020, and together theyPhases I and II are expected to increase capacity by 1,025 Mdth/d.
In March 2016, WPZ entered into an agreement with the member-sponsors of Sabal Trail to resolve several matters. In accordance with the agreement, the member-sponsors will pay us an aggregate amount of $240 million in three equal installments as certain milestones of the project are met. The first $80 million payment was received in March 2016 and the second installment was received in September 2016. WPZ expects to recognize income associated with these receipts over the term of the capacity lease agreement.
New York Bay ExpansionNortheast Supply Enhancement
In July 2016,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 Narrows meter station in Richmond County, New York.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 duringin the fourth quarterfall of 2017, and it is expected to increase capacity by 115 Mdth/d.
Atlantic Sunrise
In February 2017, we received approval from the FERC to expand Transco’s existing natural gas transmission system along with greenfield facilities to provide incremental firm transportation capacity from the northeastern Marcellus producing area to markets along Transco’s mainline as far south as Station 85 in west central Alabama. We expect to place a portion of the project facilities into service during the second half of 2017 and are targeting a full in-service during mid-2018,2021, assuming timely receipt of all necessary regulatorythese remaining approvals. The project is expected to increase capacity by 1,700400 Mdth/d.
Virginia Southside IISoutheastern Trail
In July 2016,October 2019, we received approval from the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 210 in New Jersey and Station 165 in Virginia to a new lateral extending from our Brunswick Lateral in Virginia. We plan
to place the project into service during the fourth quarter of 2017 and it is expected to increase capacity by 250 Mdth/d.
Dalton
In August 2016, we obtained approval from the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 210 in New Jersey to markets in northwest Georgia. We plan to place the project into service in 2017 and it is expected to increase capacity by 448 Mdth/d.
Gulf Connector
In August 2016, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the Pleasant Valley interconnect with Dominion’s Cove Point Pipeline in Virginia to the Station 65 pooling point in LouisianaLouisiana. We plan to delivery pointsplace the project into service in Wharton and San Patricio Counties, Texas.late 2020. The project will be constructed in two phases,is expected to increase capacity by 296 Mdth/d.
Leidy South
In July 2019, we filed an application with the initial phaseFERC for approval of the project expected to beexpand 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 duringas early as the second halffourth quarter of 2018 and the remaining phase in 2019,2021, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 475582 Mdth/d.
Williams NGL & Petchem Services
Gulf Coast NGL and Olefin Infrastructure Expansion
Certain previously acquired liquids pipelines48
West
Project Bluestem
We are expanding our presence in the Gulf CoastMid-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 combined with an organic build-outplaced into service during the first quarter of several projects to expand our petrochemical services in that region. The projects include the construction and commissioning of pipeline systems capable of transporting various purity natural gas liquids and olefins products in the Gulf Coast region. In response to the current conditions in the midstream industry, we are slowing the pace of development and may seek partners for these projects.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, expectedcash balance interest crediting rate, of compensation increase, health care cost trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed. The assumptions utilized to compute cost and the benefit obligations are shown in Note 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 | Benefit Cost | | Benefit Obligation |
| | One- Percentage- Point Increase | | One- Percentage- Point Decrease | | One- Percentage- Point Increase | | One- Percentage- Point Decrease | One- Percentage- Point Increase | | One- Percentage- Point Decrease | | One- Percentage- Point Increase | | One- Percentage- Point Decrease |
| | (Millions) | (Millions) |
| Pension benefits: | | | | | | | | | | | | | | |
| Discount rate | $ | (9 | ) | | $ | 10 |
| | $ | (130 | ) | | $ | 154 |
| $ | (2 | ) | | $ | 4 |
| | $ | (102 | ) | | $ | 120 |
|
| Expected long-term rate of return on plan assets | (13 | ) | | 13 |
| | — |
| | — |
| (12 | ) | | 12 |
| | — |
| | — |
|
| Rate of compensation increase | 3 |
| | (2 | ) | | 9 |
| | (7 | ) | |
| Cash balance interest crediting rate | | 12 |
| | (10 | ) | | 71 |
| | (60 | ) |
| Other postretirement benefits: | | | | | | | | | | | | | | |
| Discount rate | 1 |
| | 1 |
| | (21 | ) | | 25 |
| 1 |
| | 2 |
| | (23 | ) | | 28 |
|
| Expected long-term rate of return on plan assets | (2 | ) | | 2 |
| | — |
| | — |
| (2 | ) | | 2 |
| | — |
| | — |
|
| Assumed health care cost trend rate | — |
| | — |
| | 6 |
| | (5 | ) | |
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, which are weighted toward domestic and international equity securities.assets. We develop our expectations using input from our third-party independent investment consultant. The forward-looking capital market projections start with current conditions of interest rates, equity pricing, economic growth, and inflation and those are overlaid with forward looking projections of normal inflation, growth, and interest rates to determine expected returns. The capital market return projections for specific asset classes in the investment portfolio are then applied to the relative weightings of the asset classes in the investment portfolio. The resulting rates are an estimate of future results and, thus, likely to be different than actual results.
In 2016, the benefit plans’ assets outperformed their respective benchmarks for fixed income strategies, but generally underperformed the respective benchmarks for equity strategies. While the 2016 investment performance was greater than our
Our expected rateslong-term rate of return theon 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 would also impact thesethe expected rates of return. Our expected long-term rate of return on plan assets used for our pension plans was 6.85 percent in 2016. The 2016 actual return on plan assets for our pension plans was approximately 7.5 percent. The 10-year average rate of return on pension plan assets through December 2016 was approximately 3.7 percent.
The discount rates are used to measure the benefit obligations of our pension and other postretirement benefit plans. The objective of the discount rates is to determine the amount, if invested at the December 31 measurement date in a portfolio of high-quality debt securities, that will provide the necessary cash flows when benefit payments are due. Increases in the discount rates decrease the obligation and, generally, decrease the related cost. The discount rates for our pension and other postretirement benefit plans are determined separately based on an approach specific to our plans and their respective expected benefit cash flows as described in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies and Note 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 expectedcash balance interest crediting rate of compensation increaseassumption represents the average long-term salary increases.rate by which the pension plans’ cash balance accounts are expected to grow. Interest on the cash balance accounts is based on the 30-year U.S. Treasury securities rate and is credited to the accounts quarterly. An increase in this rate causes the pension obligation and cost to increase.
The assumed health care cost trend rates are based on national trend rates adjusted for our actual historical cost rates and plan design. An increase in this rate causes the other postretirement benefit obligation and cost to increase.
Equity-Method Investments
At the end of the third quarter of 2016, we became aware of changes involving certain of DBJV’s customer contracts, which impacted our estimates of DBJV’s future cash flows. As such, we evaluated this investment for impairment at September 30, 2016, and determined that no impairment was necessary. We also entered into initial discussions with the system operator regarding the terms and economic assumptions of these contract changes.
During the fourth quarter of 2016, these discussions led to negotiations with the system operator to exchange our interest in DBJV and another equity-method investment in the Permian basin (Ranch Westex) for its interests in certain gathering systems in the Northeast and cash. We already hold partial interests in these Northeast gathering systems through our Appalachia Midstream Investments. As previously discussed, we reached agreements for such transactions in February 2017.
As part of the preparation of our year-end financial statements, we evaluated the carrying amounts of our investments in DBJV, Ranch Westex and these certain gathering systems within our Appalachia Midstream Investments for impairment. We also evaluated other equity-method investments within the Northeast area for impairment as of December 31, 2016, including other gathering systems within our Appalachia Midstream Investments and our investment in UEOM. Our impairment evaluations utilized an income approach, but also considered the fair values indicated by the previously described transaction. The estimated fair value of our investment in DBJV exceeded its carrying value and no impairment was necessary. Based on the fair value of the consideration expected to be received, we currently expect to recognize a gain upon consummation of the previously described exchange transaction in 2017.
We estimated the fair value of our Appalachia Midstream Investments and UEOM using an income approach with discount rates ranging from 10.2 percent to 12.5 percent and also considered the value implied by the previously described transactions as applicable. For certain gathering systems within our Appalachia Midstream Investments, the fair value was determined to be less than our carrying value, resulting in an other-than-temporary impairment charge of $294 million. No impairment was necessary for other gathering systems within our Appalachia Midstream Investments or our investment in UEOM. For those investments evaluated for which no impairment was required, our estimate of fair value exceeded our carrying value by amounts ranging from approximately 2.5 percent to 7.5 percent. We estimate that an increase in the discount rate utilized of 50 basis points would have resulted in an additional impairment charge of approximately $45 million. We also recorded an additional impairment of $24 million related to our interest in Ranch Westex.
Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and market measures utilized. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of a different impairment charge in the consolidated financial statements.
At December 31, 2016, our Consolidated Balance Sheet includes approximately $6.7 billion of investments that are accounted for under the equity-method of accounting. We evaluate these investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. We continue to monitor our equity-method investments for any indications that the carrying value may have experienced an other-than-temporary decline in value. When evidence of a loss in value has occurred, we compare our estimate of the fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We generally estimate the fair value of our investments using an income approach where significant judgments and assumptions include expected future cash flows and the appropriate discount rate. In some cases, we mayWe 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.)
If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge. Events or changes in circumstances that may be indicative of an other-than-temporary decline in value will vary by investment, but may include:
A significant or sustained decline in the market value of an investee;
Lower than expected cash distributions from investees;
Significant asset impairments or operating losses recognized by investees;
Significant delays in or lack of producer development or significant declines in producer volumes in markets served by investees;
Significant delays in or failure to complete significant growth projects of investees.
Constitution Pipeline Capitalized Project Costs
As of December 31, 2016, Property, plant, and equipment – net in our Consolidated Balance Sheet includes approximately $381 million of capitalized project costs for Constitution, for which we are the construction manager and own a 41 percent consolidated interest. In December 2014, we received approval from the FERC to construct and operate this jointly owned pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied a necessary water quality certification for the New York portion of the Constitution pipeline. We remain steadfastly committed to the project, and in May 2016, Constitution appealed the NYSDEC's denial of the certification and filed an action in federal court seeking a declaration that the State of New York's authority to exercise permitting jurisdiction over certain other environmental matters is preempted by federal law.
As a result of the denial by the NYSDEC, we evaluated the capitalized project costs for impairment as of March 31, 2016, and as of December 31, 2016, and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including a scenario assuming successful resolution with the NYSDEC and construction of the pipeline, as well as a scenario where the project does not proceed. We continue to monitor the capitalized project costs associated with Constitution for potential impairment.
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, 2016.2019. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
| | | | Years Ended December 31, | Year Ended December 31, |
| | 2016 | | $ Change from 2015* | | % Change from 2015* | | 2015 | | $ Change from 2014* | | % Change from 2014* | | 2014 | 2019 | | $ Change from 2018* | | % Change from 2018* | | 2018 | | $ Change
from
2017* | | % Change
from
2017* | | 2017 |
| | (Millions) | (Millions) |
| Revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Service revenues | $ | 5,171 |
| | +7 |
| | — | % | | $ | 5,164 |
| | +1,048 |
| | +25 | % | | $ | 4,116 |
| $ | 5,933 |
| | +431 |
| | +8 | % | | $ | 5,502 |
| | +190 |
| | +4 | % | | $ | 5,312 |
|
| Service revenues – commodity consideration | | 203 |
| | -197 |
| | -49 | % | | 400 |
| | +400 |
| | NM |
| | — |
|
| Product sales | 2,328 |
| | +132 |
| | +6 | % | | 2,196 |
| | -1,325 |
| | -38 | % | | 3,521 |
| 2,065 |
| | -719 |
| | -26 | % | | 2,784 |
| | +65 |
| | +2 | % | | 2,719 |
|
| Total revenues | 7,499 |
| | | | | | 7,360 |
| | | | | | 7,637 |
| 8,201 |
| | | | | | 8,686 |
| | | | | | 8,031 |
|
| Costs and expenses: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Product costs | 1,725 |
| | +54 |
| | +3 | % | | 1,779 |
| | +1,237 |
| | +41 | % | | 3,016 |
| 1,961 |
| | +746 |
| | +28 | % | | 2,707 |
| | -407 |
| | -18 | % | | 2,300 |
|
| Processing commodity expenses | | 105 |
| | +32 |
| | +23 | % | | 137 |
| | -137 |
| | NM |
| | — |
|
| Operating and maintenance expenses | 1,580 |
| | +75 |
| | +5 | % | | 1,655 |
| | -163 |
| | -11 | % | | 1,492 |
| 1,468 |
| | +39 |
| | +3 | % | | 1,507 |
| | +69 |
| | +4 | % | | 1,576 |
|
| Depreciation and amortization expenses | 1,763 |
| | -25 |
| | -1 | % | | 1,738 |
| | -562 |
| | -48 | % | | 1,176 |
| 1,714 |
| | +11 |
| | +1 | % | | 1,725 |
| | +11 |
| | +1 | % | | 1,736 |
|
| Selling, general, and administrative expenses | 723 |
| | +18 |
| | +2 | % | | 741 |
| | -80 |
| | -12 | % | | 661 |
| 558 |
| | +11 |
| | +2 | % | | 569 |
| | +25 |
| | +4 | % | | 594 |
|
| Impairment of goodwill | — |
| | +1,098 |
| | +100 | % | | 1,098 |
| | -1,098 |
| | NM |
| | — |
| |
| Impairment of certain assets | 873 |
| | -664 |
| | NM |
| | 209 |
| | -157 |
| | NM |
| | 52 |
| 464 |
| | +1,451 |
| | +76 | % | | 1,915 |
| | -667 |
| | -53 | % | | 1,248 |
|
| Net insurance recoveries – Geismar Incident | (7 | ) | | -119 |
| | -94 | % | | (126 | ) | | -106 |
| | -46 | % | | (232 | ) | |
| Gain on sale of certain assets and businesses | | 2 |
| | -694 |
| | NM |
| | (692 | ) | | -403 |
| | -37 | % | | (1,095 | ) |
| Regulatory charges resulting from Tax Reform | | — |
| | -17 |
| | -100 | % | | (17 | ) | | +691 |
| | NM |
| | 674 |
|
| Other (income) expense – net | 142 |
| | -102 |
| | NM |
| | 40 |
| | -137 |
| | NM |
| | (97 | ) | 8 |
| | +59 |
| | +88 | % | | 67 |
| | +4 |
| | +6 | % | | 71 |
|
| Total costs and expenses | 6,799 |
| | | | | | 7,134 |
| | | | | | 6,068 |
| 6,280 |
| | | | | | 7,918 |
| | | | | | 7,104 |
|
| Operating income (loss) | 700 |
| | | | | | 226 |
| | | | | | 1,569 |
| 1,921 |
| | | | | | 768 |
| | | | | | 927 |
|
| Equity earnings (losses) | 397 |
| | +62 |
| | +19 | % | | 335 |
| | +191 |
| | +133 | % | | 144 |
| 375 |
| | -21 |
| | -5 | % | | 396 |
| | -38 |
| | -9 | % | | 434 |
|
| Gain on remeasurement of equity-method investment | — |
| | — |
| | — | % | | — |
| | -2,544 |
| | -100 | % | | 2,544 |
| |
| Impairment of equity-method investments | (430 | ) | | +929 |
| | +68 | % | | (1,359 | ) | | -1,359 |
| | NM |
| | — |
| |
| Other investing income (loss) – net | 63 |
| | +36 |
| | +133 | % | | 27 |
| | -16 |
| | -37 | % | | 43 |
| (79 | ) | | -266 |
| | NM |
| | 187 |
| | -95 |
| | -34 | % | | 282 |
|
| Interest expense | (1,179 | ) | | -135 |
| | -13 | % | | (1,044 | ) | | -297 |
| | -40 | % | | (747 | ) | (1,186 | ) | | -74 |
| | -7 | % | | (1,112 | ) | | -29 |
| | -3 | % | | (1,083 | ) |
| Other income (expense) – net | 74 |
| | -28 |
| | -27 | % | | 102 |
| | +71 |
| | NM |
| | 31 |
| 33 |
| | -59 |
| | -64 | % | | 92 |
| | +117 |
| | NM |
| | (25 | ) |
| Income (loss) from continuing operations before income taxes | (375 | ) | | | | | | (1,713 | ) | | | | | | 3,584 |
| 1,064 |
| | | | | | 331 |
| | | | | | 535 |
|
| Provision (benefit) for income taxes | (25 | ) | | -374 |
| | -94 | % | | (399 | ) | | +1,648 |
| | NM |
| | 1,249 |
| 335 |
| | -197 |
| | -143 | % | | 138 |
| | -2,112 |
| | NM |
| | (1,974 | ) |
| Income (loss) from continuing operations | (350 | ) | | | | | | (1,314 | ) | | | | | | 2,335 |
| 729 |
| | | | | | 193 |
| | | | | | 2,509 |
|
| Income (loss) from discontinued operations | — |
| | — |
| | — | % | | — |
| | -4 |
| | -100 | % | | 4 |
| (15 | ) | | -15 |
| | NM |
| | — |
| | — |
| | — | % | | — |
|
| Net income (loss) | (350 | ) | | | | | | (1,314 | ) | | | | | | 2,339 |
| 714 |
| | | | | | 193 |
| | | | | | 2,509 |
|
| Less: Net income (loss) attributable to noncontrolling interests | 74 |
| | -817 |
| | NM |
| | (743 | ) | | +968 |
| | NM |
| | 225 |
| (136 | ) | | +484 |
| | NM |
| | 348 |
| | -13 |
| | -4 | % | | 335 |
|
| Net income (loss) attributable to The Williams Companies, Inc. | $ | (424 | ) | | | | | | $ | (571 | ) | | | | | | $ | 2,114 |
| $ | 850 |
| | | | | | $ | (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. |
20162019 vs. 20152018
Service revenuesincreased slightly primarily due to higher transportation fee revenues at Transco associated with expansion projects placed in service in 20152019 and 2016,2018, 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 decreasecontractual 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 gathering,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 fractionation revenuetherefore are offset in Product costs below.
Product sales decreased primarily due to lower volumes in the Barnett Shale and Anadarko basin.
Product sales increased primarily due to higher olefin sales reflecting increased volumes at our Geismar plant as a result of the plant operating at higher production levels in 2016, partially offset by a decrease from our other olefin operations associated with lower volumes and per-unit sales prices. Product sales also reflect higher marketing revenues associated with higher NGL and propylene prices and natural gas prices associated with our marketing and crude oilequity NGL sales activities, lower volumes partially offset by lowerfrom our equity NGL volumes, and crude oil prices.
The decrease in Product costs includes lower olefin feedstock purchasessales primarily reflecting the absence of our former Four Corners area operations, and lower costs associated with other productsystem management gas sales, partially offset by higher marketing purchases primarily due to the same factors that increased marketing sales. The declinevolumes. Marketing sales and system management gas sales are substantially offset in olefin feedstock purchases is primarily associated with lower per-unit feedstockProduct costs and volumes at our other olefin operations, partially offset by an increase in olefin feedstock purchases at our Geismar plant reflecting increased volumes resulting from higher production levels in 2016..
Operating and maintenance expenses Product costsdecreased primarily due to lower labor-relatedNGL and outside service costs resulting from our first-quarter 2016 workforce reductions and cost containment efforts and lower costsnatural gas prices associated with general maintenance activities in the Marcellus Shale,our marketing and equity NGL production activities. This decrease also includes lower volumes acquired as well ascommodity consideration for NGL processing services reflecting the absence of ACMP transition-related costs recognized in 2015.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 $16the impact of the consolidation of UEOM and by a $32 million ofcharge for severance and related costs recognizedprimarily associated with a voluntary separation program (VSP) in 2016 and higher pipeline testing and general maintenance costs at Transco.2019.
Depreciation and amortization expensesincreased decreased primarily due to depreciation onthe 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 including Transco pipeline projects, partially offsetand by lower depreciation related to Canadian operations sold in 2016.the impact of the consolidation of UEOM.
Selling, general, and administrative expenses(SG&A) decreased primarily due to lower mergerthe 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 transition costsfees associated with the ACMP merger and lower labor-related costs resulting from our first-quarter 2016 workforce reductions and cost containment efforts. These decreases wereWPZ Merger, partially offset by certain project development costs associated with the Canadian PDH facility that we began expensing in 2016, as well as $26a $25 million ofcharge for severance and related costs recognized in 2016 and $17 million of higher costsprimarily associated with our evaluation2019 VSP, and transaction expenses associated with the acquisition of strategic alternatives.UEOM and the formation of the Northeast JV.
Impairment of goodwill decreased due tocertain 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 absence of a 2015 impairment charge associated withBarnett Shale region and certain goodwill. (Seeidle pipelines (see Note 1718 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)Statements).
ImpairmentGain on sale of certain assets reflects 2016 impairments and businesses includes gains recognized on the sales of our Canadian operationsFour Corners area and certain Mid-Continent assets,our Gulf Coast pipeline systems in 2018 (see Note 3 – Acquisitions and other assets. Impairments recognized in 2015 relate primarily to previously capitalized development costs and surplus equipment write-downs. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit RiskDivestitures of Notes to Consolidated Financial Statements.)Statements).
Net insurance recoveries – Geismar Incident changed unfavorably reflecting the receipt of $126 million of insurance proceeds in the second quarter of 2015, as compared to the receipt of $7 million of proceeds in the fourth quarter of 2016.
The unfavorablefavorable change inOther (income) expense – netwithin Operating income (loss) includes a loss on the sale of our Canadian operations that were sold in September 2016, project development costs at Constitution as we discontinued capitalization of these costs in April 2016,net favorable changes to charges and an unfavorable change in foreign currency exchange that primarily relatescredits to losses incurred on foreign currency transactions and the remeasurement of the U.S. dollar-denominated currentregulatory assets and liabilities, within our former Canadian operations, partially offset by a $10 million gain on the sale of idle pipe in 2016.
Operating income (loss) changed favorably primarily due to the absence of a goodwill impairment in 2015, higher olefin margins related to the Geismar plant operating at higher production levels in 2016, lower costs related to the merger2018 gain on asset retirement (see Note 7 – Other Income and integration of ACMP, and lower costs and expenses primarily associated with cost containment efforts.
These favorable changes are partially offset by impairments and loss on sale of certain assets in 2016, a decrease in insurance proceeds received, expensed Canadian PDH facility project development costs, and higher depreciation expenses related to new projects placed in service.
Equity earnings (losses) changed favorably primarily due to a $30 million increase at Discovery driven by the completion of the Keathley Canyon Connector in the first quarter of 2015. Additionally, OPPL, Laurel Mountain, and DBJV improved $16 million, $11 million, and $10 million, respectively.
Impairment of equity-method investments reflects 2016 impairment charges associated with our Appalachia Midstream Investments, DBJV, and Laurel Mountain equity-method investments, while the 2015 impairment charges relate to our equity-method investments in Appalachia Midstream Investments, DBJV, UEOM, and Laurel Mountain. (See Note 6 – Investing ActivitiesExpenses of Notes to Consolidated Financial Statements.)Statements).
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) – netchanged favorably due to includes higher impairments of equity-method investments, the absence of 2018 gains on the deconsolidations of our Delaware basin assets and Jackalope, and a 20162019 loss on the deconsolidation of Constitution. These were partially offset by a 2019 gain on the saledisposition of an equity-method investment interest in a gathering system that was part of our Appalachia Midstream Investments and higher interest income associated with a receivable related to the sale of certain former Venezuela assets. (SeeJackalope (see Note 6 – Investing Activitiesof Notes to Consolidated Financial Statements.)Statements).
Interest expenseincreased primarily due to higher Interest incurred of $99 million primarily attributable to new debt issuancesan increase in 2016 and 2015financing obligations associated with Transco’s Atlantic Sunrise project and lower Interest capitalized of $36 million primarily related to construction projects that have been placed into service, partially offset by lower interest due to 2015 and 2016 debt retirements.service. (See Note 1415 – Debt and Banking Arrangements and Leases of Notes to Consolidated Financial Statements.)
The unfavorable change in Other income (expense) – net below Operating income (loss) changed unfavorably is primarily due to a decrease in allowance for equity funds used during construction (AFUDC) due to decreased spendingAFUDC associated with reduced capital expenditures on Constitution andprojects, partially offset by the absence of a $14 million gain on2018 unfavorable settlement charges from our pension early debt retirement in 2015.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 decreasecharge to establish a $105 million valuation allowance, recorded in pretax loss in 2016.2018, 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 ratesrate compared to the federal statutory rate for both years.periods.
The unfavorablefavorable change in Net income (loss) attributable to noncontrolling interests is 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 operating resultstransportation fee revenues at WPZ, the impact of decreased income allocated to the WPZ general partner driven by the impact of reduced incentive distributions from WPZTransco associated with expansion projects placed in-service in 2017 and 2018, as well as higher gathering volumes at the terminationSusquehanna 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 WPZ Merger Agreement,Jackalope deconsolidation.
Service revenues – commodity considerationincreased 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
Policies of Notes to Consolidated Financial Statements.) Most of these NGL volumes are sold within the absence of the accelerated amortization of a beneficial conversion featuremonth 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 first quarterproduction of 2015.our equity NGLs, reflecting higher NGL prices. These changesincreases are partially offset by a favorable change primarily related tothe absence of $269 million in olefins sales associated with our partners’ share of Constitution project developmentformer olefins operations in 2017.
The increase in Product costs in 2016.
2015 vs. 2014
Service revenuesincreasedis primarily due to additional revenues associated with a full yearthe impact of ACMP operationsASC 606 in 2015, increased revenues associated with the start-up of operations at Gulfstar One during the fourth quarter of 2014,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 ansystem management gas purchases. This increase in Transco’s natural gas transportation fees due to new projects placed in service in 2014 and 2015. Revenues from operations associated with our acquisition of ACMP and the northeast region also increased due to higher volumes related to new well connects. A decrease in Canadian construction management revenues, reflecting a shift to internal customer construction projects, partially offset these increases.
Product sales decreased due to a decrease in marketing revenues primarily associated with lower prices across all products,is partially offset by higher non-ethane volumes, and a decrease in revenues from our equity NGLs reflecting lower NGL prices, partially offset by higher NGL volumes. Product sales also decreasedthe absence of $147 million of olefin feedstock purchases due to lower olefin sales from other olefinthe sale of our former olefins operations, associated with lower per-unit sales prices, partially offset by higher volumes. These decreases are partially offset by an increase in olefin sales primarily due to resuming our Geismar operations during 2015.
Product costs decreased due to a decrease in marketing purchases primarily associated with lower per-unit costs, partially offset by higher non-ethane volumes, and a decrease inas 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 lower natural gas prices,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 higher volumes. Product costs alsonew assets placed in-service.
Selling, general, and administrative expenses decreased
due to lower feedstock purchases in our other olefin operations primarily due to lower per-unit feedstockthe absence of severance-related, organizational realignment, and Financial Repositioning costs across all products as well as lower per-unitincurred in 2017, $25 million in reduced costs partially offset by significantly higher volumes in 2015.associated with our former olefins and Four Corners area operations, and cost containment efforts. These decreases are partially offset by an increase in olefin feedstock purchases primarilya charitable contribution of preferred stock to The Williams Companies Foundation, Inc. and fees associated with resuming our Geismar operations.the WPZ Merger.
Operating and maintenance expenses increased primarily due to new expenses associated with operations acquired in our acquisition of ACMP, increased growth of operating activity in certain areas, increased maintenance and repair expenses, and the return to operations of the Geismar plant. These increases are partially offset by a decrease in Canadian construction management expenses that reflect a shift to internal customer construction projects.
Depreciation and amortization expenses increased primarily due to new expenses associated with operations acquired in our acquisition of ACMP and from depreciation on new projects placed in service, including Gulfstar One and the Geismar expansion.
SG&A increased primarily due to administrative expenses associated with operations acquired in our acquisition of ACMP, including $31 million higher ACMP merger and transition-related costs, partially offset by the absence of $16 million of acquisition costs incurred in 2014. In addition, 2015 includes $32 million of costs associated with our evaluation of strategic alternatives. These increases are partially offset by the absence of $18 million of project development costs incurred in 2014 related to the Bluegrass Pipeline reflecting 100 percent of such costs. The 50 percent noncontrolling interest share of these costs are presented in Net income (loss) attributable to noncontrolling interests.
Impairment of goodwill reflects a 2015 impairment chargecertain assetsincludes 2018 impairments on certain assets in the Barnett Shale region and certain idle pipelines and 2017 impairments associated with certain goodwill. (Seeassets in the Mid-Continent, Marcellus South, and Houston Ship Channel areas (see Note 1718 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)Statements).
ImpairmentGain on sale of certain assets relate primarily to 2015 impairments and businesses includes gains recognized on the sales of previously capitalized development costsour Four Corners area in October 2018, our Gulf Coast pipeline systems in December 2018 and surplus equipment write-downs. (Seeour Geismar Interest in July 2017 (see Note 173 – Fair Value Measurements, Guarantees,Acquisitions and Concentration of Credit RiskDivestitures of Notes to Consolidated Financial Statements.)Statements).
Net insurance recoveries – Geismar Incident changed unfavorably primarily dueRegulatory charges resulting from Tax Reform relates to the receipt2017 establishment of $126 millionregulatory liabilities for the probable return to customers through future rates of insurance recoveriesthe future decrease in 2015 as comparedincome 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 the receipt of $246 million of insurance recoveriesConsolidated Financial Statements).
The favorable change in 2014.
Other (income) expense – netwithin Operating income (loss) changedunfavorably primarily due to 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 $154 million of cash proceeds receivedgains from certain contract settlements and terminations in 2014 related to a contingency settlement gain and2017, the absence of a $12 million net gain recognizedon the sale of our RGP Splitter in 2014 related to2017, and 2018 charges establishing a partial acreage dedication release. (Seeregulatory 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.)Statements).
Operating income (loss) changed unfavorably primarily due to a 2015 impairment of goodwill, higher impairments of certain assets, higher depreciation, operating,lower gains on sales of assets and maintenance expenses related to construction projects placed in servicebusinesses, and the start-upabsence of the Geismar plant, $229 million lower NGL margins driven by lower prices, lower insurance recoveries related to the Geismar Incident, higher costs related to the mergeroperating income associated with our former olefins and integration of ACMP into WPZ, and 2015 strategic alternative expenses. These decreases wereFour Corners area operations, partially offset by increased servicethe absence of regulatory charges resulting from Tax Reform, higher Service revenues related to construction primarily from expansion projects, placedand higher NGL margins.
The unfavorable change in service, $116 million higher olefin marginsEquity earnings (losses) is primarily due to our Geismar plant that returned to operationsa decrease in 2015, and contributions from the operations acquired in our acquisition of ACMP.
Equity earnings (losses) changed favorably primarily due to the absence of equity losses from Bluegrass Pipeline and Moss Lake in 2014 and due to contributions from investments acquired in our acquisition of ACMP. In addition, equity earningsvolumes at Discovery, increased $76 million primarily related to the completion of the Keathley Canyon Connector in early 2015. These changes were partially offset by $33 millionimproved results at our Appalachia Midstream Investments and the deconsolidation of losses associated with our shareJackalope interest, which is accounted for as an equity-method investment beginning in the second quarter of impairments recognized at equity investees2018.
Other investing income (loss) – net includes a 2017 gain on disposition of our investments in 2015.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.)
GainInterest 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 remeasurementour 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 equity-method investment reflects the 2014a net gain recognized ason early retirement of debt in 2017 and a resultloss on early retirement of remeasuring to fair value the equity-method investment that we held before we acquired a controlling interestdebt in ACMP.2018. (See Note 27 – Acquisitions Other Income and Expensesof Notes to Consolidated Financial Statements.)
Impairment of equity-method investments reflects 2015 impairment charges associated with certain equity-method investments. (See Note 6 – Investing Activitiesof Notes to Consolidated Financial Statements.)
Other investingProvision (benefit) for income (loss) – net taxeschanged unfavorably primarily due to lower interest income associated with a receivable related to the sale of certain former Venezuela assets.
Interest expense increased due to a $230 million increase in Interest incurred primarily due to new debt issuances in 2014 and 2015 and interest expense associated with debt assumed in conjunction with our acquisition of ACMP. This increase was partially offset by lower interest due to 2015 debt retirements and the absence of a $9 million transaction-related financing fee incurred in the second quarter of 2014 related to our acquisition of ACMP. In addition, Interest capitalized decreased $67 million primarily related to construction projects that have been placed into service. (See Note 2 – Acquisitions and Note 14 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)
Other income (expense) – net below Operating income(loss) changed favorably primarily due to a $43 million$1.923 billion tax provision benefit related to an increase in AFUDC associated with an increaseTax Reform and releasing a $127 million valuation allowance in spending on various Transco expansion projects and Constitution,2017. The unfavorable change also reflects a $14$105 million gain on early debt retirementvaluation allowance in April 2015, and a $9 million contingency gain settlement.
Provision (benefit) for income taxes changed favorably primarily due to lower pretax income in 2015.2018 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 ratesrate compared to the federal statutory rate for both years.periods.
The favorableunfavorable change in Net income (loss) attributable to noncontrolling interests is primarily related to WPZ, reflective of both our investmentacquisition of the publicly held interests in WPZ is primarily due toassociated with the WPZ Merger and a fourth quarter 2017 net loss incurred by WPZ, partially offset by lower operating results at WPZ, our increased percentage of limited partner ownership of WPZ, and the impact of increased income allocated to the WPZ general partner, held by us, associated with IDRs. These changes are partially offset by an unfavorable change related to our investment in Gulfstar One associated with its start up in 2014.Gulfstar.
Year-Over-Year Operating Results – Segments
We evaluate segment operating performance based upon Modified EBITDA. Note 1920 – 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.
Atlantic-Gulf
| | | | Years Ended December 31, | Year Ended December 31, |
| | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 |
| | (Millions) | (Millions) |
| Service revenues | $ | 5,173 |
| | $ | 5,135 |
| | $ | 3,888 |
| $ | 2,861 |
| | $ | 2,509 |
| | $ | 2,239 |
|
| Service revenues – commodity consideration | | 41 |
| | 59 |
| | — |
|
| Product sales | 2,318 |
| | 2,196 |
| | 3,521 |
| 288 |
| | 435 |
| | 484 |
|
| Segment revenues | 7,491 |
| | 7,331 |
| | 7,409 |
| 3,190 |
| | 3,003 |
| | 2,723 |
|
| | | | | | | | | | | |
| Product costs | (1,728 | ) | | (1,779 | ) | | (3,016 | ) | (288 | ) | | (438 | ) | | (437 | ) |
| Processing commodity expenses | | (16 | ) | | (16 | ) | | — |
|
| Other segment costs and expenses | (2,203 | ) | | (2,229 | ) | | (1,760 | ) | (814 | ) | | (799 | ) | | (819 | ) |
| Net insurance recoveries – Geismar Incident | 7 |
| | 126 |
| | 232 |
| |
| Impairment of certain assets | (457 | ) | | (145 | ) | | (52 | ) | (354 | ) | | — |
| | — |
|
| Gain on sale of certain assets and businesses | | — |
| | 81 |
| | — |
|
| Regulatory charges resulting from Tax Reform | | — |
| | 9 |
| | (493 | ) |
| Proportional Modified EBITDA of equity-method investments | 754 |
| | 699 |
| | 431 |
| 177 |
| | 183 |
| | 264 |
|
| Williams Partners Modified EBITDA | $ | 3,864 |
| | $ | 4,003 |
| | $ | 3,244 |
| |
| Atlantic-Gulf Modified EBITDA | | $ | 1,895 |
| | $ | 2,023 |
| | $ | 1,238 |
|
| | | | | | | | | | | |
| NGL margin | $ | 169 |
| | $ | 159 |
| | $ | 388 |
| |
| Olefin margin | 337 |
| | 226 |
| | 110 |
| |
| Commodity margins | | $ | 25 |
| | $ | 40 |
| | $ | 47 |
|
2019 vs. 2018
2016 vs. 2015
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 impairments, lower insurance recoveriesOther 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 Geismar Incident, sale of certain Gulf Coast pipeline assets in fourth-quarter 2018.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, and loss on sale Processing commodity expenses comprise our commodity margins. Our commodity margins associated with our Canadian operations.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 decreasesunfavorable changes were partially offset by higher olefin margins related$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 Geismar plant operatingtiming of required engine overhauls and integrity testing.
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 production levels in 2016,Service revenues, and a 2018 gain on the sale of certain assets;partially offset by lower segment costs and expenses, and higher earnings related to ourProportional Modified EBITDA of equity-method investments including the completion of the Keathley Canyon Connector at Discovery in the first quarter of 2015. Additionally, higher marketing margins, higher service revenues related to projects placed in service, and higher NGL margins improved Modified EBITDA..
The increase in Service revenuesis increased primarily due to a $79$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 service in 20152017 and 2016 and a $31 million transportation and fractionation revenue increase associated with Williams NGL & Petchem’s Horizon liquids extraction plant in Canada. The Canadian operations were sold in late September 2016. These increases were partially offset by a decrease in gathering, processing, and fractionation revenue primarily due to lower volumes primarily in the Barnett Shale and Anadarko basin and a $15 million decrease in Transco’s storage revenue related to potential refunds associated with a ruling received in certain rate case litigation in 2016.2018.
Product sales Service revenues – commodity considerationincreased primarily due to:
A $94 million increase in olefin sales comprised of a $170 million increase from our Geismar plant that returned to service in late March 2015, partially offset by a $76 million decrease from our other olefin operations. The increase at Geismar includes $153 million associated with increased volumes as a result of implementing ASC 606 using a modified retrospective approach. These revenues represent consideration we received in the plant operating at higher production levelsform 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 2016 than when production resumed in March 2015 following the Geismar Incident and $17 million primarily associated with higher ethylene per-unit sales prices. Product costs below.
The decrease in other olefinProduct sales includes 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 reduction due todecrease in sales associated with the absenceproduction of our former Canadian operations in the fourth quarterequity NGLs, as further described below as part of 2016, as well as lower volumes and lower per-unit sales prices within our other olefin operations;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. |
A $70 million increase in marketing revenuesProduct costs slightly increased primarily due to higher NGL and propylene prices and natural gas and crude oil volumes, partially offset by lower NGL volumes and crude oil prices (partially offset in marketing purchases);
A $6a $59 million increase in revenues from our equity NGLs due to a $10 million increase associated with higher volumes, partially offset by a $4 million decrease associated with lower NGL prices;
A $39 million decrease in system management gas sales from Transco. System management gas sales arepurchases (substantially offset in Product sales) and the impact of ASC 606 in which costs and, therefore, have no impact on Modified EBITDA.
The decreasereflected in Product costs includes:
A $39this 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 system management gas costs (offsetmarketing purchases (more than offset in Product sales);
A $17 million decrease in olefin feedstock purchases is primarily comprised of $78 million in lower purchases at our other olefins operations, partially offset by $61 million of higher purchases due primarily to increased volumes at our Geismar plant resulting from higher productions levels. The lower costs at our other olefin operations are comprised of $54 million in lower per-unit feedstock costs and $24 million in primarily lower propylene volumes;
A $4 million decrease inthe absence of natural gas purchases associated with the production of equity NGLs, reflecting a decreasewhich are now reported in Processing commodity expenses in conjunction with the implementation of $13 millionASC 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 lower natural gas prices,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.
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 | $ | 1,338 |
| | $ | 976 |
| | $ | 872 |
|
| Service revenues – commodity consideration | 12 |
| | 20 |
| | — |
|
| Product sales | 150 |
| | 287 |
| | 291 |
|
| Segment revenues | 1,500 |
| | 1,283 |
| | 1,163 |
|
| | | | | | |
| Product costs | (152 | ) | | (289 | ) | | (286 | ) |
| Processing commodity expenses | (8 | ) | | (9 | ) | | — |
|
| Other segment costs and expenses | (470 | ) | | (392 | ) | | (386 | ) |
| Impairment of certain assets | (10 | ) | | — |
| | (124 | ) |
| Proportional Modified EBITDA of equity-method investments | 454 |
| | 493 |
| | 452 |
|
| Northeast G&P Modified EBITDA | $ | 1,314 |
| | $ | 1,086 |
| | $ | 819 |
|
| | | | | | |
| Commodity margins | $ | 2 |
| | $ | 9 |
| | $ | 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 a $92019 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 volumes;
Lower costs associated with various other products, primarily condensate;
gathering revenues at Susquehanna Supply Hub reflecting 18 percent higher gathering volumes due to increased production from customers and higher rates;
A $22$49 million increase at Ohio Valley Midstream primarily due to higher gathering, processing, and transportation volumes;
A $36 million increase in marketing purchasesgathering 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 the same factors that increasedlower non-ethane volumes and prices within our marketing sales (more than offsetactivities. The changes in marketing revenues). The increaserevenues are offset by similar changes in marketing purchases, reflected above as Product costs does not reflect the intercompany costs associated with certain gathering and processing services performed by an affiliate..
The decrease in
Other segment costs and expenses is increased primarily due to lower operating costs and general and administrative expenses reflecting decreases in primarily labor-related and outside services costs resulting from our first-quarter 2016 workforce reductions and ongoing cost containment efforts and lower coststo:
A $53 million increase associated with general maintenance activities in the Marcellus Shale, as well as $43 millionconsolidation of lower ACMP Merger and transition-related expenses. Other items partially offsetting these decreases are as follows:UEOM;
$34A $10 million increase related to transaction expenses associated with the 2016 loss on saleacquisition of our Canadian operations;UEOM and the formation of the Northeast JV;
$37A $7 million increasecharge in 2019 for severance and related costs primarily associated with workforce reductions incurred in the first quarter of 2016 and the organizational realignment in the fourth quarter of 2016;our VSP.
$28 million higher project development costs at Constitution as we discontinued capitalization of development costs related to this project beginning in April 2016;
$22 million higher contract services for pipeline testing and general maintenance at Transco;
$20 million unfavorable change in foreign currency exchange that primarily relates to losses incurred on foreign currency transactions and the remeasurement of the U.S. dollar-denominated current assets and liabilities within our former Canadian operations;
$19 million unfavorable change in AFUDC associated with a decrease in spending on Constitution;
The absence of a $14 million gain recognized in second-quarter 2015 resulting from the early retirement of certain debt.
Net insurance recoveries – Geismar Incident decreased reflecting $7 million of insurance proceeds received in 2016 compared to $126 million received in 2015.
Impairment of certain assets increased primarily due to 2016 impairments of $341a $10 million associated with our Canadian operations and $63 million associated with certain Mid-Continent gathering assets as well as impairments or write-downswrite-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 2015 impairmentsImpairment of $94certain 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.
West
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (Millions) |
| Service revenues | $ | 1,813 |
| | $ | 2,085 |
| | $ | 2,246 |
|
Service revenues – commodity consideration | 150 |
| | 321 |
| | — |
|
| Product sales | 1,797 |
| | 2,448 |
| | 2,013 |
|
| Segment revenues | 3,760 |
| | 4,854 |
| | 4,259 |
|
| | | | | | |
| Product costs | (1,774 | ) | | (2,448 | ) | | (1,842 | ) |
| Processing commodity expenses | (79 | ) | | (116 | ) | | — |
|
| Other segment costs and expenses | (688 | ) | | (825 | ) | | (832 | ) |
| Impairment of certain assets | (100 | ) | | (1,849 | ) | | (1,032 | ) |
| Gain on sale of certain assets and businesses | (2 | ) | | 591 |
| | — |
|
| Regulatory charges resulting from Tax Reform | — |
| | 7 |
| | (220 | ) |
| Proportional Modified EBITDA of equity-method investments | 115 |
| | 94 |
| | 79 |
|
| West Modified EBITDA | $ | 1,232 |
| | $ | 308 |
| | $ | 412 |
|
| | | | | | |
| Commodity margins | $ | 94 |
| | $ | 205 |
| | $ | 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 previously capitalized project developmentasset 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.
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 gas processing plant and $20 millionregulatory 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 surplus equipment within our Ohio Valley Midstream business. (Seeassets decreased primarily due to the absence of the $1,849 million Barnett impairment in 2018, partially offset by various 2019 impairments (see Note 1718 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)Statements).
The increasedecrease 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 is primarily due to a $30 million increase from Discovery primarily associated with higher fee revenues attributable to the completion of the Keathley Canyon Connector in the first quarter of 2015. Additionally, Caiman II contributed a $20 million increase resulting from higher volumes due to assets placed into service in 2015, OPPL contributed a $16 million increase primarily due to higher transportation volumes and lower expenses, and UEOM contributed an $11 million increase primarily associated with an increase in our ownership percentage. These increases were partially offset by an $29 million decrease from Appalachia Midstream Investments primarily due to lower fee revenues driven by lower rates, partially offset by lower impairments and higher volumes.
2015 vs. 2014
Modified EBITDA increased primarily due to the acquisitionadditions of ACMP during the third quarterRMM and Brazos Permian II equity-method investments in the second half of 20142018, 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 increased feelower 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 contributions from new and expanded facilities, including Gulfstar One duringthe up-front cash payments received in conjunction with the fourth quarter of 2014, in addition to resuming our Geismar operations2016 Barnett Shale and contributionsMid-Continent contract restructurings, partially offset by a $54 million increase related to other deferred revenue amortization primarily in the completion of the Keathley Canyon Connector at Discovery. Partially offsetting these increases to Modified EBITDA is a decrease inPermian basin;
NGL marginsA $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 significant declinerate case settlement that became effective January 1, 2018;
A $29 million decrease following the Jackalope deconsolidation in commodity prices beginningsecond-quarter 2018;
A $15 million decrease driven by lower gathering volumes primarily in the fourth quarter of 2014Eagle Ford Shale, Barnett Shale, and lower insurance recoveries related to the Geismar Incident.
The increase in Service revenues is primarily due to $810 million additional revenues associated with a full year of ACMP operations in 2015 which includes a $72 million increase in the minimum volume commitment fees, $223 million in increased revenues associated with the start-up of operations at Gulfstar One during the fourth quarter of 2014, and a $155 million increase in Transco’s natural gas transportation fees due to new projects placed in service in 2015 and 2014. Additionally, service revenues reflect higher fees associated with increased volumes and additional contributions in the Northeast. Higher revenues in the Northeast include expanded gathering operations and processing, fractionation and transportation operations, contributing $59 million and $27 million of additional fees, respectively.
The decrease in Product sales includes:
A $1,173 million decrease in marketing revenues primarily associated with lower prices across all products,Mid-Continent regions, partially offset by higher non-ethane volumes (more than offset in marketing purchases);the Niobrara (prior to the Jackalope deconsolidation), Piceance, and Permian regions;
A $324 million decrease in revenues from our equity NGLs reflecting a decrease of $365 million due to lower NGL prices, partially offset by a $41$21 million increase associated with higher gathering and processing rates in the Piceance region driven by higher NGL volumes;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 $41 million decrease in revenues primarily due to lower condensate prices;
A $214$47 million increase in olefin sales primarily due to $298associated 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 highermarketing purchases (substantially offset in Product sales from our Geismar plant that returned to operation,), a $19 million increase in system management gas purchases (substantially offset in Product sales), partially offset by an $84 million decrease from our other olefin operations due to lower sales prices, partially offset by higher volumes across all products, particularly propylene.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.
The decrease in Product costs includes:
A $1,219 million decrease in marketing purchases primarily due to a decrease in non-ethane per-unit cost (substantially offset in marketing revenues);
A $95 million decrease inProcessing commodity expenses presents the natural gas purchases associated with the production of equity NGLs reflecting a decreaseas previously described in conjunction with the implementation of $126 millionASC 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 natural gas prices,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 $31$24 million increaseregulatory charge associated with higher volumes;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
A $20
million charge for a regulatory liability associated with a decrease in costsNorthwest Pipeline’s estimated deferred state income tax rate following the WPZ Merger.
Impairment of certain assets increased primarily due to lower gas prices;
A $98 million increasethe $1.849 billion impairment of certain assets in olefin feedstock purchases is comprised of $127 millionthe Barnett Shale region in higher purchases due to increased volumes at our Geismar plant as it returned to operation,2018, partially offset by $29 millionthe absence of a $1.019 billion impairment of certain gathering operations in lower other olefin operations feedstock purchasesthe 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 lower per-unit feedstock costs, partially offset by higher volumes across most products, particularly propylene.
The increase in Other segment costs and expenses includes:
An increase for new expenses associated with operationsthe absence of the $220 million initial regulatory charge associated with the acquisitionimpact of ACMP;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
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (Millions) |
| Other Modified EBITDA | $ | 6 |
| | $ | (29 | ) | | $ | 997 |
|
2019 vs. 2018
Other Modified EBITDA increased primarily due to:
The absence of $154the $66 million impairment of cash receivedcertain idle pipelines in the fourthsecond quarter of 20142018 (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 resolutionWPZ 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 contingent gain$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 claims arising from the purchasedeferred taxes on equity funds used during construction;
The absence of a business$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 prior period$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 $16$26 million increasedecrease in operating expense dueincome associated with a regulatory asset related to deferred taxes on equity funds used during construction;
$20 million in costs in 2018 associated with the Geismar plant returning to operation in 2015;WPZ Merger, as previously mentioned;
The absence of a $12 million net gain recognizedon the sale of the Refinery Grade Propylene Splitter in 2014 related2017 (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements).
These decreases were partially offset by:
The absence of a partial acreage dedication release.
The decrease$68 million impairment for a certain NGL pipeline asset in Net insurance recoveries – Geismar Incident is primarily due to the 2015 receiptthird quarter of $1262017 and a$23 million impairment of insurance proceeds compared to $246 million receivedan olefins pipeline project in 2014,the Gulf Coast region in the second quarter of 2017, partially offset by the absence of covered insurable
expenses in excess of our retentions (deductibles) related to the Geismar Incident in 2015 compared to $14a $66 million in 2014.
Impairmentimpairment of certain assets increased primarily due to a 2015 $94 million impairment charge associated with previously capitalized project development costs for a gas processing plant. (Seeidle pipelines in the second quarter of 2018 (see Note 1718 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)Statements);
The increase in Proportional Modified EBITDA of equity-method investments is primarily dueA $62 million favorable change for lower charges to a full year contribution of $160 million from investments associated with the acquisition of ACMP and a $103 million increase from Discovery associated with higher fee revenues attributablereduce regulatory assets related to the completion of the Keathley Canyon Connector in the first quarter of 2015. Additionally, Caiman II increased $21 milliondeferred taxes on AFUDC resulting from assets placed into service in 2014Tax Reform (see Note 7 – Other Income and 2015, partially offset by the absence of business interruption insurance proceeds received in the prior year, and an $11 million decrease at Laurel Mountain. The decrease at Laurel Mountain was primarily due to $13 million of impairments and lower gathering fees due to lower gathering rates indexed to natural gas prices, partially offset by 24 percent higher volumes and an increase in our ownership percentage compared to the prior year.
Williams NGL & Petchem Services
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (Millions) |
| Service revenues | $ | 2 |
| | $ | 2 |
| | $ | — |
|
| Product sales | 26 |
| | — |
| | — |
|
| Segment revenues | 28 |
| | 2 |
| | — |
|
| | | | | | |
| Product costs | (13 | ) | | — |
| | — |
|
| Other segment costs and expenses | (139 | ) | | (85 | ) | | (37 | ) |
| Impairment of certain assets | (416 | ) | | — |
| | — |
|
| Proportional Modified EBITDA of equity-method investments | — |
| | — |
| | (78 | ) |
| Williams NGL & Petchem Services Modified EBITDA | $ | (540 | ) | | $ | (83 | ) | | $ | (115 | ) |
2016 vs. 2015
The unfavorable change in Modified EBITDA is primarily due to the 2016 impairment and subsequent loss on disposal of our Canadian operations as well as the expensing of certain development costs associated with the Canadian PDH facility, partially offset by the absence of the 2015 write-off of previously capitalized project development costs for an olefins pipeline project.
The increase in Product sales and Product costs is primarily due to the Horizon liquids extraction plant coming online in March 2016 until it was sold in September 2016.
The unfavorable change in Other segment costs and expenses is primarily due to $61 million of certain project development costs associated with the Canadian PDH facility that we began expensing in 2016. Additionally, the unfavorable change includes $33 million of transportation and fractionation fees associated with our new Horizon volumes and a $32 million loss on the sale of our Canadian operations in September 2016. (See Note 3 – DivestitureExpenses of Notes to Consolidated Financial Statements.) The unfavorableStatements);
$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 Other segment costs and expenses is partially offset by a $10the 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 unused pipecertain assets and operations located in 2016 and the absence of the $64 million write-off ofGulf Coast area, as previously capitalized project development costs for an olefins pipeline project in 2015. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)mentioned.
The unfavorable change in Impairment of certain assets primarily reflects the 2016 impairment of our Canadian operations and an $8 million impairment of idle pipe. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)
.
2015 vs. 2014
The favorable change in Modified EBITDA is primarily due to the absence of our share of the 2014 write-off of previously capitalized project development costs at Bluegrass Pipeline and Moss Lake, as well as costs incurred in 2014 relating to the development of the Bluegrass Pipeline, partially offset by the 2015 write-off of previously capitalized project development costs for an olefins pipeline project.
Other segment costs and expenses increased primarily due to the $64 million write-off of previously capitalized project development costs for an olefins pipeline project in 2015, partially offset by the absence of $18 million of project development costs incurred in 2014 relating to the Bluegrass Pipeline.
The favorable change in Proportional Modified EBITDA of equity-method investments is primarily due to the absence of our share of the 2014 write-off of previously capitalized project development costs at Bluegrass Pipeline and Moss Lake.
Other
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (Millions) |
| Other Modified EBITDA | $ | (2 | ) | | $ | (29 | ) | | $ | 103 |
|
2016 vs. 2015
Modified EBITDA improved primarily due to a $31 million decrease in ACMP merger and transition related costs, as well as the impact of various other individually insignificant items, partially offset by a $17 million increase in costs related to our evaluation of strategic alternatives.
2015 vs. 2014
Modified EBITDA decreased significantly as the results from the businesses acquired with our acquisition of ACMP are presented within Williams Partners for periods subsequent to the July 1, 2014, acquisition. Other included the proportional Modified EBITDA of $104 million of our former equity-method investment in ACMP for the first half of 2014, which was partially offset by $19 million associated with our share of compensation costs triggered by the ACMP Acquisition recognized in July 2014. Modified EBITDA also decreased by $30 million related to costs incurred in 2015 related to evaluating our strategic alternatives and the Merger Agreement with Energy Transfer, as well as $24 million of higher costs associated with integration and re-alignment of resources following the ACMP acquisition and merger. These decreases are partially offset by a $9 million contingency gain settlement recognized in fourth quarter 2015.
Management’s Discussion and Analysis of Financial Condition and Liquidity
Overview
In 2016,As previously discussed, we have continued to focus uponon 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 businesses through disciplined investment and reducing our costs and funding needs. Examples of this activity included:
Expansion of WPZ’s interstate natural gas pipeline system through projects such as Rock Springs to meet the demand of growth markets;
Completion of WPZ’s Gulfstar One expansion project to provide production handling and gathering services for the Gunflint oil and gas discoveryOhio Valley Midstream business. Our partner purchased a 35 percent ownership interest in the eastern deepwater Gulfpartnership for $1.3 billion. Also, during the second quarter of Mexico;
WPZ’s restructuring2019 we sold our 50 percent ownership interest in Jackalope for $485 million. See also the following table of contracts in the Barnett Shale and Mid-Continent region,which included cash payments to WPZSources (Uses) of $820 million;
Sale of our Canadian operations (see Note 3 – Divestiture of Notes to Consolidated Financial Statements)Cash.
Outlook
Fee-based businesses are becoming an even more significant component of our portfolio and serve to reduce the influence of commodity price fluctuations on our cash flows. We expect to benefit as continued growth in demand for low-cost natural gas is driven by increases in LNG exports, industrial demand, and power generation.
We believe we have, or have access to, the financial resources and liquidity necessary to meet our requirements for working capital, capital and investment expenditures, dividends and distributions, debt service payments, and tax payments, while maintaining a sufficient level of liquidity. In particular, asAs previously discussed in Company Outlook, our expected growth capital and investment expenditures total approximately $2.1in 2020 are currently expected to be in a range from $1.1 billion to $2.8 billion$1.3 billion. Growth capital spending in 2017. Approximately $1.4 billion to $1.9 billion of our growth capital funding needs include2020 includes Transco expansions, and other interstate pipeline growth projects, mostall of which are fully contracted with firm transportation agreements. The remaining growth capital spending in 2017 primarily reflects investment in gatheringagreements, and processing systemsour Bluestem NGL pipeline project in the Northeast region limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project.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.
In January 2017, WPZ announced that it will redeem allAs of its $750 million 6.125 percent senior notes due 2022 on February 23, 2017. In addition,December 31, 2019, we expect after-taxhave $2.121 billion of long-term debt maturing in 2020. Our potential sources of liquidity available to address these maturities include proceeds in excess of $2 billion from plannedrefinancing at attractive long-term rates or from our credit facility, as well as proceeds from asset monetizations of Geismar and other select assets during 2017, which we expect Williams Partners to use for additional debt reduction and to fund capital and investment expenditures.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 2017.2020. Our potential material internal and external sources of consolidated liquidity to fund working capital requirements, capital and investment expenditures, debt service payments, dividends and distributions, and tax payments include:
Cash and cash equivalents on hand;
Cash generated from operations;
Distributions from WPZ;
Distributions from our equity-method investees based on our level of ownership;
Use of our credit facility;
Cash proceeds from issuances of debt and/or equity securities.
WPZ is expected to fund its cash needs through its cash flows from operations and its credit facility and/or commercial paper program, as well as proceeds from planned asset monetizations as previously mentioned. WPZ also established a distribution reinvestment program (DRIP) in the third quarter of 2016.
We previously announced that we intended to reinvest approximately $1.2 billion into WPZ in 2017 via the DRIP, funded primarily by our reduced quarterly cash dividend which would have allowed us to annually retain approximately $1.3 billion for reinvestment. As part of the Financial Repositioning announced in January 2017, we discontinued our participation in the DRIP and expect to increase our regular quarterly cash dividend to $0.30 for the dividend to be paid in March 2017. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements.)
We anticipate our more significant uses of cash to be:liquidity are as follows:
Working capital requirements;Maintenance and expansion capital and investment expenditures; |
| |
| |
| |
| Sources: | |
| 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 |
| |
| Uses: | |
| 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 |
Interest on our long-term debt;
Repayment of current debt maturities, and additional reductions in WPZ’s debt with funds received as part of the Financial Repositioning;
Investment in WPZ as part of the Financial Repositioning (see Note 15 – Stockholders' Equity of Notes to Consolidated Financial Statements);
Quarterly dividends to our shareholders.
Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook.
As of December 31, 2016,2019, we had a working capital deficit (current liabilities, inclusive of $785 million in Long-term$2.388 billion, including cash and cash equivalents and long-term debt due within one year, in excess of current assets) of $1.487 billion.year. Our available liquidity is as follows:
| | | | | December 31, 2016 | | | |
| Available Liquidity | | WPZ | | WMB | | Total | | December 31, 2019 |
| | | (Millions) | | (Millions) |
| Cash and cash equivalents | | $ | 145 |
| | $ | 25 |
| | $ | 170 |
| | $ | 289 |
|
| Capacity available under our $1.5 billion credit facility (1) | | | | 725 |
| | 725 |
| |
| Capacity available to WPZ under its $3.5 billion credit facility, less amounts outstanding under its $3 billion commercial paper program (2) | | 3,407 |
| | | | 3,407 |
| |
| Capacity available under our $4.5 billion credit facility, less amounts outstanding under our $4 billion commercial paper program (1) | | | 4,500 |
|
| | | $ | 3,552 |
| | $ | 750 |
| | $ | 4,302 |
| | $ | 4,789 |
|
__________
| |
| (1) | The highest amount outstanding under our credit facility during 2016 was $1.224 billion. At December 31, 2016, we were in compliance with the financial covenants associated with this credit facility. See Note 14 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements for additional information on our credit facility. Borrowing capacity available under this facility as of February 20, 2017, was $1.265 billion. |
| |
(2) | In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of WPZ’sour credit facility inclusive of any outstanding amounts under itsour commercial paper program. WPZ has $93 millionWe had no commercial paper outstanding as ofCommercial paper outstanding at December 31, 2016.2019. The highest amount outstanding under WPZ’s 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
commercial paper program and credit facility during 2016 was $2.326 billion. At December 31, 2016, WPZ wasWe 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 compliance with the financial covenants associated with this credit facility. See Note 14 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements for additional information on WPZ’s credit facility and WPZ’s commercial paper program. Borrowing capacity available under WPZ’s $3.5 billion credit facility as of February 20, 2017, was $3.5 billion.
As described in Note 14 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements, we have determined that we have net assets that are technically considered restricted in accordance with Rule 4-08(e) of Regulation S-X of the Securities and Exchange Commission in excess of 25 percent of our consolidated net assets. We do not expect this determination will impact our ability to pay dividends or meet future obligations as the terms of WPZ’s partnership agreement require it to make quarterly distributions of all available cash, as defined, to its unitholders.
WPZ Incentive Distribution Rights
As part of the Financial Repositioning, we permanently waived our right to incentive distributions from WPZ. (See Overview in Management’s Discussion and Analysis of Financial Condition and Results of Operations.)
Through December 31, 2016, our ownership interest in WPZ included the right to incentive distributions determined in accordance with WPZ’s partnership agreement. In connection with the sale of WPZ’s Canadian operations in the thirdeach quarter of 2016, we agreed2018, to waive $150 million of incentive distributions otherwise payable by WPZ to us$0.38 per share for the quarterly cash dividends paid in the fourtheach quarter of 2016. (See Note 3 – Divestiture of Notes to Consolidated Financial Statements.)
We had agreed to temporarily waive incentive distributions of approximately $2 million per quarter in connection with WPZ’s acquisition of an approximate 13 percent additional interest in UEOM on June 10, 2015. The waiver would have continued through the quarter ending September 30, 2017.
We were required to pay a $428 million termination fee to WPZ, associated with the Termination Agreement (as described in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements), which settled through a reduction of quarterly incentive distributions we are entitled to receive from WPZ (such reduction not to exceed $209 million per quarter). The November 2015, February 2016, and May 2016 distributions from WPZ were reduced by $209 million, $209 million, and $10 million, respectively, related to this termination fee.2019.
Registrations
In September 2016, WPZ filed a registration statement for its new DRIP discussed above. In November 2016, WPZ received reinvested distributions of $260 million, of which $250 million related to us.
In May 2015,February 2018, we filed a shelf registration statement as a well-known seasoned issuer.
In February 2015, WPZAugust 2018, we filed a shelf registration statement, as a well-known seasoned issuer, and WPZ also filed a shelf registration statementprospectus supplement for the offer and sale from time to time of shares of our common units representing limited partner interests in WPZstock having an aggregate offering price of up to $1 billion. These sales are to be made over a period of time and from time to time in transactions at prices which are market prices prevailing at the time of sale, prices related to market price, or at negotiatedthen-current prices. Such sales are to be made pursuant to an equity distribution agreement between WPZus and certain banksentities who may act as sales agents or purchase for their own accounts as principals. During 2016 and 2015, WPZ received net proceedsprincipals at a price agreed upon at the time of approximately $115 million and approximately $59 million, respectively, from equity issued under this registration.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. (SeeSee Note 6 – Investing Activities of Notes to Consolidated Financial Statements for our more significant equity-method investees.)
Credit Ratings
Our abilityThe interest rates at which we are able to borrow money isare impacted by our credit ratings and the credit ratings of WPZ.ratings. The current ratings are as follows:
|
| | | | | | | |
| Rating Agency | | Outlook | | Senior Unsecured Debt Rating | | Corporate
Credit Rating
|
| | | | | | | |
WMB: | S&P Global Ratings | | Stable | | BB | | BBBBB |
| Moody’s Investors Service | | Stable | | Ba2 | | N/A |
| Fitch Ratings | | Stable | | BB+ | | N/A |
| | | | | | | |
WPZ: | S&P Global Ratings | | Stable | | BBB- | | BBB- |
| Moody’s Investors Service | | Stable | | Baa3 | | N/A |
| Fitch Ratings | | StableRating Watch Positive | | BBB- | | N/A |
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
Considering
for investment-grade ratios. A downgrade of our credit ratings asmight increase our future cost of December 31, 2016, we estimate that we could be requiredborrowing and would require us to provide up to $36 million in additional collateral of either cash or letters of credit with third parties under existing contracts. At the present time, we have not provided any additional collateral to third parties, but no assurance can be given that we will not be requested to provide collateral in the future. As of December 31, 2016, we estimate that a downgrade to a rating below investment-grade for WPZ could require it to provide up to $376 million in additional collateral of either cash or letters of credit with third parties under existing contracts.
negatively impacting our available liquidity.
Sources (Uses) of Cash
The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented (see Notes to Consolidated Financial Statements for the Notes referenced in the table):
|
| | | | | | | | | | | | | |
| | Cash Flow | | Years Ended December 31, |
| | Category | | 2016 | | 2015 | | 2014 |
| | | | (Millions) |
| Sources of cash and cash equivalents: | | | | | | | |
| Operating activities - net | Operating | | $ | 3,664 |
| | $ | 2,678 |
| | $ | 2,115 |
|
| Proceeds from WPZ’s credit-facility borrowings | Financing | | 3,250 |
| | 3,832 |
| | 1,646 |
|
| Proceeds from our credit-facility borrowings | Financing | | 2,280 |
| | 2,097 |
| | 1,040 |
|
| Proceeds from sale of Canadian operations (see Note 3) | Investing | | 1,020 |
| | — |
| | — |
|
| Proceeds from WPZ’s debt offerings (see Note 14) | Financing | | 998 |
| | 3,842 |
| | 2,740 |
|
| Distributions from unconsolidated affiliates in excess of cumulative earnings | Investing | | 472 |
| | 404 |
| | 206 |
|
| Proceeds from equity offerings | Financing | | 123 |
| | 86 |
| | 3,471 |
|
| Contributions from noncontrolling interests | Financing | | 29 |
| | 111 |
| | 340 |
|
| Special distribution from Gulfstream (see Note 6) | Financing | | — |
| | 396 |
| | — |
|
| Proceeds from our debt offerings | Financing | | — |
| | — |
| | 1,895 |
|
| Proceeds from WPZ’s commercial paper - net | Financing | | — |
| | — |
| | 572 |
|
| | | | | | | | |
| Uses of cash and cash equivalents: | | | | | | | |
| Payments on WPZ’s credit-facility borrowings | Financing | | (4,560 | ) | | (3,162 | ) | | (1,156 | ) |
| Payments on our credit-facility borrowings | Financing | | (2,155 | ) | | (1,817 | ) | | (670 | ) |
| Capital expenditures | Investing | | (2,051 | ) | | (3,167 | ) | | (4,031 | ) |
| Quarterly dividends on common stock | Financing | | (1,261 | ) | | (1,836 | ) | | (1,412 | ) |
| Dividends and distributions to noncontrolling interests | Financing | | (940 | ) | | (942 | ) | | (840 | ) |
| Payments of WPZ’s commercial paper - net | Financing | | (409 | ) | | (306 | ) | | — |
|
| Payments on WPZ’s debt retirements (see Note 14) | Financing | | (375 | ) | | (1,533 | ) | | — |
|
| Purchases of and contributions to equity-method investments | Investing | | (177 | ) | | (595 | ) | | (482 | ) |
| Contribution to Gulfstream for repayment of debt (see Note 6) | Financing | | (148 | ) | | (248 | ) | | — |
|
| Purchases of businesses, net of cash acquired | Investing | | — |
| | (112 | ) | | (5,958 | ) |
| | | | | | | | |
| Other sources / (uses) - net | Financing and Investing | | 310 |
| | 132 |
| | 83 |
|
| Increase (decrease) in cash and cash equivalents | | | $ | 70 |
| | $ | (140 | ) | | $ | (441 | ) |
|
| | | | | | | | | | | | | |
| | Cash Flow | | Year Ended December 31, |
| | Category | | 2019 | | 2018 | | 2017 |
| | | | (Millions) |
| Sources of cash and cash equivalents: | | | | | | | |
Operating activities – net | Operating | | $ | 3,693 |
| | $ | 3,293 |
| | $ | 3,089 |
|
| Proceeds from sale of partial interest in consolidated subsidiary (see Note 3) | Financing | | 1,334 |
| | — |
| | — |
|
| Proceeds from credit-facility borrowings | Financing | | 700 |
| | 1,840 |
| | 1,635 |
|
| Proceeds from dispositions of equity-method investments (see Note 6) | Investing | | 485 |
| | — |
| | 200 |
|
| Proceeds from long-term debt (see Note 15) | Financing | | 67 |
| | 2,086 |
| | 1,698 |
|
| Contributions in aid of construction | Investing | | 52 |
| | 411 |
| | 426 |
|
| Proceeds from issuance of common stock | Financing | | 10 |
| | 15 |
| | 2,131 |
|
| Proceeds from sale of businesses, net of cash divested (see Note 3) | Investing | | (2 | ) | | 1,296 |
| | 2,067 |
|
| | | | | | | | |
| Uses of cash and cash equivalents: | | | | | | | |
| Capital expenditures | Investing | | (2,109 | ) | | (3,256 | ) | | (2,399 | ) |
| Common dividends paid | Financing | | (1,842 | ) | | (1,386 | ) | | (992 | ) |
| Payments on credit-facility borrowings | Financing | | (860 | ) | | (1,950 | ) | | (2,140 | ) |
| Purchases of businesses, net of cash acquired (see Note 3) | Investing | | (728 | ) | | — |
| | — |
|
| Purchases of and contributions to equity-method investments (see Note 6) | Investing | | (453 | ) | | (1,132 | ) | | (132 | ) |
| Dividends and distributions paid to noncontrolling interests | Financing | | (124 | ) | | (591 | ) | | (822 | ) |
| Payments of long-term debt (see Note 15) | Financing | | (49 | ) | | (1,254 | ) | | (3,785 | ) |
Payments of commercial paper – net | Financing | | (4 | ) | | (2 | ) | | (93 | ) |
| | | | | | | | |
Other sources / (uses) – net | Financing and Investing | | (49 | ) | | (101 | ) | | (154 | ) |
| Increase (decrease) in cash and cash equivalents | | | $ | 121 |
| | $ | (731 | ) | | $ | 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, ImpairmentEquity (earnings) losses, Gain on disposition of goodwillequity-method investments, Impairment of equity-method investments, Impairment of and net (gain) loss(Gain) on sale of certain assets and businesses, Impairment of certain assets, (Gain) loss on deconsolidation of businesses, and Gain on remeasurement of equity-method investment.Regulatory charges resulting from Tax Reform.
OurNet cash provided (used) by operating activitiesin 20162019 increased from 20152018 primarily due to the impact of net favorable changes in operating working capital in 2019, including the collection of Transco’s filed rates subject to refund and receiptsthe 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 contract restructurings.unconsolidated affiliates in 2019.
OurNet cash provided (used) by operating activitiesin 20152018 increased from 20142017 primarily due to higher operating income (excluding noncash items as previously discussed) in 2018, partially offset by the impact of net favorable changesdecreased distributions from unconsolidated affiliates in operating working capital and the absence of contributions from ACMP for the first six months of 2014.
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 1112 – Property, Plant, and Equipment, Note 14 – Debt, Banking Arrangements, and Leases, Note 1718 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk, and Note 1819 – 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, 2016:2019:
| | | | 2017 | | 2018 - 2019 | | 2020 - 2021 | | Thereafter | | Total | 2020 | | 2021 - 2022 | | 2023 - 2024 | | Thereafter | | Total |
| | | | | | (Millions) | | | | | | | | | (Millions) | | | | |
| Long-term debt: (1)(2) | | | | | | | | | | |
| Long-term debt, including current portion: (1) | | | | | | | | | | |
| Principal | $ | 785 |
| | $ | 1,382 |
| | $ | 3,767 |
| | $ | 17,506 |
| | $ | 23,440 |
| $ | 2,141 |
| | $ | 2,918 |
| | $ | 3,756 |
| | $ | 13,650 |
| | $ | 22,465 |
|
| Interest | 1,099 |
| | 2,132 |
| | 1,928 |
| | 7,947 |
| | 13,106 |
| 1,097 |
| | 2,004 |
| | 1,709 |
| | 8,561 |
| | 13,371 |
|
| Commercial paper | 93 |
| | — |
| | — |
| | — |
| | 93 |
| |
| Operating leases | 66 |
| | 109 |
| | 81 |
| | 90 |
| | 346 |
| 29 |
| | 61 |
| | 41 |
| | 157 |
| | 288 |
|
| Purchase obligations (3) | 1,074 |
| | 733 |
| | 646 |
| | 320 |
| | 2,773 |
| |
| Other obligations (4)(5) | 2 |
| | 1 |
| | 1 |
| | 1 |
| | 5 |
| |
| Purchase obligations (2) | | 890 |
| | 647 |
| | 245 |
| | 290 |
| | 2,072 |
|
| Other obligations (3)(4) | | 3 |
| | 5 |
| | — |
| | — |
| | 8 |
|
| Total | $ | 3,119 |
| | $ | 4,357 |
| | $ | 6,423 |
| | $ | 25,864 |
| | $ | 39,763 |
| $ | 4,160 |
| | $ | 5,635 |
| | $ | 5,751 |
| | $ | 22,658 |
| | $ | 38,204 |
|
______________
| |
| (1) | Includes theany borrowings outstanding under credit facilities, but does not include any related variable-rate interest payments. |
| |
| (2) | Includes $750 million of 6.125 percent senior notes due 2022 that WPZ intends to redeem on February 23, 2017 and related interest, presented in the table above according to the original contractual terms.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.)
| |
| (3) | Includes approximately $244 million in open property, plant, and equipment purchase orders. Includes an estimated $418 million long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2016 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 resold at comparable prices in the Mont Belvieu market. Includes an estimated $619 million long-term ethane purchase obligation with index-based pricing terms that primarily supplies third parties at their plants and is valued in this table at a price calculated using December 31, 2016 prices. Any excess purchased volumes may be sold at comparable market prices. Includes an estimated $586 million long-term mixed NGLs purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2016 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.) |
| |
(4) | 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 $72$68 million in 20162019 and $70$93 million in 2015.2018. In 2017,2020, we expect to contribute approximately $69$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 2016,2019, 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 2017,2020, we expect to contribute approximately $60$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. |
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.
| |
(5)(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 3949 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 1819 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements). We are monitoring these sites in a coordinated effort with other potentially responsible parties, the EPA, or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Current estimates of the most likely costs of such activities are approximately $38$31 million, all of which are included in Accrued liabilities and Regulatory liabilities, deferred income, and other on in the Consolidated Balance Sheet at December 31, 2016.2019. We will seek recovery of approximately $9 million of thesethe 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 2016,2019, we paid approximately$6 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $9$8 million in 20172020 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, 2016,2019, 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.
In March 2008, theThe EPA promulgated aand various state regulatory agencies routinely promulgate and propose new lowerrules 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 Standard (NAAQS)Standards for ground-level ozone. In May 2012, the EPA completed designation of new eight-hour ozone nonattainment areas. Several Transco facilities are located in 2008 ozone nonattainment areas. In December 2014, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels and subsequently finalized a rule on October 1, 2015. We are monitoring the rule's implementation as the reductionit will trigger additional federal and state regulatory actions that may impact our operations. To date, no federal actions have been proposed to mandate additional emission controls at these facilities. Pursuant to recently finalized state regulatory actions associated with implementation of the 2008 ozone standard, we anticipate that some facilities may be subject to increased controls within five years. 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 on in the Consolidated Balance Sheetfor both new and existing facilities in affected areas. We are unable at this time to reasonably estimate with any certainty the cost of additions that may be required to meet the regulations.
On January 22, 2010,regulations at this time due to uncertainty created by various legal challenges to these regulations and the EPA set a new one-hour nitrogen dioxide (NO2) NAAQS. The effective date of the new NO2 standard was April 12, 2010. On January 20, 2012, the EPA determined pursuant to available information that no area in the country is violating the 2010 NO2 NAAQS and thus designated all areas of the country as “unclassifiable/attainment.” Also, at that time the EPA noted its plan to deploy an expanded NO2 monitoring network beginning in 2013. However on October 5, 2012, the EPA proposed a graduated implementation of the monitoring network between
January 1, 2014 and January 1, 2017. Once three years of data is collected from the new monitoring network, the EPA will reassess attainment status with the one-hour NO2 NAAQS. Until that time, the EPA or states may require ambient air quality modeling on a case by case basis to demonstrate compliance with the NO2 standard. Because we are unable to predict the outcome of the EPA’s or states’ future assessment using the new monitoring network, we are unable to estimate the cost of additions that may be required to meet this regulation.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.
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 theour credit facilitiesfacility and any issuances under WPZ’sour 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 1415 – Debt and Banking Arrangements and Leases of Notes to Consolidated Financial Statements.)
The tables below provide information by maturity date about our interest rate risk-sensitive instruments as of December 31, 20162019 and 2015. Long-term debt2018. 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 tables represents principal cash flows, net of (discount) premium and debt issuance costs, and weighted-average interest rates by expected maturity dates. The fair value of our publicly traded long-term debt is valued using indicative year-end traded bond market prices. Private debt is valued based on market rates and the prices of similar securities with similar terms and credit ratings.debt.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | Thereafter (1) | | Total | | Fair Value December 31, 2016 |
| | (Millions) |
| Long-term debt, including current portion: | | | | | | | | | | | | | | | | |
| Fixed rate | $ | 785 |
| $ | 500 |
| $ | 32 |
| $ | 2,121 |
| $ | 871 |
| $ | 17,475 |
| $ | 21,784 |
| $ | 22,465 |
|
| Interest rate | | 5.2 | % | | 5.2 | % | | 5.2 | % | | 5.2 | % | | 5.2 | % | | 5.6 | % | | | | |
| Variable rate | $ | — |
| $ | 850 |
| $ | — |
| $ | 775 |
| $ | — |
| $ | — |
| $ | 1,625 |
| $ | 1,625 |
|
| Interest rate (3) | | | | | | | | | | | | | | | | |
| Commercial paper: | | | | | | | | | | | | | | | | |
| Variable rate | $ | 93 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 93 |
| $ | 93 |
|
| Interest rate (4) | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | 2016 | | 2017 | | 2018 | | 2019 | | 2020 | | Thereafter (1) | | Total | | Fair Value December 31, 2015 |
| | (Millions) |
| Long-term debt, including current portion: (2) | | | | | | | | | | | | | | | | |
| Fixed rate | $ | 375 | (*) | $ | 785 |
| $ | 500 |
| $ | 32 |
| $ | 2,121 |
| $ | 17,364 |
| $ | 21,177 |
| $ | 16,796 |
|
| Interest rate | | 5.1 | % | | 5.1 | % | | 5.0 | % | | 5.0 | % | | 5.0 | % | | 5.5 | % | | | | |
| Variable rate | $ | — |
| $ | — |
| $ | 850 |
| $ | — |
| $ | 1,960 |
| $ | — |
| $ | 2,810 |
| $ | 2,810 |
|
| Interest rate (5) | | | | | | | | | | | | | | | | |
| Commercial paper: | | | | | | | | | | | | | | | | |
| Variable rate | $ | 499 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 499 |
| $ | 499 |
|
| Interest rate (4) | | | | | | | | | | | | | | | | |
| _____________ | | | | | | | | | | | | | | | | |
| (*) $200 million presented as long-term debt at December 31, 2015, due to WPZ’s intent and ability to refinance. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | Thereafter (1) | | Total | | Fair Value December 31, 2019 |
| | (Millions) |
| 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 | | Fair Value December 31, 2018 |
| | (Millions) |
| Long-term debt, including current portion: | | | | | | | | | | | | | | | | |
| Fixed rate | | $ | 47 |
| | $ | 2,138 |
| | $ | 890 |
| | $ | 2,021 |
| | $ | 1,473 |
| | $ | 15,685 |
| | $ | 22,254 |
| | $ | 23,170 |
|
| Weighted-average interest rate | | 5.2 | % | | 5.2 | % | | 5.2 | % | | 5.3 | % | | 5.5 | % | | 5.7 | % | | | | |
| Variable rate (2) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 160 |
| | $ | — |
| | $ | 160 |
| | $ | 160 |
|
__________________
| |
| (1) | Includes unamortized discount / premium and debt issuance costs. |
| |
| (2) | Excludes capital leases. |
| |
(3) | The weighted-average interest ratesrate for WPZ’s $850 million term loan, and our $775$160 million credit facility borrowing at December 31, 2016 were 2.50 percent and 2.51 percent, respectively. |
| |
(4) | The weighted-average interest rate2018, was 1.06 percent and 0.92 percent at December 31, 2016 and 2015, respectively. |
| |
(5) | The weighted-average interest rates for WPZ’s $1.3 billion credit facility borrowing, WPZ’s $850 million term loan, and our $650 million credit facility borrowing at December 31, 2015 were 1.63 percent, 1.85 percent, and 2.32 percent, respectively.3.77 percent. |
Commodity Price Risk
We are exposed to the impact of fluctuations in the market price of NGLs olefins, 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, 20162019 and 2015,2018, our derivative activity was not material. (See Note 1718 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)
Foreign Currency Risk
In September 2016, we disposed of our Canadian operations, which comprised substantially all of our foreign operations. (See Note 3 – Divestiture of Notes to Consolidated Financial Statements.)
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
The Stockholders and the Board of Directors and Stockholders 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, 20162019 and 2015, and2018, 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, 2016. Our audits also included2019, and the related notes and the financial statement schedulesschedule listed in the index at Item 15(a) (collectively referred to as the “consolidated financial statements”). These financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express anIn our opinion, on these financial statements and schedules based on our audits. 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”)(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 $261$217 million and $293$225 million as of December 31, 20162019 and 2015,2018, respectively, and the Company’s equity earnings in the net income of Gulfstream were $69$74 million in 2019, $75 million in 2018 and $65$75 million respectively, for the years then ended. For the periods indicated above,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, for 2016 and 2015, is based solely on the report of the other auditors.
We conducted our auditsalso 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. An audit includesmisstatement, 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 supportingregarding the amounts and disclosures in the consolidated financial statements. An auditOur audits also includes assessingincluded evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statement presentation.statements. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and, for 2016 and 2015, the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of The Williams Companies, Inc. at December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), The Williams Companies, Inc.'s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 22, 2017 expressed an unqualified opinion thereon.
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. |
|
| | | | |
| 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 22, 201724, 2020
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, 20162019 and 2015,2018, 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, 2016. 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'sCompany’s management. Our responsibility is to express an opinion on thesethe 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 Public Company Accounting Oversight Board (United States)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. The Company is not requiredmisstatement, whether due to have, nor were we engaged to perform, an audit of its internal control over financial reporting. error or fraud.
Our audits included considerationperforming procedures to assess the risks of internal control overmaterial misstatement of the financial reporting as a basis for designing auditstatements, whether due to error or fraud, and performing procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includesrespond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements, assessingstatements. 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 statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Gulfstream Natural Gas System, L.L.C. as of December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHEPricewaterhouseCoopers LLP
Houston, Texas
February 22, 201724, 2020
We have served as the Company’s auditor since 2018.
The Williams Companies, Inc.
Consolidated Statement of Operations
| | | | | Years Ended December 31, | | Year Ended December 31, |
| | | 2016 | | 2015 | | 2014 | | 2019 | | 2018 | | 2017 |
| | (Millions, except per-share amounts) | (Millions, except per-share amounts) |
| Revenues: | | | | | | | | | | | | |
| Service revenues | | $ | 5,171 |
|
| $ | 5,164 |
| | $ | 4,116 |
| | $ | 5,933 |
|
| $ | 5,502 |
| | $ | 5,312 |
|
| Service revenues – commodity consideration (Note 1) | | | 203 |
| | 400 |
| | — |
|
| Product sales | | 2,328 |
|
| 2,196 |
| | 3,521 |
| | 2,065 |
|
| 2,784 |
| | 2,719 |
|
| Total revenues | | 7,499 |
|
| 7,360 |
| | 7,637 |
| | 8,201 |
|
| 8,686 |
| | 8,031 |
|
| Costs and expenses: | |
|
|
| | | |
|
|
| | |
| Product costs | | 1,725 |
|
| 1,779 |
| | 3,016 |
| | 1,961 |
|
| 2,707 |
| | 2,300 |
|
| Processing commodity expenses | | | 105 |
| | 137 |
| | — |
|
| Operating and maintenance expenses | | 1,580 |
|
| 1,655 |
| | 1,492 |
| | 1,468 |
|
| 1,507 |
| | 1,576 |
|
| Depreciation and amortization expenses | | 1,763 |
|
| 1,738 |
| | 1,176 |
| | 1,714 |
|
| 1,725 |
| | 1,736 |
|
| Selling, general, and administrative expenses | | 723 |
|
| 741 |
| | 661 |
| | 558 |
|
| 569 |
| | 594 |
|
| Impairment of goodwill (Note 17) | | — |
| | 1,098 |
| | — |
| |
| Impairment of certain assets (Note 17) | | 873 |
| | 209 |
| | 52 |
| |
| Net insurance recoveries – Geismar Incident | | (7 | ) | | (126 | ) | | (232 | ) | |
| Impairment of certain assets (Note 18) | | | 464 |
| | 1,915 |
| | 1,248 |
|
| Gain on sale of certain assets and businesses (Note 3) | | | 2 |
| | (692 | ) | | (1,095 | ) |
| Regulatory charges resulting from Tax Reform (Note 1) | | | — |
| | (17 | ) | | 674 |
|
| Other (income) expense – net | | 142 |
|
| 40 |
| | (97 | ) | | 8 |
|
| 67 |
| | 71 |
|
| Total costs and expenses | | 6,799 |
|
| 7,134 |
| | 6,068 |
| | 6,280 |
|
| 7,918 |
| | 7,104 |
|
| Operating income (loss) | | 700 |
|
| 226 |
| | 1,569 |
| | 1,921 |
|
| 768 |
| | 927 |
|
| Equity earnings (losses) | | 397 |
|
| 335 |
| | 144 |
| | 375 |
|
| 396 |
| | 434 |
|
| Gain on remeasurement of equity-method investment (Note 2) | | — |
| | — |
| | 2,544 |
| |
| Impairment of equity-method investments (Note 17) | | (430 | ) | | (1,359 | ) | | — |
| |
| Other investing income (loss) – net | | 63 |
| | 27 |
| | 43 |
| | (79 | ) | | 187 |
| | 282 |
|
| Interest incurred |
| (1,217 | ) |
| (1,118 | ) | | (888 | ) |
| (1,218 | ) |
| (1,160 | ) | | (1,116 | ) |
| Interest capitalized |
| 38 |
|
| 74 |
| | 141 |
|
| 32 |
|
| 48 |
| | 33 |
|
| Other income (expense) – net | | 74 |
|
| 102 |
| | 31 |
| | 33 |
|
| 92 |
| | (25 | ) |
| Income (loss) from continuing operations before income taxes | | (375 | ) |
| (1,713 | ) | | 3,584 |
| | 1,064 |
|
| 331 |
| | 535 |
|
| Provision (benefit) for income taxes | | (25 | ) |
| (399 | ) | | 1,249 |
| | 335 |
|
| 138 |
| | (1,974 | ) |
| Income (loss) from continuing operations | | (350 | ) |
| (1,314 | ) | | 2,335 |
| | 729 |
| | 193 |
| | 2,509 |
|
| Income (loss) from discontinued operations | | — |
|
| — |
| | 4 |
| | (15 | ) | | — |
| | — |
|
| Net income (loss) | | (350 | ) |
| (1,314 | ) | | 2,339 |
| | 714 |
|
| 193 |
| | 2,509 |
|
| Less: Net income (loss) attributable to noncontrolling interests | | 74 |
|
| (743 | ) | | 225 |
| | (136 | ) |
| 348 |
| | 335 |
|
| Net income (loss) attributable to The Williams Companies, Inc. | | $ | (424 | ) |
| $ | (571 | ) | | $ | 2,114 |
| | 850 |
|
| (155 | ) | | 2,174 |
|
| Amounts attributable to The Williams Companies, Inc.: | | | | | | | |
| Preferred stock dividends (Note 16) | | | 3 |
| | 1 |
| | — |
|
| Net income (loss) available to common stockholders | | | $ | 847 |
| | $ | (156 | ) | | $ | 2,174 |
|
| Amounts attributable to The Williams Companies, Inc. available to common stockholders: | | | | | | | |
| Income (loss) from continuing operations | | $ | (424 | ) | | $ | (571 | ) | | $ | 2,110 |
| | $ | 862 |
| | $ | (156 | ) | | $ | 2,174 |
|
| Income (loss) from discontinued operations | | — |
| | — |
| | 4 |
| | (15 | ) | | — |
| | — |
|
| Net income (loss) | | $ | (424 | ) | | $ | (571 | ) | | $ | 2,114 |
| | $ | 847 |
| | $ | (156 | ) | | $ | 2,174 |
|
| Basic earnings (loss) per common share: | | | | | | | | | | | | |
| Income (loss) from continuing operations | | $ | (.57 | ) | | $ | (.76 | ) | | $ | 2.93 |
| | $ | .71 |
| | $ | (.16 | ) | | $ | 2.63 |
|
| Income (loss) from discontinued operations | | — |
| | — |
| | .01 |
| | (.01 | ) | | — |
| | — |
|
| Net income (loss) | | $ | (.57 | ) | | $ | (.76 | ) | | $ | 2.94 |
| | $ | .70 |
| | $ | (.16 | ) | | $ | 2.63 |
|
| Weighted-average shares (thousands) | | 750,673 |
| | 749,271 |
| | 719,325 |
| | 1,212,037 |
| | 973,626 |
| | 826,177 |
|
| Diluted earnings (loss) per common share: | | | | | | | | | | | | |
| Income (loss) from continuing operations | | $ | (.57 | ) | | $ | (.76 | ) | | $ | 2.91 |
| | $ | .71 |
| | $ | (.16 | ) | | $ | 2.62 |
|
| Income (loss) from discontinued operations | | — |
| | — |
| | .01 |
| | (.01 | ) | | — |
| | — |
|
| Net income (loss) | | $ | (.57 | ) | | $ | (.76 | ) | | $ | 2.92 |
| | $ | .70 |
| | $ | (.16 | ) | | $ | 2.62 |
|
| Weighted-average shares (thousands) | | 750,673 |
| | 749,271 |
| | 723,641 |
| | 1,214,011 |
| | 973,626 |
| | 828,518 |
|
See accompanying notes.
The Williams Companies, Inc.
Consolidated Statement of Comprehensive Income (Loss)
| | | | | Years Ended December 31, | | Year Ended December 31, |
| | | 2016 | | 2015 | | 2014 | | 2019 | | 2018 | | 2017 |
| | | (Millions) | | (Millions) |
| Net income (loss) | | $ | (350 | ) | | $ | (1,314 | ) | | $ | 2,339 |
| | $ | 714 |
| | $ | 193 |
| | $ | 2,509 |
|
| Other comprehensive income (loss): | | | | | | | | | | | | |
| Cash flow hedging activities: | | | | | | | | | | | | |
| Net unrealized gain (loss) from derivative instruments, net of taxes of ($1) in 2016 | | 4 |
| | 6 |
| | — |
| |
| Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $1 in 2016 and 2015 | | (2 | ) | | (6 | ) | | — |
| |
| Net unrealized gain (loss) from derivative instruments, net of taxes of $1 and $2 in 2018 and 2017, respectively | | | — |
| | (7 | ) | | (9 | ) |
| Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of ($1) and ($1) in 2018 and 2017, respectively | | | — |
| | 8 |
| | 6 |
|
| Foreign currency translation activities: | | | | | | | | | | | | |
| Foreign currency translation adjustments, net of taxes of ($37), $31, and $18 in 2016, 2015, and 2014, respectively | | 50 |
| | (204 | ) | | (96 | ) | |
| Reclassification into earnings upon sale of foreign entities, net of taxes of ($36) in 2016 | | 119 |
| | — |
| | — |
| |
| Foreign currency translation adjustments | | | — |
| | — |
| | 1 |
|
| Pension and other postretirement benefits: | | | | | | | | | | | | |
| Prior service credit (cost) arising during the year (Note 10) | | — |
| | — |
| | (1 | ) | |
| Amortization of prior service cost (credit) included in net periodic benefit cost, net of taxes of $2, $3, and $3 in 2016, 2015, and 2014, respectively | | (4 | ) | | (3 | ) | | (5 | ) | |
| Net actuarial gain (loss) arising during the year, net of taxes of $8, ($5) and $60 in 2016, 2015, and 2014, respectively (Note 10) | | (15 | ) | | 8 |
| | (100 | ) | |
| Amortization of actuarial (gain) loss included in net periodic benefit cost, net of taxes of ($12), ($18), and ($15) in 2016, 2015, and 2014, respectively | | 20 |
| | 28 |
| | 26 |
| |
| Amortization of prior service cost (credit) included in net periodic benefit cost (credit), net of taxes of $2 in 2017 | | | — |
| | — |
| | (3 | ) |
| Net actuarial gain (loss) arising during the year, net of taxes of ($20), $3, and ($15) in 2019, 2018, and 2017, respectively | | | 59 |
| | (6 | ) | | 44 |
|
| 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 | | | 12 |
| | 35 |
| | 61 |
|
| Other comprehensive income (loss) | | 172 |
| | (171 | ) | | (176 | ) | | 71 |
| | 30 |
| | 100 |
|
| Comprehensive income (loss) | | (178 | ) | | (1,485 | ) | | 2,163 |
| | 785 |
| | 223 |
| | 2,609 |
|
| Less: Comprehensive income (loss) attributable to noncontrolling interests | | 143 |
| | (813 | ) | | 206 |
| | (136 | ) | | 346 |
| | 334 |
|
| Comprehensive income (loss) attributable to The Williams Companies, Inc. | | $ | (321 | ) | | $ | (672 | ) | | $ | 1,957 |
| | $ | 921 |
| | $ | (123 | ) | | $ | 2,275 |
|
See accompanying notes.
The Williams Companies, Inc.
Consolidated Balance Sheet
| | | | | December 31, | | December 31, |
| | | 2016 | | 2015 | | 2019 | | 2018 |
| | | (Millions, except per-share amounts) | | (Millions, except per-share amounts) |
| ASSETS | | | | | | | | |
| Current assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 170 |
| | $ | 100 |
| | $ | 289 |
| | $ | 168 |
|
| Trade accounts and other receivables (net of allowance of $6 at December 31, 2016 and $3 at December 31, 2015) | | 938 |
| | 1,041 |
| |
| Trade accounts and other receivables (net of allowance of $6 at December 31, 2019 and $9 at December 31, 2018) | | | 996 |
| | 992 |
|
| Inventories | | 138 |
| | 127 |
| | 125 |
| | 130 |
|
| Other current assets and deferred charges | | 216 |
| | 259 |
| | 170 |
| | 174 |
|
| Total current assets | | 1,462 |
| | 1,527 |
| | 1,580 |
| | 1,464 |
|
| | | | | | | | | |
| Investments | | 6,701 |
| | 7,336 |
| | 6,235 |
| | 7,821 |
|
| Property, plant, and equipment – net | | 28,428 |
| | 29,579 |
| | 29,200 |
| | 27,504 |
|
| Intangible assets – net of accumulated amortization | | 9,663 |
| | 10,017 |
| | 7,959 |
| | 7,767 |
|
| Regulatory assets, deferred charges, and other | | 581 |
| | 561 |
| | 1,066 |
| | 746 |
|
| Total assets | | $ | 46,835 |
| | $ | 49,020 |
| | $ | 46,040 |
| | $ | 45,302 |
|
| | | | | | | | | |
| LIABILITIES AND EQUITY | | | | | | | | |
| Current liabilities: | | | | | | | | |
| Accounts payable | | $ | 623 |
| | $ | 744 |
| | $ | 552 |
| | $ | 662 |
|
| Accrued liabilities | | 1,448 |
| | 1,078 |
| | 1,276 |
| | 1,102 |
|
| Commercial paper | | 93 |
| | 499 |
| |
| Long-term debt due within one year | | 785 |
| | 176 |
| | 2,140 |
| | 47 |
|
| Total current liabilities | | 2,949 |
| | 2,497 |
| | 3,968 |
| | 1,811 |
|
| | | | | | | | | |
| Long-term debt | | 22,624 |
| | 23,812 |
| | 20,148 |
| | 22,367 |
|
| Deferred income tax liabilities | | 4,238 |
| | 4,218 |
| | 1,782 |
| | 1,524 |
|
| Regulatory liabilities, deferred income, and other | | 2,978 |
| | 2,268 |
| | 3,778 |
| | 3,603 |
|
| Contingent liabilities and commitments (Note 18) | |
| |
| |
| Contingent liabilities and commitments (Note 19) | | |
| |
|
| | | | | | | | | |
| Equity: | | | | | | | | |
| Stockholders’ equity: | | | | | | | | |
Common stock (960 million shares authorized at $1 par value;
785 million shares issued at December 31, 2016 and 784 million shares issued at December 31, 2015) | | 785 |
| | 784 |
| |
| Preferred stock | | | 35 |
| | 35 |
|
| 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) | | | 1,247 |
| | 1,245 |
|
| Capital in excess of par value | | 14,887 |
| | 14,807 |
| | 24,323 |
| | 24,693 |
|
| Retained deficit | | (9,649 | ) | | (7,960 | ) | | (11,002 | ) | | (10,002 | ) |
| Accumulated other comprehensive income (loss) | | (339 | ) | | (442 | ) | | (199 | ) | | (270 | ) |
| Treasury stock, at cost (35 million shares of common stock) | | (1,041 | ) | | (1,041 | ) | | (1,041 | ) | | (1,041 | ) |
| Total stockholders’ equity | | 4,643 |
| | 6,148 |
| | 13,363 |
| | 14,660 |
|
| Noncontrolling interests in consolidated subsidiaries | | 9,403 |
| | 10,077 |
| | 3,001 |
| | 1,337 |
|
| Total equity | | 14,046 |
| | 16,225 |
| | 16,364 |
| | 15,997 |
|
| Total liabilities and equity | | $ | 46,835 |
| | $ | 49,020 |
| | $ | 46,040 |
| | $ | 45,302 |
|
See accompanying notes.
The Williams Companies, Inc.
Consolidated Statement of Changes in Equity
| | | | The Williams Companies, Inc., Stockholders | | | | | The Williams Companies, Inc. Stockholders | | | | |
| | Common Stock | | Capital in Excess of Par Value | | Retained Deficit | | Accumulated Other Comprehensive Income (Loss) | | Treasury Stock | | Total Stockholders’ Equity | | Noncontrolling Interests | | Total Equity | Preferred Stock | | Common Stock | | Capital in Excess of Par Value | | Retained Deficit | | AOCI* | | Treasury Stock | | Total Stockholders’ Equity | | Noncontrolling Interests | | Total Equity |
| | (Millions) | (Millions) |
| Balance – December 31, 2013 | $ | 718 |
| | $ | 11,599 |
| | $ | (6,248 | ) | | $ | (164 | ) | | $ | (1,041 | ) | | $ | 4,864 |
| | $ | 4,057 |
| | $ | 8,921 |
| |
| Balance – December 31, 2016 | | $ | — |
| | $ | 785 |
| | $ | 14,887 |
| | $ | (9,649 | ) | | $ | (339 | ) | | $ | (1,041 | ) | | $ | 4,643 |
| | $ | 9,403 |
| | $ | 14,046 |
|
| Adoption of new accounting standard | | — |
| | — |
| | 1 |
| | 36 |
| | — |
| | — |
| | 37 |
| | — |
| | 37 |
|
| Net income (loss) | — |
| | — |
| | 2,114 |
| | — |
| | — |
| | 2,114 |
| | 225 |
| | 2,339 |
| — |
| | — |
| | — |
| | 2,174 |
| | — |
| | — |
| | 2,174 |
| | 335 |
| | 2,509 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | (157 | ) | | — |
| | (157 | ) | | (19 | ) | | (176 | ) | — |
| | — |
| | — |
| | — |
| | 101 |
| | — |
| | 101 |
| | (1 | ) | | 100 |
|
| Issuance of common stock for acquisition of business (Note 15) | 61 |
| | 3,317 |
| | — |
| | — |
| | — |
| | 3,378 |
| | — |
| | 3,378 |
| |
| Noncontrolling interest resulting from acquisition of business (Note 2) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 7,502 |
| | 7,502 |
| |
| Cash dividends – common stock (Note 15) | — |
| | — |
| | (1,412 | ) | | — |
| | — |
| | (1,412 | ) | | — |
| | (1,412 | ) | |
| Dividends and distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (840 | ) | | (840 | ) | |
| Stock-based compensation and related common stock issuances, net of tax | 3 |
| | 85 |
| | — |
| | — |
| | — |
| | 88 |
| | — |
| | 88 |
| |
| Sales of limited partner units of Williams Partners L.P. | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 55 |
| | 55 |
| |
| Changes in ownership of consolidated subsidiaries, net | — |
| | (73 | ) | | — |
| | (20 | ) | | — |
| | (93 | ) | | 137 |
| | 44 |
| |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 340 |
| | 340 |
| |
| Deconsolidation of Bluegrass Pipeline (Note 6) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (63 | ) | | (63 | ) | |
| Other | — |
| | (3 | ) | | (2 | ) | | — |
| | — |
| | (5 | ) | | 1 |
| | (4 | ) | |
| Net increase (decrease) in equity | 64 |
| | 3,326 |
| | 700 |
| | (177 | ) | | — |
| | 3,913 |
| | 7,338 |
| | 11,251 |
| |
| Balance – December 31, 2014 | 782 |
| | 14,925 |
| | (5,548 | ) | | (341 | ) | | (1,041 | ) | | 8,777 |
| | 11,395 |
| | 20,172 |
| |
| Net income (loss) | — |
| | — |
| | (571 | ) | | — |
| | — |
| | (571 | ) | | (743 | ) | | (1,314 | ) | |
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | (101 | ) | | — |
| | (101 | ) | | (70 | ) | | (171 | ) | |
| Cash dividends – common stock (Note 15) | — |
| | — |
| | (1,836 | ) | | — |
| | — |
| | (1,836 | ) | | — |
| | (1,836 | ) | |
| Issuance of common stock (Note 16) | | — |
| | 75 |
| | 2,043 |
| | — |
| | — |
| | — |
| | 2,118 |
| | — |
| | 2,118 |
|
| Cash dividends – common stock ($1.20 per share) | | — |
| | — |
| | — |
| | (992 | ) | | — |
| | — |
| | (992 | ) | | — |
| | (992 | ) |
| Dividends and distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (942 | ) | | (942 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (883 | ) | | (883 | ) |
| Stock-based compensation and related common stock issuances, net of tax | 2 |
| | 28 |
| | — |
| | — |
| | — |
| | 30 |
| | — |
| | 30 |
| — |
| | 1 |
| | 73 |
| | — |
| | — |
| | — |
| | 74 |
| | — |
| | 74 |
|
| Sales of limited partner units of Williams Partners L.P. | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 59 |
| | 59 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 61 |
| | 61 |
|
| Changes in ownership of consolidated subsidiaries, net | — |
| | (160 | ) | | — |
| | — |
| | — |
| | (160 | ) | | 254 |
| | 94 |
| — |
| | — |
| | 1,497 |
| | — |
| | — |
| | — |
| | 1,497 |
| | (2,407 | ) | | (910 | ) |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 111 |
| | 111 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 17 |
| | 17 |
|
| Other | — |
| | 14 |
| | (5 | ) | | — |
| | — |
| | 9 |
| | 13 |
| | 22 |
| — |
| | — |
| | 7 |
| | (3 | ) | | — |
| | — |
| | 4 |
| | (6 | ) | | (2 | ) |
| Net increase (decrease) in equity | 2 |
| | (118 | ) | | (2,412 | ) | | (101 | ) | | — |
| | (2,629 | ) | | (1,318 | ) | | (3,947 | ) | — |
| | 76 |
| | 3,621 |
| | 1,215 |
| | 101 |
| | — |
| | 5,013 |
| | (2,884 | ) | | 2,129 |
|
| Balance – December 31, 2015 | 784 |
| | 14,807 |
| | (7,960 | ) | | (442 | ) | | (1,041 | ) | | 6,148 |
| | 10,077 |
| | 16,225 |
| |
| Balance – December 31, 2017 | | — |
| | 861 |
| | 18,508 |
| | (8,434 | ) | | (238 | ) | | (1,041 | ) | | 9,656 |
| | 6,519 |
| | 16,175 |
|
| Adoption of new accounting standards | | — |
| | — |
| | — |
| | (23 | ) | | (61 | ) | | — |
| | (84 | ) | | (37 | ) | | (121 | ) |
| Net income (loss) | — |
| | — |
| | (424 | ) | | — |
| | — |
| | (424 | ) | | 74 |
| | (350 | ) | — |
| | — |
| | — |
| | (155 | ) | | — |
| | — |
| | (155 | ) | | 348 |
| | 193 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | 103 |
| | — |
| | 103 |
| | 69 |
| | 172 |
| — |
| | — |
| | — |
| | — |
| | 32 |
| | — |
| | 32 |
| | (2 | ) | | 30 |
|
| Cash dividends – common stock (Note 15) | — |
| | — |
| | (1,261 | ) | | — |
| | — |
| | (1,261 | ) | | — |
| | (1,261 | ) | |
| WPZ Merger (Note 1) | | — |
| | 382 |
| | 6,112 |
| | — |
| | (3 | ) | | — |
| | 6,491 |
| | (4,629 | ) | | 1,862 |
|
| Issuance of preferred stock (Note 16) | | 35 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 35 |
| | — |
| | 35 |
|
| Cash dividends – common stock ($1.36 per share) | | — |
| | — |
| | — |
| | (1,386 | ) | | — |
| | — |
| | (1,386 | ) | | — |
| | (1,386 | ) |
| Dividends and distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (940 | ) | | (940 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (637 | ) | | (637 | ) |
| Stock-based compensation and related common stock issuances, net of tax | 1 |
| | 56 |
| | — |
| | — |
| | — |
| | 57 |
| | — |
| | 57 |
| — |
| | 1 |
| | 60 |
| | — |
| | — |
| | — |
| | 61 |
| | — |
| | 61 |
|
| Sales of limited partner units of Williams Partners L.P. | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| �� | 114 |
| | 114 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 46 |
| | 46 |
|
| Changes in ownership of consolidated subsidiaries, net | — |
| | 12 |
| | — |
| | — |
| | — |
| | 12 |
| | (18 | ) | | (6 | ) | — |
| | — |
| | 14 |
| | — |
| | — |
| | — |
| | 14 |
| | (18 | ) | | (4 | ) |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 29 |
| | 29 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 15 |
| | 15 |
|
| Deconsolidation of subsidiary (Note 6) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (267 | ) | | (267 | ) |
| Other | — |
| | 12 |
| | (4 | ) | | — |
| | — |
| | 8 |
| | (2 | ) | | 6 |
| — |
| | 1 |
| | (1 | ) | | (4 | ) | | — |
| | — |
| | (4 | ) | | (1 | ) | | (5 | ) |
| Net increase (decrease) in equity | 1 |
| | 80 |
| | (1,689 | ) | | 103 |
| | — |
| | (1,505 | ) | | (674 | ) | | (2,179 | ) | 35 |
| | 384 |
| | 6,185 |
| | (1,568 | ) | | (32 | ) | | — |
| | 5,004 |
| | (5,182 | ) | | (178 | ) |
| Balance – December 31, 2016 | $ | 785 |
| | $ | 14,887 |
| | $ | (9,649 | ) | | $ | (339 | ) | | $ | (1,041 | ) | | $ | 4,643 |
| | $ | 9,403 |
| | $ | 14,046 |
| |
| Balance – December 31, 2018 | | 35 |
| | 1,245 |
| | 24,693 |
| | (10,002 | ) | | (270 | ) | | (1,041 | ) | | 14,660 |
| | 1,337 |
| | 15,997 |
|
| Net income (loss) | | — |
| | — |
| | — |
| | 850 |
| | — |
| | — |
| | 850 |
| | (136 | ) | | 714 |
|
| Other comprehensive income (loss) | | — |
| | — |
| | — |
| | — |
| | 71 |
| | — |
| | 71 |
| | — |
| | 71 |
|
| Cash dividends – common stock ($1.52 per share) | | — |
| | — |
| | — |
| | (1,842 | ) | | — |
| | — |
| | (1,842 | ) | | — |
| | (1,842 | ) |
| Dividends and distributions to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (124 | ) | | (124 | ) |
| Stock-based compensation and related common stock issuances, net of tax | | — |
| | 2 |
| | 56 |
| | — |
| | — |
| | — |
| | 58 |
| | — |
| | 58 |
|
| Sale of partial interest in consolidated subsidiary (Note 3) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,334 |
| | 1,334 |
|
| Changes in ownership of consolidated subsidiaries, net (Note 3) | | — |
| | — |
| | (426 | ) | | — |
| | — |
| | — |
| | (426 | ) | | 567 |
| | 141 |
|
| Contributions from noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 36 |
| | 36 |
|
| Deconsolidation of subsidiary (Note 4) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (13 | ) | | (13 | ) |
| Other | | — |
| | — |
| | — |
| | (8 | ) | | — |
| | — |
| | (8 | ) | | — |
| | (8 | ) |
| Net increase (decrease) in equity | | — |
| | 2 |
| | (370 | ) | | (1,000 | ) | | 71 |
| | — |
| | (1,297 | ) | | 1,664 |
| | 367 |
|
| Balance – December 31, 2019 | | $ | 35 |
| | $ | 1,247 |
| | $ | 24,323 |
| | $ | (11,002 | ) | | $ | (199 | ) | | $ | (1,041 | ) | | $ | 13,363 |
| | $ | 3,001 |
| | $ | 16,364 |
|
| |
| * | Accumulated Other Comprehensive Income (Loss) |
See accompanying notes.notes.
The Williams Companies, Inc.
Consolidated Statement of Cash Flows
| | | | | Years Ended December 31, | | Year Ended December 31, |
| | | 2016 | | 2015 | | 2014 | | 2019 | | 2018 | | 2017 |
| | | (Millions) | | (Millions) |
| OPERATING ACTIVITIES: | | | | | | | | | | | | |
| Net income (loss) | | $ | (350 | ) | | $ | (1,314 | ) | | $ | 2,339 |
| | $ | 714 |
| | $ | 193 |
| | $ | 2,509 |
|
| Adjustments to reconcile to net cash provided (used) by operating activities: | | | | | | | | | | | | |
| Depreciation and amortization | | 1,763 |
| | 1,738 |
| | 1,176 |
| | 1,714 |
| | 1,725 |
| | 1,736 |
|
| Provision (benefit) for deferred income taxes | | (26 | ) | | (337 | ) | | 1,264 |
| | 376 |
| | 220 |
| | (2,012 | ) |
| Impairment of goodwill | | — |
| | 1,098 |
| | — |
| |
| Impairment of equity-method investments | | 430 |
| | 1,359 |
| | — |
| |
| Impairment of and net (gain) loss on sale of assets and businesses | | 918 |
| | 215 |
| | 67 |
| |
| Equity (earnings) losses | | | (375 | ) | | (396 | ) | | (434 | ) |
| Distributions from unconsolidated affiliates | | | 657 |
| | 693 |
| | 784 |
|
| Gain on disposition of equity-method investments (Note 6) | | | (122 | ) | | — |
| | (269 | ) |
| Impairment of equity-method investments (Note 18) | | | 186 |
| | 32 |
| | — |
|
| (Gain) on sale of certain assets and businesses (Note 3) | | | 2 |
| | (692 | ) | | (1,095 | ) |
| Impairment of certain assets (Note 18) | | | 464 |
| | 1,915 |
| | 1,249 |
|
| (Gain) loss on deconsolidation of businesses (Note 6) | | | 29 |
| | (203 | ) | | — |
|
| Amortization of stock-based awards | | 73 |
| | 82 |
| | 53 |
| | 57 |
| | 55 |
| | 78 |
|
| Gain on remeasurement of equity-method investment | | — |
| | — |
| | (2,544 | ) | |
| Regulatory charges resulting from Tax Reform (Note 1) | | | — |
| | (15 | ) | | 776 |
|
| Cash provided (used) by changes in current assets and liabilities: | | | | | | | | | | | | |
| Accounts and notes receivable | | 82 |
| | 39 |
| | (276 | ) | | 34 |
| | (36 | ) | | (88 | ) |
| Inventories | | (25 | ) | | 105 |
| | (36 | ) | | 5 |
| | (16 | ) | | 8 |
|
| Other current assets and deferred charges | | (4 | ) | | 4 |
| | (44 | ) | | 21 |
| | 17 |
| | (21 | ) |
| Accounts payable | | 25 |
| | (90 | ) | | (8 | ) | | (46 | ) | | (93 | ) | | 118 |
|
| Accrued liabilities | | 506 |
| | 26 |
| | (203 | ) | | 153 |
| | 23 |
| | (92 | ) |
| Other, including changes in noncurrent assets and liabilities | | 272 |
| | (247 | ) | | 327 |
| | (176 | ) | | (129 | ) | | (158 | ) |
| Net cash provided (used) by operating activities | | 3,664 |
| | 2,678 |
| | 2,115 |
| | 3,693 |
| | 3,293 |
| | 3,089 |
|
| FINANCING ACTIVITIES: | | | | | | | | | | | | |
| Proceeds from (payments of) commercial paper – net | | (409 | ) | | (306 | ) | | 572 |
| | (4 | ) | | (2 | ) | | (93 | ) |
| Proceeds from long-term debt | | 6,528 |
| | 9,772 |
| | 7,321 |
| | 767 |
| | 3,926 |
| | 3,333 |
|
| Payments of long-term debt | | (7,091 | ) | | (6,516 | ) | | (1,828 | ) | | (909 | ) | | (3,204 | ) | | (5,925 | ) |
| Proceeds from issuance of common stock | | 9 |
| | 27 |
| | 3,416 |
| | 10 |
| | 15 |
| | 2,131 |
|
| Proceeds from sale of limited partner units of consolidated partnership | | 114 |
| | 59 |
| | 55 |
| |
| Dividends paid | | (1,261 | ) | | (1,836 | ) | | (1,412 | ) | |
| Proceeds from sale of partial interest in consolidated subsidiary (Note 3) | | | 1,334 |
| | — |
| | — |
|
| Common dividends paid | | | (1,842 | ) | | (1,386 | ) | | (992 | ) |
| Dividends and distributions paid to noncontrolling interests | | (940 | ) | | (942 | ) | | (840 | ) | | (124 | ) | | (591 | ) | | (822 | ) |
| Contributions from noncontrolling interests | | 29 |
| | 111 |
| | 340 |
| | 36 |
| | 15 |
| | 17 |
|
| Payments for debt issuance costs | | (9 | ) | | (35 | ) | | (40 | ) | | — |
| | (26 | ) | | (17 | ) |
| Special distribution from Gulfstream | | — |
| | 396 |
| | — |
| |
| Contribution to Gulfstream for repayment of debt | | (148 | ) | | (248 | ) | | — |
| |
| Other – net | | — |
| | (1 | ) | | 17 |
| | (13 | ) | | (46 | ) | | (92 | ) |
| Net cash provided (used) by financing activities | | (3,178 | ) | | 481 |
| | 7,601 |
| | (745 | ) | | (1,299 | ) | | (2,460 | ) |
| INVESTING ACTIVITIES: | | | | | | | | | | | | |
| Property, plant, and equipment: | | | | | | | | | | | | |
| Capital expenditures (1) | | (2,051 | ) | | (3,167 | ) | | (4,031 | ) | | (2,109 | ) | | (3,256 | ) | | (2,399 | ) |
| Net proceeds from dispositions | | 30 |
| | 3 |
| | 34 |
| |
| Dispositions – net | | | (40 | ) | | (7 | ) | | (41 | ) |
| Contributions in aid of construction | | | 52 |
| | 411 |
| | 426 |
|
| Proceeds from sale of businesses, net of cash divested | | 1,020 |
| | — |
| | — |
| | (2 | ) | | 1,296 |
| | 2,067 |
|
| Purchases of businesses, net of cash acquired | | — |
| | (112 | ) | | (5,958 | ) | |
| Purchases of and contributions to equity-method investments | | (177 | ) | | (595 | ) | | (482 | ) | |
| Distributions from unconsolidated affiliates in excess of cumulative earnings | | 472 |
| | 404 |
| | 206 |
| |
| Purchases of businesses, net of cash acquired (Note 3) | | | (728 | ) | | — |
| | — |
|
| Proceeds from dispositions of equity-method investments (Note 6) | | | 485 |
| | — |
| | 200 |
|
| Purchases of and contributions to equity-method investments (Note 6) | | | (453 | ) | | (1,132 | ) | | (132 | ) |
| Other – net | | 290 |
| | 168 |
| | 74 |
| | (32 | ) | | (37 | ) | | (21 | ) |
| Net cash provided (used) by investing activities | | (416 | ) | | (3,299 | ) | | (10,157 | ) | | (2,827 | ) | | (2,725 | ) | | 100 |
|
| Increase (decrease) in cash and cash equivalents | | 70 |
| | (140 | ) | | (441 | ) | | 121 |
| | (731 | ) | | 729 |
|
| Cash and cash equivalents at beginning of year | | 100 |
| | 240 |
| | 681 |
| | 168 |
| | 899 |
| | 170 |
|
| Cash and cash equivalents at end of year | | $ | 170 |
| | $ | 100 |
| | $ | 240 |
| | $ | 289 |
| | $ | 168 |
| | $ | 899 |
|
| _________ | | | | | | | | | | | | |
| (1) Increases to property, plant, and equipment | | $ | (1,912 | ) | | $ | (3,024 | ) | | $ | (3,916 | ) | | $ | (2,023 | ) | | $ | (3,021 | ) | | $ | (2,662 | ) |
| Changes in related accounts payable and accrued liabilities | | (139 | ) | | (143 | ) | | (115 | ) | | (86 | ) | | (235 | ) | | 263 |
|
| Capital expenditures | | $ | (2,051 | ) | | $ | (3,167 | ) | | $ | (4,031 | ) | | $ | (2,109 | ) | | $ | (3,256 | ) | | $ | (2,399 | ) |
See accompanying notes.
|
| | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements |
| |
Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
General
Unless the context clearly indicates otherwise, references in this report to “Williams,” “we,” “our,” “us,” or like terms refer to The Williams Companies, Inc. and its subsidiaries. Unless the context clearly indicates otherwise, references to “Williams,” “we,” “our,” and “us” include the operations in which we own interests accounted for as equity-method investments that are not consolidated in our financial statements. When we refer to our equity investees by name, we are referring exclusively to their businesses and operations.
Financial RepositioningWPZ Merger
In January 2017,On August 10, 2018, we announced agreementscompleted 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 (IDRs) and converted our 2 percent general partner interest in WPZ to a non-economicnoneconomic 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 1516 – Stockholders’ Equity). According to the terms of this agreement, followingconcurrent with WPZ’s quarterly distributiondistributions in February 2017 and May 2017, we paid additional consideration of approximately $50totaling $56 millionto WPZ for these units. Following these transactions, we own a 74 percent limited partner interest in WPZ.
Termination of WPZ Merger Agreement
On May 12, 2015, we entered into an agreement for a unit-for-stock transaction whereby we would have acquired all of the publicly held outstanding common units of WPZ in exchange for shares of our common stock (WPZ Merger Agreement).
On September 28, 2015, we entered into a Termination Agreement and Release (Termination Agreement), terminating the WPZ Merger Agreement. Under the terms of the Termination Agreement, we were required to pay a $428 million termination fee to WPZ, at which time we owned approximately 60 percent, including the interests of the general partner and IDRs. Such termination fee settled through a reduction of quarterly incentive distributions we were entitled to receive from WPZ (such reduction not to exceed $209 million per quarter). The distributions from WPZ in November 2015, February 2016, and May 2016 were reduced by $209 million, $209 million, and $10 million, respectively, related to this termination fee.
ACMP Merger
On February 2, 2015, Williams Partners L.P. merged with and into Access Midstream Partners, L.P. (ACMP Merger). For the purpose of these financial statements and notes, WPZ refers to the renamed merged partnership, while Pre-merger Access Midstream Partners, L.P. (ACMP) and Pre-merger Williams Partners L.P. (Pre-merger WPZ) refer to the separate partnerships prior to the consummation of the ACMP Merger and subsequent name change. The net assets of Pre-merger WPZ and ACMP were combined at our historical basis. Our basis in ACMP reflected our business combination accounting resulting from acquiring control of ACMP on July 1, 2014.
Description of Business
We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located principally in the United States and are organized intopresented within the Williams Partnersfollowing reportable segments: Atlantic-Gulf, Northeast G&P, and Williams NGL & Petchem Services reportable segments.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. For periods after
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 ACMP Acquisition (see Note 2 – Acquisitions)Gulf Coast region, including a 51 percent interest in Gulfstar One LLC (Gulfstar One) (a consolidated variable interest entity, or VIE), the acquired ACMP businesswhich is reported within Williams Partners. For periods prior to the ACMP Acquisition, the results associated with our formera proprietary floating production system, as well as a 50 percent equity-method investment in ACMP are reported within Other.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
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Williams Partners
Williams Partners consists of our consolidated master limited partnership, WPZ, and primarily includes gas pipeline and midstream businesses.
WPZ’s gas pipeline businesses primarily consist of two interstate natural gas pipelines, which are Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline LLC (Northwest Pipeline), and several joint venture investments in interstate and intrastate natural gas pipeline systems, including a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), and a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), which is under development.
WPZ’s midstream businesses primarily consist of (1) natural gas gathering, treating, compression, and processing; (2) natural gas liquid (NGL) fractionation, storage, and transportation; (3) crude oil production handling and transportation; and (4) olefins production. The primary service areas are concentrated in major producing basins in Colorado, Texas, Oklahoma, Kansas, New Mexico, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio which include the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, and Utica Shale plays as well as the Mid-Continent region.
The midstream businesses include equity-method investments in natural gas gathering and processing assets and NGL fractionation and transportation assets, including a 62 percent equity-method investment in Utica East Ohio Midstream, LLC (UEOM), a 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region, a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 58 percent equity-method investment in Caiman Energy II, LLC (Caiman II), a 60 percent equity-method investment in Discovery Producer Services, LLC (Discovery), a 50 percent equity-method investment in Overland Pass Pipeline, LLC (OPPL), and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 4166 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).
The midstream businessesWest 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 Canadian midstream operations,former natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado, which were comprisedsold during the fourth quarter of an oil sands offgas processing plant located near Fort McMurray, Alberta, and an NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, we completed the sale of our Canadian operations. (See2018 (see Note 3 – Divestiture.)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).
Williams NGL & Petchem Services
Williams NGL & Petchem Services includes certain other domestic olefins pipeline assets, a liquids extraction plant located near Fort McMurray, Alberta, that began operations in March 2016, and a propane dehydrogenation facility under development in Canada. In September 2016, we completed the sale of our Canadian operations. (See Note 3 – Divestiture.)
Other
Other includes otherminor 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),anda refinery grade propylene splitter in the Gulf region, which was sold in June 2017.
Basis of Presentation
Canada Dropdown
In February 2014, we contributed certain Canadian operations to Pre-merger WPZ (Canada Dropdown) for total consideration of $56 million of cash from Pre-merger WPZ (including a $31 million post-closing adjustment received in the second quarter of 2014), 25,577,521 Pre-merger WPZ Class D limited-partner units, and an increase in the capital account of its general partner to allow us to maintain our 2 percent general partner interest. In lieu of cash distributions, the Class D units received quarterly distributions of additional paid-in-kind Class D units.
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In October 2014, a purchase price adjustment was finalized whereby we paid $56 million in cash to Pre-merger WPZ in the fourth quarter and waived $2 million in payment of IDRs with respect to the November 2014 distribution.
Consolidated master limited partnership
As of December 31, 2016, we owned approximately 60 percent of the interests in WPZ, a variable interest entity (VIE) (see Note 4 – Variable Interest Entities), including the interests of the general partner, which are wholly owned by us, and IDRs.
During 2016, WPZ issued 3,273,601 common units pursuant to an equity distribution agreement between WPZ and certain banks resulting in net proceeds of $115 million. WPZ also implemented a distribution reinvestment program in the third quarter of 2016 resulting in 7,891,414 common units issued associated with reinvested distributions of $260 million, of which $250 million related to our participation. In addition, in August 2016, WPZ completed an equity issuance of 6,975,446 common units sold to us in a private placement transaction for an aggregate purchase price of $250 million.
The above transactions, WPZ’s quarterly distribution of additional paid-in-kind Class B units to us, and other equity issuances by WPZ had the combined net impact of decreasing Noncontrolling interests in consolidated subsidiaries by $18 million, and increasing Capital in excess of par value by $12 million and Deferred income tax liabilities by $6 million in the Consolidated Balance Sheet.
WPZ is self-funding and maintains separate lines of bank credit and cash management accounts and also has a commercial paper program. (See Note 14 – Debt, Banking Arrangements, and Leases.) Cash distributions from WPZ to all partners, including us, are governed by WPZ’s partnership agreement.
Discontinued operations
Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our continuing operations.
Significant risks and uncertainties
We have announced plans to monetize our olefins production plant in Geismar, Louisiana, as well as other select assetsbelieve that are not core to our strategy. As we pursue these other select asset monetizations, it is possible that we may incur impairmentsthe carrying value of certain equity-method investments,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 impairmentstransactions or developments may also indicate that certain of our equity-method investments have experienced other-than-temporary declines in value, which could potentially be caused by indications ofresult in impairment, or that the fair value implied through the monetization process or, in the case of asset dispositions that are part of a broader asset group, the impact of the loss of future estimated cash flows.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. Management’sOur judgment is required to evaluate whether we control an entity. Key areas of that evaluation include:
Determining whether an entity is a VIE;
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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;
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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;
RealizationDepreciation and/or amortization of deferred income taxlong-lived assets;
Depreciation and/or amortization of equity-method investment basis differences;
Asset retirement obligations;obligations (AROs);
Pension and postretirement valuation variables;
AcquisitionMeasurement of regulatory liabilities;
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Measurement of deferred income tax assets and liabilities, including assumptions related purchaseto the realization of deferred income tax assets;
Revenue recognition, including estimates utilized in recognition of deferred revenue;
Purchase price allocations.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, our management haswe 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
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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, and pension and other postretirement benefits. 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.
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Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 20162019 and 20152018 are as follows:
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| | 2019 | | 2018 |
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Current assets reported within Other current assets and deferred charges | $ | 72 |
| | $ | 103 |
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Noncurrent assets reported within Regulatory assets, deferred charges, and other | 466 |
| | 495 |
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| Total regulated assets | $ | 538 |
| | $ | 598 |
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Current liabilities reported within Accrued liabilities | $ | 60 |
| | $ | 5 |
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Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other | 1,277 |
| | 1,321 |
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| Total regulated liabilities | $ | 1,337 |
| | $ | 1,326 |
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| | December 31, |
| | 2016 | | 2015 |
| | (Millions) |
Current assets reported within Other current assets and deferred charges | $ | 91 |
| | $ | 84 |
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Noncurrent assets reported within Regulatory assets, deferred charges, and other | 387 |
| | 370 |
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| Total regulated assets | $ | 478 |
| | $ | 454 |
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Current liabilities reported within Accrued liabilities | $ | 11 |
| | $ | 4 |
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Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other | 498 |
| | 434 |
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| Total regulated liabilities | $ | 509 |
| | $ | 438 |
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Cash and cash equivalents
Cash and cash equivalents in the Consolidated Balance Sheet includes amounts primarily invested in funds consist of highly liquid investments with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity datesoriginal 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 natural gas liquids, olefins,NGLs, natural gas in underground storage, and materials and supplies and are stated at the lower of cost or market.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
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We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. As regulated entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that is attributable to capitalized ARO cost to a regulatory asset as management expectswe 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, a computation ofan impairment charge is recorded for the implied fair value of the goodwill is compared with its related carrying value. Ifdifference (not to exceed the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess.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 management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s 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.
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We evaluate our investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. 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 management’s estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal.
Deferred income
We record a liability for deferred income related to cash received from customers in advance of providing our services. Such amounts are generally recognized in revenue upon satisfying our performance obligations, primarily providing services based on units of production or over remaining contractual service periods ranging from 1 to 25 years. Deferred incomeis reflected within Accrued liabilities and Regulatory liabilities, deferred income, and other on the Consolidated Balance Sheet. (See Note 13 – Accrued Liabilities.)
During 2016, we received cash proceeds totaling $820 million associated with restructuring certain gas gathering contracts in the Barnett Shale and Mid-Continent regions. The proceeds were recorded as deferred incomeand are being amortized into income in 2016 and future periods.
In October 2016, we received $104 million of newly constructed assets as part of a noncash investing transaction with a customer for which we provide production handling and other services. The transaction was recorded in Property, plant, and equipment – net and deferred income in the Consolidated Balance Sheet and is being amortized based on units of production through 2024. Due to the noncash nature of this transaction, it is not presented within the Consolidated Statement of Cash Flows.
Contingent liabilities
We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable, and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration 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 1415 – Debt and Banking Arrangements, and Leases.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.
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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 1718 – 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:
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| 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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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 effective portion of the change in fair value of the derivative is reported in Accumulated other comprehensive income (loss) (AOCI)AOCI in the Consolidated Balance Sheet and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in Product sales or Product costs in the Consolidated Statement of Operations. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in Product sales or Product costs in the Consolidated Statement of Operations at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by management.us.
For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in Product sales or Product costs in the Consolidated Statement of Operations.
Certain gains and losses on derivative instruments included in the Consolidated Statement of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded
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The Williams Companies, Inc. |
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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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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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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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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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Certain revenues from our midstream operations include those derived from natural gas gathering, processing, treating, and compression services and are performed under volumetric-based fee contracts. These revenues are recorded when services have been performed.
Certain of our gas gathering and processing agreements have minimum volume commitments.MVCs. If a customer under such an agreement fails to meet its minimum volume commitmentMVC for a specified period, generally measured on an annual basis, it is obligated to pay a contractually determined fee based upon the shortfall between actual production volumes and the minimum volume commitmentMVC for that period. The revenue associated with minimum volume commitmentsMVCs 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.
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We market NGLs, crude oil, and natural gas and olefins that we purchase from our producer customers as part of the overall service provided to producers. Revenues from marketing NGLsactivities 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 producesproduced olefins from purchased or produced feedstock and we recognizerecognized revenues when the olefins are sold and delivered.
Our Canadian businesses that were sold in September 2016 had processing and fractionation operations where we retained certain NGLs and olefins from an upgrader’s offgas stream and we recognized revenues when the fractionated products were sold and delivered.
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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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 net of estimated forfeitures, on a straight-line basis.basis; forfeitures are recognized when they occur. (See Note 1617 – 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.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.cost (credit). Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation or the market-related value of plan assets are amortized over the participants’ average remaining future years of service, which is approximately 13 years for our pension plans and approximately 7 years for our other postretirement benefit plans. Unrecognized prior service costs and credits for the other postretirement benefit plans are amortized on a straight line basis over the average remaining years of service to eligibility for eligible plan participants, which is approximately 4 years.
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The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
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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 value of plan assets for our other postretirement benefit plans is equal to the unadjusted fair value of plan assets at the beginning of the year.
Income taxes
We include the operations of our domestic corporate subsidiaries and income from our subsidiary partnerships in our consolidated federal income tax return and also file tax returns in various foreign and state jurisdictions as required. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of our assets and liabilities. Our management’s judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets.
Earnings (loss) per common share
Basic earnings (loss) per common share in the Consolidated Statement of Operations is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share in the Consolidated Statement of Operations includes any dilutive effect of stock options, nonvested restricted stock units, and convertible debt, unless otherwise noted. Diluted earnings (loss) per common share are calculated using the treasury-stock method.
Foreign currency translation
Certain of our foreign subsidiaries that used the Canadian dollar as their functional currency were sold in 2016. The assets and liabilities of such foreign subsidiaries were translated at the spot rate in effect at the applicable reporting date, and the combined statements of operations were translated into the U.S. dollar at the average exchange rates in effect during the applicable period. The resulting cumulative translation adjustment was recorded as a separate component of AOCI in the Consolidated Balance Sheet.
Transactions denominated in currencies other than the functional currency were recorded based on exchange rates at the time such transactions arose. Subsequent changes in exchange rates when the transactions were settled resulted in transaction gains and losses which were reflected in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Operations. Substantially all of our Canadian operations were sold in September 2016.
Accounting standards issued but not yet adopted
In January 2017, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2017-04 “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment” (ASU 2017-04). ASU 2017-04 modifies the concept of goodwill impairment to represent the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. Under ASU 2017-04, entities will no longer be required to determine the implied fair value of goodwill by assigning the fair value of a reporting unit to its individual assets and liabilities as if that reporting unit had been acquired in a business combination. ASU 2017-04 is effective for goodwill impairment testing for interim and annual periods beginning after December 15, 2019, and requires a prospective transition. Early adoption is permitted for interim and annual goodwill impairment tests performed after January 1, 2017, and we plan to adopt this standard in 2017. Our Williams Partners reportable segment has $47 million of goodwill included in Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet (see Note 12 – Goodwill and Other Intangible Assets).
In August 2016, the FASB issued ASU 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). ASU 2016-15 provides specific guidance on eight cash flow classification issues, including debt prepayment or debt extinguishment costs and distributions received from equity
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| Notes to Consolidated Financial Statements – (Continued) |
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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 investees, 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 reduce diversitydetermine the levels, if any, of valuation allowances associated with deferred tax assets.
Earnings (loss) per common share
Basic earnings (loss) per common share in practice.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 2016-152016-02 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, 2017. Early2018. 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 is permitted. ASU 2016-15 requires a retrospective transition. We are evaluating the impact of ASU 2016-152016-02. 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 Sheetfor operating leases. We also evaluated ASU 2016-02’s available practical expedients on our consolidated financial statements.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. Early adoption is permitted.We are adopting ASU 2016-13 requires varying transition methods for the different categories of amendments.effective January 1, 2020. We are evaluating the impact ofanticipate that ASU 2016-13 onwill primarily apply to our consolidated financial statements. Althoughtrade receivables. While we do not expect ASU 2016-13 to have a significant financial impact, it will impactwe have analyzed our trade receivables as the related allowance forhistorical credit losses will be recognized earlier under theloss experience, and considered current conditions and reasonable forecasts, in developing our expected credit loss model than under our current policy.
In March 2016, the FASB issued ASU 2016-09 “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting” (ASU 2016-09). The objective of ASU 2016-09 is to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities,rate, and classification on the statement of cash flows. ASU 2016-09 is effective for interim and annual periods beginning after December 15, 2016. We adopted ASU 2016-09 effective January 1, 2017. The standard requires varying transition methods for the different categories of amendments. ASU 2016-09 will not have a material effect on our consolidated financial statements.
In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 clarifies the definition of a lease, requires a dual approach to lease classification similar to current lease classifications, and causes lessees to recognize leases on the balance sheet as a lease liability with a corresponding right-of-use asset. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. ASU 2016-02 requires a modified retrospective transition for capital or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. We are reviewing contracts to identify leases, particularly reviewing the applicability of ASU 2016-02 to contracts involving easements/rights-of-way.
In May 2014, the FASB issued ASU 2014-09 establishing Accounting Standards Codification (ASC) Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016.
We continue to evaluate the impact the standard may have on our financial statements. For each revenue contract type, we are conducting a formal contract review process to evaluate the impact, if any, that the new revenue standard may have. We have substantially completed that process, but continue to evaluate our accounting for noncash consideration, which exists in contracts where we receive commodities as full or partial consideration, contracts with a significant financing component, which may exist in situations where the timing of the consideration we received varies significantly from the timing of the service we provide,develop and the accounting for contributions in aid of construction. As such, we are unable to determine the potential impact upon the amount and timing of revenue recognition and related disclosures. Additionally, we have identified possible financial systemimplement processes, procedures, and internal control changescontrols in order to make the necessary forcredit loss assessments and required disclosures upon adoption. We currently anticipate utilizing a modified retrospective transition upon the adoption of ASC 606 as of January 1, 2018.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Note 2 – AcquisitionsRevenue Recognition
ACMPRevenue by Category
On December 20, 2012, we purchased approximately 24 percent of ACMP’s outstanding limited partnership units and 50 percent of the ACMP general partner 2 percent interest which included IDRs for approximately $2.19 billion in cash, including transaction costs. We accounted for these acquired interests as equity-method investments.
On July 1, 2014, we acquired control of ACMP (ACMP Acquisition) through the acquisition of an additional 26 percent of ACMP’s outstanding limited partnership units and the remaining 50 percent interest in the general partner for $5.995 billion in cash. The acquisition was funded through the issuance of equity (see Note 15 – Stockholders' Equity) and debt, credit facility borrowings, and cash on hand.
At the time of acquisition, ACMP owned, operated, developed, and acquired natural gas gathering systems and other midstream energy assets. The purpose of the acquisition was to enhance our position in the Marcellus and Utica Shale plays, provide additional diversity via the Eagle Ford, Haynesville, Barnett, Mid-Continent, and Niobrara areas, and to fortify our stable, fee-based business model and support our dividend growth strategy.
Our basis in ACMP reflects business combination accounting, which, among other things, requires identifiable assets acquired and liabilities assumed to be measured at their acquisition-date fair values. Prior to the ACMP Acquisition we accounted for our investment in ACMP using the equity method. The acquisition-date fair value of our equity-method investment in ACMP was $4.6 billion. As a result of remeasuring our equity-method investment to fair value, for the year ended December 31, 2014 we recognized a $2.5 billion noncash gain within the Gain on remeasurement of equity-method investment line item in the Consolidated Statement of Operations.
The valuation techniques used to measure the acquisition-date fair value of the ACMP Acquisition, including our previous equity-method investment in ACMP, consisted of valuing the limited partner units and general partner interest separately. The limited partner units, consisting of common and Class B units, were valued based on ACMP’s closing common unit price at July 1, 2014. The general partner interest, including IDRs, was valued on a noncontrolling basis using an income approach based on a discounted cash flow analysis and a market comparison analysis based on comparable guideline companies and an implied fair value from our purchase.
The following table presents the allocation of the acquisition-date fair value of theour revenue disaggregated by major classes of the assets acquired, which are presented in the Williams Partners segment, liabilities assumed, and noncontrolling interest at July 1, 2014. The fair value of accounts receivable acquired equaled contractual amounts receivable. Changes to the preliminary allocation disclosed in Exhibit 99.1 of our Form 8-K dated May 6, 2015, which were recorded in the first quarter of 2015, reflect an increase of $150 million in Property, plant, and equipment and $25 million in Goodwill, and a decrease of $168 million in Other intangible assets and $7 million in Investments. These adjustments during the measurement period were not considered significant to require retrospective revisions of our financial statements.service line:
|
| | | |
| | (Millions) |
| Accounts receivable | $ | 168 |
|
| Other current assets | 63 |
|
| Investments | 5,865 |
|
| Property, plant, and equipment | 7,165 |
|
| Goodwill | 499 |
|
| Other intangible assets | 8,841 |
|
| Current liabilities | (408 | ) |
| Debt | (4,052 | ) |
| Other noncurrent liabilities | (9 | ) |
| Noncontrolling interest in ACMP’s subsidiaries | (958 | ) |
| Noncontrolling interest in ACMP | (6,544 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Transco | | Northwest Pipeline | | Atlantic-
Gulf Midstream | | Northeast Midstream | | West Midstream | | Other | | Eliminations | | Total |
| | (Millions) |
| 2019 | | |
| Revenues from contracts with customers: | | | | | | | | | | | | | | | |
| Service revenues: | | | | | | | | | | | | | | | |
| Non-regulated gathering, processing, transportation, and storage: | | | | | | | | | | | | | | | |
| Monetary consideration | $ | — |
| | $ | — |
| | $ | 479 |
| | $ | 1,171 |
| | $ | 1,309 |
| | $ | — |
| | $ | (75 | ) | | $ | 2,884 |
|
| Commodity consideration | — |
| | — |
| | 41 |
| | 12 |
| | 150 |
| | — |
| | — |
| | 203 |
|
| Regulated interstate natural gas transportation and storage | 2,336 |
| | 450 |
| | — |
| | — |
| | — |
| | — |
| | (6 | ) | | 2,780 |
|
| Other | 11 |
| | — |
| | 26 |
| | 147 |
| | 42 |
| | — |
| | (16 | ) | | 210 |
|
| Total service revenues | 2,347 |
| | 450 |
| | 546 |
| | 1,330 |
| | 1,501 |
| | — |
| | (97 | ) | | 6,077 |
|
| Product Sales: | | | | | | | | | | | | | | | |
| NGL and natural gas | 106 |
| | — |
| | 185 |
| | 150 |
| | 1,795 |
| | — |
| | (173 | ) | | 2,063 |
|
| Total revenues from contracts with customers | 2,453 |
| | 450 |
| | 731 |
| | 1,480 |
| | 3,296 |
| | — |
| | (270 | ) | | 8,140 |
|
| Other revenues (1) | 1 |
| | — |
| | 8 |
| | 20 |
| | 14 |
| | 30 |
| | (12 | ) | | 61 |
|
| Total revenues | $ | 2,454 |
| | $ | 450 |
| | $ | 739 |
| | $ | 1,500 |
| | $ | 3,310 |
| | $ | 30 |
| | $ | (282 | ) | | $ | 8,201 |
|
| | | | | | | | | | | | | | | | |
| 2018 | | |
| Revenues from contracts with customers: | | | | | | | | | | | | | | | |
| Service revenues: | | | | | | | | | | | | | | | |
| Non-regulated gathering, processing, transportation, and storage: | | | | | | | | | | | | | | | |
| Monetary consideration | $ | — |
| | $ | — |
| | $ | 541 |
| | $ | 861 |
| | $ | 1,590 |
| | $ | 2 |
| | $ | (73 | ) | | $ | 2,921 |
|
| Commodity consideration | — |
| | — |
| | 59 |
| | 20 |
| | 321 |
| | — |
| | — |
| | 400 |
|
| Regulated interstate natural gas transportation and storage | 1,921 |
| | 443 |
| | — |
| | — |
| | — |
| | — |
| | (2 | ) | | 2,362 |
|
| Other | 2 |
| | — |
| | 17 |
| | 94 |
| | 46 |
| | — |
| | (15 | ) | | 144 |
|
| Total service revenues | 1,923 |
| | 443 |
| | 617 |
| | 975 |
| | 1,957 |
| | 2 |
| | (90 | ) | | 5,827 |
|
| Product Sales: | | | | | | | | | | | | | | | |
| NGL and natural gas | 127 |
| | — |
| | 307 |
| | 287 |
| | 2,421 |
| | — |
| | (382 | ) | | 2,760 |
|
| Other | — |
| | — |
| | — |
| | — |
| | 21 |
| | — |
| | (4 | ) | | 17 |
|
| Total product sales | 127 |
| | — |
| | 307 |
| | 287 |
| | 2,442 |
| | — |
| | (386 | ) | | 2,777 |
|
| Total revenues from contracts with customers | 2,050 |
| | 443 |
| | 924 |
| | 1,262 |
| | 4,399 |
| | 2 |
| | (476 | ) | | 8,604 |
|
| Other revenues (1) | 11 |
| | — |
| | 18 |
| | 21 |
| | 12 |
| | 32 |
| | (12 | ) | | 82 |
|
| Total revenues | $ | 2,061 |
| | $ | 443 |
| | $ | 942 |
| | $ | 1,283 |
| | $ | 4,411 |
| | $ | 34 |
| | $ | (488 | ) | | $ | 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. |
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Contract Assets
The following table presents a reconciliation of our contract assets:
|
| | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 |
| | (Millions) |
| Balance at beginning of period | $ | 4 |
| | $ | 4 |
|
| Revenue recognized in excess of amounts invoiced | 62 |
| | 66 |
|
| Minimum volume commitments invoiced | (58 | ) | | (66 | ) |
| Balance at end of period | $ | 8 |
| | $ | 4 |
|
Contract Liabilities
The following table presents a reconciliation of our contract liabilities:
|
| | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 |
| | (Millions) |
| Balance at beginning of period | $ | 1,397 |
| | $ | 1,596 |
|
| Payments received and deferred | 157 |
| | 314 |
|
| Significant financing component | 13 |
| | 16 |
|
| Deconsolidation of Jackalope interest (Note 6) | — |
| | (52 | ) |
| Deconsolidation of certain Permian assets (Note 6) | — |
| | (26 | ) |
| Recognized in revenue | (352 | ) | | (451 | ) |
| Balance at end of period | $ | 1,215 |
| | $ | 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.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
|
| | | | | | | |
| | Contract Liabilities | | Remaining Performance Obligations |
| | (Millions) |
| 2020 | $ | 160 |
| | $ | 3,418 |
|
| 2021 | 121 |
| | 3,241 |
|
| 2022 | 113 |
| | 3,117 |
|
| 2023 | 101 |
| | 2,524 |
|
| 2024 | 91 |
| | 2,339 |
|
| Thereafter | 629 |
| | 18,815 |
|
| Total | $ | 1,215 |
| | $ | 33,454 |
|
Note 3 – Acquisitions and Divestitures
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.
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 0 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.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
|
| | | |
| | (Millions) |
| Current assets, including $13 million cash acquired | $ | 55 |
|
| Property, plant, and equipment | 1,387 |
|
| Other intangible assets | 328 |
|
| Total identifiable assets acquired | 1,770 |
|
| | |
| Current liabilities | 7 |
|
| Total liabilities assumed | 7 |
|
| | |
| Net identifiable assets acquired | 1,763 |
|
| | |
| Goodwill | 188 |
|
| Net assets acquired | $ | 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 wasis 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 30a period of 20 years during which represents the term over which the contractual customer relationships are expected to contribute to our cash flows. As estimated at the time of acquisition, approximately 56Approximately 49 percent of the expected future revenues from these contractual customer relationships wereare 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 periodsperiod prior to the next renewal or extension of the existing contractual customer contracts wererelationships was approximately 1710 years.
The noncash adjustment to record the fair value of the noncontrolling interest in ACMP was determined based on the common units and ACMP’s closing common unit price at July 1, 2014.
The following unaudited pro forma Total revenuesRevenues and Net income (loss) attributable to The Williams Companies, Inc. for the yearyears ended December 31, 2014,2019 and 2018, respectively, are presented as if the ACMP AcquisitionUEOM acquisition had been completed on January 1, 2014.2018. 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 periodperiods indicated, nor do they purport to project Total revenuesRevenues 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 transactionstransaction or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements.
|
| | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 |
| | (Millions) |
| Revenues | $ | 8,233 |
| | $ | 8,836 |
|
| Net income (loss) attributable to The Williams Companies, Inc. | 928 |
| | (128 | ) |
|
| | | | |
| | | December 31, |
| | | 2014 |
| | | (Millions) |
| Total revenues | | $ | 8,181 |
|
| Net income (loss) attributable to The Williams Companies, Inc. | | $ | 622 |
|
Significant adjustmentsAdjustments to pro forma Net income (loss) attributable to The Williams Companies, Inc. include the removal of the previously described $2.5 billion gain on remeasurement of equity-method investment, and include additional depreciation and amortization expense associated with reflecting the acquired investments, property, plant, and equipment, and other intangible assets at fair value. The adjustments assume estimated useful lives of 30 years. Other significant adjustments to pro forma Net income (loss) attributable to The Williams Companies, Inc. include interest expense related to debt financing associated with the acquisition as well as Net income (loss) attributable to noncontrolling interests.
During the year ended December 31, 2014, ACMP contributed Total revenues of $781$74 million and Net income (loss) attributable to The Williams Companies, Inc. of $165 million.
Costs related to this acquisition were $16 millionimpairment loss recognized in 2014 and are reported within our Williams Partners segment and included in Selling, general, and administrative expenses in the Consolidated Statement of Operations. Direct transaction costs associated with financing commitments were $9 million in 2014 and reported within Interest incurred in the Consolidated Statement of Operations. Equity earnings (losses) within the Consolidated Statement of Operations in 2014 includes $19 million of equity losses associated with certain compensation-related costs at ACMP that were triggered by the acquisition.
Eagle Ford Gathering System
In May 2015, WPZ acquired a gathering system comprised of approximately 140 miles of pipeline and a sour gas compression facility in the Eagle Ford Shale for $112 million. The acquisition was accounted for as a business combination, and the allocation of the acquisition-date fair value of the major classes of assets acquired includes $80 million of Property, plant, and equipment – net and $32 million of Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet. ChangesMarch 2019 just prior to the preliminary allocation disclosed in the second quarter of 2015 reflectacquisition.
|
| | | | |
| 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 increaseagreement 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, $20as 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 Property, plant,the Consolidated Balance Sheet. Costs related to this transaction are $6 million and equipment – net,are reported within our Northeast G&P segment and a decreaseincluded in Selling, general, and administrative expenses in our Consolidated Statement of $20 million in Intangible assets – netOperations.
Sale of accumulated amortization.
UEOM Equity-Method InvestmentGulf Coast Pipeline Systems
In June 2015, WPZ acquired an approximate 13 percent additional interest in its equity-method investment, UEOM, for $357 million. Following the acquisition WPZ owns approximately 62 percent of UEOM. However, WPZ continues to account for this as an equity-method investment because WPZ does not control UEOM due to the significant participatory rights of its partner. In connection with the acquisition of the additional interest, we agreed to waive approximately $2 million of our WPZ IDR payments each quarter through 2017. See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies for discussion of agreement with WPZ wherein we permanently waived IDR payment obligations from WPZ.
Note 3 – Divestiture
In September 2016,November 2018, we completed the sale of subsidiaries conducting Canadiancertain assets and operations including subsidiarieslocated in the Gulf Coast area for $177 million in cash. As a result of WPZ, (such subsidiaries, the disposal group). Consideration received to date totaled $1.020 billion, net of $31 million of cash divested and subject to customary working capital adjustments. In connection with thethis sale, we waived $150recorded a gain of approximately $101 million of incentive distributions otherwise payable by WPZ to us in the fourth quarter of 20162018, consisting of $81 million in recognitionour Atlantic-Gulf segment and $20 million in Other.
Previous impairments made to a portion of certain affiliate contracts wherein WPZ’s Canadianthese assets and operations provided servicesinclude $66 million related to certain of our other businesses. The proceeds were primarily used to reduce borrowings on credit facilities.
Duringidle pipelines in the second quarter of 2016, we designated these operations2018, as held for sale. As a result, we measuredwell as $68 million and $23 million related to an NGL pipeline near the fair value of the disposal group as of June 30, 2016, resultingHouston Ship Channel region and project development costs associated with an olefins pipeline project, respectively, in an impairment charge of $747 million,2017. These impairments are reflected in Impairment of certain assets in the Consolidated Statement of Operations. (See Note 1718 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) DuringThe results of operations for this disposal group, excluding the second halfimpairments and gains noted, were not significant for the reporting periods.
Sale of 2016Four 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 an additional lossa gain of $66approximately $591 million upon completion ofwithin the sale, primarily reflecting revisions to the sales price and estimated contingent consideration and including a $15 million benefit related to transactions to hedge our foreign currency exchange risk on the Canadian proceeds, reflected in Other (income) expense – net within Costs and expenses West segment in the Consolidated Statementfourth quarter of Operations. The total loss consists of a loss of $34 million at Williams Partners and $32 million at Williams NGL & Petchem Services.2018.
The following table presents the results of operations for the disposal group,Four Corners area, excluding the impairment and lossgain noted above:
|
| | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 |
| | (Millions) |
| Income (loss) before income taxes of Four Corners area | $ | 52 |
| | $ | 47 |
|
| Income (loss) before income taxes of Four Corners area attributable to The Williams Companies, Inc. | 43 |
| | 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.
|
| | | | | | | |
| | Years Ended December 31, |
| | 2016 | | 2015 |
| | (Millions) |
| Income (loss) before income taxes of disposal group | $ | (98 | ) | | $ | 17 |
|
| Income (loss) before income taxes of disposal group attributable to The Williams Companies, Inc. | (95 | ) | | 15 |
|
|
| | | | |
| 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:
|
| | | |
| | Year Ended December 31, |
| | 2017 |
| | (Millions) |
| Income (loss) before income taxes of the Geismar Interest | $ | 26 |
|
| Income (loss) before income taxes of the Geismar Interest attributable to The Williams Companies, Inc. | 19 |
|
Note 4 – Variable Interest Entities
On January 1, 2016,Consolidated VIEs
As of December 31, 2019, we adopted ASU 2015-02 “Amendments to the Consolidation Analysis," which eliminated certain presumptions related to a general partner interest in a master limited partnership. As a result of adopting this new accounting standard, our consolidated master limited partnership is now a VIE. We are the primary beneficiary of WPZ because we have the power to direct the activities that most significantly impact WPZ’s economic performance.
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of WPZ and/or its subsidiaries, and which comprise a significant portion of our consolidated assets and liabilities:
|
| | | | | | | | | |
| | December 31, | | |
| | 2016 | | 2015 | | Classification |
| | (Millions) | | |
| Assets (liabilities): | | | | | |
| Cash and cash equivalents | $ | 145 |
| | $ | 73 |
| | Cash and cash equivalents |
Trade accounts and other receivables – net | 925 |
| | 1,026 |
| | Trade accounts and other receivables |
| Inventories | 138 |
| | 127 |
| | Inventories |
| Other current assets | 205 |
| | 190 |
| | Other current assets and deferred charges |
| Investments | 6,701 |
| | 7,336 |
| | Investments |
Property, plant, and equipment – net | 28,021 |
| | 28,593 |
| | Property, plant, and equipment – net |
Intangible assets – net | 9,662 |
| | 10,016 |
| | Intangible assets – net of accumulated amortization |
| Regulatory assets, deferred charges, and other noncurrent assets | 467 |
| | 479 |
| | Regulatory assets, deferred charges, and other |
| Accounts payable | (589 | ) | | (625 | ) | | Accounts payable |
| Accrued liabilities including current asset retirement obligations | (1,122 | ) | | (757 | ) | | Accrued liabilities |
| Commercial paper | (93 | ) | | (499 | ) | | Commercial paper |
| Long-term debt due within one year | (785 | ) | | (176 | ) | | Long-term debt due within one year |
| Long-term debt | (17,685 | ) | | (19,001 | ) | | Long-term debt |
| Deferred income tax liabilities | (20 | ) | | (119 | ) | | Deferred income tax liabilities |
| Noncurrent asset retirement obligations | (798 | ) | | (857 | ) | | Regulatory liabilities, deferred income, and other |
| Regulatory liabilities, deferred income, and other noncurrent liabilities | (1,860 | ) | | (1,066 | ) | | Regulatory liabilities, deferred income, and other |
The assets and liabilities presented in the table above also include the consolidated interests ofconsolidate the following individual VIEs within WPZ:VIEs:
Gulfstar One
WPZ ownsWe own a 51 percentinterest in Gulfstar One, LLC (Gulfstar One), a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. Gulfstar One includes a proprietary floating-production system, Gulfstar FPS, and associated pipelines which provide production handling and gathering services for the Tubular Bells oil and gas discovery in the eastern deepwater Gulf of Mexico. WPZ isWe are the primary beneficiary because it haswe have the power to direct the activities that most significantly impact Gulfstar One’s economic performance.
ConstitutionCardinal
WPZ ownsWe own a 4166 percent interest in Constitution,Cardinal, a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to shipper fixed-payment commitments under its long-term firm transportation contracts, is a VIE. WPZ iscertain risks shared with customers. We are the primary beneficiary because it haswe have the power to direct the activities that most significantly impact Constitution’sCardinal’s economic performance. WPZ, as construction manager for Constitution,Future expansion activity is responsible for constructing the proposed pipeline connecting its gathering system in Susquehanna County, Pennsylvania,expected to the Iroquois Gas Transmissionbe funded with capital contributions from us and the Tennessee Gas Pipeline systems.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 total remainingNortheast 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.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
costThe 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 | $ | 102 |
| | $ | 33 |
|
| Trade accounts and other receivables – net | 167 |
| | 62 |
|
| Other current assets and deferred charges | 5 |
| | 2 |
|
| Property, plant, and equipment – net | 5,745 |
| | 2,363 |
|
| Intangible assets – net of accumulated amortization | 2,669 |
| | 1,177 |
|
| Regulatory assets, deferred charges, and other | 13 |
| | — |
|
| Accounts payable | (58 | ) | | (15 | ) |
| Accrued liabilities | (66 | ) | | (115 | ) |
| Regulatory liabilities, deferred income, and other | (283 | ) | | (264 | ) |
Nonconsolidated VIEs
Jackalope
At December 31, 2018, we owned a50 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 is estimatedextending from Susquehanna County, Pennsylvania, to be approximately $687 million, which is expected to be funded with capital contributions from WPZthe Iroquois Gas Transmission and the other equity partners onTennessee Gas Pipeline systems in New York. Constitution was considered a proportional basis.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.
In December 2014, weAlthough Constitution received approvala certificate of public convenience and necessity from the FERC to construct and operate the Constitution pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) deniedproposed pipeline and obtained, among other approvals, a necessary water quality certification for the New York portionwaiver of the Constitution pipeline. We remain steadfastly committed to the project, and in May 2016, Constitution appealed the NYSDEC's denial of the certification and filed an action in federal court seeking a declaration that the State of New York's authority to exercise permitting jurisdiction over certain other environmental matters is preempted by federal law. The oral argument before the Second Circuit Court of Appeals regarding the NYSDEC’s denial of Constitution’s application for water quality certification under Section 401 of the Clean Water Act was held on November 16, 2016. We anticipate a decision fromfor the Second Circuit Court of Appeals as early as second quarter 2017. In light of the NYSDEC's denial of the water quality certification and the actions taken to challenge the decision, the project in-service date is targeted as early as the second half of 2018, which assumes that the legal challenge process is satisfactorily and promptly concluded. An unfavorable resolution could result in the impairment of a significantNew 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 total $381considered 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 on a consolidated basis at December 31, 2016, and are includedshare of this impairment is reflected within Property, plant, and equipment – net Net income (loss) attributable to noncontrolling interestsin the Consolidated Balance Sheet. Beginning in April 2016, we discontinued capitalizationStatement of development costs related to this project. ItOperations.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
Constitution is also possible that we could incur certain supplier-related costs in the event of a prolonged delay or termination of the project.
Cardinal
WPZ owns a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal), a subsidiary that provides gathering services for the Utica Shale region and isstill considered a VIE due to certain risks shared with customers. WPZ isinsufficient equity at risk, but we are no longer the primary beneficiary because it hasbeneficiary. As a result, we deconsolidated Constitution as of December 31, 2019, recognizing a loss on deconsolidation of $27 million in the power to directfourth quarter of 2019, which is included in Other investing income (loss) - net in the activities that most significantly impact Cardinal’s economic performance. Future expansion activity is expected to be funded with capital contributions from WPZ and the other equity partner on a proportional basis.
Jackalope
WPZ owns a 50 percent interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope), a subsidiary that provides gathering and processing services for the Powder River basin and is a VIE due to certain risks shared with customers. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Jackalope’s economic performance. Future expansion activity is expected to be funded with capital contributions from WPZ and the other equity partner on a proportional basis.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 costsin the Consolidated Statement of Operationsof $180$304 million, $187$236 million,, and $197$226 million for the years ended 2016, 2015,2019, 2018, and 2014,2017, respectively. We have $19$36 million and $12$18 million included in Accounts payablein the Consolidated Balance Sheetwith our equity-method investees at December 31, 20162019 and 2015,2018, respectively.
WPZ hasWe have operating agreements with certain equity-method investees. These operating agreements typically provide for reimbursement or payment to WPZus for certain direct operational payroll and employee benefit costs, materials, supplies, and other charges and also for management services. We supplied a portion of these services, primarily those related to employees since WPZ does not have any employees, to certain equity-method investees. The total charges to equity-method investees for these fees are $66$103 million, $64$75 million, and $65$67 million for the years ended 2016, 2015,2019, 2018, and 2014,2017, respectively.
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
Board of Directors
A former member of our Board of Directors, who was elected in 2013 and resigned during 2016, is also the current chairman, president, and chief executive officer of an energy services company that is a customer of ours. We recorded $144 million, $111 million, and $115 million in Service revenues in the Consolidated Statement of Operations from this company for transportation and storage of natural gas for the years ended December 31, 2016, 2015, and 2014, respectively.
Note 6 – Investing Activities
Impairment of equity-method investments
The following table presents other-than-temporary impairment charges related to certain equity-method investments (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk):
|
| | | | | | | | |
| | | Years Ended December 31, |
| | | 2016 | | 2015 |
| | | (Millions) |
| Williams Partners | | | | |
| Appalachia Midstream Investments | | $ | 294 |
| | $ | 562 |
|
| DBJV | | 59 |
| | 503 |
|
| Laurel Mountain | | 50 |
| | 45 |
|
| UEOM | | — |
| | 241 |
|
| Ranch Westex | | 24 |
| | — |
|
| Other | | 3 |
| | 8 |
|
| | | $ | 430 |
| | $ | 1,359 |
|
Equity earnings (losses)
Equity earnings (losses) in 2015 includes a loss of $19 million associated with WPZ’s share of underlying property impairments at certain of the Appalachia Midstream Investments. This loss is reported within the Williams Partners segment.
Equity earnings (losses) in 2014 includes:
Write-offs of capitalized project development costs on our discontinued investments in Bluegrass Pipeline Company LLC (Bluegrass) of $67 million and Moss Lake Fractionation LLC and Moss Lake LPG Terminal LLC (collectively referred to as Moss Lake) of $4 million;
A $7 million equity loss recognized from our interest in ACMP that was accounted for under the equity-method of accounting for the first six months of the year, including $19 million of equity losses associated with certain compensation-related costs at ACMP that were triggered by the acquisition and $30 million noncash amortization of the difference between the cost of our investment and our underlying share of the net assets for the first six months of the year.
Other investing income (loss) – net
In 2016, we recognized a $27 million gain from the sale of an equity-method investment interestThe following table presents certain items reflected in a gathering system that was part of the Appalachia Midstream Investments within the Williams Partners segment.
Other investing income (loss) – net also includes $36 million, in the Consolidated Statement of Operations:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (Millions) |
| Impairment of equity-method investments (Note 18) | $ | (186 | ) | | $ | (32 | ) | | $ | — |
|
| Gain (loss) on deconsolidation of businesses | (29 | ) | | 203 |
| | — |
|
| Gain on disposition of equity-method investments | 122 |
| | — |
| | 269 |
|
| Other | 14 |
| | 16 |
| | 13 |
|
Other investing income (loss) – net | $ | (79 | ) | | $ | 187 |
| | $ | 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 $41crude 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 income for 2016, 2015 and 2014, respectively, associated withover the carrying value of the assets contributed. We estimated the fair value of our interest to be $192 million primarily using a receivable relatedmarket 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 salefact that we are able to exert significant influence over its operating and financial policies.
RMM Equity-Method Investment
During the third quarter of certain former Venezuela assets. Due2018, 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 changes in circumstances that led to late payments and increased uncertainty regarding50 percent at December 31, 2018, based on additional capital contributions made after the recovery of the receivable, we began accounting for the receivable under a cost recovery model in first quarter 2015. Subsequently,initial purchase.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Jackalope Deconsolidation
During the second quarter of 2018, we received payments greater thandeconsolidated 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 remaining carrying amountConsolidated 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 receivable, whichcost 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 recognitionConsolidated Statement of interest income.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.
|
| | | | | | | | | |
| | Ownership Interest at December 31, 2016 | | December 31, |
| | | 2016 | | 2015 |
| | | | (Millions) |
| Equity-method investments: | | | | | |
| Appalachia Midstream Investments | (1) | | $ | 2,062 |
| | $ | 2,464 |
|
| UEOM | 62% | | 1,448 |
| | 1,525 |
|
| DBJV | 50% | | 988 |
| | 977 |
|
| Discovery | 60% | | 572 |
| | 602 |
|
| OPPL | 50% | | 430 |
| | 445 |
|
| Caiman II | 58% | | 426 |
| | 418 |
|
| Laurel Mountain | 69% | | 324 |
| | 391 |
|
| Gulfstream | 50% | | 261 |
| | 293 |
|
| Other | Various | | 190 |
| | 221 |
|
| | | | $ | 6,701 |
| | $ | 7,336 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
Equity-Method Investments |
| | | | | | | | | |
| | Ownership Interest at December 31, 2019 | | December 31, |
| | | 2019 | | 2018 |
| | | | (Millions) |
| Appalachia Midstream Investments | (1) | | $ | 3,236 |
| | $ | 3,218 |
|
| RMM | 50% | | 881 |
| | 776 |
|
| Discovery | 60% | | 472 |
| | 507 |
|
| Caiman II | 58% | | 428 |
| | 412 |
|
| OPPL | 50% | | 403 |
| | 415 |
|
| Laurel Mountain | 69% | | 249 |
| | 314 |
|
| Gulfstream | 50% | | 217 |
| | 225 |
|
| Brazos Permian II | 15% | | 194 |
| | 191 |
|
| UEOM | (2) | | — |
| | 1,293 |
|
| Jackalope | (3) | | — |
| | 343 |
|
| Other | Various | | 155 |
| | 127 |
|
| | | | $ | 6,235 |
| | $ | 7,821 |
|
___________
| |
| (1) | Includes equity-method investments in multiple gathering systems in the Marcellus Shale with an approximate average 4166 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 $1.9$1 billion at December 31, 20162019 and $2.4$1.8 billion at December 31, 2015.2018. These differences primarily relate to our investments in AppalachianAppalachia Midstream Investments DBJV, and(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:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (Millions) |
| RMM | $ | 145 |
| | $ | 795 |
| | $ | — |
|
| Appalachia Midstream Investments | 140 |
| | 246 |
| | 70 |
|
| Laurel Mountain | 36 |
| | 16 |
| | — |
|
| Caiman II | 28 |
| | — |
| | 24 |
|
| Jackalope | 24 |
| | 42 |
| | — |
|
| Brazos Permian II | 18 |
| | 27 |
| | — |
|
| Discovery | — |
| | 5 |
| | 1 |
|
| DBJV | — |
| | — |
| | 32 |
|
| Other | 62 |
| | 1 |
| | 5 |
|
| | $ | 453 |
| | $ | 1,132 |
| | $ | 132 |
|
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (Millions) |
| DBJV | $ | 105 |
| | $ | 57 |
| | $ | 20 |
|
| Appalachia Midstream Investments | 28 |
| | 93 |
| | 84 |
|
| Caiman II | 22 |
| | — |
| | 175 |
|
| UEOM | — |
| | 357 |
| | 57 |
|
| Discovery | — |
| | 35 |
| | 106 |
|
| Other | 22 |
| | 53 |
| | 40 |
|
| | $ | 177 |
| | $ | 595 |
| | $ | 482 |
|
|
| | | | |
| 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 interestinvestment 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:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (Millions) |
| Appalachia Midstream Investments | $ | 293 |
| | $ | 297 |
| | $ | 270 |
|
| Gulfstream | 86 |
| | 93 |
| | 92 |
|
| OPPL | 77 |
| | 73 |
| | 68 |
|
| Caiman II | 42 |
| | 46 |
| | 49 |
|
| Discovery | 41 |
| | 45 |
| | 127 |
|
| RMM | 38 |
| | — |
| | — |
|
| Laurel Mountain | 30 |
| | 23 |
| | 32 |
|
| UEOM | 13 |
| | 70 |
| | 80 |
|
| DBJV | — |
| | — |
| | 39 |
|
| Other | 37 |
| | 46 |
| | 27 |
|
| | $ | 657 |
| | $ | 693 |
| | $ | 784 |
|
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (Millions) |
| Appalachia Midstream Investments | $ | 211 |
| | $ | 219 |
| | $ | 130 |
|
| Discovery | 141 |
| | 116 |
| | 36 |
|
| Gulfstream | 100 |
| | 88 |
| | 81 |
|
| UEOM | 92 |
| | 42 |
| | — |
|
| OPPL | 69 |
| | 45 |
| | 27 |
|
| Caiman II | 40 |
| | 33 |
| | 13 |
|
| DBJV | 39 |
| | 33 |
| | — |
|
| Laurel Mountain | 28 |
| | 31 |
| | 39 |
|
| ACMP | — |
| | — |
| | 64 |
|
| Other | 22 |
| | 26 |
| | 50 |
|
| | $ | 742 |
| | $ | 633 |
| | $ | 440 |
|
In addition, on September 24, 2015, WPZ received a special distribution of $396 million from Gulfstream reflecting its proportional share of the proceeds from new debt issued by Gulfstream. The new debt was issued to refinance Gulfstream’s debt maturities. Subsequently, WPZ contributed $248 million and $148 million to Gulfstream for its proportional share of amounts necessary to fund debt maturities of $500 million due on November 1, 2015, and $300 million due on June 1, 2016, respectively.
Summarized Financial Position and Results of Operations of All Equity-Method Investments
| | | | December 31, | December 31, |
| | 2016 | | 2015 | 2019 | | 2018 |
| | (Millions) | (Millions) |
| Assets (liabilities): | | | | | | |
| Current assets | $ | 508 |
| | $ | 773 |
| $ | 581 |
| | $ | 834 |
|
| Noncurrent assets | 9,695 |
| | 9,549 |
| 11,966 |
| | 13,199 |
|
| Current liabilities | (412 | ) | | (633 | ) | (341 | ) | | (605 | ) |
| Noncurrent liabilities | (1,484 | ) | | (1,450 | ) | (2,532 | ) | | (2,491 | ) |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (Millions) |
| Gross revenue | $ | 2,490 |
| | $ | 2,411 |
| | $ | 1,961 |
|
| Operating income | 685 |
| | 804 |
| | 871 |
|
| Net income | 598 |
| | 795 |
| | 806 |
|
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (Millions) |
| Gross revenue | $ | 1,883 |
| | $ | 1,707 |
| | $ | 1,623 |
|
| Operating income | 799 |
| | 690 |
| | 534 |
|
| Net income | 726 |
| | 611 |
| | 460 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Note 7 – Other Income and Expenses
The following table presentstables present by segment, certain gains or losses reflectedother items included in Other (income) expense – net within Costs and expenses in the 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 |
|
| Net accrual (amortization) of regulatory liability related to overcollection of certain employee expenses | (17 | ) | | 22 |
| | 22 |
|
| Project development costs related to Constitution (see Note 4) | 3 |
| | 4 |
| | 16 |
|
| Amortization of regulatory liability associated with Tax Reform | (26 | ) | | — |
| | — |
|
| Gains on asset retirements | — |
| | (12 | ) | | — |
|
| | | | | | |
| West | | | | | |
| Regulatory charge per approved rates related to Tax Reform | 24 |
| | 24 |
| | — |
|
| Charge for regulatory liability associated with the decrease in Northwest Pipeline’s estimated deferred state income tax rates following WPZ Merger | — |
| | 12 |
| | — |
|
| Gains on contract settlements and terminations | — |
| | — |
| | (15 | ) |
| | | | | | |
| Other | | | | | |
| Change to (benefit of) regulatory asset associated with Transco’s estimated deferred state income tax rate following WPZ Merger | 12 |
| | (37 | ) | | — |
|
| Gain on sale of refinery grade propylene splitter | — |
| | — |
| | (12 | ) |
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (Millions) |
| Williams Partners | | | | | |
| Loss on sale of Canadian operations (Note 3) | $ | 34 |
| | $ | — |
| | $ | — |
|
| Amortization of regulatory assets associated with asset retirement obligations | 33 |
| | 33 |
| | 33 |
|
| Accrual of regulatory liability related to overcollection of certain employee expenses | 25 |
| | 20 |
| | 14 |
|
| Project development costs related to Constitution (Note 4) | 28 |
| | — |
| | — |
|
| Net foreign currency exchange (gains) losses (1) | 10 |
| | (10 | ) | | (3 | ) |
| Contingency gain settlement (2) | — |
| | — |
| | (154 | ) |
| Net gain related to partial acreage dedication release | — |
| | — |
| | (12 | ) |
| Gain on asset retirement | (11 | ) | | — |
| | — |
|
| Loss related to sale of certain assets | — |
| | — |
| | 10 |
|
| Williams NGL & Petchem Services | | | | | |
| Loss on sale of Canadian operations (Note 3) | 32 |
| | — |
| | — |
|
| Gain on sale of unused pipe | (10 | ) | | — |
| | — |
|
________________
| |
(1) | Primarily relates to gains and losses incurred on foreign currency transactions and the remeasurement of U.S. dollar-denominated current assets and liabilities within our former Canadian operations (see Note 3 – Divestiture). |
| |
(2) | In November 2014, we settled a claim arising from the resolution of a contingent gain related to claims associated with the purchase of a business in a prior period. Pursuant to the settlement, we received $154 million in cash, all of which was recognized as a gain in the fourth quarter of 2014. |
ACMP Acquisition, Merger, and Transition
Certain ACMP acquisition, merger, and transition costs included in the Consolidated Statement of Operations are as follows:
Selling, general, and administrative expenses includes $26 million in 2015 and $27 million in 2014 (including $16 million of acquisition costs) primarily related to professional advisory fees within the Williams Partners segment.
Selling, general, and administrative expenses includes $9 million in 2015 and $15 million in 2014 of related employee transition costs within the Williams Partners segment and $32 million in 2015 and $10 million in 2014 of general corporate expenses associated with integration and realignment of resources within the Other segment.
107Operating and maintenance expenses includes $12 million in 2015 and $15 million in 2014 primarily related to employee transition costs within the Williams Partners segment.
Interest incurred includes transaction-related financing costs of $2 million in 2015 from the merger and $9 million in 2014 from the acquisition.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Additional Items
Certain additional items included in the Consolidated Statement of Operations are as follows:
Service revenues includes $173 million associated with the amortization of deferred income |
| | | | | | | | | | | |
| | 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 | $ | 29 |
| | $ | 87 |
| | $ | 70 |
|
| Settlement charge from pension early payout program | — |
| | (7 | ) | | (15 | ) |
| Regulatory adjustments resulting from Tax Reform | — |
| | — |
| | (33 | ) |
| | | | | | |
| Northeast G&P | | | | | |
| Settlement charge from pension early payout program | — |
| | (4 | ) | | (7 | ) |
| | | | | | |
| West | | | | | |
| Settlement charge from pension early payout program | — |
| | (6 | ) | | (13 | ) |
| Regulatory adjustments resulting from Tax Reform | — |
| | — |
| | (6 | ) |
| | | | | | |
| Other | | | | | |
| Income associated with a regulatory asset related to deferred taxes on equity funds used during construction | 9 |
| | 35 |
| | 52 |
|
| Net gain (loss) associated with early retirement of debt | — |
| | (7 | ) | | 27 |
|
| Settlement charge from pension early payout program | — |
| | (5 | ) | | (35 | ) |
| Regulatory adjustments resulting from Tax Reform | — |
| | (1 | ) | | (63 | ) |
Severance and other related to the restructuring of certain gas gathering contracts in the Barnett Shalecosts included withinOperating and Mid-Continent regions within the Williams Partners segment. Service revenues also includes $58 million, $239 million, maintenance expenses and $167 million recognized in the fourth quarter of 2016, 2015, and 2014, respectively, from minimum volume commitment feesin the Barnett Shale and Mid-Continent regions within the Williams Partners segment.
Selling, general, and administrative expensesand Operating and maintenance expenses include $42 million in 2016 of severance and other related costs.
are as follows: |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (Millions) |
| Atlantic-Gulf | $ | 32 |
| | $ | — |
| | $ | — |
|
| Northeast G&P | 7 |
| | — |
| | — |
|
| West | 17 |
| | — |
| | — |
|
| Other | 1 |
| | — |
| | 22 |
|
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 income (expense)segment (see Note 16 – net below Operating income (loss) includes $89 million, $95 million,Stockholders' Equity) and $44$20 million for equity AFUDC for 2016, 2015, and 2014, respectively, primarilyWPZ Merger related costs within the Williams PartnersOther segment.
Other income (expense) – net below Operating income (loss) includes a $14 million gain in 2015 resulting from the early retirement of certain debt within the Williams Partners segment.
108
Note 8 – Provision (Benefit) for Income Taxes
The Provision (benefit) for income taxes includes:
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (Millions) |
| Current: | | | | | |
| Federal | $ | — |
| | $ | — |
| | $ | (9 | ) |
| State | 2 |
| | (7 | ) | | 2 |
|
| Foreign | (1 | ) | | (55 | ) | | 10 |
|
| | 1 |
| | (62 | ) | | 3 |
|
| Deferred: | | | | | |
| Federal | (6 | ) | | (317 | ) | | 1,108 |
|
| State | 61 |
| | (25 | ) | | 119 |
|
| Foreign | (81 | ) | | 5 |
| | 19 |
|
| | (26 | ) | | (337 | ) | | 1,246 |
|
| Provision (benefit) for income taxes | $ | (25 | ) | | $ | (399 | ) | | $ | 1,249 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Note 8 – Provision (Benefit) for Income Taxes
The Provision (benefit) for income taxes includes:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (Millions) |
| Current: | | | | | |
| Federal | $ | (41 | ) | | $ | (83 | ) | | $ | 15 |
|
| State | (5 | ) | | 1 |
| | 23 |
|
| Foreign | 2 |
| | — |
| | — |
|
| | (44 | ) | | (82 | ) | | 38 |
|
| Deferred: | | | | | |
| Federal | 280 |
| | 183 |
| | (2,004 | ) |
| State | 99 |
| | 37 |
| | (8 | ) |
| | 379 |
| | 220 |
| | (2,012 | ) |
| Provision (benefit) for income taxes | $ | 335 |
| | $ | 138 |
| | $ | (1,974 | ) |
Reconciliations from the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes are as follows:
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (Millions) |
| Provision (benefit) at statutory rate | $ | 224 |
| | $ | 69 |
| | $ | 187 |
|
| Increases (decreases) in taxes resulting from: | | | | | |
| Impact of nontaxable noncontrolling interests | 29 |
| | (73 | ) | | (117 | ) |
| Federal Tax Reform rate change | — |
| | — |
| | (1,932 | ) |
| State income taxes (net of federal benefit) | 74 |
| | (10 | ) | | (17 | ) |
| State deferred income tax rate change | — |
| | 38 |
| | 26 |
|
| Foreign operations – net (including tax effect of Canadian Sale) | 2 |
| | — |
| | (127 | ) |
| Federal valuation allowance | 3 |
| | 105 |
| | — |
|
| Other – net | 3 |
| | 9 |
| | 6 |
|
| Provision (benefit) for income taxes | $ | 335 |
| | $ | 138 |
| | $ | (1,974 | ) |
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (Millions) |
| Provision (benefit) at statutory rate | $ | (131 | ) | | $ | (600 | ) | | $ | 1,255 |
|
| Increases (decreases) in taxes resulting from: | | | | | |
| Impact of nontaxable noncontrolling interests | (22 | ) | | 263 |
| | (75 | ) |
| State income taxes (net of federal benefit) | 3 |
| | (21 | ) | | 82 |
|
| State deferred income tax rate change | 43 |
| | — |
| | — |
|
| Foreign operations – net (Including tax effect of Canadian Sale) | 78 |
| | 8 |
| | (11 | ) |
| Taxes on undistributed earnings of foreign subsidiaries – net | — |
| | — |
| | (37 | ) |
| Translation adjustment of certain unrecognized tax benefits | (1 | ) | | (71 | ) | | — |
|
| Other – net | 5 |
| | 22 |
| | 35 |
|
| Provision (benefit) for income taxes | $ | (25 | ) | | $ | (399 | ) | | $ | 1,249 |
|
Income (loss) from continuing operations before income taxes includes $885$6 million, $3 million, and $7 million of foreign loss in 2016,2019, 2018, and $20 million and $102 million of foreign income in 2015 and 2014,2017, respectively.
Foreign operations – net (Including(including tax effect of Canadian Sale) increased in 2016 due to2017 reflects the release of a valuation allowance associated with impairments and losses on the sale of our Canadian operations (see Note 3 – Divestiture) and the reversal of anticipatory foreign tax credits, partially offset by the tax effectoperations.
On December 22, 2017, Tax Reform was enacted. Most of the impairments associated with our Canadian disposition.
The Translation adjustmentprovisions of certain unrecognizedTax Reform were effective after January 1, 2018. However, the deferred tax benefits in 2016 and 2015 reflects the impact of changesreducing the U.S. corporate tax rate from 35 percent to 21 percent was recognized in foreign currency exchange rates on the period of enactment. This remeasurement ofresulted in a foreign currency denominated unrecognized tax benefit, including associated penalties and interest.
The 2015 federal and state income tax provisions include the tax effect of a $2.7 billion impairment loss associated with certain goodwill, equity-method investments, and other assets. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) The 2014 federal and state income tax provisions include the tax effect of a $2.5 billion gain associated with remeasuring our equity-method investment to fair value as a result of the ACMP Acquisition. (See Note 2 – Acquisitions.)
Taxes on undistributed earnings of foreign subsidiaries - net decreased in 2014 due to revisionsreduction of our estimatedeferred tax liabilities of the undistributed earnings, partially offset by an increase of tax expense, which decreased our share of the foreign tax credit dueapproximately $1.9 billion, with a corresponding net adjustment to the Canada Dropdown.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.
|
| | | | |
| 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:
|
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| | (Millions) |
| Deferred income tax liabilities: | | | |
| Property, plant and equipment | $ | 1,921 |
| | $ | 2,317 |
|
| Investments | 1,411 |
| | 295 |
|
| Other | 82 |
| | 30 |
|
| Total deferred income tax liabilities | 3,414 |
| | 2,642 |
|
| Deferred income tax assets: | | | |
| Accrued liabilities | 729 |
| | 667 |
|
| Minimum tax credit | 29 |
| | 71 |
|
| Foreign tax credit | 140 |
| | 140 |
|
| Federal loss carryovers | 544 |
| | 147 |
|
| State losses and credits | 362 |
| | 319 |
|
| Other | 147 |
| | 94 |
|
| Total deferred income tax assets | 1,951 |
| | 1,438 |
|
| Less valuation allowance | 319 |
| | 320 |
|
| Net deferred income tax assets | 1,632 |
| | 1,118 |
|
| Overall net deferred income tax liabilities | $ | 1,782 |
| | $ | 1,524 |
|
|
| | | | | | | |
| | December 31, |
| | 2016 | | 2015 |
| | (Millions) |
| Deferred income tax liabilities: | | | |
| Property, plant, and equipment | $ | — |
| | $ | 4 |
|
| Investments | 5,300 |
| | 5,272 |
|
| Other | 29 |
| | 15 |
|
| Total deferred income tax liabilities | 5,329 |
| | 5,291 |
|
| Deferred income tax assets: | | | |
| Accrued liabilities | 145 |
| | 150 |
|
| Minimum tax credits | 139 |
| | 139 |
|
| Foreign tax credit | 140 |
| | 193 |
|
| Federal loss carryovers | 651 |
| | 485 |
|
| State losses and credits | 313 |
| | 296 |
|
| Other | 37 |
| | 42 |
|
| Total deferred income tax assets | 1,425 |
| | 1,305 |
|
| Less valuation allowance | 334 |
| | 190 |
|
| Net deferred income tax assets | 1,091 |
| | 1,115 |
|
| Overall net deferred income tax liabilities | $ | 4,238 |
| | $ | 4,176 |
|
The valuation allowance at December 31, 20162019 and 20152018, serves to reduce the available deferred income tax assets to an amount that will, more likely than not, be realized. We considerconsidered 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 and Federal loss carryovers may not be realized. The changecompletion 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 Valuation allowance is partially duean 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 evaluation.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 creditsis primarily due to 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 20172019 and 20362038 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 includes the tax effect of a capital loss carryover of $364 million, incurred with the sale of our Canadian operations, which, if unused, will expire in 2021. The Valuation allowance change from prior year is primarily due to a valuation allowance on the include deferred tax asset associated with this capital loss carryover. We reasonably anticipate that this valuation allowance could be released in the near future due to tax impactsassets of the potential monetization of certain assets as previously announced by management. The federal tax Minimum tax credits of $139$5 million currently has no expiration date. Foreign tax credit of $140 million is expected to be utilized prior to expiration in 2026.
Federal net operating loss carryovers and charitable contribution carryovers of $1.6 billion at the end of 20162019 that are expected to be utilized by us prior to expiration between 20182020 and 2036. Employee share-based compensation attributable to the exercise2023. Deferred tax assets on net operating loss carryovers of stock options and vesting of restricted stock is deductible by us$539 million have no expiration date.
Cash refunds for tax purposes. To the extent these tax deductions exceed the previously accrued deferred income tax benefit for these items, the additional tax benefit is not recognized until the deduction reduces current income taxes payable. Since the additional tax benefit does not reduce our current income taxes payable for 2014 through 2016, these tax benefits are not included(net of payments) were $86 million in our Federal loss carryovers deferred income tax assets. The additional tax benefits deductible for tax purposes but not included in our Federal loss carryovers deferred income tax assets were $38 million through 2016.
2019. Cash payments for income taxes (net of refunds) were $5$11 million, and $29$28 million in 20162018 and 2014,2017, respectively. Cash refunds for income taxes (net of payments and discontinued operations) were $136 million in 2015.
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
As of December 31, 2016,2019, we had approximately $50$51 million of unrecognized tax benefits. If recognized, income tax expense would be reduced by $49 million and $51 million for 2016each of the years 2019 and 2015, respectively,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:
|
| | | | | | | |
| | 2016 | | 2015 |
| | (Millions) |
| Balance at beginning of period | $ | 55 |
| | $ | 89 |
|
| Additions for tax positions of prior years | — |
| | 2 |
|
| Reductions for tax positions of prior years | (4 | ) | | — |
|
| Changes due to currency translation | (1 | ) | | (36 | ) |
| Balance at end of period | $ | 50 |
| | $ | 55 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
|
| | | | | | | |
| | 2019 | | 2018 |
| | (Millions) |
| Balance at beginning of period | $ | 51 |
| | $ | 50 |
|
| Additions for tax positions of prior years | — |
| | 1 |
|
| Balance at end of period | $ | 51 |
| | $ | 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 $300$500 thousand and $8 million$800 thousand for 20162019 and 2014, respectively, and a benefit of $22 million for 2015, including a $35 million benefit due to currency fluctuation.2018, respectively. Approximately $3 million and $2 million of interest and penalties primarily relating to uncertain tax positions have been accrued as of both December 31, 20162019 and 2015, respectively. Changes due to currency translation in 2015 reflects the unrecognized tax benefit portion of the previously described impact of changes in foreign currency exchange rates on the remeasurement of a foreign currency denominated balance.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.SU.S. Federal income tax returns are open to Internal Revenue Service (IRS) examination for years after 2010.2010, excluding 2015, for which the statute expired on August 31, 2019. As of December 31, 2016,2019, 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 2011.2012. Tax years 2013 and 2014 are currently under income tax examination, while tax year 2016 is under Goods and Services Tax (GST) examination. We have indemnifiedIn September 2016, we sold the purchasermajority of our Canadian operations and, as part of the sale, indemnified the purchaser for any adjustments toincreases in Canadian tax returns fordue to an audit of any tax periods prior to the sale of our Canadian operations in September 2016.sale.
In November 2015, the FASB issued ASU 2015-17 “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes” (ASU 2015-17). The standard requires that deferred income tax liabilities and assets, along with any related valuation allowance, be presented as noncurrent in a classified statement of financial position. The standard is effective for interim and annual periods beginning after December 15, 2016 and early adoption is permitted. We have elected to early adopt ASU 2015-17 prospectively as of December 31, 2016. TheConsolidated Balance Sheetas of December 31, 2015 was not retrospectively adjusted.
On September 13, 2013, the IRS issued final regulations providing guidance on the treatment of amounts paid to acquire, produce, or improve tangible property. On August 18, 2014, the IRS issued final regulations providing guidance on the dispositions of such property. The implementation date for these regulations was January 1, 2014. The IRS is expected to issue additional procedural guidance regarding how the requirements may be implemented for the gas transmission and distribution industry. Pending the issuance of this additional procedural guidance from the IRS, we cannot at this time estimate the impact of implementing the regulations for our gas transmission business, although we anticipate that it will result in an immaterial balance sheet only impact.
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
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 |
| | $ | (156 | ) | | $ | 2,174 |
|
| Basic weighted-average shares | 1,212,037 |
| | 973,626 |
| | 826,177 |
|
| Effect of dilutive securities: | | | | | |
| Nonvested restricted stock units | 1,811 |
| | — |
| | 1,704 |
|
| Stock options | 163 |
| | — |
| | 637 |
|
| Diluted weighted-average shares (1) | 1,214,011 |
| | 973,626 |
| | 828,518 |
|
| Earnings (loss) per common share from continuing operations: | | | | | |
| Basic | $ | .71 |
| | $ | (.16 | ) | | $ | 2.63 |
|
| Diluted | $ | .71 |
| | $ | (.16 | ) | | $ | 2.62 |
|
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (Dollars in millions, except per-share amounts; shares in thousands) |
| Income (loss) from continuing operations attributable to The Williams Companies, Inc. available to common stockholders for basic and diluted earnings (loss) per common share | $ | (424 | ) | | $ | (571 | ) | | $ | 2,110 |
|
| Basic weighted-average shares | 750,673 |
| | 749,271 |
| | 719,325 |
|
| Effect of dilutive securities: | | | | | |
| Nonvested restricted stock units | — |
| | — |
| | 2,234 |
|
| Stock options | — |
| | — |
| | 2,064 |
|
| Convertible debentures | — |
| | — |
| | 18 |
|
| Diluted weighted-average shares (1) | 750,673 |
| | 749,271 |
| | 723,641 |
|
| Earnings (loss) per common share from continuing operations: | | | | | |
| Basic | $ | (.57 | ) | | $ | (.76 | ) | | $ | 2.93 |
|
| Diluted | $ | (.57 | ) | | $ | (.76 | ) | | $ | 2.91 |
|
| |
| (1) | For the yearsyear ended December 31, 2016 and December 31, 2015, 0.6 million and 1.72018, 2.0 million weighted-average nonvested restricted stock units and 0.5 million and 1.5 million weighted-average stock options have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to The Williams Companies, Inc. |
Note 10 – Employee Benefit Plans
We have noncontributory defined benefit pension plans in which all eligible employees participate. Currently, eligible employees earn benefits primarily based on a cash balance formula. Various other formulas, as defined in the plan documents, are utilized to calculate the retirement benefits for plan participants not covered by the cash balance formula. At the time of retirement, participants may elect, to the extent they are eligible for the various options, to receive annuity payments, a lump sumlump-sum payment, or a combination of a lump sumannuity and annuitylump-sum payments. In addition to our pension plans, we currently provide subsidized retiree medical and life insurance benefits (other postretirement benefits) to certain eligible participants. Generally, employees hired after December 31, 1991, are not eligible for the subsidized retiree medical benefits, except for participants that were employees or retirees of Transco Energy Company on December 31, 1995, and other miscellaneous defined participant groups.1995. Subsidized retiree medical benefits for
|
| | | | |
| 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 these plansthis 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.
|
| | | | |
| 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 | $ | 1,187 |
| | $ | 1,319 |
| | $ | 186 |
| | $ | 206 |
|
| Service cost | 45 |
| | 50 |
| | 1 |
| | 1 |
|
| Interest cost | 50 |
| | 46 |
| | 8 |
| | 7 |
|
| Plan participants’ contributions | — |
| | — |
| | 2 |
| | 2 |
|
| Benefits paid | (111 | ) | | (35 | ) | | (12 | ) | | (13 | ) |
| Net actuarial loss (gain) | 69 |
| | (90 | ) | | 30 |
| | (17 | ) |
| Settlements | (3 | ) | | (103 | ) | | — |
| | — |
|
| Net increase (decrease) in benefit obligation | 50 |
| | (132 | ) | | 29 |
| | (20 | ) |
| Benefit obligation at end of year | 1,237 |
| | 1,187 |
| | 215 |
| | 186 |
|
| Change in plan assets: | | | | | | | |
| Fair value of plan assets at beginning of year | 1,132 |
| | 1,227 |
| | 214 |
| | 227 |
|
| Actual return on plan assets | 218 |
| | (45 | ) | | 38 |
| | (7 | ) |
| Employer contributions | 63 |
| | 88 |
| | 5 |
| | 5 |
|
| Plan participants’ contributions | — |
| | — |
| | 2 |
| | 2 |
|
| Benefits paid | (111 | ) | | (35 | ) | | (12 | ) | | (13 | ) |
| Settlements | (3 | ) | | (103 | ) | | — |
| | — |
|
| Net increase (decrease) in fair value of plan assets | 167 |
| | (95 | ) | | 33 |
| | (13 | ) |
| Fair value of plan assets at end of year | 1,299 |
| | 1,132 |
| | 247 |
| | 214 |
|
| Funded status — overfunded (underfunded) | $ | 62 |
| | $ | (55 | ) | | $ | 32 |
| | $ | 28 |
|
| Accumulated benefit obligation | $ | 1,221 |
| | $ | 1,171 |
| | | | |
|
| | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | 2016 | | 2015 | | 2016 | | 2015 |
| | (Millions) |
| Change in benefit obligation: | | | | | | | |
| Benefit obligation at beginning of year | $ | 1,464 |
| | $ | 1,544 |
| | $ | 202 |
| | $ | 233 |
|
| Service cost | 54 |
| | 59 |
| | 1 |
| | 2 |
|
| Interest cost | 62 |
| | 58 |
| | 8 |
| | 9 |
|
| Plan participants’ contributions | — |
| | — |
| | 2 |
| | 2 |
|
| Benefits paid | (130 | ) | | (101 | ) | | (15 | ) | | (13 | ) |
| Actuarial loss (gain) | 20 |
| | (91 | ) | | (1 | ) | | (31 | ) |
| Settlements | (4 | ) | | (5 | ) | | — |
| | — |
|
| Net increase (decrease) in benefit obligation | 2 |
| | (80 | ) | | (5 | ) | | (31 | ) |
| Benefit obligation at end of year | 1,466 |
| | 1,464 |
| | 197 |
| | 202 |
|
| Change in plan assets: | | | | | | | |
| Fair value of plan assets at beginning of year | 1,241 |
| | 1,293 |
| | 201 |
| | 208 |
|
| Actual return on plan assets | 82 |
| | (11 | ) | | 13 |
| | (1 | ) |
| Employer contributions | 65 |
| | 65 |
| | 7 |
| | 5 |
|
| Plan participants’ contributions | — |
| | — |
| | 2 |
| | 2 |
|
| Benefits paid | (130 | ) | | (101 | ) | | (15 | ) | | (13 | ) |
| Settlements | (4 | ) | | (5 | ) | | — |
| | — |
|
| Net increase (decrease) in fair value of plan assets | 13 |
| | (52 | ) | | 7 |
| | (7 | ) |
| Fair value of plan assets at end of year | 1,254 |
| | 1,241 |
| | 208 |
| | 201 |
|
| Funded status — overfunded (underfunded) | $ | (212 | ) | | $ | (223 | ) | | $ | 11 |
| | $ | (1 | ) |
| Accumulated benefit obligation | $ | 1,440 |
| | $ | 1,432 |
| | | | |
The overfunded (underfunded) status of our pension plans and other postretirement benefit plansplan 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 | $ | 92 |
| | $ | — |
|
| Current liabilities | (3 | ) | | (2 | ) |
| Noncurrent liabilities | (27 | ) | | (53 | ) |
| | | | |
| Overfunded (underfunded) other postretirement benefit plan: | | | |
| Noncurrent assets | 38 |
| | 34 |
|
| Current liabilities | (6 | ) | | (6 | ) |
|
| | | | | | | |
| | December 31, |
| | 2016 | | 2015 |
| | (Millions) |
| Underfunded pension plans: | | | |
| Current liabilities | $ | (2 | ) | | $ | (2 | ) |
| Noncurrent liabilities | (210 | ) | | (221 | ) |
| Overfunded (underfunded) other postretirement benefit plans: | | | |
| Current liabilities | (7 | ) | | (7 | ) |
| Noncurrent assets (liabilities) | 18 |
| | 6 |
|
The plan assets within our other postretirement benefit plansplan are intended to be used for the payment of benefits for certain groups of participants. The Current liabilities for the other postretirement benefit plansplan 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.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
The pension plans’ benefit obligation ActuarialNet actuarial loss (gain) of $20$69 million in 20162019 is primarily due to the impact of a decrease in the discount rates utilized to calculate the benefit obligation.obligation, partially offset by the impact of a decrease in the cash balance interest crediting rate assumption. The pension plans’ benefit obligation ActuarialNet actuarial loss (gain) of$(91)(90) million in 20152018 is primarily due to the impact of a decrease in the assumed future interest crediting rate for the cash balance pension formula and an increase in the discount rates utilized to calculate the benefit obligation.
The 20152019 benefit obligation ActuarialNet actuarial loss (gain) of $(31)$30 million for our other postretirement benefit plansplan 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, tax law changes, and other assumption changes.obligation.
At December 31, 2016 and 2015, all of ourThe following table summarizes information for pension plans had a projected benefit obligation and accumulated benefit obligationwith 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 | $ | 29 |
| | $ | 1,187 |
|
| Fair value of plan assets | — |
| | 1,132 |
|
| | | | |
| Plans with an accumulated benefit obligation in excess of plan assets: | | | |
| Accumulated benefit obligation | 26 |
| | 367 |
|
| Fair value of plan assets | — |
| | 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 |
|
|
| | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | 2016 | | 2015 | | 2016 | | 2015 |
| | (Millions) |
Amounts included in Accumulated other comprehensive income (loss): | | | | | | | |
| Prior service credit | $ | — |
| | $ | — |
| | $ | 5 |
| | $ | 11 |
|
| Net actuarial loss | (535 | ) | | (544 | ) | | (18 | ) | | (18 | ) |
| Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline: | | | | | | | |
| Prior service credit | N/A |
| | N/A |
| | $ | 10 |
| | $ | 19 |
|
| Net actuarial gain | N/A |
| | N/A |
| | 8 |
| | 6 |
|
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 plansplan 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 $94$106 million at December 31, 20162019 and $78$116 million at December 31, 2015,2018, 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, 20162019 and 2015,2018, these regulatory liabilities were $21$43 million and $8$49 million, respectively. These pension and other postretirement plans amounts will be reflected in future rates based on the rate structures of these gas pipelines.
|
| | | | |
| 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 | | Other Postretirement Benefits |
| | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| | (Millions) |
| Components of net periodic benefit cost (credit): | | | | | | | | | | | |
| Service cost | $ | 45 |
| | $ | 50 |
| | $ | 50 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
|
| Interest cost | 50 |
| | 46 |
| | 59 |
| | 8 |
| | 7 |
| | 8 |
|
| Expected return on plan assets | (61 | ) | | (63 | ) | | (82 | ) | | (10 | ) | | (11 | ) | | (11 | ) |
| Amortization of prior service credit | — |
| | — |
| | — |
| | — |
| | (2 | ) | | (13 | ) |
| Amortization of net actuarial loss | 15 |
| | 23 |
| | 27 |
| | — |
| | — |
| | — |
|
| Net actuarial loss from settlements | 1 |
| | 23 |
| | 71 |
| | — |
| | — |
| | — |
|
| Reclassification to regulatory liability | — |
| | — |
| | — |
| | 1 |
| | 2 |
| | 3 |
|
| Net periodic benefit cost (credit) | $ | 50 |
| | $ | 79 |
| | $ | 125 |
| | $ | — |
| | $ | (3 | ) | | $ | (12 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | 2016 | | 2015 | | 2014 | | 2016 | | 2015 | | 2014 |
| | (Millions) |
| Components of net periodic benefit cost: | | | | | | | | | | | |
| Service cost | $ | 54 |
| | $ | 59 |
| | $ | 40 |
| | $ | 1 |
| | $ | 2 |
| | $ | 2 |
|
| Interest cost | 62 |
| | 58 |
| | 62 |
| | 8 |
| | 9 |
| | 10 |
|
| Expected return on plan assets | (85 | ) | | (75 | ) | | (76 | ) | | (12 | ) | | (12 | ) | | (12 | ) |
| Amortization of prior service credit | — |
| | — |
| | — |
| | (15 | ) | | (17 | ) | | (20 | ) |
| Amortization of net actuarial loss | 30 |
| | 42 |
| | 39 |
| | — |
| | 2 |
| | — |
|
| Net actuarial (gain) loss from settlements and curtailments | 2 |
| | 2 |
| | 1 |
| | — |
| | — |
| | (1 | ) |
| Reclassification to regulatory liability | — |
| | — |
| | — |
| | 4 |
| | 3 |
| | 4 |
|
| Net periodic benefit cost | $ | 63 |
| | $ | 86 |
| | $ | 66 |
| | $ | (14 | ) | | $ | (13 | ) | | $ | (17 | ) |
Items Recognized in Other Comprehensive Income (Loss) and Regulatory Assets/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) | $ | 88 |
|
| $ | (18 | ) |
| $ | 62 |
|
| $ | (9 | ) |
| $ | 9 |
|
| $ | (3 | ) |
| Amortization of prior service credit | — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| (5 | ) |
| Amortization of net actuarial loss | 15 |
|
| 23 |
|
| 27 |
|
| — |
|
| — |
|
| — |
|
| Net actuarial loss from settlements | 1 |
| | 23 |
| | 71 |
| | — |
| | — |
| | — |
|
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) | $ | 104 |
|
| $ | 28 |
|
| $ | 160 |
|
| $ | (9 | ) |
| $ | 9 |
|
| $ | (8 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits |
| Other Postretirement Benefits |
| | 2016 |
| 2015 |
| 2014 |
| 2016 |
| 2015 |
| 2014 |
| | (Millions) |
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
| Net actuarial gain (loss) | $ | (23 | ) |
| $ | 5 |
|
| $ | (142 | ) |
| $ | — |
|
| $ | 8 |
|
| $ | (18 | ) |
| Prior service (cost) credit | — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| (1 | ) |
| Amortization of prior service credit | — |
|
| — |
|
| — |
|
| (6 | ) |
| (6 | ) |
| (8 | ) |
| Amortization of net actuarial loss | 30 |
|
| 42 |
|
| 39 |
|
| — |
|
| 2 |
|
| — |
|
| Loss from settlements and curtailments | 2 |
| | 2 |
| | 1 |
| | — |
| | — |
| | 1 |
|
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) | $ | 9 |
|
| $ | 49 |
|
| $ | (102 | ) |
| $ | (6 | ) |
| $ | 4 |
|
| $ | (26 | ) |
Other changes in plan assets and benefit obligations for our other postretirement benefit plansplan associated with Transco and Northwest Pipeline are recognized in regulatory assets/assets and liabilities.Amounts recognized in regulatory assets/assets and liabilities for the years ended December 31 consist of the following:
|
| | | | | | | | | | | | |
| | | 2019 | | 2018 | | 2017 |
| | | (Millions) |
Other changes in plan assets and benefit obligations recognized in regulatory (assets) and liabilities: | | | | | | |
| Net actuarial gain (loss) | | $ | 7 |
| | $ | (10 | ) | | $ | 6 |
|
| Amortization of prior service credit | | — |
| | (2 | ) | | (8 | ) |
|
| | | | | | | | | | | | |
| | | 2016 | | 2015 | | 2014 |
| | | (Millions) |
Other changes in plan assets and benefit obligations recognized in regulatory (assets) liabilities: | | | | | | |
| Net actuarial gain (loss) | | $ | 2 |
| | $ | 10 |
| | $ | (2 | ) |
| Amortization of prior service credit | | (9 | ) | | (11 | ) | | (12 | ) |
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Pre-tax amounts expected to be amortized in Net periodic benefit cost in 2017 are as follows:
|
| | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | (Millions) |
Amounts included in Accumulated other comprehensive income (loss): | | | |
| Prior service credit | $ | — |
| | $ | (5 | ) |
| Net actuarial loss | 28 |
| | — |
|
| Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline: | | | |
| Prior service credit | N/A |
| | $ | (8 | ) |
| Net actuarial loss | N/A |
| | — |
|
Key Assumptions
The weighted-average assumptions utilized to determine benefit obligations as of December 31 are as follows:
| | | | Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits |
| | 2016 | | 2015 | | 2016 | | 2015 | 2019 | | 2018 | | 2019 | | 2018 |
| Discount rate | 4.17 | % | | 4.38 | % | | 4.27 | % | | 4.50 | % | 3.19 | % | | 4.34 | % | | 3.27 | % | | 4.39 | % |
| Rate of compensation increase | 4.87 |
| | 4.88 |
| | N/A |
| | N/A |
| 3.68 |
| | 4.83 |
| | N/A |
| | N/A |
|
| Cash balance interest crediting rate | | 3.50 |
| | 4.25 |
| | 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:
|
| | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| Discount rate | 4.33 | % | | 3.67 | % | | 4.17 | % | | 4.39 | % | | 3.71 | % | | 4.27 | % |
| Expected long-term rate of return on plan assets | 5.26 |
| | 5.34 |
| | 6.45 |
| | 5.01 |
| | 4.95 |
| | 5.53 |
|
| Rate of compensation increase | 4.83 |
| | 4.93 |
| | 4.87 |
| | N/A |
| | N/A |
| | N/A |
|
| Cash balance interest crediting rate | 4.25 |
| | 4.25 |
| | 4.25 |
| | N/A |
| | N/A |
| | N/A |
|
|
| | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | 2016 | | 2015 | | 2014 | | 2016 | | 2015 | | 2014 |
| Discount rate | 4.37 | % | | 3.96 | % | | 4.68 | % | | 4.50 | % | | 4.12 | % | | 4.80 | % |
| Expected long-term rate of return on plan assets | 6.85 |
| | 6.38 |
| | 6.85 |
| | 6.11 |
| | 5.70 |
| | 6.11 |
|
| Rate of compensation increase | 4.88 |
| | 4.62 |
| | 4.56 |
| | N/A |
| | 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 20172020 is 7.57.2 percent. This rate decreases to 4.5 percent by 2025. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
|
| | | | | | | |
| | Point increase | | Point decrease |
| | (Millions) |
| Effect on total of service and interest cost components | $ | — |
| | $ | — |
|
| Effect on other postretirement benefit obligation | 6 |
| | (5 | ) |
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
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
approximately 3837 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, 20162019, of 6025 percent equity securities and 4075 percent fixed income securities. The target allocation includes the investments in equity and fixed income mutual funds and commingled investment funds. The investment policy allows for a broad range of asset allocations that permit the plans to de-risk in response to changes in the plans’ funded status.
Equity securities may include U.S. equities and non-U.S. equities. Investment in Williams’ securities or an entity in which Williams has a majority ownership is prohibited except where these securities may be owned in a commingled investment fund in which the plans’ trusts invest. No more than 5 percent of the total stock portfolio valued at market may be invested in the common stock of any one corporation.
Fixed income securities may consist of U.S. as well as international instruments, including emerging markets. The fixed income strategies may invest in government, corporate, asset-backed securities, and mortgage-backed obligations. The weighted-average credit rating of the fixed income strategies must be at least “investment grade” including ratings by Moody’s and/or Standard & Poor’s. No more than 5 percent of the total fixed income portfolio may be invested in the fixed income securities of any one issuer with the exception of bond index funds and U.S. government guaranteed and agency securities.
|
| | | | |
| The 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. Investment strategies using direct investments in derivative securities require approval and, historically, have not been used; however, these instruments may be used in mutual funds and commingled investment funds held by the plans’ trusts. Additionally, real estate equity, natural resource property, venture capital, leveraged buyouts, and other high-return, high-risk investments are generally restricted. 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:
115 |
| | | | | | | | | | | | | | | |
| | 2019 |
| Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) | | Significant
Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Total |
| | (Millions) |
| Pension assets: | | | | | | | |
| Cash management fund | $ | 11 |
| | $ | — |
| | $ | — |
| | $ | 11 |
|
| Equity securities | 41 |
| | 22 |
| | — |
| | 63 |
|
| Fixed income securities (1): | | | | | | | |
| U.S. Treasury securities | 62 |
| | — |
| | — |
| | 62 |
|
| Governments and municipal bonds | — |
| | 35 |
| | — |
| | 35 |
|
| Mortgage and asset-backed securities | — |
| | 11 |
| | — |
| | 11 |
|
| Corporate bonds | — |
| | 360 |
| | — |
| | 360 |
|
| Other | 5 |
| | 4 |
| | — |
| | 9 |
|
| | $ | 119 |
| | $ | 432 |
| | $ | — |
| | 551 |
|
| Commingled investment funds measured at net asset value practical expedient (2): | | | | | | | |
| Equities — U.S. large cap | | | | | | | 133 |
|
| Equities — Global large and mid cap | | | | | | | 100 |
|
| Equities — International emerging markets | | | | | | | 26 |
|
| Fixed income — U.S. long and intermediate duration | | | | | | | 380 |
|
| Fixed income — Corporate bonds | | | | | | | 109 |
|
| Total assets at fair value at December 31, 2019 | | | | | | | $ | 1,299 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
The fair values of our pension plan assets at December 31, 2016 and 2015 by asset class are as follows:
| | | | 2016 | 2018 |
| Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) | | Significant
Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Total | Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) | | Significant
Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Total |
| | (Millions) | (Millions) |
| Pension assets: | | | | | | | | | | | | | | |
| Cash management fund | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | 14 |
| $ | 10 |
| | $ | — |
| | $ | — |
| | $ | 10 |
|
| Equity securities: | | | | | | | | |
| U.S. large cap | 87 |
| | — |
| | — |
| | 87 |
| |
| U.S. small cap | 77 |
| | — |
| | — |
| | 77 |
| |
| Equity securities | | 52 |
| | — |
| | — |
| | 52 |
|
| Fixed income securities (1): | | | | | | | | | | | | | | |
| U.S. Treasury securities | 68 |
| | — |
| | — |
| | 68 |
| 157 |
| | — |
| | — |
| | 157 |
|
| Government and municipal bonds | — |
| | 10 |
| | — |
| | 10 |
| — |
| | 21 |
| | — |
| | 21 |
|
| Mortgage and asset-backed securities | — |
| | 80 |
| | — |
| | 80 |
| — |
| | 48 |
| | — |
| | 48 |
|
| Corporate bonds | — |
| | 148 |
| | — |
| | 148 |
| — |
| | 210 |
| | — |
| | 210 |
|
| Insurance company investment contracts and other | — |
| | 5 |
| | — |
| | 5 |
| — |
| | 6 |
| | — |
| | 6 |
|
| | $ | 246 |
| | $ | 243 |
| | $ | — |
| | 489 |
| $ | 219 |
| | $ | 285 |
| | $ | — |
| | 504 |
|
| Commingled investment funds measured at net asset value practical expedient (3): | | | | | | | | |
| Commingled investment funds measured at net asset value practical expedient (2): | | | | | | | | |
| Equities — U.S. large cap | | | | | | | 369 |
| | | | | | | 123 |
|
| Equities — International small cap | | | | | | | 27 |
| | | | | | | 8 |
|
| Equities — International emerging markets | | | | | | | 50 |
| | | | | | | 19 |
|
| Equities — International developed markets | | | | | | | 149 |
| | | | | | | 51 |
|
| Fixed income — U.S. long duration | | | | | | | 88 |
| | | | | | | 335 |
|
| Fixed income — Corporate bonds | | | | | | | 82 |
| | | | | | | 92 |
|
| Total assets at fair value at December 31, 2016 | | | | | | | $ | 1,254 |
| |
| Total assets at fair value at December 31, 2018 | | | | | | | | $ | 1,132 |
|
|
| | | | |
| 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:
|
| | | | | | | | | | | | | | | |
| | 2015 |
| | Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) | | Significant
Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Total |
| | (Millions) |
| Pension assets: | | | | | | | |
| Cash management fund | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | 8 |
|
| Equity securities: | | | | | | | |
| U.S. large cap | 83 |
| | — |
| | — |
| | 83 |
|
| U.S. small cap | 64 |
| | — |
| | — |
| | 64 |
|
| Fixed income securities (1): | | | | | | | |
| U.S. Treasury securities | 65 |
| | — |
| | — |
| | 65 |
|
| Government and municipal bonds | — |
| | 8 |
| | — |
| | 8 |
|
| Mortgage and asset-backed securities | — |
| | 87 |
| | — |
| | 87 |
|
| Corporate bonds | — |
| | 145 |
| | — |
| | 145 |
|
| Insurance company investment contracts and other | — |
| | 5 |
| | — |
| | 5 |
|
| | $ | 220 |
| | $ | 245 |
| | $ | — |
| | 465 |
|
| Commingled investment funds measured at net asset value practical expedient (3): | | | | | | | |
| Equities — U.S. large cap | | | | | | | 367 |
|
| Equities — International small cap | | | | | | | 27 |
|
| Equities — International emerging markets | | | | | | | 50 |
|
| Equities — International developed markets | | | | | | | 153 |
|
| Fixed income — U.S. long duration | | | | | | | 95 |
|
| Fixed income — Corporate bonds | | | | | | | 84 |
|
| Total assets at fair value at December 31, 2015 | | | | | | | $ | 1,241 |
|
|
| | | | | | | | | | | | | | | |
| | 2019 |
| | Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) | | Significant
Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Total |
| | (Millions) |
| Other postretirement benefit assets: | | | | | | | |
| Cash management funds | $ | 11 |
| | $ | — |
| | $ | — |
| | $ | 11 |
|
| Equity securities | 35 |
| | 9 |
| | — |
| | 44 |
|
| Fixed income securities (1): | | | | | | | |
| U.S. Treasury securities | 8 |
| | — |
| | — |
| | 8 |
|
| Governments and municipal bonds | — |
| | 4 |
| | — |
| | 4 |
|
| Mortgage and asset-backed securities | — |
| | 1 |
| | — |
| | 1 |
|
| Corporate bonds | — |
| | 43 |
| | — |
| | 43 |
|
| Mutual fund — Municipal bonds | 46 |
| | — |
| | — |
| | 46 |
|
| | $ | 100 |
| | $ | 57 |
| | $ | — |
| | 157 |
|
| Commingled investment funds measured at net asset value practical expedient (2): | | | | | | | |
| Equities — U.S. large cap | | | | | | | 16 |
|
| Equities — Global large and mid cap | | | | | | | 12 |
|
| Equities — International emerging markets | | | | | | | 3 |
|
| Fixed income — U.S. long and intermediate duration | | | | | | | 46 |
|
| Fixed income — Corporate bonds | | | | | | | 13 |
|
| Total assets at fair value at December 31, 2019 | | | | | | | $ | 247 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
The fair values of our other postretirement benefits plan assets at December 31, 2016 and 2015 by asset class are as follows:
|
| | | | | | | | | | | | | | | |
| | 2016 |
| | Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) | | Significant
Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Total |
| | (Millions) |
| Other postretirement benefit assets: | | | | | | | |
| Cash management funds | $ | 11 |
| | $ | — |
| | $ | — |
| | $ | 11 |
|
| Equity securities: | | | | | | | |
| U.S. large cap | 24 |
| | — |
| | — |
| | 24 |
|
| U.S. small cap | 15 |
| | — |
| | — |
| | 15 |
|
| International developed markets large cap growth | — |
| | 5 |
| | — |
| | 5 |
|
| Fixed income securities (2): | | | | | | | |
| U.S. Treasury securities | 7 |
| | — |
| | — |
| | 7 |
|
| Government and municipal bonds | — |
| | 1 |
| | — |
| | 1 |
|
| Mortgage and asset-backed securities | — |
| | 8 |
| | — |
| | 8 |
|
| Corporate bonds | — |
| | 15 |
| | — |
| | 15 |
|
| Mutual fund — Municipal bonds | 42 |
| | — |
| | — |
| | 42 |
|
| | $ | 99 |
| | $ | 29 |
| | $ | — |
| | 128 |
|
| Commingled investment funds measured at net asset value practical expedient (3): | | | | | | | |
| Equities — U.S. large cap | | | | | | | 38 |
|
| Equities — International small cap | | | | | | | 3 |
|
| Equities — International emerging markets | | | | | | | 5 |
|
| Equities — International developed markets | | | | | | | 16 |
|
| Fixed income — U.S. long duration | | | | | | | 9 |
|
| Fixed income — Corporate bonds | | | | | | | 9 |
|
| Total assets at fair value at December 31, 2016 | | | | | | | $ | 208 |
|
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
| | | | 2015 | 2018 |
| | Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) | | Significant
Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Total | Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1) | | Significant
Other
Observable
Inputs
(Level 2) | | Significant
Unobservable
Inputs
(Level 3) | | Total |
| | (Millions) | (Millions) |
| Other postretirement benefit assets: | | | | | | | | | | | | | | |
| Cash management funds | $ | 11 |
| | $ | — |
| | $ | — |
| | $ | 11 |
| $ | 11 |
| | $ | — |
| | $ | — |
| | $ | 11 |
|
| Equity securities: | | | | | | | | |
| U.S. large cap | 37 |
| | — |
| | — |
| | 37 |
| |
| U.S. small cap | 20 |
| | — |
| | — |
| | 20 |
| |
| International developed markets large cap growth | 1 |
| | 9 |
| | — |
| | 10 |
| |
| Emerging markets growth | — |
| | 1 |
| | — |
| | 1 |
| |
| Fixed income securities (2): | | | | | | | | |
| Equity securities | | 29 |
| | 5 |
| | — |
| | 34 |
|
| Fixed income securities (1): | | | | | | | | |
| U.S. Treasury securities | 7 |
| | — |
| | — |
| | 7 |
| 19 |
| | — |
| | — |
| | 19 |
|
| Government and municipal bonds | — |
| | 12 |
| | — |
| | 12 |
| — |
| | 2 |
| | — |
| | 2 |
|
| Mortgage and asset-backed securities | — |
| | 9 |
| | — |
| | 9 |
| — |
| | 6 |
| | — |
| | 6 |
|
| Corporate bonds | — |
| | 15 |
| | — |
| | 15 |
| — |
| | 25 |
| | — |
| | 25 |
|
| Mutual fund — Municipal bonds | | 43 |
| | — |
| | — |
| | 43 |
|
| | $ | 76 |
| | $ | 46 |
| | $ | — |
| | 122 |
| $ | 102 |
| | $ | 38 |
| | $ | — |
| | 140 |
|
| Commingled investment funds measured at net asset value practical expedient (3): | | | | | | | | |
| Commingled investment funds measured at net asset value practical expedient (2): | | | | | | | | |
| Equities — U.S. large cap | | | | | | | 37 |
| | | | | | | 14 |
|
| Equities — International small cap | | | | | | | 3 |
| | | | | | | 1 |
|
| Equities — International emerging markets | | | | | | | 5 |
| | | | | | | 2 |
|
| Equities — International developed markets | | | | | | | 16 |
| | | | | | | 6 |
|
| Fixed income — U.S. long duration | | | | | | | 10 |
| | | | | | | 40 |
|
| Fixed income — Corporate bonds | | | | | | | 8 |
| | | | | | | 11 |
|
| Total assets at fair value at December 31, 2015 | | | | | | | $ | 201 |
| |
| | | | | | | | | |
| Total assets at fair value at December 31, 2018 | | | | | | | | $ | 214 |
|
____________
| |
| (1) | The weighted-average credit quality rating of the pension assets fixed income security portfolio is investment grade with a weighted-average duration of approximately 814 years for 20162019 and 2015.13 years for 2018. |
| |
| (2) | The weighted-average credit quality rating of the other postretirement benefit assets fixed income security portfolio is investment grade with a weighted-average duration of approximately 8 years for 2016 and 7 years for 2015. |
| |
(3) | 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 101 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 Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
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.
|
| | | | |
| 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.
The investment contracts with insurance companies are valued at fair value by discounting the cash flow of a bond using a yield to maturity based on an investment grade index or comparable index with a similar maturity value, maturity period, and nominal coupon rate.
There have been no significant changes in the preceding valuation methodologies used at December 31, 20162019 and 2015.2018. Additionally, there were no0 transfers or reclassifications of investments between Level 1 and Level 2 from December 20152018 to December 2016.2019. 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.
|
| | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | (Millions) |
| 2020 | $ | 100 |
| | $ | 14 |
|
| 2021 | 99 |
| | 14 |
|
| 2022 | 97 |
| | 14 |
|
| 2023 | 93 |
| | 14 |
|
| 2024 | 90 |
| | 14 |
|
| 2025-2029 | 433 |
| | 62 |
|
|
| | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | (Millions) |
| 2017 | $ | 99 |
| | $ | 13 |
|
| 2018 | 103 |
| | 13 |
|
| 2019 | 103 |
| | 13 |
|
| 2020 | 106 |
| | 13 |
|
| 2021 | 111 |
| | 13 |
|
| 2022-2026 | 562 |
| | 62 |
|
In 2017,2020, we expect to contribute approximately $60$10 million to our tax-qualified pension plans and approximately $2$3 million to our nonqualified pension plans, for a total of approximately $62$13 million, and approximately $7$6 million to our other postretirement benefit plans.plan.
Defined Contribution PlansPlan
We also maintain a defined contribution plansplan for the benefit of substantially all of our employees. Generally, plan participants may contribute a portion of their compensation on a pre-tax and after-tax basis in accordance with the plans’plan’s guidelines. We match employees’ contributions up to certain limits. Our matching contributions charged to expense were $36 million in 2016, $392019, $35 million in 2015,2018, and $39$34 million in 2014.2017.
|
| | | | |
| 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 | $ | 40 |
|
| Short-term lease cost | — |
|
| Variable lease cost | 27 |
|
| Sublease income | (2 | ) |
| Total lease cost | $ | 65 |
|
| Cash paid for amounts included in the measurement of operating lease liabilities | $ | 39 |
|
| | December 31, 2019 |
| | (Millions) |
| Other Information: | |
Right-of-use asset (included in Regulatory assets, deferred charges, and other in our Consolidated Balance Sheet) | $ | 207 |
|
| Operating lease liabilities: | |
Current (included in Accrued liabilities in our Consolidated Balance Sheet) | $ | 21 |
|
Noncurrent (included in Regulatory liabilities, deferred income, and other in our Consolidated Balance Sheet) | $ | 188 |
|
Weighted-average remaining lease term – operating leases (years) | 13 |
Weighted-average discount rate – operating leases | 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.
|
| | | | |
| 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:
|
| | | |
| | (Millions) |
| 2020 | $ | 29 |
|
| 2021 | 33 |
|
| 2022 | 28 |
|
| 2023 | 22 |
|
| 2024 | 19 |
|
| Thereafter | 157 |
|
| Total future lease payments | 288 |
|
| Less amount representing interest | 79 |
|
| Total obligations under operating leases | $ | 209 |
|
We are the lessor to certain lease agreements for office space in our headquarters building, which are insignificant to our financial statements.
Note 1112 – 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:
| | | | | | | | | | | |
| | Estimated Useful Life (1) (Years) | | Depreciation Rates (1) (%) | | December 31, | Estimated Useful Life (1) (Years) | | Depreciation Rates (1) (%) | | December 31, |
| 2016 |
| 2015 | 2019 |
| 2018 |
| | | | | | (Millions) | | | | | (Millions) |
| Nonregulated: | | | | | | | | |
| Natural gas gathering and processing facilities | 5 - 40 | | $ | 20,413 |
| | $ | 20,789 |
| 5 - 40 | | $ | 17,593 |
| | $ | 15,324 |
|
| Construction in progress | Not applicable | | 412 |
| | 1,366 |
| Not applicable | | 354 |
| | 778 |
|
| Other | 2 - 45 | | 2,202 |
| | 2,170 |
| 2 - 45 | | 2,519 |
| | 2,356 |
|
| Regulated: | | | | | | | | |
| Natural gas transmission facilities | | 1.20 - 6.97 | | 12,692 |
| | 12,189 |
| | 1.25 - 7.13 | | 18,076 |
| | 17,312 |
|
| Construction in progress | Not applicable | | Not applicable | | 1,603 |
| | 941 |
| Not applicable | | Not applicable | | 586 |
| | 965 |
|
| Other | 5 - 45 | | 1.35 - 33.33 | | 1,590 |
| | 1,584 |
| 5 - 45 | | 0.00 - 33.33 | | 2,382 |
| | 1,926 |
|
| Total property, plant, and equipment, at cost | | 38,912 |
| | 39,039 |
| | 41,510 |
| | 38,661 |
|
| Accumulated depreciation and amortization | | (10,484 | ) | | (9,460 | ) | | (12,310 | ) | | (11,157 | ) |
| Property, plant, and equipment — net | | $ | 28,428 |
| | $ | 29,579 |
| | $ | 29,200 |
| | $ | 27,504 |
|
__________
| |
| (1) | Estimated useful life and depreciation rates are presented as of December 31, 2016.2019. 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 $1,407 million, $1,382 million,$1.390 billion, $1.392 billion, and $967 million$1.389 billion in 2016, 2015,2019, 2018, and 2014,2017, respectively.
Regulated Property, plant, and equipment – net includes approximately $665$547 million and $706$586 million at December 31, 20162019 and 2015,2018, 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.
|
| | | | |
| 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 Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
The following table presents the significant changes to our ARO, of which $801 million$1.117 billion and $858$968 million are included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued liabilities at December 31, 20162019 and 2015,2018, respectively.
| | | | December 31, | December 31, |
| | 2016 | | 2015 | 2019 | | 2018 |
| | (Millions) | (Millions) |
| Beginning balance | $ | 915 |
| | $ | 831 |
| $ | 1,032 |
| | $ | 998 |
|
| Liabilities incurred | 24 |
| | 42 |
| 15 |
| | 21 |
|
| Liabilities settled | (8 | ) | | (3 | ) | (8 | ) | | (19 | ) |
| Accretion expense | 69 |
| | 60 |
| 59 |
| | 71 |
|
| Revisions (1) | (138 | ) | | (15 | ) | 67 |
| | (39 | ) |
| Ending balance | $ | 862 |
| | $ | 915 |
| $ | 1,165 |
| | $ | 1,032 |
|
___________
| |
| (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 20162019 revisions reflect changes in removal cost estimates, increasesdecreases in the estimated remaining useful life of certain assets, increases in inflation rates, and decreases in the inflation rate and discount rates used in the annual review process. The 20152018 revisions reflect changes in removal cost estimates, anddecreases in the estimated remaining useful life of certain assets, a decrease in the inflation rate, and increases in the discount rates used in the annual review process. |
The funds Transco collects through a portion of its rates to fund its ARO are deposited into an external trust account dedicated to funding its ARO (ARO Trust). (See Note 1718 – 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 1213 – 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 |
| | (Millions) |
| December 31, 2017 | $ | — |
| | $ | 47 |
| | $ | 47 |
|
| Jackalope Deconsolidation (see Note 6) | | | (47 | ) | | (47 | ) |
| December 31, 2018 | — |
| | — |
| | — |
|
| UEOM Acquisition (see Note 3) | 188 |
| | | | 188 |
|
| December 31, 2019 | $ | 188 |
| | $ | — |
| | $ | 188 |
|
|
| | | |
| | Williams Partners |
| | (Millions) |
| December 31, 2014 | $ | 1,120 |
|
| Purchase accounting adjustment | 25 |
|
| Impairment | (1,098 | ) |
| December 31, 2015 | $ | 47 |
|
| December 31, 2016 | $ | 47 |
|
|
| | | | |
| 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 annual evaluation of goodwill for impairment (performed as of October 1) during the years ended December 31, 20162019, 2018, and 2014. During 2015, we performed an interim assessment and an annual assessment as of September 30, 2015 and October 1, 2015, respectively, of certain goodwill within the Williams Partners segment. The estimated fair value of the reporting units evaluated exceeded their carrying amounts, and thus no impairment was identified. We performed an additional goodwill impairment evaluation as of December 31, 2015, of the goodwill recorded within the Williams Partners segment. As a result of this evaluation, we recorded goodwill impairment charges totaling $1.098 billion. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.)
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
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 | ) |
|
| | | | | | | | | | | | | | | |
| | 2016 | | 2015 |
| | Gross Carrying Amount | | Accumulated Amortization | | Gross Carrying Amount | | Accumulated Amortization |
| | (Millions) |
| Contractual customer relationships | $ | 10,635 |
| | $ | (1,019 | ) | | $ | 10,633 |
| | $ | (663 | ) |
Other intangible assets primarily relate to gas gathering, processing, and fractionation contractual customer relationships recognized in acquisitions. The increase in the ACMP and Eagle Ford acquisitionsgross carrying amount of other intangible assets during 2019 is primarily related to the acquisition of UEOM (see Note 23 – Acquisitions) as well as previous acquisitions.Acquisitions and Divestitures). Other intangible assets are being amortized on a straight-line basis over an initiala 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 respective acquisition), the weighted-average periodsperiod prior to the next renewal or extension of the contractual customer relationships associated with the ACMP and Eagle Ford acquisitions wereUEOM acquisition was approximately 17 years and 10 years, respectively.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 $356$324 million, $353$333 million, and $209$347 million in 2016, 2015,2019, 2018, and 2014,2017, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $356$328 million.
Note 1314 – Accrued Liabilities
|
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| | (Millions) |
| Interest on debt | $ | 288 |
| | $ | 282 |
|
| Employee costs | 226 |
| | 205 |
|
| Estimated rate refund liabilities (Note 19) | 189 |
| | — |
|
| Contract liabilities (Note 2) | 158 |
| | 244 |
|
| Asset retirement obligation (Note 12) | 48 |
| | 64 |
|
| Operating lease liabilities (Note 11) | 21 |
| | — |
|
| Other, including other loss contingencies | 346 |
| | 307 |
|
| | $ | 1,276 |
| | $ | 1,102 |
|
|
| | | | | | | |
| | December 31, |
| | 2016 | | 2015 |
| | (Millions) |
| Deferred income | $ | 338 |
| | $ | 94 |
|
| Interest on debt | 310 |
| | 284 |
|
| Employee costs | 223 |
| | 215 |
|
| Refundable deposits | 160 |
| | — |
|
| Special distribution repayable to Gulfstream (See Note 6 - Investing Activities) | — |
| | 149 |
|
| Asset retirement obligations | 61 |
| | 57 |
|
| Other, including other loss contingencies | 356 |
| | 279 |
|
| | $ | 1,448 |
| | $ | 1,078 |
|
Deferred income in 2016 includes cash proceeds associated with restructuring certain gas gathering contracts in the Barnett Shale and Mid-Continent regions. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)
Refundable deposits in 2016 includes receipts related to an agreement to resolve several matters in relation to Transco’s Hillabee Expansion Project. In accordance with the agreement, the member–sponsors of Sabal Trail will pay WPZ an aggregate amount of $240 million in three equal installments as certain milestones of the project are met, of
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
which $160 million was received in 2016. WPZ expects to recognize income associated with these receipts over the term of an underlying contract once the project is in service.
Note 1415 – Debt and Banking Arrangements and Leases
Long-Term Debt |
| | | | | | | |
| | December 31, |
| | 2019 | | 2018 |
| | (Millions) |
| Transco: | | | |
| 7.08% Debentures due 2026 | $ | 8 |
| | $ | 8 |
|
| 7.25% Debentures due 2026 | 200 |
| | 200 |
|
| 7.85% Notes due 2026 | 1,000 |
| | 1,000 |
|
| 4% Notes due 2028 | 400 |
| | 400 |
|
| 5.4% Notes due 2041 | 375 |
| | 375 |
|
| 4.45% Notes due 2042 | 400 |
| | 400 |
|
| 4.6% Notes due 2048 | 600 |
| | 600 |
|
| Other financing obligation - Atlantic Sunrise | 857 |
| | 807 |
|
| Other financing obligation - Dalton | 259 |
| | 260 |
|
| Northwest Pipeline: |
| | |
| 7.125% Debentures due 2025 | 85 |
| | 85 |
|
| 4% Notes due 2027 | 500 |
| | 500 |
|
| WMB: | | | |
| 4.125% Notes due 2020 | 600 |
| | 600 |
|
| 5.25% Notes due 2020 | 1,500 |
| | 1,500 |
|
| 4% Notes due 2021 | 500 |
| | 500 |
|
| 7.875% Notes due 2021 | 371 |
| | 371 |
|
| 3.35% Notes due 2022 | 750 |
| | 750 |
|
| 3.6% Notes due 2022 | 1,250 |
| | 1,250 |
|
| 3.7% Notes due 2023 | 850 |
| | 850 |
|
| 4.5% Notes due 2023 | 600 |
| | 600 |
|
| 4.3% Notes due 2024 | 1,000 |
| | 1,000 |
|
| 4.55% Notes due 2024 | 1,250 |
| | 1,250 |
|
| 3.9% Notes due 2025 | 750 |
| | 750 |
|
| 4% Notes due 2025 | 750 |
| | 750 |
|
| 3.75% Notes due 2027 | 1,450 |
| | 1,450 |
|
| 7.5% Debentures due 2031 | 339 |
| | 339 |
|
| 7.75% Notes due 2031 | 252 |
| | 252 |
|
| 8.75% Notes due 2032 | 445 |
| | 445 |
|
| 6.3% Notes due 2040 | 1,250 |
| | 1,250 |
|
| 5.8% Notes due 2043 | 400 |
| | 400 |
|
| 5.4% Notes due 2044 | 500 |
| | 500 |
|
| 5.75% Notes due 2044 | 650 |
| | 650 |
|
| 4.9% Notes due 2045 | 500 |
| | 500 |
|
| 5.1% Notes due 2045 | 1,000 |
| | 1,000 |
|
| 4.85% Notes due 2048 | 800 |
| | 800 |
|
| Various — 7.625% to 10.25% Notes and Debentures due 2019 to 2027 | 24 |
| | 55 |
|
| Credit facility loans | — |
| | 160 |
|
| Debt issuance costs | (119 | ) | | (131 | ) |
| Net unamortized debt premium (discount) | (58 | ) | | (62 | ) |
| Total long-term debt, including current portion | 22,288 |
| | 22,414 |
|
| Long-term debt due within one year | (2,140 | ) | | (47 | ) |
| Long-term debt | $ | 20,148 |
| | $ | 22,367 |
|
|
| | | | | | | |
| | December 31, |
| | 2016 | | 2015 |
| | (Millions) |
| Unsecured: | | | |
| Transco: | | | |
| 6.4% Notes due 2016 (1) | $ | — |
| | $ | 200 |
|
| 6.05% Notes due 2018 | 250 |
| | 250 |
|
| 7.08% Debentures due 2026 | 8 |
| | 8 |
|
| 7.25% Debentures due 2026 | 200 |
| | 200 |
|
| 7.85% Notes due 2026 | 1,000 |
| | — |
|
| 5.4% Notes due 2041 | 375 |
| | 375 |
|
| 4.45% Notes due 2042 | 400 |
| | 400 |
|
| Northwest Pipeline: |
| | |
| 7% Notes due 2016 | — |
| | 175 |
|
| 5.95% Notes due 2017 | 185 |
| | 185 |
|
| 6.05% Notes due 2018 | 250 |
| | 250 |
|
| 7.125% Debentures due 2025 | 85 |
| | 85 |
|
| WPZ: | | | |
| 7.25% Notes due 2017 | 600 |
| | 600 |
|
| 5.25% Notes due 2020 | 1,500 |
| | 1,500 |
|
| 4.125% Notes due 2020 | 600 |
| | 600 |
|
| 4% Notes due 2021 | 500 |
| | 500 |
|
| 3.6% Notes due 2022 | 1,250 |
| | 1,250 |
|
| 3.35% Notes due 2022 | 750 |
| | 750 |
|
| 6.125% Notes due 2022 | 750 |
| | 750 |
|
| 4.5% Notes due 2023 | 600 |
| | 600 |
|
| 4.875% Notes due 2023 | 1,400 |
| | 1,400 |
|
| 4.3% Notes due 2024 | 1,000 |
| | 1,000 |
|
| 4.875% Notes due 2024 | 750 |
| | 750 |
|
| 3.9% Notes due 2025 | 750 |
| | 750 |
|
| 4% Notes due 2025 | 750 |
| | 750 |
|
| 6.3% Notes due 2040 | 1,250 |
| | 1,250 |
|
| 5.8% Notes due 2043 | 400 |
| | 400 |
|
| 5.4% Notes due 2044 | 500 |
| | 500 |
|
| 4.9% Notes due 2045 | 500 |
| | 500 |
|
| 5.1% Notes due 2045 | 1,000 |
| | 1,000 |
|
| Term Loan, variable interest rate, due 2018 | 850 |
| | 850 |
|
| Credit facility loans | — |
| | 1,310 |
|
| WMB: |
| | |
| 7.875% Notes due 2021 | 371 |
| | 371 |
|
| 3.7% Notes due 2023 | 850 |
| | 850 |
|
| 4.55% Notes due 2024 | 1,250 |
| | 1,250 |
|
| 7.5% Debentures due 2031 | 339 |
| | 339 |
|
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
|
| | | | | | | |
| | December 31, |
| | 2016 | | 2015 |
| | (Millions) |
| 7.75% Notes due 2031 | 252 |
| | 252 |
|
| 8.75% Notes due 2032 | 445 |
| | 445 |
|
| 5.75% Notes due 2044 | 650 |
| | 650 |
|
| Various — 5.5% to 10.25% Notes and Debentures due 2019 to 2033 | 55 |
| | 55 |
|
| Credit facility loans | 775 |
| | 650 |
|
| Capital lease obligations | — |
| | 1 |
|
| Debt issuance costs | (119 | ) | | (123 | ) |
| Net unamortized debt premium (discount) | 88 |
| | 110 |
|
| Total long-term debt, including current portion | 23,409 |
| | 23,988 |
|
| Long-term debt due within one year | (785 | ) | | (176 | ) |
| Long-term debt | $ | 22,624 |
| | $ | 23,812 |
|
___________
| |
(1) | Presented as long-term debt at December 31, 2015, due to Transco’s intent and ability to refinance. |
Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, sell assets, and incur additional debt. Default of these agreements could also restrict our ability to make certain distributions or repurchase equity.
The following table presents aggregate minimum maturities of long-term debt, excluding net unamortized debt premium (discount), debt issuance costs, and capital lease obligations, for each of the next five years:
|
| | | |
| | December 31, 2016 |
| | (Millions) |
| 2017 | $ | 785 |
|
| 2018 | 1,350 |
|
| 2019 | 32 |
|
| 2020 | 2,896 |
|
| 2021 | 871 |
|
Issuances and retirements
WPZ retired $600 million of 7.25 percent senior unsecured notes that matured on February 1, 2017.
Northwest Pipeline retired $175 million of 7 percent senior unsecured notes that matured on June 15, 2016.
Transco retired $200 million of 6.4 percent senior unsecured notes that matured on April 15, 2016.
On January 22, 2016, Transco issued $1 billion of 7.85 percent senior unsecured notes due 2026 to investors in a private debt placement. In January 2017, Transco completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended. Transco used the net proceeds to repay debt and to fund capital expenditures.
In December 2015, WPZ borrowed $850 million on a variable interest rate loan with certain lenders due 2018. At December 31, 2016, the interest rate was 2.50 percent. WPZ used the proceeds for working capital, capital expenditures, and for general partnership purposes.
On April 15, 2015, WPZ paid $783 million, including a redemption premium, to early retire $750 million of 5.875 percent senior notes due 2021 with a carrying value of $797 million.
|
| | | | |
| 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 | $ | 2,141 |
|
| 2021 | 893 |
|
| 2022 | 2,025 |
|
| 2023 | 1,477 |
|
| 2024 | 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 3, 2015,5, 2018, WPZ completed a public offering of $1.25 billion$800 million of 3.64.85 percent senior unsecured notes due 2022,2048. 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 2025,2028 and $1 billion$600 million of 5.14.6 percent senior unsecured notes due 2045. WPZ2048 to investors in a private debt placement. Transco used the net proceeds to repay amounts outstanding under its commercial paper program and credit facility, to fund capital expenditures, and for general partnership purposes.
WPZ retired $750retire $250 million of 3.86.05 percent senior unsecured notes that matured on FebruaryJune 15, 2015.2018, 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.
Credit FacilitiesOther 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.
|
| | | | | | | |
| | December 31, 2016 |
| | Available | | Outstanding |
| | (Millions) |
| WMB | | | |
| Long-term credit facility | $ | 1,500 |
| | $ | 775 |
|
| Letters of credit under certain bilateral bank agreements | | | 13 |
|
| WPZ | | | |
| Long-term credit facility (1) | 3,500 |
| | — |
|
| Letters of credit under certain bilateral bank agreements |
| | 1 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
|
| | | | | | | |
| | December 31, 2019 |
| | Stated Capacity | | Outstanding |
| | (Millions) |
| Long-term credit facility (1) | $ | 4,500 |
| | $ | — |
|
| Letters of credit under certain bilateral bank agreements | | | 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. |
WMB long-termRevolving credit facility
On February 2, 2015,July 13, 2018, we along with Transco and Northwest Pipeline, the lenders named therein, and an administrative agent entered into the Second Amended and Restated Credit Agreement. Thea credit agreement (Credit Agreement) with aggregate commitments available remained at $1.5of $4.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. The maturity dateOn August 10, 2018, following the completion of the credit facility was extended to February 2, 2020. However, we may request up to two extensions ofWPZ Merger, the maturity date each for an additional one year period to allow a maturity date as late as February 2, 2022, under certain circumstances. The agreement also allows for swing line loans up to an aggregate amount of $50 million, subject to available capacity under the credit facility, and the letters of credit up to $675 million.
The agreements governing the credit facilities contain the following terms and conditions:
Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, make investments, and allow any material change in the nature of its business.
If an event of default with respect to a borrower occurs under its respective credit facility, the lenders will be able to terminate the commitments for the respective borrowers and accelerate the maturity of any loans of the defaulting borrower under the respective credit facility agreement and exercise other rights and remedies.
Each time funds are borrowed under our credit facility, the borrower may choose from two methods of calculating interest: a fluctuating base rate equal to the bank’s alternate base rate plus an applicable margin or a periodic fixed rate equal to LIBOR plus an applicable margin. The borrower is required to pay a commitment fee based on the unused portion of its respective credit facility. The applicable margin and the commitment fee are determined for us by reference to a pricing schedule based on our senior unsecured long-term debt ratings.
Significant financial covenants under the agreement require the ratio of debt to EBITDA (each as defined in the credit agreement) be no greater than 5 to 1, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the ratio of debt to EBITDA is to be no greater than 5.5 to 1.
We are in compliance with these financial covenants as measured at December 31, 2016.
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
As of February 20, 2017, $235 million is outstanding under our long-term credit facility.
WPZ long-term credit facilities
Prior to their merger both WPZ and ACMP had separate credit facilities that terminated on February 2, 2015.
On February 2, 2015, WPZ along with Transco, Northwest Pipeline, the lenders named therein, and an administrative agent entered into the Second Amended & Restated Credit Agreement with aggregate commitments available of $3.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances.became effective. The maturity date of the credit facility is February 2, 2020.August 10, 2023. However, the co-borrowers may request up to two extensions of the maturity date each for an additional one yearone-year period to allow a maturity date as late as February 2, 2022,August 10, 2025, under certain circumstances. The agreementCredit Agreement allows for swing line loans up to an aggregate amount of $150$200 million, subject to available capacity under the credit facility, and letters of credit commitments of $1.125$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. On December 18, 2015, WPZ along with Transco, Northwest Pipeline, the lenders named therein and an administrative agent entered into the Amendment No. 1 to Second Amended & Restated
The Credit Agreement modifying the thresholds specified in the covenant related to the maximum ratio of WPZ’s debt to EBITDA.
The agreement governing this credit facility contains the following terms and conditions:
Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, and enter into certain restrictive agreements, and allow any material change in the nature of its business.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 for all borrowers and accelerate the maturity of anythe loans of the defaulting borrower under the credit facility agreement and exercise other rights and remedies.
Other than swing line loans, each time funds are borrowed, the applicable borrower mustmay choose whether such borrowing will be anfrom two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.'s alternate base rate borrowingplus an applicable margin or a Eurodollar borrowing. If such borrowing is an alternate base rate borrowing, interest is calculated on the basis of the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus one half of 1 percent and (c) a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus 1 percent, plus, in the case of each of (a), (b) and (c), an applicable margin. If the borrowing is a Eurodollar borrowing, interest is calculated on the basis of LIBOR for the relevant period plus an applicable margin. Interest on swing line loans is calculated as the sum of the alternate base rate plus an applicable margin. The borrower isWe 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 for each borrower by reference to a pricing schedule based on suchthe applicable borrower’s senior unsecured long-term debt ratings.
Significant financial covenants under the agreementCredit 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 the quarters ending December 31, 2015, March 31, 2016 andeach fiscal quarter end through June 30, 2016;2019;
5.505.5 to 1 for the fiscal quarters ending September 30, 20162019, and December 31, 2016;2019;
5.005.0 to 1 for the fiscal quarter ending March 31, 20172020, and each subsequent fiscal quarter end, except for the 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 1.00.1.
|
| | | | |
| 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. WPZ is
At December 31, 2019, we are in compliance with these financial covenants as measured at December 31, 2016.
As of February 20, 2017, there are no amounts outstanding under the long-term credit facility.
WPZ short-term credit facilities
On August 26, 2015, WPZ entered into a $1.0 billion short-term credit facility. On December 23, 2015, WPZ’s short-term credit facility capacity decreased to $150 million in conjunction with entering into the $850 million term loan. The $150 million short-term credit facility is no longer available as it expired August 24, 2016.covenants.
Commercial Paper Program
On February 2, 2015,August 10, 2018, following the consummation of the WPZ amended and restated theMerger, we entered into a $4 billion commercial paper program for the ACMP Merger and to allow a maximum outstanding amount of unsecured commercial paper notes of $3 billion.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. Proceeds from theseThe net proceeds of issuances of the commercial paper notes are expected to be used for general partnership purposes, including fundingto fund planned capital expenditures working capital, and partnership distributions. We classify WPZ’sfor other general corporate purposes. At December 31, 2019 and 2018, 0 commercial paper outstanding in Current liabilities in the Consolidated Balance Sheet, as the outstanding notes at December 31, 2016 and December 31, 2015, have maturity dates less than three months from the date of issuance. At December 31, 2016, WPZ had $93 million in Commercial paper outstanding at a weighted-average interest rate of 1.06 percent and at December 31, 2015, WPZ had $499 million in Commercial paper outstanding at a weighted-average interest rate of 0.92 percent.was outstanding.
Cash Payments for Interest (Net of Amounts Capitalized)
Cash payments for interest (net of amounts capitalized)were $1.152$1.153 billion in 2016, $1.0232019, $1.064 billion in 2015,2018, and $681 million$1.110 billion in 2014.
Restricted Net Assets of Subsidiaries
We have considered the guidance in the Securities and Exchange Commission’s Regulation S-X related to restricted net assets of subsidiaries. In accordance with Rule 4-08(e) of Regulation S-X, we have determined that certain net assets of our subsidiaries are considered restricted under this guidance and exceed 25 percent of our consolidated net assets. As of December 31, 2016, substantially all of these restricted net assets relate to the net assets of WPZ, which are technically considered restricted under this accounting rule due to terms within WPZ’s partnership agreement that govern the partnerships’ assets. Our interest in WPZ’s net assets that are considered to be restricted at December 31, 2016, was $13 billion.
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
Leases-Lessee
The future minimum annual rentals under noncancelable operating leases, are payable as follows:
|
| | | |
| | December 31, 2016 |
| | (Millions) |
| 2017 | $ | 62 |
|
| 2018 | 58 |
|
| 2019 | 51 |
|
| 2020 | 46 |
|
| 2021 | 35 |
|
| Thereafter | 90 |
|
| Total | $ | 342 |
|
Total rent expense was $64 million in 2016, $69 million in 2015, and $62 million in 2014 and primarily included in Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement of Operations.
Other
On January 25, 2017, WPZ announced that it will redeem all of its $750 million 6.125 percent senior notes due 2022 on February 23, 2017.
Note 1516 – Stockholders' Equity
Cash dividends declared per common share were $1.68, $2.45, and $1.9575 for 2016, 2015, and 2014, respectively. On February 20, 2017,January 28, 2020, our board of directors approved a regular quarterly dividend to common stockholders of $0.30$0.40 per share payable on March 27, 2017.30, 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.)
On June 23, 2014, we issued 61 million sharesAOCI
The following table presents the changes in AOCI by component, net of common stock in a public offering at a price of $57.00 per share. That amount includes 8 million shares purchased pursuant to the full exercise of the underwriter’s option to purchase additional shares. The net proceeds of $3.378 billion were used in July 2014 to finance a portion of the ACMP Acquisition. (See Note 2 - Acquisitions.)
income taxes:
|
| | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | Foreign Currency Translation | | Pension and Other Post Retirement Benefits | | Total |
| | (Millions) |
| Balance at December 31, 2018 | $ | (2 | ) | | $ | (1 | ) | | $ | (267 | ) | | $ | (270 | ) |
Other comprehensive income (loss) before reclassifications | — |
| | — |
| | 59 |
| | 59 |
|
Amounts reclassified from accumulated other comprehensive income (loss) | — |
| | — |
| | 12 |
| | 12 |
|
| Other comprehensive income (loss) | — |
| | — |
| | 71 |
| | 71 |
|
| Balance at December 31, 2019 | $ | (2 | ) | | $ | (1 | ) | | $ | (196 | ) | | $ | (199 | ) |
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
AOCI
The following table presents the changes in AOCI by component, net of income taxes:
|
| | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | Foreign Currency Translation | | Pension and Other Post Retirement Benefits | | Total |
| | (Millions) |
| Balance at December 31, 2015 | $ | (1 | ) | | $ | (103 | ) | | $ | (338 | ) | | $ | (442 | ) |
Other comprehensive income (loss) before reclassifications | 2 |
| | 25 |
| | (15 | ) | | 12 |
|
Amounts reclassified from accumulated other comprehensive income (loss) | (1 | ) | | 76 |
| | 16 |
| | 91 |
|
| Other comprehensive income (loss) | 1 |
| | 101 |
| | 1 |
| | 103 |
|
| Balance at December 31, 2016 | $ | — |
| | $ | (2 | ) | | $ | (337 | ) | | $ | (339 | ) |
Reclassifications out of AOCI are presented in the following table by component for the year ended December 31, 2016:2019:
|
| | | | | | |
| Component | | Reclassifications | | Classification |
| | | (Millions) | | |
| Pension and other postretirement benefits: | | | | |
| Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit) | | $ | 16 |
| | Other income (expense) – net below Operating income (loss) |
| Income tax benefit | | (4 | ) | | Provision (benefit) for income taxes |
| Reclassifications during the period | | $ | 12 |
| | |
|
| | | | | | |
| Component | | Reclassifications | | Classification |
| | | (Millions) | | |
| Cash flow hedges: | | | | |
| Energy commodity contracts | | $ | (3 | ) | | Product sales |
| Total cash flow hedges | | (3 | ) | | |
| | | | | |
| Pension and other postretirement benefits: | | | | |
| Amortization of prior service cost (credit) included in net periodic benefit cost | | (6 | ) | | Note 10 – Employee Benefit Plans |
| Amortization of actuarial (gain) loss included in net periodic benefit cost | | 32 |
| | Note 10 – Employee Benefit Plans |
| Total pension and other postretirement benefits | | 26 |
| | |
| Foreign currency translation: | | | | |
| Reclassification of cumulative foreign currency translation adjustment upon sale of foreign entities | | 155 |
| | Other (income) expense - net |
| | | | | |
| Total before tax | | 178 |
| | |
| Income tax benefit | | (45 | ) | | Provision (benefit) for income taxes |
| Net of income tax | | 133 |
| | |
| Noncontrolling interest | | (42 | ) | | Net income (loss) attributable to noncontrolling interests |
| Reclassifications during the period | | $ | 91 |
| | |
Note 1617 – Equity-Based Compensation
Williams’ Plan Information
On May 17, 2007, our stockholders approved The Williams Companies, Inc. 2007 Incentive Plan (the Plan) that provides common-stock-based awards to both employees and nonmanagement directors and reserved 19directors. To date, 40 million new shares for issuance. On May 20, 2010 and May 22, 2014, our stockholders approved amendments and restatements of the Plan to increase by 11 million and 10 million, respectively, the number of new shareshave been authorized for making awards under the Plan, among other changes.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 purchased322 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 | Options | | Weighted- Average Exercise Price | | Aggregate Intrinsic Value |
| | (Millions) | | | | (Millions) |
| Outstanding at December 31, 2018 | 7.3 |
| | $ | 31.55 |
| | |
| Granted | — |
| | $ | — |
| | |
| Exercised | (0.4 | ) | | $ | 11.31 |
| | |
| Cancelled | (0.1 | ) | | $ | 35.62 |
| | |
| Outstanding at December 31, 2019 | 6.8 |
| | $ | 32.64 |
| | $ | 2 |
|
| Exercisable at December 31, 2019 | 5.8 |
| | $ | 33.22 |
| | $ | 2 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
to, restricted stock units and stock options. At December 31, 2016, 27 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 17 million shares were available for future grants.
Additionally, on May 17, 2007, our stockholders approved an Employee Stock Purchase Plan (ESPP) which authorized up to 2 million new shares of our common stock to be available for sale under the ESPP. On May 22, 2014, our stockholders approved an amendment and restatement of the ESPP to increase by 1.6 million the number of new shares authorized for sale under the ESPP. The ESPP enables eligible participants to purchase our common stock through payroll deductions not exceeding an annual amount of $15,000 per participant. The ESPP provides for offering periods during which shares may be purchased and continues until the earliest of (1) the Board of Directors terminates the ESPP, (2) the sale of all shares available under the ESPP, or (3) the tenth anniversary of the date the amended and restated ESPP was approved by the stockholders. Offering periods are from January through June and from July through December. Generally, all employees are eligible to participate in the ESPP, with the exception of executives and international employees. The number of shares eligible for an employee to purchase during each offering period is limited to 750 shares. The purchase price of the stock is 85 percent of the lower closing price of either the first or the last day of the offering period. The ESPP requires a one-year holding period before the stock can be sold. The plan was suspended during the period from January 1, 2016 to August 31, 2016, and was reinstated effective September 1, 2016. Employees purchased111 thousand shares at an average price of $23.93 per share during the period from September 1, 2016 to December 31, 2016. Approximately 1.4 million shares were available for purchase under the ESPP at December 31, 2016.
Operating and maintenance expenses and Selling, general and administrative expenses include equity-based compensation expense for the years ended December 31, 2016, 2015, and 2014 of $53 million, $56 million, and $44 million, respectively. Income tax benefit recognized related to the stock-based compensation expense for the years ended December 31, 2016, 2015, and 2014 was $20 million, $21 million, and $17 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2016, was $67 million, which does not include the effect of estimated forfeitures of $2 million. Unrecognized stock-based compensation expense is comprised of $5 million related to stock options and $62 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.9 years.
Stock Options
Stock options are valued at the date of award, which does not precede the approval date. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of grant. Stock options generally expire ten years after the grant.
The following summary reflects stock option activity and related information for the year ended December 31, 2016:
|
| | | | | | | | | | |
| Stock Options | Options | | Weighted- Average Exercise Price | | Aggregate Intrinsic Value |
| | (Millions) | | | | (Millions) |
| Outstanding at December 31, 2015 | 5.7 |
| | $ | 31.51 |
| | |
| Granted | 0.9 |
| | $ | 24.99 |
| | |
| Exercised | (0.3 | ) | | $ | 17.84 |
| | |
| Cancelled | (0.1 | ) | | $ | 24.04 |
| | |
| Outstanding at December 31, 2016 | 6.2 |
| | $ | 31.32 |
| | $ | 28 |
|
| Exercisable at December 31, 2016 | 5.0 |
| | $ | 29.75 |
| | $ | 23 |
|
|
| | | | |
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 | | 2017 |
| | (Millions) |
| Total intrinsic value of options exercised | $ | 6 |
| | $ | 3 |
| | $ | 4 |
|
| Tax benefits realized on options exercised | $ | 1 |
| | $ | — |
| | $ | 1 |
|
| Cash received from the exercise of options | $ | 4 |
| | $ | 9 |
| | $ | 7 |
|
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (Millions) |
| Total intrinsic value of options exercised | $ | 2 |
| | $ | 37 |
| | $ | 48 |
|
| Tax benefits realized on options exercised | $ | 1 |
| | $ | 13 |
| | $ | 18 |
|
| Cash received from the exercise of options | $ | 4 |
| | $ | 20 |
| | $ | 31 |
|
The weighted-average remaining contractual lifelives for stock options outstanding and exercisable at December 31, 2016, was 5.52019, were 4.2 years and 4.23.6 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:
|
| | | | | | | |
| | 2018 | | 2017 |
| 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 | 4.7 | % | | 4.2 | % |
| Volatility | 30.1 | % | | 35.1 | % |
| Risk-free interest rate | 2.7 | % | | 2.1 | % |
| Expected life (years) | 6.0 |
| | 6.0 |
|
|
| | | | | | | | | | | |
| | 2016 | | 2015 | | 2014 |
| Weighted-average grant date fair value of options for our common stock granted during the year, per share | $ | 7.90 |
| | $ | 7.61 |
| | $ | 7.50 |
|
| Weighted-average assumptions: | | | | | |
| Dividend yield | 3.2 | % | | 4.8 | % | | 4.2 | % |
| Volatility | 44.7 | % | | 27.8 | % | | 28.0 | % |
| Risk-free interest rate | 1.2 | % | | 1.8 | % | | 2.2 | % |
| Expected life (years) | 6.0 |
| | 6.0 |
| | 6.5 |
|
There were no stock options granted in 2019. The 2016 expected dividend yield for each respective year is based on the 2016 dividend forecast for that year and the grant-date market price of our stock. ExpectedOur 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 average of our peer groupblended 10-year historical volatility adjusted by a ratio of our implied volatility to the adjusted average of ourstock and certain peer group’s implied volatility. The adjustment is made because the difference in implied volatility between our peer group and us may indicate that we are expected to be more volatile than our peer group average.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, 2016:2019:
| | | Restricted Stock Units Outstanding | Shares | | Weighted- Average Fair Value (1) | Shares | | Weighted- Average Fair Value (1) |
| | (Millions) | | | (Millions) | | |
| Nonvested at December 31, 2015 | 3.4 |
| | $ | 39.38 |
| |
| Nonvested at December 31, 2018 | | 4.5 |
| | $ | 28.96 |
|
| Granted | 1.5 |
| | $ | 26.51 |
| 2.5 |
| | $ | 25.87 |
|
| Forfeited | (0.1 | ) | | $ | 38.18 |
| (0.5 | ) | | $ | 28.48 |
|
| Vested | (0.9 | ) | | $ | 35.49 |
| (1.1 | ) | | $ | 26.25 |
|
| Nonvested at December 31, 2016 | 3.9 |
| | $ | 35.19 |
| |
| Nonvested at December 31, 2019 | | 5.4 |
| | $ | 28.11 |
|
______________
| |
| (1) | Performance-based restricted stock units are valued considering measures of total shareholder return utilizing a Monte Carlo valuation method using measures of total shareholder return. Certain of the performance-based restricted stock units are subject to a holding period of up to two years after the vesting date. Discounts for the restrictions of liquidity were applied to the estimated fair value at the date of certain awards and ranged from 5.83 percent to 15.58 percent. The discounts were developed using the Chaffe model and the Finnerty model.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. |
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
|
| | | | | | | | | | | |
| Value of Restricted Stock Units | 2019 | | 2018 | | 2017 |
| Weighted-average grant date fair value of restricted stock units granted during the year, per share | $ | 25.87 |
| | $ | 30.48 |
| | $ | 29.47 |
|
| Total fair value of restricted stock units vested during the year (in millions) | $ | 29 |
| | $ | 35 |
| | $ | 33 |
|
|
| | | | | | | | | | | |
| Value of Restricted Stock Units | 2016 | | 2015 | | 2014 |
| Weighted-average grant date fair value of restricted stock units granted during the year, per share | $ | 26.51 |
| | $ | 40.15 |
| | $ | 42.79 |
|
| Total fair value of restricted stock units vested during the year ($’s in millions) | $ | 32 |
| | $ | 42 |
| | $ | 27 |
|
Performance-based restricted stock units granted under the Plan represent4039 percent of nonvested restricted stock units outstanding at December 31, 2016.2019. 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 zero0 percent to 500200 percent of the original grant amount.
WPZ’s Plan Information
During 2014, certain employees of ACMP’s general partner received equity-based compensation through ACMP’s equity-based compensation program. The fair value of the awards issued was based on the fair market value of the common units on the date of grant. This value is being amortized over the vesting period, which is one to four years from the date of grant. These awards were converted to WPZ equity-based awards in accordance with the terms of the ACMP Merger. No additional grants of restricted common units were awarded through WPZ’s equity-based compensation programs in 2016 or 2015, and no additional grants are expected in the future. Equity-based compensation expense of $20 million, $29 million, and $11 million related to WPZ’s equity-based compensation program is included in Operating and maintenance expenses and Selling, general, and administrative expenses for the years ended December 31, 2016, 2015, and 2014, respectively. As of December 31, 2016, there was $11 million of unrecognized compensation expense attributable to the outstanding awards, which does not include the effect of estimated forfeitures of $1 million. These amounts are expected to be recognized over a weighted average period of 1.2 years.
The following summary reflects nonvested WPZ restricted common unit activity and related information for the year ended December 31, 2016:
|
| | | | | | |
| Restricted Common Units Outstanding | Units | | Weighted- Average Fair Value |
| | (Millions) | | |
| Nonvested at December 31, 2015 | 1.2 |
| | $ | 55.93 |
|
| Forfeited | (0.1 | ) | | $ | 52.85 |
|
| Vested | (0.5 | ) | | $ | 59.09 |
|
| Nonvested at December 31, 2016 | 0.6 |
| | $ | 52.97 |
|
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
Note 1718 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, commercial paper,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 |
| | Carrying Amount | | Fair Value | | Quoted Prices In Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) |
| | (Millions) |
| 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 | 1 |
| | 1 |
| | 1 |
| | — |
| | — |
|
| Energy derivative liabilities not designated as hedging instruments | (3 | ) | | (3 | ) | | (1 | ) | | — |
| | (2 | ) |
| Additional disclosures: | | | | | | | | | |
| Long-term debt, including current portion | (22,288 | ) | | (25,319 | ) | | — |
| | (25,319 | ) | | — |
|
| Guarantees | (41 | ) | | (27 | ) | | — |
| | (11 | ) | | (16 | ) |
| | | | | | | | | | |
| Assets (liabilities) at December 31, 2018: | | | | | | | | | |
| Measured on a recurring basis: | | | | | | | | | |
| ARO Trust investments | $ | 150 |
| | $ | 150 |
| | $ | 150 |
| | $ | — |
| | $ | — |
|
| Energy derivative assets not designated as hedging instruments | 3 |
| | 3 |
| | 3 |
| | — |
| | — |
|
| Energy derivative liabilities not designated as hedging instruments | (7 | ) | | (7 | ) | | (4 | ) | | — |
| | (3 | ) |
| Additional disclosures: | | | | | | | | | |
| Long-term debt, including current portion | (22,414 | ) | | (23,330 | ) | | — |
| | (23,330 | ) | | — |
|
| Guarantees | (43 | ) | | (30 | ) | | — |
| | (14 | ) | | (16 | ) |
|
| | | | | | | | | | | | | | | | | | | |
| | | | | | Fair Value Measurements Using |
| | Carrying Amount | | Fair Value | | Quoted Prices In Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) |
| | (Millions) |
| Assets (liabilities) at December 31, 2016: | | | | | | | | | |
| Measured on a recurring basis: | | | | | | | | | |
| ARO Trust investments | $ | 96 |
| | $ | 96 |
| | $ | 96 |
| | $ | — |
| | $ | — |
|
| Energy derivatives assets designated as hedging instruments | 2 |
| | 2 |
| | — |
| | 2 |
| | — |
|
| Energy derivatives assets not designated as hedging instruments | 1 |
| | 1 |
| | — |
| | — |
| | 1 |
|
| Energy derivatives liabilities not designated as hedging instruments | (6 | ) | | (6 | ) | | — |
| | — |
| | (6 | ) |
| Additional disclosures: | | | | | | | | | |
| Other receivables | 15 |
| | 15 |
| | 15 |
| | — |
| | — |
|
| Long-term debt, including current portion | (23,409 | ) | | (24,090 | ) | | — |
| | (24,090 | ) | | — |
|
| Guarantees | (44 | ) | | (30 | ) | | — |
| | (14 | ) | | (16 | ) |
| | | | | | | | | | |
| Assets (liabilities) at December 31, 2015: | | | | | | | | | |
| Measured on a recurring basis: | | | | | | | | | |
| ARO Trust investments | $ | 67 |
| | $ | 67 |
| | $ | 67 |
| | $ | — |
| | $ | — |
|
| Energy derivatives assets not designated as hedging instruments | 5 |
| | 5 |
| | — |
| | 3 |
| | 2 |
|
| Energy derivatives liabilities not designated as hedging instruments | (2 | ) | | (2 | ) | | — |
| | — |
| | (2 | ) |
| Additional disclosures: | | | | | | | | | |
| Other receivables | 12 |
| | 30 |
| | 10 |
| | 2 |
| | 18 |
|
| Long-term debt, including current portion (1) | (23,987 | ) | | (19,606 | ) | | — |
| | (19,606 | ) | | — |
|
| Guarantee | (29 | ) | | (16 | ) | | — |
| | (16 | ) | | — |
|
___________
|
| | | | |
(1)The Williams Companies, Inc. |
Excludes capital leases.Notes to Consolidated Financial Statements – (Continued) |
|
Fair Value Methods
We use the following methods and assumptions in estimating the fair value of our financial instruments:
Assets and liabilities measured at fair value on a recurring basis
ARO Trust investments: Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust that is specifically designated to fund future asset retirement obligations.ARO’s. The ARO Trust invests in a
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market is classified as available-for-sale, and is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet.Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.
Energy derivatives: Energy derivatives include commodity basedcommodity-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 derivativesderivative assets are reported in Other current assets and deferred charges and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet.Sheet. Energy derivativesderivative liabilities are reported in Accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.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, 20162019 or 20152018.
Additional fair value disclosures
Other receivables: Other receivables primarily consist of margin deposits, which are reported in OtherLong-term debt, including current assets and deferred charges in the Consolidated Balance Sheet. The disclosed fair value of our margin deposits is considered to approximate the carrying value generally due to the short-term nature of these items.
Other receivables also include a receivable related to the sale of certain former Venezuela assets. The disclosed fair value of this receivable is determined by an income approach. We calculated the net present value of a probability-weighted set of cash flows utilizing assumptions based on contractual terms, historical payment patterns by the counterparty, future probabilities of default, our likelihood of using arbitration if the counterparty does not perform, and discount rates. We determined the fair value of the receivable to be $18 million at December 31, 2015. We received two payments in 2016. The carrying value of this receivable iszero at December 31, 2016 and December 31, 2015.
Long-term debtportion: 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 disclosed 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.Sheet. The maximum potential undiscounted exposure is approximately $32$28 million at December 31, 2016.2019. 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.
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
Sheet.
We are required by our revolving credit agreementsagreement to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.
Nonrecurring fair value measurements
We performed an interim assessment of the goodwill associated with our Central and Northeast G&P reporting units as of September 30, 2015, and the annual assessment of goodwill associated with our Northeast G&P and West reporting units as of October 1, 2015. No impairment charges were required following these evaluations.
During the fourth quarter of 2015, we observed a significant decline in the market values of WPZ and comparable midstream companies within the industry. This served to reduce our estimate of enterprise value and increased our estimates of discount rates. As a result, we performed an impairment assessment as of December 31, 2015, of the goodwill associated with these reporting units, all within the Williams Partners segment.
We estimated the fair value of each reporting unit based on an income approach utilizing discount rates specific to the underlying businesses of each reporting unit. These discount rates considered variables unique to each business area, including equity yields of comparable midstream businesses, expectations for future growth, and customer performance considerations. Weighted-average discount rates utilized ranged from approximately 10 percent to 13 percent across the three reporting units.
As a result of the increases in discount rates during the fourth quarter of 2015, coupled with certain reductions in estimated future cash flows determined during the same period, the fair values of the Central and Northeast G&P reporting units were determined to be below their respective carrying values. For these measurements, the book basis of each reporting unit was reduced by the associated deferred tax liabilities. We then calculated the implied fair value of goodwill by performing a hypothetical application of the acquisition method wherein the estimated fair value was allocated to the underlying assets and liabilities of each reporting unit. As a result of these Level 3 measurements, we determined that the previously recorded goodwill associated with each reporting unit was fully impaired, resulting in a fourth-quarter 2015 noncash charge of $1,098 million, reflected in Impairment of goodwill in the Consolidated Statement of Operations. For the West reporting unit, the estimated fair value exceeded the carrying value and no impairment was recorded.
|
| | | | |
| 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 0 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.hierarchy, except as specifically noted. Impairments of equity-method investments are reported in Other investing income (loss) – netin the Consolidated Statement of Operations.
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| | | | | | | | | Impairments |
| | | | | | | | | Year Ended December 31, |
| | | Segment | | Date of Measurement | | Fair Value | | 2019 | | 2018 | | 2017 |
| | | | | | | (Millions) |
| Impairment of certain assets: | | | | | | | | | | | | |
| Certain pipeline project (1) | | Atlantic-Gulf | | December 31, 2019 | | $ | 22 |
| | $ | 354 |
| | | | |
| Certain gathering assets (2) | | West | | December 31, 2019 | | 25 |
| | 20 |
| | | | |
| Certain gathering assets (2) | | West | | June 30, 2019 | | 40 |
| | 59 |
| | | | |
| Certain idle gathering assets (3) | | West | | March 31, 2019 | | — |
| | 12 |
| | | | |
| Certain gathering assets (4) | | West | | December 31, 2018 | | 470 |
| | | | $ | 1,849 |
| | |
| Certain idle pipeline assets (5) | | Other | | June 30, 2018 | | 25 |
| |
| | 66 |
| | |
| Certain gathering assets (6) | | West | | September 30, 2017 | | 439 |
| |
| |
| | $ | 1,019 |
|
| Certain gathering assets (7) | | Northeast G&P | | September 30, 2017 | | 21 |
| |
| |
| | 115 |
|
| Certain NGL pipeline (8) | | Other | | September 30, 2017 | | 32 |
| |
| |
| | 68 |
|
| Certain olefins pipeline project (9) | | Other | | June 30, 2017 | | 18 |
| |
| |
| | 23 |
|
| Other impairments and write-downs (10) | | | | | | | | 19 |
| | — |
| | 23 |
|
| Impairment of certain assets | | | | | | | | $ | 464 |
| | $ | 1,915 |
| | $ | 1,248 |
|
| Impairment of equity-method investments: | | | | | | | | | | | | |
| Laurel Mountain (11) | | Northeast G&P | | September 30, 2019 | | $ | 242 |
| | $ | 79 |
| | | | |
| Appalachia Midstream Investments (12) | | Northeast G&P | | September 30, 2019 | | 102 |
| | 17 |
| | | | |
| Pennant (13) | | Northeast G&P | | August 31, 2019 | | 11 |
| | 17 |
| | | | |
| UEOM (14) | | Northeast G&P | | March 17, 2019 | | 1,210 |
| | 74 |
| | | | |
| UEOM (14) | | Northeast G&P | | December 31, 2018 | | 1,293 |
| |
| | $ | 32 |
| | |
| Other | | | | | |
| | (1 | ) | |
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|
| Impairment of equity-method investments | | | | | | | | $ | 186 |
| | $ | 32 |
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| | | | | | | | | | Impairments |
| | | | | | | | | | Years Ended December 31, |
| | Classification | | Segment | | Date of Measurement | | Fair Value | | 2016 | | 2015 | | 2014 |
| | | | | | | | (Millions) |
| Surplus equipment (1) | Property, plant, and equipment – net | | Williams Partners | | June 30, 2014 | | $ | 46 |
| | | | | | $ | 17 |
|
| Surplus equipment (1) | Property, plant, and equipment – net | | Williams Partners | | December 31, 2014 | | 32 |
| | | | | | 13 |
|
| Surplus equipment (1) | Property, plant, and equipment – net | | Williams Partners | | June 30, 2015 | | 17 |
| | | | $ | 20 |
| | |
| Surplus equipment (1) | Assets held for sale | | Williams Partners | | December 31, 2014 | | 1 |
| | | | | | 12 |
|
| Previously capitalized project development costs (2) | Property, plant, and equipment – net | | Williams Partners | | December 31, 2015 | | 13 |
| | | | 94 |
| | |
| Previously capitalized project development costs (3) | Property, plant, and equipment – net | | Williams NGL & Petchem Services | | December 31, 2015 | | 40 |
| | | | 64 |
| | |
| Canadian operations (4) | Assets held for sale | | Williams Partners | | June 30, 2016 | | 924 |
| | $ | 341 |
| | | | |
| Canadian operations (4) | Assets held for sale | | Williams NGL & Petchem Services | | June 30, 2016 | | 206 |
| | 406 |
| | | | |
| Certain gathering operations (5) | Property, plant, and equipment – net | | Williams Partners | | June 30, 2016 | | 18 |
| | 48 |
| | | | |
| Certain idle assets | Property, plant, and equipment – net | | Williams NGL & Petchem Services | | December 31, 2016 | | 73 |
| | 8 |
| | | | |
| Level 3 fair value measurements of certain assets | | | | | | | | | 803 |
| | 178 |
| | 42 |
|
| Other impairments and write-downs (6) | | | | | | | | | 70 |
| | 31 |
| | 10 |
|
| Impairment of certain assets | | | | | | | | | $ | 873 |
| | $ | 209 |
| | $ | 52 |
|
| | | | | | | | | | | | | | |
| Equity-method investments (7) | Investments | | Williams Partners | | September 30, 2015 | | $ | 1,203 |
| | | | $ | 461 |
| | |
| Equity-method investments (8) | Investments | | Williams Partners | | December 31, 2015 | | 4,017 |
| | | | 890 |
| | |
| Equity-method investments (9) | Investments | | Williams Partners | | March 31, 2016 | | 1,294 |
| | $ | 109 |
| | | | |
| Equity-method investments (10) | Investments | | Williams Partners | | December 31, 2016 | | 1,295 |
| | 318 |
| | | | |
| Other equity-method investment | Investments | | Williams Partners | | December 31, 2015 | | 58 |
| | | | 8 |
| | |
| Other equity-method investment | Investments | | Williams Partners | | March 31, 2016 | | — |
| | 3 |
| | | | |
| Impairment of equity-method investments | | | | | | | | | $ | 430 |
| | $ | 1,359 |
| | |
______________
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| (1) | Relates to certain surplus equipment.the Constitution development project. The estimated fair value of the Property, plant, and equipment – net was determined by a market approach based on our analysis of observable inputs in the principal market.probability-weighted third-party quotes. See Note 4 – Variable Interest Entities for further discussion. |
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
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| (2) | Relates to a gas processinggathering 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. |
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| (3) | Reflects impairment of Property, plant, and equipment – net that is no longer in use for which the completionfair value was determined to be lower than the carrying value. |
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| (4) | Relates to our gathering operations in the Barnett Shale. Certain of which is considered remote due to unfavorable impactour contractual gathering rates, primarily those in the Barnett Shale, are based on a percentage of lowthe New York Mercantile Exchange (NYMEX) natural gas prices onprices. 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 activities.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 assessedresulting estimate of future undiscounted cash flows was less than our carrying value, necessitating the estimation of the fair value primarily representsof 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 salvagecost of capital and risks associated with the underlying assets. |
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| (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.) |
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| (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 measured– 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. |
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| (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. |
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| (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.) |
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(3)(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 of which is considered remote due to lack of customer interest.be remote. The assessed fair value primarily represents the estimated fair value of unused pipeline measured usingthe remaining Property, plant, and equipment – net considered a market approach based on our analysis of observable inputs in the principal market. |
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
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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.)
| |
(4) | Relates to our Canadian operations. We designated these operations as held for sale as of June 30, 2016. As a result, we measured the fair value of the disposal group, resulting in an impairment charge. The estimated fair value was determined by a market approach based primarily on inputs received in the marketing process and reflected our estimate of the potential assumed proceeds. We disposed of our Canadian operations through a sale during the third quarter of 2016. See Note 3 – Divestiture. |
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(5) | Relates to certain gathering assets within the Mid-Continent region. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market. |
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(6)(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 zero or an insignificant salvagelower than the carrying value. |
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(7)(11) | Relates to equity-method investmentsa gas gathering system in DBJVthe Marcellus region that was adversely impacted by lower sustained forward natural gas price expectations and certain of the Appalachia Midstream Investments.changes in expected producer activity. The historical carrying value of these investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We estimated the fair value of these investmentswas determined using an income approach based on expected future cash flows and appropriateapproach. We utilized a discount rates. The determinationrate of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized were 11.810.2 percent and 8.8 percent for DBJV and certain of the Appalachia Midstream Investments, respectively, and reflectedin our cost of capital as impacted by market conditions, and risks associated with the underlying businesses.analysis. |
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(8)(12) | Relates to equity-method investmentsa certain gathering system held in DBJV, certain of the Appalachia Midstream Investments UEOM, and Laurel Mountain. Wethat was adversely impacted by changes in the timing of expected producer activity. The estimated the fair value of these investmentswas determined using an income approach based on expected future cash flows and appropriateapproach. We utilized a discount rates. The determinationrate of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from 10.89.0 percent to 14.4 percent and reflected further fourth-quarter 2015 increases in our cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses.analysis. |
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(9)(13) | RelatesThe 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. |
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| (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 equity-method investmentsthe signing and closing of the acquisition in DBJVMarch 2019 (see Note 3 – Acquisitions and Laurel Mountain. Our carrying valuesDivestitures). These inputs resulted in these equity-method investments had been written down toa fair value measurement within Level 2 of the fair value hierarchy. The estimated fair value at December 31, 2015. Our first-quarter 2016 analysis reflected higher discount rates for both of these investments, along with lower natural gas prices for Laurel Mountain. We estimated the fair value of these investments using an income2018, was determined by a market approach based on expected future cash flows and appropriate discount rates. The determinationour analysis of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from 13.0 percent to 13.3 percent and reflected increasesinputs in our cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses.principal market. |
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(10) | Relates to equity-method investments in Ranch Westex and multiple Appalachia Midstream Investments. The historical carrying value of these investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We estimated the fair value of these Appalachia Midstream Investments using an income approach based on expected future cash flows and appropriate discount |
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The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
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rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes, rates, and related capital spending. The discount rate utilized for the Appalachia Midstream Investments evaluation was 10.2 percent and reflected our cost of capital as impacted by market conditions and risks associated with the underlying businesses. In addition to utilizing an income approach, we also considered a market approach for certain Appalachia Midstream Investments and Ranch Westex based on an agreement reached in February 2017 to exchange our interests in DBJV and Ranch Westex for additional interests in certain Appalachia Midstream Investments and cash.
Concentration of Credit Risk
Cash equivalents
Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.
Trade accounts and other receivables
The following table summarizes concentration of receivables, net of allowances:
| | | | December 31, | December 31, |
| | 2016 | | 2015 | 2019 | | 2018 |
| | (Millions) | (Millions) |
| NGLs, natural gas, and related products and services | $ | 736 |
| | $ | 823 |
| $ | 613 |
| | $ | 626 |
|
| Transportation of natural gas and related products | 187 |
| | 202 |
| 277 |
| | 232 |
|
| Accounts Receivable related to revenues from contracts with customers | | 890 |
| | 858 |
|
| Other | 15 |
| | 16 |
| 106 |
| | 134 |
|
| Total | $ | 938 |
| | $ | 1,041 |
| |
| Trade accounts and other receivables | | $ | 996 |
| | $ | 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. As of December 31, 2016
In 2019, 2018, and 2015,2017, Chesapeake Energy Corporation, and its affiliates, (Chesapeake), a customer currently primarily within our Williams PartnersWest segment, accounted for$133 million and $364 million, respectively, of the consolidated Trade accounts and other receivables balances.
Revenues
In 2016 and 2015, Chesapeake accounted for 14approximately 6 percent, 8 percent, and 1810 percent, respectively, of our consolidated revenues.revenues, and as of December 31, 2019, accounted for $78 million of the consolidated Trade accounts and other receivables balance.
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
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Note 1819 – Contingent Liabilities and Commitments
Reporting of Natural Gas-Related Information to Trade Publications
Direct and indirect purchasers of natural gas in various states filed an individual and class actions against us, our former affiliate WPX Energy, Inc. (WPX) and its subsidiaries, and others alleging the manipulation of published gas price indices and seeking unspecified amounts of damages. Such actions were transferred to the Nevada federal district court for consolidation of discovery and pre-trial issues. We have agreed to indemnify WPX and its subsidiaries related to this matter.
In the individual action, filed by Farmland Industries Inc. (Farmland), the court issued an order on May 24, 2016, granting one of our co-defendant’s motion for summary judgment as to Farmland’s claims. On January 5, 2017, the court extended such ruling to us, entering final judgment in our favor. Farmland 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 appealed.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, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposure at this
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The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
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time. However, it is reasonably possible that the ultimate resolution of these actions and our related indemnification obligation could result in a potential loss that may be material to our results of operations. In connection with this indemnification, we have an accrued liability balance associated with this matter, and as a result, have exposure to future developments in this matter.
Geismar Incident
On June 13, 2013, an explosion and fire occurred at our Geismar olefins plant and rendered the facility temporarily inoperable (Geismar Incident). As a result, there were two fatalities and numerous individuals (including employees and contractors) reported injuries. We are addressing the following contingent liabilities in connection with the Geismar Incident.
On October 21, 2013, the U.S. Environmental Protection Agency (EPA) issued an Inspection Report pursuant to the Clean Air Act’s Risk Management Program following its inspection of the facility on June 24 through June 28, 2013. The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating procedures, employee training, and other matters. On June 16, 2014, we received a request for information related to the Geismar Incident from the EPA under Section 114 of the Clean Air Act to which we responded on August 13, 2014. The EPA could issue penalties pertaining to final determinations.
Multiple lawsuits, including class actions for alleged offsite impacts, property damage, customer claims, and personal injury, have been filed against us. To date, we have settled certain of the personal injury claims for an aggregate immaterial amount that we have recovered from our insurers. The first two trials, for nine plaintiffs claiming personal injury, were held in Louisiana state court in Iberville Parish, Louisiana in September and November 2016. The juries returned adverse verdicts against us, our subsidiary Williams Olefins, LLC, and other defendants. The defendants, including us, intend to appeal the verdicts. Trial dates for additional plaintiffs are scheduled in April 2017 and August 2017. We believe it is probable that additional losses will be incurred on some lawsuits, while for others we believe it is only reasonably possible that losses will be incurred. However, due to ongoing litigation involving defenses to liability, the number of individual plaintiffs, limited information as to the nature and extent of all plaintiffs’ damages, and the ultimate outcome of all appeals, we are unable to reliably estimate any such losses at this time. We believe that it is probable that any ultimate losses incurred will be covered by our general liability insurance policy, which has an aggregate limit of $610 million applicable to this event and retention (deductible) of $2 million per occurrence.developments.
Alaska Refinery Contamination Litigation
In 2010, James West filed a class action lawsuitWe are involved in state court in Fairbanks, Alaska on behalflitigation arising from our ownership and operation of individual property owners whose water contained sulfolane contamination allegedly emanating from the Flint Hills OilNorth Pole Refinery in North Pole, Alaska. The suit namedAlaska, from 1980 until 2004, through our subsidiary,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 owned and operated the refinery until 2004 when we sold it to FHRA. We and FHRA made claims under the pollution liability insurance policy issued in connection with the sale of the North Pole refinery to FHRA. We and FHRA also 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 claim. We andWest. Certain claims by FHRA subsequently filed motions for summary judgment on the other’s claims. On July 8, 2014, the court dismissed all FHRA’s claims and entered judgment for us. On August 6, 2014, FHRA appealed the court’s decision toagainst us were resolved by the Alaska Supreme Court which heard oral arguments in October of 2015, and issued a decision on August 26, 2016. The Alaska Supreme Court affirmed dismissal of FHRA’s equitable claims and statutory claims for damages related to sulfolane located on the refinery property. The Alaska Supreme Court remandedour favor. FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-site sulfolane for further resolution bywere remanded to the trial court. We currently estimate that our reasonably possible loss exposureAlaska Superior Court. The State of Alaska filed its action in this matter could range from an insignificant amount up to $32 million, although uncertainties inherentMarch 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 litigation process, expert evaluations,cases are similar and jury dynamics might cause our exposure to exceed that amount.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
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
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On March 6, 2014, the StateWest case and those of Alaska filed suit against FHRA, WAPI, and us in state court in Fairbanks seeking injunctive relief and damages in connection with sulfolane contamination of the water supply near the Flint Hills Oil Refinery in North Pole, Alaska. On May 5, 2014, FHRA filed cross-claims against us in the State of Alaska suit. FHRA also seeks injunctive relief and damages.
On November 26, 2014, the City of North Pole (North Pole) filed suit in Alaska state court in Fairbanks against FHRA, WAPI, and us alleging nuisance and violations of municipal and state statutes based upon the same alleged sulfolane contamination of the water supply. North Pole claims an unspecified amount of past and future damages as well as punitive damages against WAPI. FHRA filed cross-claims against us.
In October of 2015, the court consolidated the State of Alaska and North Pole cases. On February 29, 2016, wePole. The State of Alaska later announced the discovery of additional contaminants per- and WAPI filed Amended Answers inpolyfluoralkyl (PFOS and PFOA) offsite of the consolidated cases. Both werefinery, and WAPI asserted counter claims against boththe Court permitted the State of Alaska and North Pole, and crossto amend its complaint to add a claim for offsite PFOS/PFOA contamination. The Court subsequently remanded the offsite PFOS/PFOA claims against FHRA. A trial is scheduled to commence May 30, 2017. All or a portion of the exposure in this consolidated State of Alaska and North Pole action may duplicate exposure in the James West case. As such, on February 9, 2017, the remanded claims in the James West case were consolidated into the State of Alaska and North Pole action. Due to the ongoing assessment of the level and extent of sulfolane contamination, the lack of an articulated cleanup level for sulfolane, and the lack of a concrete remedial proposal and cost estimate, we are unable to estimate a range of exposure for the consolidated action at this time.
Independent of the litigation matter described in the preceding paragraphs, in 2013, the Alaska Department of Environmental Conservation indicated that it viewsfor 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 us as responsible parties, and that it intendedpotential future damages estimated to enter a compliance order to address the environmental remediation of sulfolane and other possible contaminants including cleanup work outside the refinery’s boundaries. Duebe $86 million. The Court did not award natural resource damages to the ongoing assessmentState 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 levelprobable loss. It is reasonably possible that we may not be successful on appeal and extentcould ultimately pay up to the amount of sulfolane contamination and the ultimate cost of remediation and division of costs among the potentially responsible parties, we are unable to estimate a range of exposure at this time.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 Texas, Pennsylvania and Ohio based on allegations that we improperly participated with that major customer in causing the alleged royalty underpayments. We have also received subpoenas from the United States Department of Justice and the Pennsylvania Attorney General requesting documents relating to the agreements between us and our major customer and calculations of the major customer’s royalty payments. On December 9, 2015, the Pennsylvania Attorney General filed a civil suit against one of our major customers and us alleging breaches of the Pennsylvania Unfair Trade Practices and Consumer Protection Law, and on February 8, 2016, the Pennsylvania Attorney General filed an amended complaint in such civil suit, which omitted us as a party. We believe that the claims asserted are subject to indemnity obligations owed to us by that major customer. OurThat customer has reached a tentative settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement would apply to both the customer and plaintiffs in the Texas cases reached aus. The settlement and therefore all claims asserted (or possibly asserted) byas reported would not require any such plaintiffs against us in the Texas cases have been fully dismissed with prejudice. On February 7, 2017, the plaintiffs in the Ohio case voluntarily dismissed the case without prejudice. Due to the preliminary status of the remaining cases, we are unable to estimate a range of potential loss at this time.
Shareholder Litigation
Between October 2015 and December 2015, purported shareholders of us filed six putative class action lawsuits in the Delaware Court of Chancery that were consolidated into a single suit on January 13, 2016. This consolidated putative class action lawsuit relates to our terminated merger with Energy Transfer Equity, L.P. (Energy Transfer). The complaint asserts various claims against the individual members of our Board of Directors, including that they breached their fiduciary duties by agreeing to sell us through an allegedly unfair process and for an allegedly unfair price and by allegedly failing to disclose allegedly material information about the merger. The complaint seeks, among other things, an injunction against the merger and an award of costs and attorneys’ fees. On March 22, 2016, the court granted
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The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
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the parties’ proposed order in the consolidated action to stay the proceedings pending the close of the transaction with Energy Transfer. The plaintiffs have not filed an amended complaint.
A purported shareholder filed a separate class action lawsuit in the Delaware Court of Chancery on January 15, 2016. The putative class action complaint alleged that the individual members of our Board of Directors breached their fiduciary duties by, among other things, agreeing to the WPZ Merger Agreement, which purportedly reduced the merger consideration to have been received in the subsequently proposed but now terminated merger with Energy Transfer. The plaintiff filed a motion to voluntarily dismiss, which the court granted on January 13, 2017. On September 2, 2016, the same purported shareholder filed a derivative action claiming that the members of our Board of Directors breached their fiduciary duties by executing the WPZ Merger Agreement as a defensive measure against Energy Transfer. On September 28, 2016, we requested the court dismiss this action also.
On March 7, 2016, a purported unitholder of WPZ filed a putative class action on behalf of certain purchasers of WPZ units in U.S. District Court in Oklahoma. The action names as defendants us, WPZ, Williams Partners GP LLC, Alan S. Armstrong, and Donald R. Chappel and alleges violations of certain federal securities laws for failure to disclose Energy Transfer’s intention to pursue a purchase of us conditioned on us not closing the WPZ Merger Agreement when announcing the WPZ Merger Agreement. The complaint seeks, among other things, damages and an award of costs and attorneys’ fees. The plaintiff filed an amended complaint on August 31, 2016. On October 17, 2016, we requested the court dismiss the action. We cannot reasonably estimate a range of potential loss at this time.contribution from us.
Litigation againstAgainst Energy Transfer and related partiesRelated 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 (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
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| 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. The appeal has been fully briefed for consideration byOn March 23, 2017, the Supreme Court of Delaware and oral argument occurredaffirmed 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 January 11,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,
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The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
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payment of the $1.48 billion termination fee due to our alleged breaches of the ETE Merger Agreement. WeOn 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 dismiss Energy Transfer’s counterclaims,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 was fully briefed on November 14, 2016, and oral argument occurred on November 30, 2016.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, andand/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 EPA, andU.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, 2016,2019, we have accrued liabilities totaling $38$31 million for these matters, as discussed below. Our accrual reflectsEstimates of the most likely costs of cleanup which are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. CertainAt December 31, 2019, certain assessment studies arewere still
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
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in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty aboutTherefore, the actual number of contaminated sites ultimately identified,costs incurred will depend on the actualfinal amount, type, and extent of contamination discovered andat these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other governmental authorities.factors.
The EPA and various state regulatory agencies routinely promulgate and propose new rules and issue updated guidance to existing rules. More recent rules andThese rulemakings include, but are not limited to, rules for reciprocating internal combustion engine and combustion turbine maximum achievable control technology, new air quality standards for one hourone-hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. On October 1, 2015, theThe EPA previously issued its new rule regarding National Ambient Air Quality Standards for ground-level ozone, setting a new standard of 70 parts per billion.ozone. We are monitoring the rule’s implementation as it will trigger additional federal and evaluating potentialstate regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations. For theseoperations and otherincrease the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both new regulations, weand existing facilities in affected areas. We are unable to reasonably estimate the costscost of asset additions or modifications necessarythat may be required to complymeet the regulations at this time due to uncertainty created by the 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, 20162019, we have accrued liabilities of $9$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, 20162019, we have accrued liabilities totaling $7 million for these costs.
Former operations including operations classified as discontinued
We have potential obligations in connection with assets and businesses we no longer operate. These potential obligations include remediation activities at the direction of federal and state environmental authorities and the indemnification of the purchasers of certain of these assets and businesses for environmental and other liabilities existing at the time the sale was consummated. Our responsibilities relate to the operations of the assets and businesses described below.
Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations;
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The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
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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, 20162019, we have accrued environmental liabilities of $22$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
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| 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, 20162019, 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.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 $244$206 million at December 31, 2016.2019.
Note 1920 – Segment Disclosures
Our reportable segments are Williams PartnersAtlantic-Gulf, Northeast G&P, and Williams NGL & Petchem Services.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.)
Our segment presentation of Williams Partners, which includes our consolidated master limited partnership, is reflective of the parent-level focus by our chief operating decision-maker, considering the resource allocation and governance provisions associated with the master limited partnership structure. This partnership maintains capital and cash management structures that are separate from ours. It is self-funding and maintains its own lines of bank credit and cash management accounts. These factors, coupled with different costs of capital from our other businesses, serve to differentiate the management of this entity as a whole.
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The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
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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);
◦Gain on remeasurement of equity-method investment;
◦Impairment of equity-method investments;
◦Other investing income (loss) – net;
◦Impairment of goodwill;
◦Depreciation and amortization expenses;
◦Accretion expense associated with asset retirement obligations for nonregulated operations.
This measure is further adjusted to include our proportionate share (based on ownership interest) of Modified EBITDA from our equity-method investments calculated consistently with the definition described above.
The following geographic area data includes Revenues from external customers based on product shipment origin and Long-lived assets based upon physical location:141
|
| | | | | | | | | | | | | |
| | | | United States | | Canada | | Total |
| | | | (Millions) |
| Revenues from external customers: | | | | | | |
| | 2016 | | $ | 7,425 |
| | $ | 74 |
| | $ | 7,499 |
|
| | 2015 | | 7,247 |
| | 113 |
| | 7,360 |
|
| | 2014 | | 7,229 |
| | 408 |
| | 7,637 |
|
| | | | | | | | |
| Long-lived assets: | | | | | | |
| | 2016 | | $ | 38,091 |
| | $ | — |
| | $ | 38,091 |
|
| | 2015 | | 38,016 |
| | 1,580 |
| | 39,596 |
|
| | 2014 | | 38,290 |
| | 1,364 |
| | 39,654 |
|
Long-lived assets are comprised of property, plant, and equipment, goodwill, and other intangible assets.
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| 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◦Depreciation and Other financial information:amortization expenses;
|
| | | | | | | | | | | | | | | | | | | |
| | Williams Partners | | Williams NGL & Petchem Services | | Other | | Eliminations | | Total |
| | (Millions) |
| 2016 |
| Segment revenues: | | | | | | | | | |
| Service revenues | | | | | | | | | |
| External | $ | 5,140 |
| | $ | 2 |
| | $ | 29 |
| | $ | — |
| | $ | 5,171 |
|
| Internal | 33 |
| | — |
| | 19 |
| | (52 | ) | | — |
|
| Total service revenues | 5,173 |
| | 2 |
| | 48 |
| | (52 | ) | | 5,171 |
|
| Product sales | | | | | | | | | |
| External | 2,318 |
| | 10 |
| | — |
| | — |
| | 2,328 |
|
| Internal | — |
| | 16 |
| | — |
| | (16 | ) | | — |
|
| Total product sales | 2,318 |
| | 26 |
| | — |
| | (16 | ) | | 2,328 |
|
| Total revenues | $ | 7,491 |
| | $ | 28 |
| | $ | 48 |
| | $ | (68 | ) | | $ | 7,499 |
|
| | | | | | | | | | |
| Other financial information: | | | | | | | | | |
| Additions to long-lived assets | $ | 2,102 |
| | $ | 33 |
| | $ | 11 |
| | $ | (1 | ) | | $ | 2,145 |
|
| Proportional Modified EBITDA of equity-method investments | 754 |
| | — |
| | — |
| | — |
| | 754 |
|
| | | | | | | | | | |
| 2015 |
| Segment revenues: | | | | | | | | | |
| Service revenues | | | | | | | | | |
| External | $ | 5,134 |
| | $ | 2 |
| | $ | 28 |
| | $ | — |
| | $ | 5,164 |
|
| Internal | 1 |
| | — |
| | 158 |
| | (159 | ) | | — |
|
| Total service revenues | 5,135 |
| | 2 |
| | 186 |
| | (159 | ) | | 5,164 |
|
| Product sales | | | | | | | | | |
| External | 2,196 |
| | — |
| | — |
| | — |
| | 2,196 |
|
| Internal | — |
| | — |
| | — |
| | — |
| | — |
|
| Total product sales | 2,196 |
| | — |
| | — |
| | — |
| | 2,196 |
|
| Total revenues | $ | 7,331 |
| | $ | 2 |
| | $ | 186 |
| | $ | (159 | ) | | $ | 7,360 |
|
| | | | | | | | | | |
| Other financial information: | | | | | | | | | |
| Additions to long-lived assets | $ | 2,960 |
| | $ | 360 |
| | $ | 28 |
| | $ | (12 | ) | | $ | 3,336 |
|
| Proportional Modified EBITDA of equity-method investments | 699 |
| | — |
| | — |
| | — |
| | 699 |
|
| | | | | | | | | | |
| 2014 | | | | | | | | | |
| Segment revenues: | | | | | | | | | |
| Service revenues | | | | | | | | | |
| External | $ | 3,887 |
| | $ | — |
| | $ | 229 |
| | $ | — |
| | $ | 4,116 |
|
| Internal | 1 |
| | — |
| | 30 |
| | (31 | ) | | — |
|
| Total service revenues | 3,888 |
| | — |
| | 259 |
| | (31 | ) | | 4,116 |
|
| Product sales | | | | | | | | | |
| External | 3,521 |
| | — |
| | — |
| | — |
| | 3,521 |
|
| Internal | — |
| | — |
| | — |
| | — |
| | — |
|
| Total product sales | 3,521 |
| | — |
| | — |
| | — |
| | 3,521 |
|
| Total revenues | $ | 7,409 |
| | $ | — |
| | $ | 259 |
| | $ | (31 | ) | | $ | 7,637 |
|
| | | | | | | | | | |
| Other financial information: | | | | | | | | | |
| Additions to long-lived assets (1) | $ | 20,413 |
| | $ | 291 |
| | $ | 54 |
| | $ | (2 | ) | | $ | 20,756 |
|
| Proportional Modified EBITDA of equity-method investments | 431 |
| | (78 | ) | | 85 |
| | — |
| | 438 |
|
_______________◦Accretion expense associated with asset retirement obligations for nonregulated operations.
| |
(1)• | 2014 AdditionsThis measure is further adjusted to long-lived assets withininclude our Williams Partners segment primarily includesproportionate share (based on ownership interest) of Modified EBITDA from our equity-method investments calculated consistently with the acquisition-date fair value of long-lived assets from the ACMP Acquisition. (See Note 2 - Acquisitions.)definition described above.
|
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
The following table reflects the reconciliation of Modified EBITDASegment revenues to Net income (loss)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 |
| | $ | 1,291 |
| | $ | 1,813 |
| | $ | 17 |
| | $ | — |
| | $ | 5,933 |
|
| Internal | 49 |
| | 47 |
| | — |
| | 13 |
| | (109 | ) | | — |
|
| Total service revenues | 2,861 |
| | 1,338 |
| | 1,813 |
| | 30 |
| | (109 | ) | | 5,933 |
|
| Total service revenues – commodity consideration | 41 |
| | 12 |
| | 150 |
| | — |
| | — |
| | 203 |
|
| Product sales | | | | | | | | | | | |
| External | 217 |
| | 115 |
| | 1,733 |
| | — |
| | — |
| | 2,065 |
|
| Internal | 71 |
| | 35 |
| | 64 |
| | — |
| | (170 | ) | | — |
|
| Total product sales | 288 |
| | 150 |
| | 1,797 |
| | — |
| | (170 | ) | | 2,065 |
|
| Total revenues | $ | 3,190 |
| | $ | 1,500 |
| | $ | 3,760 |
| | $ | 30 |
| | $ | (279 | ) | | $ | 8,201 |
|
| | | | | | | | | | | | |
| Other financial information: | | | | | | | | | | | |
| Additions to long-lived assets | $ | 1,179 |
| | $ | 1,245 |
| | $ | 466 |
| | $ | 21 |
| | $ | — |
| | $ | 2,911 |
|
| Proportional Modified EBITDA of equity-method investments | 177 |
| | 454 |
| | 115 |
| | — |
| | — |
| | 746 |
|
| | | | | | | | | | | | |
| 2018 | | | | | | | | | | | |
| Segment revenues: | | | | | | | | | | | |
| Service revenues | | | | | | | | | | | |
| External | $ | 2,460 |
| | $ | 935 |
| | $ | 2,085 |
| | $ | 22 |
| | $ | — |
| | $ | 5,502 |
|
| Internal | 49 |
| | 41 |
| | — |
| | 12 |
| | (102 | ) | | — |
|
| Total service revenues | 2,509 |
| | 976 |
| | 2,085 |
| | 34 |
| | (102 | ) | | 5,502 |
|
| Total service revenues – commodity consideration | 59 |
| | 20 |
| | 321 |
| | — |
| | — |
| | 400 |
|
| Product sales | | | | | | | | | | | |
| External | 174 |
| | 245 |
| | 2,365 |
| | — |
| | — |
| | 2,784 |
|
| Internal | 261 |
| | 42 |
| | 83 |
| | — |
| | (386 | ) | | — |
|
| Total product sales | 435 |
| | 287 |
| | 2,448 |
| | — |
| | (386 | ) | | 2,784 |
|
| Total revenues | $ | 3,003 |
| | $ | 1,283 |
| | $ | 4,854 |
| | $ | 34 |
| | $ | (488 | ) | | $ | 8,686 |
|
| | | | | | | | | | | | |
| Other financial information: | | | | | | | | | | | |
| Additions to long-lived assets | $ | 2,297 |
| | $ | 477 |
| | $ | 361 |
| | $ | 36 |
| | $ | — |
| | $ | 3,171 |
|
| Proportional Modified EBITDA of equity-method investments | 183 |
| | 493 |
| | 94 |
| | — |
| | — |
| | 770 |
|
| | | | | | | | | | | | |
| 2017 | | | | | | | | | | | |
| Segment revenues: | | | | | | | | | | | |
| Service revenues | | | | | | | | | | | |
| External | $ | 2,202 |
| | $ | 837 |
| | $ | 2,246 |
| | $ | 27 |
| | $ | — |
| | $ | 5,312 |
|
| Internal | 37 |
| | 35 |
| | — |
| | 11 |
| | (83 | ) | | — |
|
| Total service revenues | 2,239 |
| | 872 |
| | 2,246 |
| | 38 |
| | (83 | ) | | 5,312 |
|
| Product sales | | | | | | | | | | | |
| External | 257 |
| | 264 |
| | 1,840 |
| | 358 |
| | — |
| | 2,719 |
|
| Internal | 227 |
| | 27 |
| | 173 |
| | 8 |
| | (435 | ) | | — |
|
| Total product sales | 484 |
| | 291 |
| | 2,013 |
| | 366 |
| | (435 | ) | | 2,719 |
|
| Total revenues | $ | 2,723 |
| | $ | 1,163 |
| | $ | 4,259 |
| | $ | 404 |
| | $ | (518 | ) | | $ | 8,031 |
|
| | | | | | | | | | | | |
| Other financial information: | | | | | | | | | | | |
| Additions to long-lived assets | $ | 2,001 |
| | $ | 460 |
| | $ | 321 |
| | $ | 32 |
| | $ | — |
| | $ | 2,814 |
|
| Proportional Modified EBITDA of equity-method investments | 264 |
| | 452 |
| | 79 |
| | — |
| | — |
| | 795 |
|
|
| | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | | | | | (Millions) |
| Modified EBITDA by segment: | | | | | |
| Williams Partners | $ | 3,864 |
| | $ | 4,003 |
| | $ | 3,244 |
|
| Williams NGL & Petchem Services | (540 | ) | | (83 | ) | | (115 | ) |
| Other | (2 | ) | | (29 | ) | | 103 |
|
| | 3,322 |
| | 3,891 |
| | 3,232 |
|
| Accretion expense associated with asset retirement obligations for nonregulated operations | (31 | ) | | (28 | ) | | (18 | ) |
| Depreciation and amortization expenses | (1,763 | ) | | (1,738 | ) | | (1,176 | ) |
| Impairment of goodwill | — |
| | (1,098 | ) | | — |
|
| Equity earnings (losses) | 397 |
| | 335 |
| | 144 |
|
| Gain on remeasurement of equity-method investment | — |
| | — |
| | 2,544 |
|
| Impairment of equity-method investments | (430 | ) | | (1,359 | ) | | — |
|
| Other investing income (loss) – net | 63 |
| | 27 |
| | 43 |
|
| Proportional Modified EBITDA of equity-method investments | (754 | ) | | (699 | ) | | (438 | ) |
| Interest expense | (1,179 | ) | | (1,044 | ) | | (747 | ) |
| (Provision) benefit for income taxes | 25 |
| | 399 |
| | (1,249 | ) |
| Income (loss) from discontinued operations, net of tax | — |
| | — |
| | 4 |
|
| Net income (loss) | $ | (350 | ) | | $ | (1,314 | ) | | $ | 2,339 |
|
|
| | | | |
| 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:
|
| | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | | | | | (Millions) |
| Modified EBITDA by segment: | | | | | |
| Atlantic-Gulf | $ | 1,895 |
| | $ | 2,023 |
| | $ | 1,238 |
|
| Northeast G&P | 1,314 |
| | 1,086 |
| | 819 |
|
| West | 1,232 |
| | 308 |
| | 412 |
|
| Other | 6 |
| | (29 | ) | | 997 |
|
| | 4,447 |
| | 3,388 |
| | 3,466 |
|
| Accretion expense associated with asset retirement obligations for nonregulated operations | (33 | ) | | (33 | ) | | (33 | ) |
| Depreciation and amortization expenses | (1,714 | ) | | (1,725 | ) | | (1,736 | ) |
| Equity earnings (losses) | 375 |
| | 396 |
| | 434 |
|
| Other investing income (loss) – net | (79 | ) | | 187 |
| | 282 |
|
| Proportional Modified EBITDA of equity-method investments | (746 | ) | | (770 | ) | | (795 | ) |
| Interest expense | (1,186 | ) | | (1,112 | ) | | (1,083 | ) |
| (Provision) benefit for income taxes | (335 | ) | | (138 | ) | | 1,974 |
|
| Income (loss) from discontinued operations | (15 | ) | | — |
| | — |
|
| Net income (loss) | $ | 714 |
| | $ | 193 |
| | $ | 2,509 |
|
The following table reflects Total assets and Equity-method investments by reportable segments:
|
| | | | | | | | | | | | | | | | |
| | | Total Assets | | Equity-Method Investments |
| | | December 31, 2019 | | December 31, 2018 | | December 31, 2019 | | December 31, 2018 |
| | | (Millions) |
| Atlantic-Gulf | | $ | 16,575 |
| | $ | 16,346 |
| | $ | 741 |
| | $ | 776 |
|
| Northeast G&P | | 15,399 |
| | 14,526 |
| | 3,973 |
|
| 5,319 |
|
| West | | 13,487 |
| | 13,948 |
| | 1,521 |
| | 1,726 |
|
| Other | | 1,151 |
| | 849 |
| | — |
| | — |
|
| Eliminations (1) | | (572 | ) | | (367 | ) | | — |
| | — |
|
| Total | | $ | 46,040 |
| | $ | 45,302 |
| | $ | 6,235 |
| | $ | 7,821 |
|
|
| | | | | | | | | | | | | | | | |
| | | Total Assets | | Equity-Method Investments |
| | | December 31, 2016 | | December 31, 2015 | | December 31, 2016 | | December 31, 2015 |
| | | (Millions) |
| Williams Partners | | $ | 46,265 |
| | $ | 47,870 |
| | $ | 6,701 |
|
| $ | 7,336 |
|
| Williams NGL & Petchem Services | | 249 |
| | 835 |
| | — |
| | — |
|
| Other | | 674 |
| | 850 |
| | — |
| | — |
|
| Eliminations | | (353 | ) | | (535 | ) | | — |
| | — |
|
| Total | | $ | 46,835 |
| | $ | 49,020 |
| | $ | 6,701 |
| | $ | 7,336 |
|
| |
| (1) | Eliminations primarily relate to the intercompany notes and accounts receivable generated by our cash management program. |
|
| | |
| 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) |
| 2016 | |
| Revenues | $ | 1,660 |
| | $ | 1,736 |
| | $ | 1,905 |
| | $ | 2,198 |
|
| Product costs | 318 |
| | 401 |
| | 461 |
| | 545 |
|
| Net income (loss) | (13 | ) | | (505 | ) | | 131 |
| | 37 |
|
| Amounts attributable to The Williams Companies, Inc.: | | | | | | | |
| Net income (loss) | (65 | ) | | (405 | ) | | 61 |
| | (15 | ) |
| Basic and diluted earnings (loss) per common share | (.09 | ) | | (.54 | ) | | .08 |
| | (.02 | ) |
| | | | | | | | |
| 2015 | | | | | | | |
| Revenues | $ | 1,716 |
| | $ | 1,839 |
| | $ | 1,799 |
| | $ | 2,006 |
|
| Product costs | 462 |
| | 494 |
| | 426 |
| | 397 |
|
| Net income (loss) | 13 |
| | 183 |
| | (173 | ) | | (1,337 | ) |
| Amounts attributable to The Williams Companies, Inc.: | | | | | | | |
| Net income (loss) | 70 |
| | 114 |
| | (40 | ) | | (715 | ) |
| Basic and diluted earnings (loss) per common share: | .09 |
| | .15 |
| | (.05 | ) | | (.95 | ) |
|
| | | | | | | | | | | | | | | |
| | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
| | (Millions, except per-share amounts) |
| 2019 | |
| Revenues | $ | 2,054 |
| | $ | 2,041 |
| | $ | 1,999 |
| | $ | 2,107 |
|
| Product costs and processing commodity expenses | 565 |
| | 507 |
| | 453 |
| | 541 |
|
| Income (loss) from continuing operations | 214 |
| | 324 |
| | 242 |
| | (51 | ) |
| Income (loss) from discontinued operations | — |
| | — |
| | — |
| | (15 | ) |
| Net income (loss) | 214 |
| | 324 |
| | 242 |
| | (66 | ) |
| Amounts attributable to The Williams Companies, Inc. available to common stockholders: | | | | | | | |
| Income (loss) from continuing operations | 194 |
| | 310 |
| | 220 |
| | 138 |
|
| Income (loss) from discontinued operations | — |
| | — |
| | — |
| | (15 | ) |
| Net income (loss) | 194 |
| | 310 |
| | 220 |
| | 123 |
|
| Basic and diluted income (loss) from continuing operations per common share | .16 |
| | .26 |
| | .18 |
| | .11 |
|
| Basic and diluted income (loss) from discontinued operations per common share | — |
| | — |
| | — |
| | (.01 | ) |
| Basic and diluted net income (loss) per common share | .16 |
| | .26 |
| | .18 |
| | .10 |
|
| | | | | | | | |
| 2018 | | | | | | | |
| Revenues | $ | 2,088 |
| | $ | 2,091 |
| | $ | 2,303 |
| | $ | 2,204 |
|
| Product costs and processing commodity expenses | 648 |
| | 662 |
| | 820 |
| | 714 |
|
| Income (loss) from continuing operations | 270 |
| | 269 |
| | 200 |
| | (546 | ) |
| Net income (loss) | 270 |
| | 269 |
| | 200 |
| | (546 | ) |
| Amounts attributable to The Williams Companies, Inc. available to common stockholders: | | | | | | | |
| Income (loss) from continuing operations | 152 |
| | 135 |
| | 129 |
| | (572 | ) |
| Net income (loss) | 152 |
| | 135 |
| | 129 |
| | (572 | ) |
| Basic and diluted net income (loss) per common share | .18 |
| | .16 |
| | .13 |
| | (.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.
20162019
Net income (loss) for fourth-quarter 20162019 includes the following pretax items:
$173$354 million of income associated with the amortizationimpairment of deferred income related to the restructuring of certain gas gathering contracts in the Barnett Shale and Mid-Continent regions and $58 million of related minimum volume commitment feesConstitution’s capitalized project costs (see Note 74 – Other Income and ExpensesVariable Interest Entities of Notes to Consolidated Financial Statements);
.$318Net income (loss) for third-quarter 2019 includes $114 million of impairment loss onof certain equity-method investments (see Note 1718 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk)Risk of Notes to Consolidated Financial Statements).
Net income (loss) for second-quarter 20162019 includes a $747$122 million impairment lossgain on Canadian assetssale of our equity-method investment in Jackalope (see Note 176 – 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).
Net income (loss) for first-quarter 2016 includes a $112 million impairment loss on certain equity-method investments (see Note 17 – Fair Value Measurements, Guarantees, and ConcentrationRisk of Credit Risk).
2015
Net income (loss) for fourth-quarter 2015 includes the following pretax items:
$239 million in revenue associated with minimum volume commitment fees in the Barnett Shale and Mid-Continent regions (see Note 7 – Other Income and Expenses)Notes to Consolidated Financial Statements);
$180 million impairment loss on certain assets (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk);
|
| | |
| The Williams Companies Inc. |
| Quarterly Financial Data – (Continued) |
| (Unaudited) |
$898591 million impairment lossgain on certain equity-method investmentsthe sale of our natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado (see Note 173 – Fair Value Measurements, Guarantees,Acquisitions and ConcentrationDivestitures of Credit Risk)Notes to Consolidated Financial Statements);
$1,098141 million impairment of goodwill (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk).
Net income (loss) for third-quarter 2015 includes a $461 million impairment loss on certain equity-method investments (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk).
Net income (loss) for second-quarter 2015 includes a $126 milliondeconsolidation gain associated with insurance recoveries relatedour investment in the Brazos Permian II joint venture (see Note 6 – Investing Activities of Notes to Consolidated Financial Statements);
$101 million gain on the Geismar Incident.sale of certain assets and operations located in the Gulf Coast area (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).
The Williams Companies, Inc.
Schedule I — Condensed Financial Information of Registrant
Statement of Comprehensive Income (Loss) (Parent)
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (Millions, except per-share amounts) |
| Equity in earnings of consolidated subsidiaries | $ | 522 |
| | $ | 232 |
| | $ | 1,799 |
|
| Equity earnings (losses) from investment in Access Midstream Partners | — |
| | — |
| | (7 | ) |
| Interest incurred — external | (268 | ) | | (255 | ) | | (206 | ) |
| Interest incurred — affiliate | (568 | ) | | (828 | ) | | (797 | ) |
| Interest income — affiliate | — |
| | 6 |
| | 10 |
|
| Gain on remeasurement of equity-method investment | — |
| | — |
| | 2,544 |
|
| Other income (expense) — net | (53 | ) | | (75 | ) | | (13 | ) |
| Income (loss) from continuing operations before income taxes | (367 | ) | | (920 | ) | | 3,330 |
|
| Provision (benefit) for income taxes | 57 |
| | (349 | ) | | 1,220 |
|
| Income (loss) from continuing operations | (424 | ) | | (571 | ) | | 2,110 |
|
| Income (loss) from discontinued operations | — |
| | — |
| | 4 |
|
| Net income (loss) | $ | (424 | ) | | $ | (571 | ) | | $ | 2,114 |
|
| Basic earnings (loss) per common share: | | | | | |
| Income (loss) from continuing operations | $ | (.57 | ) | | $ | (.76 | ) | | $ | 2.93 |
|
| Income (loss) from discontinued operations | — |
| | — |
| | .01 |
|
| Net income (loss) | $ | (.57 | ) | | $ | (.76 | ) | | $ | 2.94 |
|
| Weighted-average shares (thousands) | 750,673 |
| | 749,271 |
| | 719,325 |
|
| Diluted earnings (loss) per common share: | | | | | |
| Income (loss) from continuing operations | $ | (.57 | ) | | $ | (.76 | ) | | $ | 2.91 |
|
| Income (loss) from discontinued operations | — |
| | — |
| | .01 |
|
| Net income (loss) | $ | (.57 | ) | | $ | (.76 | ) | | $ | 2.92 |
|
| Weighted-average shares (thousands) | 750,673 |
| | 749,271 |
| | 723,641 |
|
| Other comprehensive income (loss): | | | | | |
| Equity in other comprehensive income (loss) of consolidated subsidiaries | $ | 171 |
| | $ | (204 | ) | | $ | (96 | ) |
| Other comprehensive income (loss) attributable to The Williams Companies, Inc. | 1 |
| | 33 |
| | (80 | ) |
| Other comprehensive income (loss) | 172 |
| | (171 | ) | | (176 | ) |
| Less: Other comprehensive income (loss) attributable to noncontrolling interests | 69 |
| | (70 | ) | | (19 | ) |
| Comprehensive income (loss) attributable to The Williams Companies, Inc. | $ | (321 | ) | | $ | (672 | ) | | $ | 1,957 |
|
See accompanying notes.
The Williams Companies, Inc.
Schedule I — Condensed Financial Information of Registrant – (Continued)
Balance Sheet (Parent)
|
| | | | | | | |
| | December 31, |
| | 2016 | | 2015 |
| | (Millions) |
| ASSETS | | | |
| Current assets: | | | |
| Cash and cash equivalents | $ | 14 |
| | $ | 12 |
|
| Other current assets and deferred charges | 16 |
| | 62 |
|
| Total current assets | 30 |
| | 74 |
|
| Investments in and advances to consolidated subsidiaries | 22,359 |
| | 30,927 |
|
| Property, plant, and equipment — net | 77 |
| | 99 |
|
| Other noncurrent assets | 8 |
| | 12 |
|
| Total assets | $ | 22,474 |
| | $ | 31,112 |
|
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | |
| Current liabilities: | | | |
| Accounts payable | $ | 27 |
| | $ | 27 |
|
| Other current liabilities | 169 |
| | 163 |
|
| Total current liabilities | 196 |
| | 190 |
|
| Long-term debt | 4,939 |
| | 4,811 |
|
| Notes payable — affiliates | 8,171 |
| | 15,506 |
|
| Pension, other postretirement, and other noncurrent liabilities | 287 |
| | 336 |
|
| Deferred income tax liabilities | 4,238 |
| | 4,121 |
|
| Contingent liabilities and commitments |
| |
|
| Equity: | | | |
| Common stock | 785 |
| | 784 |
|
| Other stockholders’ equity | 3,858 |
| | 5,364 |
|
| Total stockholders’ equity | 4,643 |
| | 6,148 |
|
| Total liabilities and stockholders’ equity | $ | 22,474 |
| | $ | 31,112 |
|
See accompanying notes.
The Williams Companies, Inc.
Schedule I — Condensed Financial Information of Registrant – (Continued)
Statement of Cash Flows (Parent)
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2016 | | 2015 | | 2014 |
| | (Millions) |
| NET CASH FLOWS PROVIDED (USED) BY OPERATING ACTIVITIES | $ | (833 | ) | | $ | (1,209 | ) | | $ | (500 | ) |
| | | | | | |
| FINANCING ACTIVITIES: | | | | | |
| Proceeds from long-term debt | 2,280 |
| | 2,097 |
| | 2,935 |
|
| Payments of long-term debt | (2,155 | ) | | (1,817 | ) | | (671 | ) |
| Changes in notes payable to affiliates | 9 |
| | 2,211 |
| | 2,465 |
|
| Tax benefit of stock-based awards | — |
| | — |
| | 25 |
|
| Proceeds from issuance of common stock | 9 |
| | 27 |
| | 3,416 |
|
| Dividends paid | (1,261 | ) | | (1,836 | ) | | (1,412 | ) |
| Other — net | — |
| | (2 | ) | | (17 | ) |
| Net cash provided (used) by financing activities | (1,118 | ) | | 680 |
| | 6,741 |
|
| | | | | | |
| INVESTING ACTIVITIES: | | | | | |
| Capital expenditures | (13 | ) | | (29 | ) | | (54 | ) |
| Purchase of Access Midstream Partners | — |
| | — |
| | (5,995 | ) |
| Changes in investments in and advances to consolidated subsidiaries | 1,966 |
| | 521 |
| | (450 | ) |
| Other — net | — |
| | — |
| | 25 |
|
| Net cash provided (used) by investing activities | 1,953 |
| | 492 |
| | (6,474 | ) |
| Increase (decrease) in cash and cash equivalents | 2 |
| | (37 | ) | | (233 | ) |
| Cash and cash equivalents at beginning of year | 12 |
| | 49 |
| | 282 |
|
| Cash and cash equivalents at end of year | $ | 14 |
| | $ | 12 |
| | $ | 49 |
|
See accompanying notes.
The Williams Companies, Inc.
Schedule I — Condensed Financial Information of Registrant – (Continued)
Notes to Financial Information (Parent)
Note 1. Guarantees
In addition to the guarantees disclosed in the accompanying consolidated financial statements in Item 8, we have financially guaranteed the performance of certain consolidated subsidiaries. The duration of these guarantees varies, and we estimate the maximum undiscounted potential future payment obligation related to these guarantees as of December 31, 2016, is approximately $305 million.
Note 2. Cash Dividends Received
We receive dividends and distributions either directly from our subsidiaries or indirectly through dividends received by subsidiaries and subsequent transfers of cash to us through our corporate cash management system. The total of such receipts ultimately related to dividends and distributions for the years ended December 31, 2016, 2015, and 2014 was approximately $1.7 billion, $1.8 billion, and $1.9 billion, respectively.
The Williams Companies, Inc.
Schedule II — Valuation and Qualifying Accounts
|
| | | | | | | | | | | | | | | | | | | |
| | | | Additions | | | | |
| | Beginning Balance | | Charged (Credited) To Costs and Expenses | | Other | | Deductions | | Ending Balance |
| | (Millions) |
| 2016 | | | | | | | | | |
| Allowance for doubtful accounts — accounts and notes receivable (1) | $ | 3 |
| | $ | 6 |
| | $ | — |
| | $ | 3 |
| | $ | 6 |
|
| Deferred tax asset valuation allowance (1) | 190 |
| | 144 |
| | — |
| | — |
| | 334 |
|
| 2015 | | | | | | | | | |
| Allowance for doubtful accounts — accounts and notes receivable (1) | — |
| | 3 |
| | — |
| | — |
| | 3 |
|
| Deferred tax asset valuation allowance (1) | 206 |
| | (16 | ) | | — |
| | — |
| | 190 |
|
| 2014 | | | | | | | | | |
| Allowance for doubtful accounts — accounts and notes receivable (1) | — |
| | — |
| | — |
| | — |
| | — |
|
| Deferred tax asset valuation allowance (1) | 181 |
| | 25 |
| | — |
| | — |
| | 206 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | | | Additions | | | | |
| | Beginning Balance | | Charged (Credited) To Costs and Expenses | | Other | | Deductions | | Ending Balance |
| | (Millions) |
| 2019 | | | | | | | | | |
| Deferred tax asset valuation allowance (1) | $ | 320 |
| | $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | 319 |
|
| 2018 | | | | | | | | | |
| Deferred tax asset valuation allowance (1) | 224 |
| | 96 |
| | — |
| | — |
| | 320 |
|
| 2017 | | | | | | | | | |
| Deferred tax asset valuation allowance (1) | 334 |
| | (110 | ) | | — |
| | — |
| | 224 |
|
__________
(1) Deducted from related assets.
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 20162019 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.
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, 2016,2019, 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, 2016,2019, 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.
Report of Independent Registered Public Accounting Firm
On Internal Control Over Financial Reporting
The Stockholders and the Board of Directors and Stockholders 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, 2016,2019, based on criteria established in Internal Control - IntegratedControl-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.’s (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 Public Company Accounting Oversight Board (United States).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.
In our opinion, The Williams Companies, Inc.maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of The Williams Companies, Inc. as of December 31, 2016 and 2015, 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, 2016, and our report datedFebruary 22, 2017,expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 22, 201724, 2020
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The information regarding our directors and nominees for director required by Item 401 of Regulation S-K will be presented under the heading “Election of Directors” in our definitive proxy statement prepared for the solicitation of proxies in connection with our Annual Meeting of Stockholders to be held May 18, 2017,April 28, 2020, which shall be filed no later than April 30, 2017March 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 “Executive“Information About Our Executive Officers, of the Registrant”” as permitted by General Instruction G(3) to and Instruction 3 to Item 401(b) of Regulation S-K.
Information required by Item 405 of Regulation S-K will be included under the heading “Section 16(a) Beneficial Ownership Reporting Compliance” in our Proxy Statement, which information is incorporated by reference herein.
Information required by paragraphs (c)(3), (d)(4) and (d)(5) of Item 407 of Regulation S-K will be included under the heading “Questions and Answers About the Annual Meeting and Voting” and “Corporate Governance and Board Matters” in our Proxy Statement, which information is incorporated by reference herein.
We have adopted aOur Code of Ethics for Senior Officers that applies to our Chief Executive Officer, Chief Financial Officer, and Controller, or persons performing similar functions. The Code of Ethics for Senior Officers,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 EthicsBusiness 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 EthicsBusiness Conduct on behalf of our Chief Executive Officer, Chief Financial Officer, Controller,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)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.
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.
PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) 1 and 2.
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| Covered by report of independent auditors: | |
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Schedule for each year in the three-year period ended December 31, 2016:2019: | |
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| Not covered by report of independent auditors: | |
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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.
INDEX TO EXHIBITS
|
| | |
Exhibit
No. | | Description |
| | | |
2.1+2.1 | — | 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). |
| | | |
| 2.2 | — | |
| | |
| 2.3 | — | 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). |
| | | |
2.3+2.4 | — | 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). |
| | |
|
| | |
Exhibit
No. | | Description |
| | | |
2.4 | — | Share Purchase Agreement by and between The Williams Companies International Holdings B.V. and Inter Pipeline Ltd. and The Williams Companies, Inc., dated August 8, 2016 (filed on August 12, 2016 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (file No. 001-04174) and incorporated herein by reference). |
| | | |
| 2.5 | — | Share Purchase Agreement by and between Williams Energy Canada LP and Inter Pipeline Ltd. and Williams Partners L.P., dated August 8, 2016 (filed on August 12, 2016 as Exhibit 2.2 to The Williams Companies, Inc.’s current report on Form 8-K (file No. 001-04174) and incorporated herein by reference). |
| | |
2.6+ | — | 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 exhibitExhibit 2.1 to The Williams Companies Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
| | |
| 2.6 | — | 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). |
| | | |
| 3.1 | — | |
| | |
| 3.2 | — | |
| | |
| 3.3 | — | |
| | | |
3.23.4 | — | |
| | | |
| 4.1 | — | |
| | | |
| 4.2 | — | Supplemental Indenture No. 1 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(o) to MAPCO Inc.’s annual report on Form 10-K for the fiscal year ended December 31, 1997 (File No. 001-05254) and incorporated herein by reference). |
| | |
4.3 | — | |
| | | |
4.44.3 | — | 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 K10-K for the fiscal year ended December 31, 1998 (File No. 000-20555) and incorporated herein by reference). |
| | | |
4.54.4 | — | Fourth Supplemental Indenture, No. 4 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). |
| | |
| 4.5 | —
| |
| | | |
| 4.6 | — | |
|
| | |
Exhibit
No. | | Description |
| | |
| | | |
| 4.7 | — | |
| | |
|
| | |
Exhibit
No. | | Description |
| | | |
| 4.8 | —
| Indenture dated as of May 28, 2003, by and between The Williams Companies, Inc. and JPMorgan Chase Bank, as Trustee for the issuance of the 5.50% Junior Subordinated Convertible Debentures due 2033 (filed on August 12, 2003 as Exhibit 4.2 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference). |
| | |
4.9 | — | Indenture dated as of March 5, 2009, among The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on March 11, 2009 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
| | |
4.10 | — | |
| | | |
4.114.9 | — | First Supplemental Indenture dated as of February 1, 2010 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.2 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
| | |
4.12 | — | 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). |
| | |
4.13 | — | |
| | | |
4.144.10 | — | |
| | | |
4.154.11 | — | |
| | | |
4.164.12 | — | Indenture, dated December 13, 2006, by and among Williams Partners L.P., Williams Partners Finance Corporation and The Bank of New York (filed on December 19, 2006 as Exhibit 4.1 to Pre-merger WPZ’s report on Form 8-K (File No. 001-32599) and incorporated herein by reference). |
| | |
4.17 | — | First Supplemental Indenture, dated as of February 2, 2015, among Williams Partners L.P., Williams Partners Finance Corporation and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015, as Exhibit 4.6 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
4.18 | — | |
| | | |
| | |
|
| | |
Exhibit
No. | | Description |
| | |
4.194.13 | — | |
| | | |
4.204.14 | — | |
| | |
| 4.15 | — | |
| | | |
4.214.16 | — | |
| | | |
4.224.17 | — | |
| | |
|
| | |
Exhibit
No. | | Description |
| | | |
4.234.18 | — | |
| | | |
4.244.19 | — | |
| | | |
4.254.20 | — | |
| | | |
4.264.21 | — | |
| | | |
4.274.22 | — | |
| | | |
4.284.23 | — | |
| | | |
4.294.24 | — | Ninth Supplemental Indenture, dated as of January 11, 2012, by and among the Chesapeake MidstreamJune 5, 2017, between Williams Partners L.P., CHKM Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on January 11, 2012June 5, 2017, as Exhibit 4.1 to Williams Partners L.P.’s (then known as Access Midstream Partners L.P.) current report on 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
|
| | |
Exhibit
No. | | Description |
| | |
4.30 | — | First Supplemental Indenture, dated as of January 7, 2013, by and among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on February 21, 2014 as Exhibit 4.5 to Williams Partners L.P.’s (then known as Access Midstream Partners L.P.) annual report on 10-K (File No. 001-34831) and incorporated herein by reference). |
| | |
4.31 | — | Second Supplemental Indenture and Amendment - Subsidiary Guarantee, dated as of April 18, 2014 among the Access Midstream Partners, L.P., ACMP Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee filed on May 1, 2014 as Exhibit 4.4 to Williams Partners L.P.’s (then known as Access Midstream Partners L.P.) quarterly report on 10-Q (File No. 001-34831) and incorporated herein by reference). |
| | |
4.32 | — | Third Supplemental Indenture among Williams Partners L.P., ACMP Finance Corp. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015, as Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference). |
| | | |
4.334.25 | — | Indenture, dated as of December 19, 2012, by and among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors listed therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on December 19, 2012 as Exhibit 4.1 to Williams Partners L.P.’s (formerly known as Access Midstream Partners L.P.) current report on 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
4.34 | — | First Supplemental Indenture, dated as of December 19, 2012, among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors listed therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on December 19, 2012 as Exhibit 4.2 to Williams Partners L.P.’s (formerly known as Access Midstream Partners L.P.) current report on 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
4.35 | — | Second Supplemental Indenture and Amendment - Subsidiary Guarantee, dated as of January 7, 2013, by among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on February 21, 2014 as Exhibit 4.9 to Williams Partners L.P.’s (formerly known as Access Midstream Partners L.P.) annual report on 10-K (File No. 001-34831) and incorporated herein by reference). |
| | |
4.36 | — | ThirdTenth Supplemental Indenture, dated as of March 7, 2014, among the Access Midstream5, 2018, between Williams Partners L.P., ACMP Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 7, 20145, 2018, as Exhibit 4.2 to Williams Partners L.P.’s (formerly known as Access Midstream Partners L.P.) current report on 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
4.37 | — | Third Supplemental Indenture and Amendment - Subsidiary Guarantee, dated as of April 18, 2014, among the Access Midstream Partners, L.P., ACMP Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on May 1, 2014 as Exhibit 4.3 to Williams Partners L.P.’s (formerly known as Access Midstream Partners L.P.) quarterly report on 10-Q (File No. 001-34831) and incorporated herein by reference). |
| | |
4.38 | — | Fifth Supplemental Indenture dated as of February 2, 2015 among Williams Partners L.P., ACMP Finance Corp. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015, as Exhibit 4.34.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference). |
| | | |
4.394.26 | — | |
| | |
| 4.27 | — | |
| | |
|
| | |
Exhibit
No. | | Description |
| | | |
4.404.28 | — | Indenture, dated as of June 22, 2006,April 3, 2017, between Northwest Pipeline CorporationLLC and JPMorgan ChaseThe Bank of New York Mellon Trust Company, N.A., as Trusteetrustee (filed on June 23, 2006April 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). |
| | | |
4.414.29 | — | Indenture dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York (filed on April 5, 2007 as Exhibit 4.1 to Northwest Pipeline Corporation’s current report on Form 8-K (File No. 001-07414) and incorporated herein by reference). |
| | |
4.42 | — | Indenture dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Northwest Pipeline GP’s current report on Form 8-K (File No. 001-07414) and incorporated herein by reference). |
| | |
4.43 | — | |
| | |
|
| | |
Exhibit
No. | | Description |
| | | |
4.444.30 | — | Indenture dated as of April 11, 2006 between Transcontinental Gas Pipe Line Corporation and JPMorgan Chase Bank, N.A., as Trustee (filed on April 11, 2006 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference). |
| | |
4.45 | — | Indenture dated May 22, 2008, between Transcontinental Gas Pipe Line Corporation and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference). |
| | |
4.46 | — | |
| | | |
4.474.31 | — | |
| | | |
4.484.32 | — | 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 Company,Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
| | |
| 4.33 | — | |
| | |
| 4.34* | — | |
| | | |
| 10.1§ | — | The Williams Companies Amended and Restated Retirement Restoration Plan effective January l, 2008 (filed on February 25, 2009 as Exhibit 10.1 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.2§ | — | |
| | | |
10.3§10.2§ | — | Form of 2013 Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on February 27, 2013 as Exhibit 10.4 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
| | |
| | |
|
| | |
Exhibit
No. | | Description |
| | |
10.4§ | — | Form of 2013 Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on February 27, 2013 as Exhibit 10.5 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.5§ | — | 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). |
| | | |
10.6§10.3§ | — | |
| | | |
10.7§10.4§ | — | Form of 2014 Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on February 26, 2014 as Exhibit 10.6 to The Williams Companies, Inc. annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.8§ | — | Form of 2014 Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on February 26, 2014 as Exhibit 10.7 to The Williams Companies, Inc. annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.9§ | — | |
| | | |
10.10§10.5§ | — | |
| | | |
10.11§10.6§ | — | Form of October 2014 Leveraged Performance Unit Award Agreement among Williams and certain officers (filed on February 25, 2015 as Exhibit 10.13 to The Williams Companies, Inc. annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.12§ | — | Form of Leveraged Performance Unit Award Agreement dated January 1, 2015 between Williams and Walter Bennett (filed on February 25, 2015 as Exhibit 10.14 to The Williams Companies, Inc. annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.13§ | — | Form of 2015 Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on February 25, 2015 as Exhibit 10.15 to The Williams Companies, Inc. annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
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10.14§ | — | |
| | | |
10.15§10.7§ | — | |
| | | |
10.16§
10.8§ | — | |
| | | |
10.17§
10.9§ | — | |
|
| | |
Exhibit
No. | | Description |
| | |
| 10.23§ | — | |
| | |
| 10.24§ | — | |
| | |
| 10.25§ | — | |
| | | |
10.27§10.26§ | — | |
| | | |
10.28§10.27§ | — | |
| | | |
10.29§10.28§ | — | |
| | |
| 10.29§* | — | |
| | | |
| 10.30§* | — | Amended |
| | | |
| 10.31§ | — | Amended and Restated Change-in-Control Severance Agreement between the Company and certain executive officers (Tier II Executives) (filed on February 28, 2012, as Exhibit 10.14 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.32 | — | |
| | |
|
| | |
Exhibit
No. | | Description |
| | | |
10.3310.32§ | — | |
| | | |
10.3410.33§ | — | Separation and Distribution Agreement dated as of December 30, 2011, between |
| | | |
10.3510.34 | — | Tax Sharing Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (filed on January 6, 2012 as Exhibit 10.3 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.36 | — | Letter Agreement, dated January 27, 2014, with James E. Scheel, Senior Vice President - Northeast G&P, regarding Relocation from Pennsylvania Benefits (filed on May 1, 2014 as Exhibit 10.2 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference). |
| | |
10.37§ | — | The Williams Companies, Inc. 2007 Incentive Plan as amended and restated effective May 22, 2014 (filed April 11, 2014 as Appendix A to The Williams Companies, Inc.’s Definitive Proxy Statement on Schedule 14A (File No. 001-04174) and incorporated herein by reference). |
| | |
10.38*§ | — | The Williams Companies, Inc. 2007 Incentive Plan as amended and restated effective July 14, 2016. |
| | |
10.39 | — | Termination Agreement and Release, dated as of September 28, 2015, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P. and WPZ GP LLC (filed on September 28, 2015 as Exhibit 10.1 to Williams Companies, Inc.’s Current Report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.40 | — | Second Amended and Restated Credit Agreement dated as of February 2, 2015,July 13, 2018, between The Williams Companies, Inc., the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on February 3, 2015 as Exhibit 10.1 to The Williams Companies, Inc.’s current report on Form 8-K (File 001-04174) and incorporated herein by reference). |
| | |
10.41 | — | Credit Agreement dated as of August 26, 2015, by and among Williams Partners L.P., the lenders named therein, and Barclays Bank PLC as Administrative Agent (filed on August 28, 2015 as Exhibit 10.1 to Williams Partners L.P.’s Current Report on Form 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
10.42 | — | Credit Agreement dated as of December 23, 2015, between Williams Partners L.P., the lenders named therein, and Barclays Bank PLC as Administrative Agent (filed on December 23, 2015 as Exhibit 10.2 to Williams Companies, Inc.’s Current Report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.43 | — | Second Amended and Restated Credit Agreement dated as of February 2, 2015, between Williams Partners L.P. (formerly known as Access Midstream Partners, L.P.), Northwest Pipeline LLC, Transcontinental Gas Pipeline Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on February 3, 2015 as Exhibit 10.1 to Williams Partners L.P.’s Current Report on Form 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
10.44 | — | Amendment No. 1 to Second Amended and Restated Credit Agreement dated as of December 18, 2015, between Williams Partners L.P., Northwest Pipeline LLC, Transcontinental Gas Pipe Line Company, LLC as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on December 23, 2015July 17, 2018, as Exhibit 10.1 to The Williams Companies, Inc.’s Current Reportcurrent report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
| | |
| 10.35 | — | |
| | |
| 21* | — | |
| | | |
|
| | |
Exhibit
No. | | Description |
| | | |
10.45 | — | Form of Amended and Restated Commercial Paper Dealer Agreement, dated as of February 2, 2015, between Williams Partners L.P., as Issuer, and the Dealer party thereto(filed on February 3, 2015 as Exhibit 10.3 to Williams Partners L.P.’s Current Report on Form 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
10.46 | — | Registration Rights Agreement, dated January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC and each of the initial purchasers listed therein (filed on January 22, 2016 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 8-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.47 | — | Common Unit Issuance Agreement, dated January 9, 2017 (filed on January 10, 2017, as Exhibit 2 to Schedule 13D/A (File No. 005-86017) by The Williams Companies, Inc. relating to the common units representing limited partner interests of Williams Partners L.P. and incorporated herein by reference.) |
| | |
10.48 | — | Common Unit Purchase Agreement, dated January 9, 2017 (filed on January 10, 2017, as Exhibit 3 to Schedule 13D/A (File No. 005-86017) by The Williams Companies, Inc. relating to the common units representing limited partner interests of Williams Partners L.P. and incorporated herein by reference.) |
| | |
12* | — | Computation of Ratio of Earnings to Combined Fixed Charges. |
| | |
14 | — | Code of Ethics for Senior Officers (filed on March 15, 2004 as Exhibit 14 to The Williams
Companies, Inc.’s Form 10-K and incorporated herein by reference). |
| | |
21* | — | Subsidiaries of the registrant. |
| | |
| 23.1* | — | |
| | | |
| 23.2* | — | |
| | |
24* | — | Power of Attorney. |
| | | |
| 31.1* | — | |
| | | |
| 31.2* | — | |
| | | |
| 32** | — | |
| | | |
| 101.INS* | — | XBRL Instance Document. |
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101.SCH* | — | The instance document does not appear in the Interactive Data File because its XBRL Taxonomy Extension Schema. |
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101.CAL* | — | tags are embedded within the inline XBRL Taxonomy Extension Calculation Linkbase. |
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101.DEF* | — | XBRL Taxonomy Extension Definition Linkbase. |
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Exhibit
No. | | Description |
| | |
101.LAB* | — | XBRL Taxonomy Extension Label Linkbase. |
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101.PRE* | — | XBRL Taxonomy Extension Presentation Linkbase. |
|
| |
______________ |
* | Filed herewith |
** | Furnished herewith |
§ | Management contract or compensatory plan or arrangement |
+ | Pursuant to item 601(6)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request. |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
| | |
THE WILLIAMS COMPANIES, INC.
(Registrant)
|
| | |
By: | | /s/ TED T. TIMMERMANS
|
| | Ted T. Timmermans
Vice President, Controller and
Chief Accounting Officer
|
Date: February 22, 2017
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
|
| | | | |
Signature | | Title | | Date |
| | | | |
/s/ ALAN S. ARMSTRONG
| | President, Chief Executive Officer and Director | | February 22, 2017 |
Alan S. Armstrong | | (Principal Executive Officer) | | |
| | | | |
/s/ DONALD R. CHAPPEL
| | Senior Vice President and Chief Financial Officer | | February 22, 2017 |
Donald R. Chappel | | (Principal Financial Officer) | | |
| | | | |
/s/ TED T. TIMMERMANS
| | Vice President, Controller and Chief Accounting Officer | | February 22, 2017 |
Ted T. Timmermans | | (Principal Accounting Officer) | | |
| | | | |
/s/ STEPHEN W. BERGSTROM*
| | Director | | February 22, 2017 |
Stephen W. Bergstrom* | | | | |
| | | | |
/s/ STEPHEN I. CHAZEN*
| | Director | | February 22, 2017 |
Stephen I. Chazen* | | | | |
| | | | |
/s/ CHARLES I. COGUT*
| | Director | | February 22, 2017 |
Charles I. Cogut* | | | | |
|
| | | | |
| | | | |
/s/ KATHLEEN B. COOPER*
| | Chairman of the Board | | February 22, 2017 |
Kathleen B. Cooper* | | | | |
| | | | |
/s/ MICHAEL A. CREEL*
| | Director | | February 22, 2017 |
Michael A. Creel* | | | | |
| | | | |
/s/ PETER A. RAGAUSS*
| | Director | | February 22, 2017 |
Peter A. Ragauss* | | | | |
|
| | | | |
Signature | | Title | | Date |
| | | | |
/s/ SCOTT D. SHEFFIELD*
| | Director | | February 22, 2017 |
Scott D. Sheffield* | | | | |
| | | | |
/s/ MURRAY D. SMITH*
| | Director | | February 22, 2017 |
Murray D. Smith* | | | | |
| | | | |
/S/ WILLIAM H. SPENCE*
| | Director | | February 22, 2017 |
William H. Spence | | | | |
| | | | |
/S/ JANICE D. STONEY*
| | Director | | February 22, 2017 |
Janice D. Stoney* | | | | |
|
| | | | | | |
*By: | | /s/ Sarah C. Miller | | | | February 22, 2017 |
| | Sarah C. Miller
Attorney-in-Fact
| | | | |
INDEX TO EXHIBITS
|
| | |
Exhibit
No. | | Description |
| | |
2.1+ | — | 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). |
| | |
2.2 | — | 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). |
| | |
2.3+ | — | 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). |
| | |
2.4 | — | Share Purchase Agreement by and between The Williams Companies International Holdings B.V. and Inter Pipeline Ltd. and The Williams Companies, Inc., dated August 8, 2016 (filed on August 12, 2016 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (file No. 001-04174) and incorporated herein by reference). |
| | |
2.5 | — | Share Purchase Agreement by and between Williams Energy Canada LP and Inter Pipeline Ltd. and Williams Partners L.P., dated August 8, 2016 (filed on August 12, 2016 as Exhibit 2.2 to The Williams Companies, Inc.’s current report on Form 8-K (file No. 001-04174) and incorporated herein by reference). |
| | |
2.6+ | — | 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). |
| | |
3.1 | — | Amended and Restated Certificate of Incorporation, as supplemented (filed on May 26, 2010 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). |
| | |
3.2 | — | By-Laws (filed on January 20, 2017, as Exhibit 3.1 to The Williams Companies Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
| | |
4.1 | — | 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 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). |
| | |
4.2 | — | Supplemental Indenture No. 1 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(o) to MAPCO Inc.’s annual report on Form 10-K for the fiscal year ended December 31, 1997 (File No. 001-05254) and incorporated herein by reference). |
| | |
4.3 | — | 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 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). |
| | |
|
| | |
Exhibit
No. | | Description |
| | |
4.4 | — | 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 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). |
| | |
4.5 | — | Supplemental Indenture No. 4 dated as of July 31, 1999, among Williams Holdings of Delaware, Inc., Williams 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). |
| | |
4.6 | — | Fifth Supplemental Indenture between Williams 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). |
| | |
4.7 | — | 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). |
| | |
4.8 | — | Indenture dated as of May 28, 2003, by and between The Williams Companies, Inc. and JPMorgan Chase Bank, as Trustee for the issuance of the 5.50% Junior Subordinated Convertible Debentures due 2033 (filed on August 12, 2003 as Exhibit 4.2 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference). |
| | |
4.9 | — | Indenture dated as of March 5, 2009, among The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on March 11, 2009 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
| | |
4.10 | — | 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). |
| | |
4.11 | — | First Supplemental Indenture dated as of February 1, 2010 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.2 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
| | |
4.12 | — | 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). |
| | |
4.13 | — | 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). |
| | |
4.14 | — | 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). |
| | |
|
| | |
Exhibit
No. | | Description |
| | |
4.15 | — | 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). |
| | |
4.16 | — | Indenture, dated December 13, 2006, by and among Williams Partners L.P., Williams Partners Finance Corporation and The Bank of New York (filed on December 19, 2006 as Exhibit 4.1 to Pre-merger WPZ’s report on Form 8-K (File No. 001-32599) and incorporated herein by reference). |
| | |
4.17 | — | First Supplemental Indenture, dated as of February 2, 2015, among Williams Partners L.P., Williams Partners Finance Corporation and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015, as Exhibit 4.6 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
4.18 | — | 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). |
| | |
4.19 | — | First Supplemental Indenture, dated as of February 2, 2015, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015, as Exhibit 4.5 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
4.20 | — | 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). |
| | |
4.21 | — | 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). |
| | |
4.22 | — | 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). |
| | |
4.23 | — | 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). |
| | |
4.24 | — | 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). |
| | |
4.25 | — | 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 report on Form 8-K (File No. 001-32599) and incorporated herein by reference). |
| | |
4.26 | — | 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 report on Form 8-K (File No. 001-32599) and incorporated herein by reference). |
| | |
|
| | |
Exhibit
No. | | Description |
| | |
4.27 | — | Seventh Supplemental Indenture, dated as of February 2, 2015, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015, as Exhibit 4.4 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
4.28 | — | 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). |
| | |
4.29 | — | Indenture, dated as of January 11, 2012, by and among the Chesapeake Midstream Partners, L.P., CHKM Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on January 11, 2012 as Exhibit 4.1 to Williams Partners L.P.’s (then known as Access Midstream Partners L.P.) current report on 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
4.30 | — | First Supplemental Indenture, dated as of January 7, 2013, by and among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on February 21, 2014 as Exhibit 4.5 to Williams Partners L.P.’s (then known as Access Midstream Partners L.P.) annual report on 10-K (File No. 001-34831) and incorporated herein by reference). |
| | |
4.31 | — | Second Supplemental Indenture and Amendment - Subsidiary Guarantee, dated as of April 18, 2014 among the Access Midstream Partners, L.P., ACMP Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee filed on May 1, 2014 as Exhibit 4.4 to Williams Partners L.P.’s (then known as Access Midstream Partners L.P.) quarterly report on 10-Q (File No. 001-34831) and incorporated herein by reference). |
| | |
4.32 | — | Third Supplemental Indenture among Williams Partners L.P., ACMP Finance Corp. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015, as Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
4.33 | — | Indenture, dated as of December 19, 2012, by and among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors listed therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on December 19, 2012 as Exhibit 4.1 to Williams Partners L.P.’s (formerly known as Access Midstream Partners L.P.) current report on 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
4.34 | — | First Supplemental Indenture, dated as of December 19, 2012, among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors listed therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on December 19, 2012 as Exhibit 4.2 to Williams Partners L.P.’s (formerly known as Access Midstream Partners L.P.) current report on 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
4.35 | — | Second Supplemental Indenture and Amendment - Subsidiary Guarantee, dated as of January 7, 2013, by among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on February 21, 2014 as Exhibit 4.9 to Williams Partners L.P.’s (formerly known as Access Midstream Partners L.P.) annual report on 10-K (File No. 001-34831) and incorporated herein by reference). |
| | |
4.36 | — | Third Supplemental Indenture, dated as of March 7, 2014, among the Access Midstream Partners, L.P., ACMP Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 7, 2014 as Exhibit 4.2 to Williams Partners L.P.’s (formerly known as Access Midstream Partners L.P.) current report on 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
|
| | |
Exhibit
No. | | Description |
| | |
4.37 | — | Third Supplemental Indenture and Amendment - Subsidiary Guarantee, dated as of April 18, 2014, among the Access Midstream Partners, L.P., ACMP Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on May 1, 2014 as Exhibit 4.3 to Williams Partners L.P.’s (formerly known as Access Midstream Partners L.P.) quarterly report on 10-Q (File No. 001-34831) and incorporated herein by reference). |
| | |
4.38 | — | Fifth Supplemental Indenture dated as of February 2, 2015 among Williams Partners L.P., ACMP Finance Corp. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015, as Exhibit 4.3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
4.39 | — | 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). |
| | |
4.40 | — | Indenture dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., as Trustee (filed on June 23, 2006 as Exhibit 4.1 to Northwest Pipeline’s current report on Form 8-K (File No. 001-07414) and incorporated herein by reference). |
| | |
4.41 | — | Indenture dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York (filed on April 5, 2007 as Exhibit 4.1 to Northwest Pipeline Corporation’s current report on Form 8-K (File No. 001-07414) and incorporated herein by reference). |
| | |
4.42 | — | Indenture dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Northwest Pipeline GP’s current report on Form 8-K (File No. 001-07414) and incorporated herein by reference). |
| | |
4.43 | — | 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). |
| | |
4.44 | — | Indenture dated as of April 11, 2006 between Transcontinental Gas Pipe Line Corporation and JPMorgan Chase Bank, N.A., as Trustee (filed on April 11, 2006 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference). |
| | |
4.45 | — | Indenture dated May 22, 2008, between Transcontinental Gas Pipe Line Corporation and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference). |
| | |
4.46 | — | 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 8K (File No. 001-07584) and incorporated herein by reference). |
| | |
4.47 | — | 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). |
| | |
4.48 | — | 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 Company, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
| | |
|
| | |
Exhibit
No. | | Description |
| | |
10.1§ | — | The Williams Companies Amended and Restated Retirement Restoration Plan effective January l, 2008 (filed on February 25, 2009 as Exhibit 10.1 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.2§ | — | Form of Director and Officer Indemnification Agreement (filed on September 24, 2008 as Exhibit 10.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.3§ | — | Form of 2013 Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on February 27, 2013 as Exhibit 10.4 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.4§ | — | Form of 2013 Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on February 27, 2013 as Exhibit 10.5 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.5§ | — | 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). |
| | |
10.6§ | — | 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). |
| | |
10.7§ | — | Form of 2014 Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on February 26, 2014 as Exhibit 10.6 to The Williams Companies, Inc. annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.8§ | — | Form of 2014 Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on February 26, 2014 as Exhibit 10.7 to The Williams Companies, Inc. annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.9§ | — | 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). |
| | |
10.10§ | — | 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). |
| | |
10.11§ | — | Form of October 2014 Leveraged Performance Unit Award Agreement among Williams and certain officers (filed on February 25, 2015 as Exhibit 10.13 to The Williams Companies, Inc. annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.12§ | — | Form of Leveraged Performance Unit Award Agreement dated January 1, 2015 between Williams and Walter Bennett (filed on February 25, 2015 as Exhibit 10.14 to The Williams Companies, Inc. annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.13§ | — | Form of 2015 Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on February 25, 2015 as Exhibit 10.15 to The Williams Companies, Inc. annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.14§ | — | 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). |
| | |
|
| | |
Exhibit
No. | | Description |
| | |
10.15§ | — | 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). |
| | |
10.16§
| — | Form of 2015 Short-Term Non-Equity Incentive Award Agreement among The Williams Companies Inc. and certain employees and officers (filed on October 29, 2015 as Exhibit 10.2 to The Williams Companies, Inc. quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference). |
| | |
10.17§
| — | Form of 2015 Non-Equity Incentive Award Agreement among The Williams Companies Inc. and certain employees and officers (filed on October 29, 2015 as Exhibit 10.3 to The Williams Companies, Inc. quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference). |
| | |
10.18*§ | — | Form of 2016 Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers. |
| | |
10.19*§
| — | Form of 2016 Time-Based Restricted Stock Unit Agreement among Williams and certain employees and officers. |
| | |
10.20*§ | — | Form of 2016 Time-Based Restricted Stock Unit Agreement among Williams and certain employees and officers vesting February 22, 2019. |
| | |
10.21*§
| — | Form of 2016 Time-Based Restricted Stock Unit Agreement among Williams and certain non-management directors. |
| | |
10.22*§ | — | Form of 2016 Nonqualified Stock Option Agreement among Williams and certain employees and officers. |
| | |
10.23*§ | — | Form of 2017 Time-Based Restricted Stock Unit Agreement among Williams and certain employees and officers. |
| | |
10.24*§ | — | Form of 2017 Time-Based Restricted Stock Unit Agreement among Williams and certain non-management directors. |
| | |
10.25*§ | — | Form of 2017 Nonqualified Stock Option Agreement among Williams and certain employees and officers. |
| | |
10.26§ | — | The Williams Companies, Inc. 1996 Stock Plan for Nonemployee Directors (filed on March 27, 1996 as Exhibit B to The Williams Companies, Inc.’s Proxy Statement (File No. 002-27038) and incorporated herein by reference). |
| | |
10.27§ | — | 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). |
| | |
10.28§ | — | 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). |
| | |
10.29§ | — | 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). |
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|
| | |
Exhibit
No. | | Description |
| | |
10.30§ | — | Amended and Restated Change-in-Control Severance Agreement between the Company and certain executive officers (Tier I Executives) (filed on February 27, 2013 as Exhibit 10.14 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.31§ | — | Amended and Restated Change-in-Control Severance Agreement between the Company and certain executive officers (Tier II Executives) (filed on February 28, 2012, as Exhibit 10.14 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.32 | — | 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). |
| | |
10.33 | — | 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). |
| | |
10.34 | — | Separation and Distribution Agreement dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (Filed on February 27, 2012 as Exhibit 10.19 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.35 | — | Tax Sharing Agreement, dated as of December 30, 2011, between The Williams Companies, Inc. and WPX Energy, Inc. (filed on January 6, 2012 as Exhibit 10.3 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.36 | — | Letter Agreement, dated January 27, 2014, with James E. Scheel, Senior Vice President - Northeast G&P, regarding Relocation from Pennsylvania Benefits (filed on May 1, 2014 as Exhibit 10.2 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference). |
| | |
10.37§ | — | The Williams Companies, Inc. 2007 Incentive Plan as amended and restated effective May 22, 2014 (filed April 11, 2014 as Appendix A to The Williams Companies, Inc.’s Definitive Proxy Statement on Schedule 14A (File No. 001-04174) and incorporated herein by reference). |
| | |
10.38*§ | — | The Williams Companies, Inc. 2007 Incentive Plan as amended and restated effective July 14, 2016. |
| | |
10.39 | — | Termination Agreement and Release, dated as of September 28, 2015, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P. and WPZ GP LLC (filed on September 28, 2015 as Exhibit 10.1 to Williams Companies, Inc.’s Current Report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.40 | — | Second Amended and Restated Credit Agreement dated as of February 2, 2015, between The Williams Companies, Inc., the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on February 3, 2015 as Exhibit 10.1 to The Williams Companies, Inc.’s current report on Form 8-K (File 001-04174) and incorporated herein by reference). |
| | |
10.41 | — | Credit Agreement dated as of August 26, 2015, by and among Williams Partners L.P., the lenders named therein, and Barclays Bank PLC as Administrative Agent (filed on August 28, 2015 as Exhibit 10.1 to Williams Partners L.P.’s Current Report on Form 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
10.42 | — | Credit Agreement dated as of December 23, 2015, between Williams Partners L.P., the lenders named therein, and Barclays Bank PLC as Administrative Agent (filed on December 23, 2015 as Exhibit 10.2 to Williams Companies, Inc.’s Current Report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
|
| | |
Exhibit
No. | | Description |
| | |
| | |
10.43 | — | Second Amended and Restated Credit Agreement dated as of February 2, 2015, between Williams Partners L.P. (formerly known as Access Midstream Partners, L.P.), Northwest Pipeline LLC, Transcontinental Gas Pipeline Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on February 3, 2015 as Exhibit 10.1 to Williams Partners L.P.’s Current Report on Form 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
10.44 | — | Amendment No. 1 to Second Amended and Restated Credit Agreement dated as of December 18, 2015, between Williams Partners L.P., Northwest Pipeline LLC, Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on December 23, 2015 as Exhibit 10.1 to Williams Companies, Inc.’s Current Report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.45 | — | Form of Amended and Restated Commercial Paper Dealer Agreement, dated as of February 2, 2015, between Williams Partners L.P., as Issuer, and the Dealer party thereto(filed on February 3, 2015 as Exhibit 10.3 to Williams Partners L.P.’s Current Report on Form 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
10.46 | — | Registration Rights Agreement, dated January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC and each of the initial purchasers listed therein (filed on January 22, 2016 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 8-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.47 | — | Common Unit Issuance Agreement, dated January 9, 2017 (filed on January 10, 2017, as Exhibit 2 to Schedule 13D/A (File No. 005-86017) by The Williams Companies, Inc. relating to the common units representing limited partner interests of Williams Partners L.P. and incorporated herein by reference.) |
| | |
10.48 | — | Common Unit Purchase Agreement, dated January 9, 2017 (filed on January 10, 2017, as Exhibit 3 to Schedule 13D/A (File No. 005-86017) by The Williams Companies, Inc. relating to the common units representing limited partner interests of Williams Partners L.P. and incorporated herein by reference.) |
| | |
12* | — | Computation of Ratio of Earnings to Combined Fixed Charges. |
| | |
14 | — | Code of Ethics for Senior Officers (filed on March 15, 2004 as Exhibit 14 to The Williams
Companies, Inc.’s Form 10-K and incorporated herein by reference). |
| | |
21* | — | Subsidiaries of the registrant. |
| | |
23.1* | — | Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP. |
| | |
23.2* | — | Consent of Independent Registered Public Accounting Firm, Deloitte & Touche LLP. |
| | |
24* | — | Power of Attorney. |
| | |
31.1* | — | Certification of the Chief Executive Officer pursuant to Rules 13a-l 4(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(3 l) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | |
31.2* | — | Certification of the Chief Financial Officer pursuant to Rules 13a-14(a) and l 5d-l 4(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | |
|
| | |
Exhibit
No. | | Description |
| | |
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.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 |
Item 16.Form 10-K Summary
Not applicable.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
+ |
| Pursuant to item 601(6)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request. | |
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.
182 |
| | | | |
| 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 | | Vice President, Controller and Chief Accounting Officer | | February 24, 2020 |
| John D. Porter | | (Principal Accounting Officer) | | |
| | | | |
| /s/ STEPHEN W. BERGSTROM | | Chairman of the Board | | February 24, 2020 |
| Stephen W. Bergstrom | | | | |
| | | | |
| /s/ NANCY K. BUESE | | Director | | February 24, 2020 |
| Nancy K. Buese | | | | |
| | | | |
| /s/ STEPHEN I. CHAZEN | | Director | | February 24, 2020 |
| Stephen I. Chazen | | | | |
| | | | |
| /s/ CHARLES I. COGUT | | Director | | February 24, 2020 |
| Charles I. Cogut | | | | |
| | | | |
| /s/ KATHLEEN B. COOPER | | Director | | February 24, 2020 |
| Kathleen B. Cooper | | | | |
| | | | |
| /s/ MICHAEL A. CREEL | | Director | | February 24, 2020 |
| Michael A. Creel | | | | |
| | | | |
| /s/ VICKI L. FULLER | | Director | | February 24, 2020 |
| Vicki L. Fuller | | | | |
| | | | |
| /s/ PETER A. RAGAUSS | | Director | | February 24, 2020 |
| Peter A. Ragauss | | | | |
| | | | |
|
| | | | |
| Signature | | Title | | Date |
| | | | |
| /s/ SCOTT D. SHEFFIELD | | Director | | February 24, 2020 |
| Scott D. Sheffield | | | | |
| | | | |
| /s/ MURRAY D. SMITH | | Director | | February 24, 2020 |
| Murray D. Smith | | | | |
| | | | |
| /s/ WILLIAM H. SPENCE | | Director | | February 24, 2020 |
| William H. Spence | | | | |
