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, 20172018 |
| | OR |
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| | For the transition period from to |
Commission file number 1-4174
The Williams Companies, Inc.
(Exact Name of Registrant as Specified in Its Charter)
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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) |
918-573-2000
(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 | | Name of Each Exchange on Which Registered |
| Common Stock, $1.00 par value | | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No þ
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ 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. ¨þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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Large accelerated filer þ | | 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 $24,993,673,967.$21,489,112,717.
The number of shares outstanding of the registrant’s common stock outstanding at February 19, 201815, 2019 was 827,327,3361,210,981,263.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s Definitive Proxy Statement for the Registrant’s Annual Meeting of Stockholders to be held on May 10, 2018,9, 2019, 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. | | |
| Item 2. | | |
| Item 3. | | |
| Item 4. | | |
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| PART II | |
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| Item 5. | | |
| Item 6. | | |
| Item 7. | | |
| Item 7A. | | |
| Item 8. | | |
| Item 9. | | |
| Item 9A. | | |
| Item 9B. | | |
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| PART III | |
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| Item 10. | | |
| Item 11. | | |
| Item 12. | | |
| Item 13. | | |
| Item 14. | | |
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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:
Cardinal: Cardinal Gas Services, L.L.C.
Constitution: Constitution Pipeline Company, LLC
Gulfstar One: Gulfstar One LLC
Jackalope: Jackalope Gas Gathering Services, L.L.C.
Northwest Pipeline: Northwest Pipeline LLC
Transco: Transcontinental Gas Pipe Line Company, LLC
WPZ: Williams Partners L.P. 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, 2017,2018, we account for as an equity-method investment, including principally the following:
Aux Sable: Aux Sable Liquid Products LP
Brazos Permian II: Brazos Permian II, LLC
Caiman II: Caiman Energy II, LLC
Discovery: Discovery Producer Services LLC
Gulfstream: Gulfstream Natural Gas System, L.L.C.
Jackalope: Jackalope Gas Gathering Services, L.L.C.
Laurel Mountain: Laurel Mountain Midstream, LLC
OPPL: Overland Pass Pipeline Company LLC
RMM: Rocky Mountain Midstream Holdings LLC
UEOM: Utica East Ohio Midstream LLC
Government and Regulatory:
EPA: Environmental Protection Agency
Exchange Act, the: Securities and Exchange Act of 1934, as amended
FERC: Federal Energy Regulatory Commission
GAAP: Generally accepted accounting principles
IRS: Internal Revenue Service
SEC: Securities and Exchange Commission
Other:
ACMP: Access Midstream Partners, L.P. prior to its 2015 merger with Pre-Merger WPZ
Energy Transfer: Energy Transfer Equity, L.P.
ETC: Energy Transfer Corp LP
ETC Merger: Merger wherein Williams would have been merged into ETC
ETE Merger Agreement: Merger Agreement and Plan of Merger of Williams with Energy Transfer Equity, L.P. and certain of its affiliates
Fractionation: The process by which a mixed stream of natural gas liquids is separated into its constituent products,
such as ethane, propane, and butane
Geismar Incident: An explosion and fire which occurred on June 13, 2013, at our formerly owned Geismar olefins plant and rendered the facility temporarily inoperable.
IDR: Incentive distribution right
LNG: Liquefied natural gas; natural gas which has been liquefied at cryogenic temperatures
Merger Agreement: Merger Agreement and Plan of Merger of Williams with Energy Transfer and certain of its
affiliates
MVC: Minimum volume commitment
NGLs: Natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are
used as petrochemical feedstocks, heating fuels, and gasoline additives, among other applications
NGL margins: NGL revenues less Btu replacement cost, plant fuel, transportation, and fractionation
Pre-merger WPZ: Williams Partners L.P. prior to its merger with ACMP
PDH facility: Propane dehydrogenation facility
RGP Splitter: Refinery grade propylene splitter
Throughput: The volume of product transported or passing through a pipeline, plant, terminal, or other facility
WPZ Merger: The August 10, 2018, merger transactions pursuant to which we acquired all outstanding common units of WPZ held by others, merged WPZ into Williams, and Williams continued as the surviving entity.
The statements in this Annual Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements. Forward-looking statements may be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “guidance,” “outlook,” “in-service date,” or other similar expressions and other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that such expectations or assumptions will be achieved. Additional information regarding forward-looking statements and important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Part I, Item 1A in this Annual Report.
PART I
Item 1. Business
In this report, Williams (which includes The Williams Companies, Inc. and, unless the context otherwise indicates, all of our subsidiaries) is at times referred to in the first person as “we,” “us” or “our.” We also sometimes refer to Williams as the “Company.”
WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION
We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and other documents electronically with the SEC under the Exchange Act. You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also obtain such reports from the SEC’s Internet website at www.sec.gov.
Our Internet website is http://investor.williams.com/. We make available, free of charge, through the Investors tab of our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our Corporate Governance Guidelines, information regarding corporate social responsibility, Code of Ethics for Senior Officers, Board committee charters, and the Williams Code of Business Conduct are also available on our Internet website. We will also provide, free of charge, a copy of any of our corporate documents listed above upon written request to our Corporate Secretary, One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.
GENERAL
We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to markets for natural gas and NGLs. Our operations are located principally in the United States.
As of December 31, 2017, our interstate gas pipelines and midstream interests were largely held through our significant investment in WPZ. We own the general partner interest and a 74 percent limited partner interest in WPZ.
We were founded in 1908, originally incorporated under the laws of the state of Nevada in 1949 and reincorporated under the laws of the state of Delaware in 1987. Williams’ headquarters are located in Tulsa, Oklahoma, with other major offices in Salt Lake City, Utah; Houston, Texas; and Pittsburgh, Pennsylvania; and the Four Corners Area.Pennsylvania. Our telephone number is 918-573-2000.
FINANCIAL INFORMATION ABOUT SEGMENTSOn August 10, 2018, we completed our merger with Williams Partners L.P. (WPZ), our previously consolidated master limited partnership, pursuant to which we acquired all of the approximately 256 million publicly held outstanding common units of WPZ in exchange for 382 million shares of our common stock in a noncash equity transaction.
See Part II, “Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements — Note 18 – Segment Disclosures.”
BUSINESS SEGMENTS
Substantially allPrior to our merger with WPZ, we had one reportable segment, Williams Partners. Beginning in the third-quarter 2018, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are conducted through our subsidiaries. Our activities in 2017 were operated throughnow presented within the following reportingreportable segments: Northeast G&P, Atlantic-Gulf, and West. Prior period segment disclosures have been recast for the new segment presentation. Our reportable segments as presented inare comprised of the accompanying financial statements and management’s discussion and analysis.following businesses:
Williams Partners —Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern Ohio, as well as a 66 percent interest in Cardinal (a consolidated master limited partnership, WPZ,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 includes gas pipeline and midstream businesses. The gas pipeline business includes interstate natural gas pipelines and pipeline joint project investments. The midstream business provides naturalowns equity-method investments with an approximate average 66 percent interest in multiple gas gathering treating, processing and compression services; NGL production, fractionation, storage, marketing and transportation; deepwater production handling and crude oil transportation services; an olefin production business (see Note 2 –
systems in the Marcellus Shale (Appalachia Midstream Investments).
AcquisitionsAtlantic-Gulf is comprised of our interstate natural gas pipeline, Transco, and significant natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated entity), which is a proprietary floating production system, and various petrochemical and feedstock pipelines in the Gulf Coast region, as well as a 50 percent equity-method investment in Gulfstream, a 60 percent equity-method investment in Discovery, and a 41 percent interest in Constitution (a consolidated entity), which is developing a pipeline project (see Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements).
West is comprised of our interstate natural gas pipeline, Northwest Pipeline, and our gathering, processing, and treating operations in Colorado, Wyoming, and the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware, and Permian basins. This segment also includes our NGL and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in OPPL, a 50 percent interest in Jackalope (an equity-method investment following deconsolidation as of June 30, 2018), a 50 percent equity-method investment in RMM, a 15 percent equity-method investment in Brazos Permian II, and our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see Note 6 – Investing Activities of Notes to Consolidated Financial Statements). West also included our former natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado (see Note 3 – Divestitures of Notes to Consolidated Financial Statements), and is comprised .
Other includes our previously owned operations, including an 88.5 percent undivided interest in an olefins production facility in Geismar, Louisiana, which was sold in July 2017 (see Note 3 – Divestituresof several wholly owned Notes to Consolidated Financial Statements),and partially owned subsidiaries and joint project investments.
a refinery grade propylene splitter in the Gulf region, which was sold in June 2017. This reporting segment also included our formerpreviously owned Canadian midstream operations comprised ofassets, which included an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility and the Boreal Pipeline, which were sold inat Redwater, Alberta. In September 2016, (see Note 2 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).
these Canadian operations were sold. Other — comprised of also includes minor business activities that are not operating segments, as well as corporate operations. Other also includes certain domestic olefins pipeline assets as well as certain Canadian assets, which included a liquids extraction plant located near Fort McMurray, Alberta, that began operations in March 2016, and a propane dehydrogenation facility which was under development. In September 2016, the Canadian assets were sold (see Note 2 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).
Detailed discussion of each of our reporting segments follows. For a discussion of our ongoing expansion projects, see Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Williams PartnersNortheast G&P
Gas Pipeline BusinessThis segment includes our natural gas gathering, compression, processing, and NGL fractionation business in the Marcellus and Utica Shale regions in Pennsylvania, West Virginia, New York, and Ohio.
Williams Partners’
The following tables summarize the significant consolidated assets of this segment:
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| | | | | Natural Gas Gathering Assets |
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| | | | | | | Pipeline | | Capacity | | Ownership | | |
| | | | | Location | | Miles | | (Bcf/d) | | Interest | | Supply Basins |
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| | Ohio Valley Midstream | | Ohio, West Virginia, & Pennsylvania | | 216 | | 0.8 | | 100% | | Appalachian |
| | Susquehanna Supply Hub | | Pennsylvania & New York | | 454 | | 3.6 | | 100% | | Appalachian |
| | Cardinal (1) | | Ohio | | 360 | | 0.9 | | 66% | | Appalachian |
| | Flint | | Ohio | | 75 | | 0.5 | | 100% | | Appalachian |
| | Beaver Creek | | Pennsylvania | | 41 | | 0.1 | | 100% | | Appalachian |
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| (1) | Statistics reflect 100 percent of the assets from our 66 percent ownership of Cardinal gathering system. |
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| | | | | Natural Gas Processing Facilities |
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| | | | | | | Inlet | | Production | | | | |
| | | | | | | Capacity | | Capacity | | Ownership | | |
| | | | | Location | | (Bcf/d) | | (Mbbls/d) | | Interest | | Supply Basins |
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| | Fort Beeler | | Marshall County, WV | | 0.5 | | 62 | | 100% | | Appalachian |
| | Oak Grove | | Marshall County, WV | | 0.2 | | 25 | | 100% | | Appalachian |
We also own and operate fractionation facilities at Moundsville, de-ethanization and condensate facilities at our Oak Grove plant, a condensate stabilization facility near our Moundsville fractionator, and an ethane transportation pipeline. Our condensate stabilizers are capable of handling approximately 17 Mbbls/d of field condensate. NGLs are extracted from the natural gas stream in our Oak Grove and Fort Beeler cryogenic processing plants. Our Oak Grove de-ethanizer is capable of handling up to approximately 80 Mbbls/d of mixed NGLs to extract up to approximately 40 Mbbls/d of ethane. Ethane produced at our de-ethanizer is transported to markets via our 50-mile ethane pipeline businesses consist primarilyfrom 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 Transco and Northwest Pipeline. Ourhandling approximately 43 Mbbls/d of mixed NGLs. The resulting products are then transported on truck or rail. Ohio Valley Midstream provides residue natural gas pipeline business also holds intereststake away options for our customers with interconnections to three interstate transmission pipelines.
Northeast G&P Operating Statistics
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| | | 2018 | | 2017 | | 2016 |
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| Volumes: (1) | | | | | | |
| Gathering (Bcf/d) | | 3.63 |
| | 3.31 |
| | 3.21 |
| Plant inlet natural gas volumes (Bcf/d) | | 0.52 |
| | 0.43 |
| | 0.33 |
| NGL production volumes (Mbbls/d) (2) | | 46 |
| | 38 |
| | 32 |
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| (1) | Excludes volumes associated with equity-method investments. |
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| (2) | Annual average Mbbls/d. |
Certain Equity-Method Investments
Laurel Mountain
We own a 69 percent interest in a joint venture, interstate and intrastateLaurel Mountain, that includes a 2,053-mile gathering system that we operate in western Pennsylvania with the capacity to gather 0.6 Bcf/d of natural gas. Laurel Mountain has a long-term, dedicated, volumetric-based fee agreement, with exposure to natural gas pipeline systems includingprices, to gather the anchor customer’s production in the western Pennsylvania area of the Marcellus Shale.
Caiman II
We own a 58 percent interest in Caiman II, which owns a 50 percent equity-method investmentinterest in GulfstreamBlue Racer, a joint project to own, operate, develop and acquire midstream assets in the Utica Shale and certain adjacent areas in the Marcellus Shale. Blue Racer’s assets include 723 miles of gathering pipelines, and the Natrium complex in Marshall County, West Virginia, with a 41cryogenic processing capacity of 400 MMcf/d and fractionation capacity of approximately 134 Mbbls/d. Blue Racer also owns the Berne complex in Monroe County, Ohio, with a cryogenic processing capacity of 400 MMcf/d, and NGL and condensate pipelines connecting Natrium to Berne. Blue Racer provides gathering, processing, and marketing service primarily under percentage of liquids and fixed fee agreements.
Utica East Ohio Midstream
We own a 62 percent interest in Constitution (a consolidated entity),UEOM, which includes infrastructure for the gathering, processing, and fractionation of natural gas and NGLs in the Utica Shale play in eastern Ohio. Our partner operates a natural gas gathering pipeline, inlet compression, two processing plants with a total capacity of 800 MMcf/d, 36 Mbbls/d of condensate stabilization
capacity, a 135 Mbbls/d NGL fractionation facility, approximately 950,000 barrels of NGL storage capacity, and other ancillary assets, including loading and terminal facilities. These assets earn a fixed fee that escalates annually within a specified range.
Appalachia Midstream Investments
Through our Appalachia Midstream Investments, we operate 100 percent of and own an approximate average 66 percent interest in the Bradford Supply Hub gathering system and own an approximate average 68 percent interest in the Marcellus South gathering system, together which consist of approximately 1,028 miles of gathering pipeline in the Marcellus Shale region with the capacity to gather 4,623 MMcf/d of natural gas. The majority of our volumes in the region are gathered from northern Pennsylvania, southwestern Pennsylvania, and the northwestern panhandle of West Virginia in core areas of the Marcellus Shale. We operate the assets under long-term, 100 percent fixed-fee gathering agreements that include significant acreage dedications and, in the Bradford Supply Hub, a cost of service mechanism.
During the first quarter of 2017, we exchanged all of our 50 percent interest in the Delaware basin gas gathering system, previously reported within the West segment, for an increased interest in the Bradford Supply Hub natural gas gathering system that is developing a pipeline project (seepart 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 36 – Variable Interest EntitiesInvesting Activities of Notes to Consolidated Financial Statements). TranscoStatements.)
Aux Sable
We also own a 15 percent interest in Aux Sable and Northwest Pipeline ownits Channahon, Illinois, gas processing and operate a combined totalNGL fractionation facility near Chicago. The facility is capable of approximately 13,600 miles of pipelines with a total annual throughput of approximately 4,533 TBtuprocessing up to 2.1 Bcf/d of natural gas from the Alliance Pipeline system and peak-day delivery capacityfractionating approximately 132 Mbbls/d of approximately 18.8 MMdthextracted liquids into NGL products. Additionally, Aux Sable owns an 80 MMcf/d gas conditioning plant and a 12-inch, 83-mile gas pipeline infrastructure in North Dakota that provides additional NGLs to Channahon from the Bakken Shale in the Williston basin.
Atlantic-Gulf
This segment includes the Transco interstate natural gas pipeline that extends from the Gulf of Mexico to the eastern seaboard, as well as natural gas.gas gathering, processing and treating, crude oil production handling, and NGL fractionation assets within the onshore, offshore shelf, and deepwater areas in and around the Gulf Coast states of Texas, Louisiana, Mississippi, and Alabama. This segment also includes various petrochemical and feedstock pipelines in the Gulf Coast region.
Transco
Transco is an interstate natural gas transmission company that owns and operates a 9,700-mile9,900-mile natural gas pipeline system, which is regulated by the FERC, extending from Texas, Louisiana, Mississippi, and the Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Delaware, Pennsylvania, and New Jersey to the New York City metropolitan area. The system serves customers in Texas and 12 southeast and Atlantic seaboard states, including major metropolitan areas in Georgia, North Carolina, Washington, D.C., Maryland, New York, New Jersey, and Pennsylvania.
Pipeline system and customers
At December 31, 2017,2018, Transco’s system, which extends from Texas to New York, had a system-wide delivery capacity totaling approximately 15.016.7 MMdth of natural gas per day. During 2017,2018, Transco completed fivetwo fully-contracted expansions, which added more than 2.81.75 MMdth of firm transportation capacity per day to the existing pipeline system. Transco’s system includes 5055 compressor stations, four underground storage fields, and anone LNG storage facility. Compression facilities at sea level-rated capacity total approximately 2.12.2 million horsepower.
Transco’s major natural gas transportation customers are public utilities and municipalities that provide service to residential, commercial, industrial and electric generation end users. Shippers on Transco’s system include public utilities, municipalities, intrastate pipelines, direct industrial users, electric power generators, and natural gas marketers and producers. Transco’s firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of Transco’s business. Additionally, Transco offers interruptible transportation services under shorter-term agreements.
Transco has natural gas storage capacity in four underground storage fields located on or near its pipeline system or market areas and operates two of these storage fields. Transco also has storage capacity in an LNG storage facility that it owns and operates. The total usable gas storage capacity available to Transco and its customers in such underground storage fields and LNG storage facility and through storage service contracts is approximately 200 Bcf of natural gas.
At December 31, 2017,2018, Transco’s customers had stored in its facilities approximately 141130
Bcf of natural gas. In addition, wholly owned subsidiaries of Transco operate and hold a 35 percent equity-method investment in Pine Needle LNG Company, LLC, an LNG storage facility with 4 Bcf of storage capacity. Storage capacity permits Transco’s customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter demand periods.
Gas Gathering, Processing, and Treating Assets
The following tables summarize the significant consolidated assets of this segment:
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| | | Natural Gas Gathering Assets |
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| | | | | | | Inlet | | | | |
| | | | | Pipeline | | Capacity | | Ownership | | |
| | | Location | | Miles | | (Bcf/d) | | Interest | | Supply Basins |
| | | | | | | | | | | |
| 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 | | 105 | | 0.5 | | 100% | | Western Gulf of Mexico |
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| | | Natural Gas Processing Facilities |
| | | | | | | | | | | |
| | | | | | | NGL | | | | |
| | | | | Inlet | | Production | | | | |
| | | | | Capacity | | Capacity | | Ownership | | |
| | | Location | | (Bcf/d) | | (Mbbls/d) | | Interest | | Supply Basins |
| | | | | | | | | | | |
| Markham | | Markham, TX | | 0.5 | | 45 | | 100% | | Western Gulf of Mexico |
| Mobile Bay | | Coden, AL | | 0.7 | | 30 | | 100% | | Eastern Gulf of Mexico |
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:
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| | | | | | Crude Oil Pipelines |
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| | | | | | Pipeline | | Capacity | | Ownership | | |
| | | | | | Miles | | (Mbbls/d) | | Interest | | Supply Basins |
| | | | | | | | | | | | |
| 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 |
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| | | | | | | | | | | |
| | | | | Production Handling Platforms |
| | | | | | | | | | | | |
| | | | | | | | Crude/NGL | | | | |
| | | | | | Gas Inlet | | Handling | | | | |
| | | | | | Capacity | | Capacity | | Ownership | | |
| | | | | | (MMcf/d) | | (Mbbls/d) | | Interest | | Supply Basins |
| | | | | | | | | | | |
| Devils Tower | | 210 | | 60 | | 100% | | Eastern Gulf of Mexico |
| Gulfstar I FPS (1) | | 172 | | 80 | | 51% | | Eastern Gulf of Mexico |
__________
| |
| (1) | Statistics reflect 100 percent of the assets from our 51 percent interest in Gulfstar One. |
Other NGL & Petchem Operations
We own 283 miles of pipeline systems in Louisiana and Texas that provide feedstock transportation from fractionation and storage facilities to various third-party crackers. These systems include the Bayou ethane pipeline, which provides ethane transportation from Mont Belvieu, Texas; certain ethane and propane systems in Louisiana; and a pipeline that has the capacity to transport 12 Mbbls/d of ethane from Discovery’s Paradis fractionator.
We previously owned pipelines in the Houston Ship Channel area which were used to transport a variety of products including ethane, propane, ammonia, tertiary butyl alcohol, and other industrial products. These assets were sold in November 2018.
Atlantic-Gulf Operating Statistics |
| | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| | | | | | |
Volumes: (1) | | | | | |
| Interstate natural gas pipeline throughput (Tbtu) | 4,309 |
| | 3,783 |
| | 3,503 |
|
| Gathering (Bcf/d) | 0.26 |
| | 0.31 |
| | 0.41 |
|
| Plant inlet natural gas (Bcf/d) | 0.50 |
| | 0.55 |
| | 0.72 |
|
| NGL production (Mbbls/d) (2) | 32 |
| | 33 |
| | 41 |
|
| NGL equity sales (Mbbls/d) (2) | 6 |
| | 9 |
| | 13 |
|
| Crude oil transportation (Mbbls/d) (2) | 140 |
| | 134 |
| | 113 |
|
_____________
| |
| (1) | Excludes volumes associated with equity-method investments. |
| |
| (2) | Annual average Mbbls/d. |
Certain Equity-Method Investments
Discovery
We own a 60 percent interest in and operate the facilities of Discovery. Discovery’s assets include a 600 MMcf/d cryogenic natural gas processing plant near Larose, Louisiana, a 32 Mbbls/d NGL fractionator plant near Paradis, Louisiana, and a 594-mile offshore natural gas gathering and transportation system in the Gulf of Mexico. Discovery’s mainline has a gathering inlet capacity of 600 MMcf/d, while the Keathley Canyon Connector, a deepwater lateral pipeline in the central deepwater Gulf of Mexico has a gathering inlet capacity of 400 MMcf/d. Discovery’s assets also include a crude oil production handling platform with a crude oil/NGL handling capacity of 10 Mbbls/d and natural gas processing capacity of 75 MMcf/d.
Gulfstream
Gulfstream is a 745-mile interstate natural gas pipeline system extending from the Mobile Bay area in Alabama to markets in Florida, which has a capacity to transport 1.3 Bcf/d. We own, through a subsidiary, a 50 percent equity-method investment in Gulfstream. We share operating responsibilities for Gulfstream with the other 50 percent owner.
West
This segment includes the Northwest Pipeline interstate natural gas pipeline, as well as natural gas gathering, processing, and treating assets in Colorado, Wyoming, Louisiana, Texas, Arkansas, and Oklahoma. This segment also includes an NGL and natural gas marketing business, storage facilities, and an undivided 50 percent interest in an NGL fractionator near Conway, Kansas.
Northwest Pipeline
Northwest Pipeline is an interstate natural gas transmission company that owns and operates a natural gas pipeline system, which is regulated by the FERC, extending from the San Juan basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon, and Washington to a point on the Canadian border near Sumas, Washington. Northwest Pipeline provides services for markets in Washington, Oregon, Idaho, Wyoming, Nevada, Utah, Colorado, New Mexico, California, and Arizona, either directly or indirectly through interconnections with other pipelines.
Pipeline system and customers
At December 31, 2017,2018, 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, municipal utilities, direct industrial users, electric power generators, and natural gas marketers and producers. Northwest Pipeline’s firm transportation and storage contracts are generally long-term contracts with various expiration dates and account for the major portion of Northwest Pipeline’s business. Additionally, Northwest Pipeline offers interruptible and short-term firm transportation service.
Northwest Pipeline owns a one-third interest in the Jackson Prairie underground storage facility in Washington and contracts with a third party for natural gas storage services in the Clay Basinbasin underground field in Utah. Northwest Pipeline also owns and operates an LNG storage facility in Washington. These storage facilities have an aggregate working natural gas storage capacity of 14.2 MMdth of natural gas, which is substantially utilized for third-party natural gas. These natural gas storage facilities enable Northwest Pipeline to balance daily receipts and deliveries and provide storage services to customers.
GulfstreamGas Gathering, Processing, and Treating Assets
Gulfstream is a 745-mile interstate natural gas pipeline system extending fromThe following tables summarize the Mobile Bay area in Alabama to markets in Florida, which has a capacity to transport 1.3 Bcf/d. Williams Partners owns, through a subsidiary, a 50 percent equity-method investment in Gulfstream. Williams Partners shares operating responsibilities for Gulfstream with the other 50 percent owner.significant consolidated assets of this segment:
Williams Partners’ midstream business, one of the nation’s largest natural gas gatherers and processors, has primary service areas concentrated in major producing basins in Arkansas, Colorado, New Mexico, Oklahoma, Texas, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio. The primary businesses are: (1) natural gas gathering, treating, and processing; (2) NGL fractionation, storage and transportation; (3) crude oil transportation; and (4) olefins production (see Note 2 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements). These fall within the middle of the process of taking raw natural gas and crude oil from the producing fields to the consumer. |
| | | | | | | | | | | |
| | | | Natural Gas Gathering Assets |
| | | | | | | | | | | | |
| | | | Location | | Pipeline Miles | | Inlet Capacity (Bcf/d) | | Ownership Interest | | Supply Basins/Shale Formations |
| | | | | | | | | | | | |
| Wamsutter | | Wyoming | | 2,084 | | 0.7 | | 100% | | Wamsutter |
| Southwest Wyoming | | Wyoming | | 1,614 | | 0.5 | | 100% | | Southwest Wyoming |
| Piceance | | Colorado | | 352 | | 1.8 | | (1) | | 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 |
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;
| |
| (1) | Includes our 60 percent ownership of a gathering system in the Ryan Gulch area with 140 miles of pipeline and 0.2 Bcf/d of inlet capacity, and our 67 percent ownership of a gathering system at Allen Point with 8 miles of pipeline and 0.1 Bcf/d of inlet capacity. We operate both systems. We own and operate 100 percent of the balance of the Piceance gathering assets. |
|
| | | | | | | | | | | |
| | | | Natural Gas Processing Facilities |
| | | | | | | | | | | | |
| | | | | | | | NGL | | | | |
| | | | | | Inlet | | Production | | | | |
| | | | | | Capacity | | Capacity | | Ownership | | |
| | | | Location | | (Bcf/d) | | (Mbbls/d) | | Interest | | Supply Basins |
| | | | | | | | | | | | |
| Echo Springs | | Echo Springs, WY | | 0.7 | | 58 | | 100% | | Wamsutter |
| Opal | | Opal, WY | | 1.1 | | 47 | | 100% | | Southwest Wyoming |
| Willow Creek | | Rio Blanco County, CO | | 0.5 | | 30 | | 100% | | Piceance |
| Parachute | | Garfield County, CO | | 1.1 | | 6 | | 100% | | Piceance |
Marketing Services
We market NGL products to a wide range of users in the energy and attractingpetrochemical 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 continuingDiscovery. The NGL marketing business bears the risk of price changes in these NGL volumes while they are being transported to final sales delivery points. In order to meet sales contract obligations, we may purchase products in the spot market for resale.
In certain situations to facilitate our gas gathering and processing activities, we buy natural gas from our producer customers for resale.
Other NGL Operations
We own interests in and/or operate NGL fractionation and storage assets in central Kansas near Conway. These assets include a 50 percent interest in an NGL fractionation facility with capacity of slightly more than 100 Mbbls/d and we own approximately 20 million barrels of NGL storage capacity.
West Operating Statistics
|
| | | | | | | | | |
| | | 2018 | | 2017 | | 2016 |
| | | | | | | |
| Volumes: | | | | | | |
| Interstate natural gas pipeline throughput (Tbtu) | | 820 |
| | 750 |
| | 727 |
|
| Gathering (Bcf/d) | | 4.27 |
| | 4.53 |
| | 4.62 |
|
| Plant inlet natural gas (Bcf/d) | | 2.01 |
| | 2.07 |
| | 2.45 |
|
| NGL production (Mbbls/d) (1) | | 84 |
| | 77 |
| | 78 |
|
| NGL equity sales (Mbbls/d) (1) | | 33 |
| | 29 |
| | 28 |
|
__________
| |
| (1) | Annual average Mbbls/d. |
Certain Equity-Method Investments
Jackalope gathering system
We operate and own a 50 percent interest in Jackalope which provides gas gathering and processing services for the Powder River basin. During the second quarter of 2018, we deconsolidated Jackalope (see Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements). Jackalope, which includes the Bucking Horse gas processing plant, consists of a 257-mile natural gas pipeline, 0.2 Bcf/d of gas gathering inlet capacity, 0.1 Bcf/d of natural gas processing inlet capacity, and 12 Mbbls/d of NGL production capacity.
Brazos Permian II
We acquired a non-operated 15 percent interest in Brazos Permian II in December 2018 by contributing cash and our existing Delaware basin assets. This partnership consists of 725 miles of gas gathering pipelines, 260 MMcf/d of natural gas processing inlet capacity, and 75 miles of crude oil gathering pipelines.
Rocky Mountain Midstream
During the third quarter of 2018, our joint venture, RMM, purchased a natural gas and oil gathering and natural gas processing business in Colorado’s Denver-Julesburg basin. As of December 31, 2018, we own 50 percent of RMM. RMM consists of 60 MMcf/d of gas processing capacity, an approximate 105-mile natural gas gathering system, and an approximate 70-mile oil gathering system. There are two additional processing plants currently under construction that are expected to increase natural gas processing capacity to 480 MMcf/d by the end of 2019.
Delaware basin gas gathering system
We previously owned a non-operated 50 percent interest in the Delaware basin gas gathering system in the Permian basin, which was sold in February 2017. The system was comprised of more than 450milesof gathering pipeline, located in west Texas.
Overland Pass Pipeline
We also operate and own a 50 percent interest in OPPL. OPPL is capable of transporting 255 Mbbls/d and includes approximately 1,035 miles of NGL pipeline extending from Opal, Wyoming, to the Mid-Continent NGL market center near Conway, Kansas, along with extensions into the Piceance and Denver-Julesberg basins in Colorado and the Bakken Shale in the Williston basin in North Dakota. Our equity NGL volumes from two of our three Wyoming plants and our Willow Creek facility in Colorado are dedicated for transport on OPPL under a long-term transportation agreement. NGL volumes from our RMM equity-method investment are also expected to be transported on OPPL.
Other
Other includes our previously owned operations, minor business activities that are not operating segments, as well as corporate operations.
Geismar Interest
In July 2017, we completed the sale of Williams Olefins, L.L.C, a wholly owned subsidiary which owned our 88.5 percent undivided interest in the Geismar, Louisiana, olefins plant (Geismar Interest). Upon closing the sale, we entered into a long-term supply and transportation agreement with the purchaser to provide reliable services;feedstock to the plant via our Bayou Ethane pipeline system.
Revenue growthCanadian Operations
We completed the sale of our Canadian operations in September 2016. This business included an oil sands offgas processing plant located near Fort McMurray, Alberta, and an NGL/olefin fractionation facility located at Redwater, Alberta, which is near Edmonton, Alberta, and the Boreal Pipeline which transported NGLs and associated olefins from the Fort McMurray plant to the Redwater fractionation facility. This business allowed us to extract, fractionate, treat, store, terminal, and sell the ethane/ethylene, propane, propylene, normal butane, iso-butane, alky feedstock, and condensate recovered from a third-party oil sands bitumen upgrader.
Service Assets, Customers, and Contracts
Interstate Natural Gas Pipeline Assets
Our interstate natural gas pipelines are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce are subject to regulation. The rates are established through the FERC’s ratemaking process.
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 additional infrastructure either completed or currentlyvarious expiration dates and account for the major portion of our regulated businesses. Additionally, we offer storage services and interruptible transportation services under construction;shorter-term agreements.
Disciplined growthOn August 31, 2018, Transco filed a general rate case with the FERC for an overall increase in service areas.rates. In September 2018, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general rate filing to be effective March 1, 2019, subject to refund and the outcome of a hearing. The specific rates that reflected a rate decrease were accepted, without suspension, to be effective October 1, 2018, as requested by Transco, and will not be subject to refund.
Gathering, Processing and Treating Assets
Williams Partners’Our gathering systems receive natural gas from producers’ oil and natural gas wells and gather these volumes to gas processing, treating or redelivery facilities. Typically, natural gas, in its raw form, is not acceptable for transportation in major interstate natural gas pipelines or for commercial use as a fuel. Williams Partners’Our treating facilities remove water vapor, carbon dioxide and other contaminants and collect condensate, but do not extract NGLs. Williams Partners’ isWe are generally paid a fee based on the volume ofnatural gas gathered and/or treated, generally measured in the Btu heating value.
In addition, natural gas contains various amounts of NGLs, which generally have a higher value when separated from the natural gas stream. Our processing plants extract the NGLs in addition to removing water vapor, carbon dioxide, and other contaminants. NGL products include:
Ethane, primarily used in the petrochemical industry as a feedstock for ethylene production, one of the basic building blocks for plastics;
Propane, used for heating, fuel and as a petrochemical feedstock in the production of ethylene and propylene, another building block for petrochemical-based products such as carpets, packing materials, and molded plastic parts;
Normal butane, isobutane, and natural gasoline, primarily used by the refining industry as blending stocks for motor gasoline or as a petrochemical feedstock.
Our gas processing services generate revenues primarily from the following types of contracts:
Fee-based: We are paid a fee based on the volume of natural gas processed, generally measured in the Btu heating value. Our customers are entitled to the NGLs produced in connection with this type of processing agreement. A portion of our fee-based processing revenuesrevenue includes a share of the margins on the NGLs produced. For the year ended December 31, 2017, 702018, 74 percent of our NGL production volumes were under fee-based contracts.
Noncash commodity-based: We also process gas under two types of commodity-based contracts, keep-whole and percent-of-liquids, where we receive consideration for our services in the form of NGLs. Under these contracts, we retain some or all of the extracted NGLs as compensation for our services. For a keep-whole arrangement we replace the Btu content of the retained NGLs that were extracted during processing with natural gas purchases, also known as shrink replacement gas. For a percent-of-liquids arrangement, we deliver to customers an agreed-upon percentage of the extracted NGLs and retain the remainder. NGLs we retain in connection with these types of processing agreements are referred to as our equity NGL production. Under keep-whole agreements, we have commodity price exposure on the difference between NGL and natural gas prices. For the year ended December 31, 2017, 302018, 26 percent of our NGL production volumes were under noncash commodity-based contracts.
Our gathering and processing agreements have terms ranging from month-to-month to the life of the producing lease. Generally, our gathering and processing agreements are long-term agreements. Some contracts have price escalators which annually increase our gathering rates. In addition, certain contracts include fee redetermination or cost of service mechanisms that are designed to support a return on invested capital and allow our gathering rates to be adjusted, subject to specified caps in certain cases, to account for variability in volume, capital expenditures, commodity price fluctuations, compression and other expenses. Certain of our gas gathering agreements include MVCs. If the minimum annual or semi-annual volume commitmenta customer under such an agreement fails to meet its MVC for a specified period, it is not met, these customers are obligated to pay a contractually determined fee equal to
based upon the applicable fee for each Mcf by which the applicable customer’s minimum annual or semi-annual volume commitment exceedsshortfall between the actual volume gathered. The revenue associated with such shortfall fees is generally recognizedgathered or processed volumes and the MVC for the period contained in the fourth quartercontract. When we conclude it is probable that the customer will not exercise all or a portion of each year.its remaining rights, we recognize revenue in an amount in proportion to the pattern of exercised rights within the respective MVC period.
Demand for gas gathering and processing services is dependent on producers’ drilling activities, which is impacted by the strength of the economy, natural gas prices, and the resulting demand for natural gas by manufacturing and industrial companies and consumers. Williams Partners’Our gas gathering and processing customers are generally natural gas producers who have proved and/or producing natural gas fields in the areas surrounding itsour infrastructure. During 2017, Williams Partners’2018, our facilities gathered and processed gas and crude oil for approximately 260 customers. Williams Partners’Our top ten customers accounted for approximately 7570 percent of our gathering and processing fee revenues and NGL margins from our noncash commodity-based agreements.
Demand for our equity NGLs is affected by economic conditions and the resulting demand from industries using these commodities to produce petrochemical-based products such as plastics, carpets, packing materials, and blending stocks for motor gasoline and the demand from consumers using these commodities for heating and fuel. NGL products are currently the preferred feedstock for ethylene and propylene production, which has shifted away from the more expensive crude-based feedstocks.
Geographically, the midstream
Key variables for our business will continue to be:
Producer drilling activities impacting natural gas assets are positioned to maximize commercial and operational synergies withsupplies supporting our other assets. For example, most of the offshore gathering and processing assets attachvolumes;
Prices impacting our commodity-based activities;
Retaining and processattracting customers by continuing to provide reliable services;
Revenue growth associated with additional infrastructure either completed 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.currently under construction;
The following table summarizes our significant consolidated natural gas gathering assets:
|
| | | | | | | | | |
| | Natural Gas Gathering Assets |
| | Location | | Pipeline Miles | | Inlet Capacity (Bcf/d) | | Ownership Interest | | Supply Basins/Shale Formations |
| Northeast | | | | | | | | | |
| Ohio Valley Midstream | Ohio, West Virginia, & Pennsylvania | | 216 | | 0.8 | | 100% | | Appalachian |
| Susquehanna Supply Hub | Pennsylvania & New York | | 436 | | 3.2 | | 100% | | Appalachian |
| Cardinal (1) | Ohio | | 353 | | 1.0 | | 66% | | Appalachian |
| Flint | Ohio | | 75 | | 0.4 | | 100% | | Appalachian |
| Marcellus South (2) | 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 | | 105 | | 0.5 | | 100% | | Western Gulf of Mexico |
| West | | | | | | | | | |
| Four Corners | Colorado & New Mexico | | 3,742 | | 1.8 | | 100% | | San Juan |
| Wamsutter | Wyoming | | 2,084 | | 0.7 | | 100% | | Wamsutter |
| Southwest Wyoming | Wyoming | | 1,614 | | 0.5 | | 100% | | Southwest Wyoming |
| Piceance | Colorado | | 352 | | 1.8 | | (3) | | Piceance |
| Niobrara | Wyoming | | 224 | | 0.2 | | (4) | | Powder River |
| Barnett Shale | Texas | | 858 | | 0.8 | | 100% | | Barnett Shale |
| Eagle Ford Shale | Texas | | 1,225 | | 0.6 | | 100% | | Eagle Ford Shale |
| Haynesville Shale | Louisiana | | 626 | | 1.8 | | 100% | | Haynesville Shale |
| Permian | Texas | | 365 | | 0.1 | | 100% | | Permian |
| Mid-Continent | Oklahoma, Texas, & Kansas | | 2,248 | | 0.9 | | 100% | | Miss-Lime, Granite Wash, Colony Wash, Arkoma |
__________
| |
(1) | Statistics reflect 100 percent of the assets from our 66 percent ownership of Cardinal gathering system. |
| |
(2) | Statistics reflect 100 percent of the Beaver Creek assets in the consolidated Marcellus South gathering system. |
| |
(3) | Includes our 60 percent ownership of a gathering system in the Ryan Gulch area with 140 miles of pipeline and 0.2 Bcf/d of inlet capacity, and our 67 percent ownership of a gathering system at Allen Point with 8 miles of pipeline and 0.1 Bcf/d of inlet capacity. We operate both systems. We own and operate 100 percent of the balance of the Piceance gathering assets. |
| |
(4) | Statistics reflect 100 percent of the assets from our 50 percent ownership of the Jackalope gathering system. |
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 |
__________
| |
(1) | Statistics reflect 100 percent of the assets from our 50 percent ownership of Bucking Horse gas processing facility. |
In addition, we own and operate several natural gas treating facilities in New Mexico, Colorado, Texas, and Louisiana which bring natural gas to specifications allowable by major interstate pipelines.
We also own and operate fractionation facilities at Moundsville, de-ethanization and condensate facilities at our Oak Grove processing plant, a condensate stabilization facility near our Oak Grove plant, and an ethane transportation pipeline. Our three condensate stabilizers are capable of handling 17 Mbbls/d of field condensate. NGLs are extracted from the natural gas streamDisciplined growth in our cryogenic processing plants. Our Oak Grove de-ethanizer is capable of handling up to approximately 80 Mbbls/d of mixed NGLs to extract up to approximately 40 Mbbls/d of ethane. The remaining mixed NGL stream from the de-ethanizer is then transported and fractionated at our Moundsville facilities, which are capable of handling more than 43 Mbbls/d of mixed NGLs. Ethane produced at our de-ethanizer is transported to markets via our 50-mile ethane pipeline from Oak Grove to Houston, Pennsylvania.
Our gathering business in the Northeast also provides multiple takeaway options to its customers. Ohio Valley Midstream makes customer deliveries with interconnections to two pipelines. Susquehanna Supply Hub makes deliveries for its customers with interconnections to Transco, as well as five other pipelines, while our Cardinal system utilizes interconnections with Blue Racer Midstream, LLC (Blue Racer), and UEOM. In addition, our NGL processing business utilizes connections with multiple pipelines, as well as truck and rail transportation to local and regional markets.service areas.
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,Crude oil marketing activity is now presented on a portionnet basis within Product costs in the Consolidated Statement of our marketing revenues are recognized from purchaseOperations in 2018 in conjunction with the adoption of ASC 606. (See Note 1 – General, Description of Business, Basis of Presentation, and sale arrangements whereby the oil that we transport is purchased and sold as a functionSummary of the same index-based price. Our offshore floating production platforms provide centralized servicesSignificant Accounting Policies of Notes to deepwater producers such as compression, separation, production handling, water removal, and pipeline landings.Consolidated Financial Statements.) Revenue sources have historically included a combination of fixed-fee, volumetric-based fee, and cost reimbursement arrangements. Fixed fees associated with the resident production at our Devils Tower facility are recognized on a units-of-production basis. Fixed fees associated with the resident production at our Gulfstar One facility are recognized as the guaranteed capacity is made available.
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 | 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 |
| | 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.
Operating statistics
The following table summarizes our significant operating statistics:
|
| | | | | |
| | 2016 | | 2015 |
| Volumes: | | | |
| Canadian propylene sales (millions of pounds) | 87 |
| | 161 |
|
| Canadian NGL sales (millions of gallons) | 141 |
| | 284 |
|
Gulf Olefins
In mid-2017, Williams Partners completed the sale of its 88.5 percent undivided interest and operatorship of an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter in the Gulf region. The olefins business also operated an ethylene storage hub at Mont Belvieu using leased third-party underground storage caverns.
Our refinery grade propylene splitter had production capacity of approximately 500 million pounds per year of propylene. At the propylene splitter, we purchased refinery grade propylene and fractionated it into polymer grade propylene and propane; as a result, the asset was exposed to the price spread between those commodities.
Marketing Services
We market NGL products to a wide range of users in the energy and petrochemical industries. The NGL marketing business transports and markets our equity NGLs from the production at our processing plants, and also markets NGLs on behalf of third-party NGL producers, including some of our fee-based processing customers, and the NGL volumes
owned by Discovery. The NGL marketing business bears the risk of price changes in these NGL volumes while they are being transported to final sales delivery points. In order to meet sales contract obligations, we may purchase products in the spot market for resale. Other than a long-term agreement to sell our equity NGLs transported on OPPL, the majority of sales are based on supply contracts of one year or less in duration.
In certain situations to facilitate our gas gathering and processing activities, we buy natural gas from our producer customers for resale.
Prior to the sale of our olefin operations, we marketed olefin products to a wide range of users in the energy and petrochemical industries.
Other NGL & Petchem Operations
We own interests in and/or operate NGL fractionation and storage assets in central Kansas near Conway. These assets include a 50 percent interest in an NGL fractionation facility with capacity of slightly more than 100 Mbbls/d and we own approximately 20 million barrels of NGL storage capacity.
We own 283 miles of pipeline systems in Louisiana and Texas that provide feedstock transportation from fractionation and storage facilities to various third-party crackers. These systems include the Bayou ethane pipeline, which provides ethane transportation from Mont Belvieu, Texas; certain ethane and propane systems in Louisiana; and a pipeline that has the capacity to transport 12 Mbbls/d of ethane from Discovery’s Paradis fractionator.
We own 114 miles of pipelines in the Houston Ship Channel area which transport a variety of products including ethane, propane, ammonia, tertiary butyl alcohol, and other industrial products used in the petrochemical industry. We also own a tunnel crossing pipeline under the Houston Ship Channel. A portion of these pipelines are leased to third parties.
WPZ Operating Areas
WPZ organizes these businesses into the following operating areas:
Northeast G&P is comprised of natural gas gathering and processing, compression, and NGL fractionation businesses in the Marcellus and Utica Shale regions in Pennsylvania, West Virginia, New York, and Ohio, as well as a 66 percent interest in Cardinal (a consolidated entity), a 62 percent equity-method investment in UEOM, a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, and Appalachia Midstream Services, LLC, which owns an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale.
Atlantic-Gulf is comprised of an interstate natural gas pipeline, Transco, and significant natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated entity) which is a proprietary floating production system, and various petrochemical and feedstock pipelines in the Gulf Coast region, as well as a 50 percent equity-method investment in Gulfstream, a 41 percent interest in Constitution (a consolidated entity) which is developing a pipeline project (see Note 3 – Variable Interest Entities of Notes to Consolidated Financial Statements), and a 60 percent equity-method investment in Discovery.
West is comprised of an interstate natural gas pipeline, Northwest Pipeline, and natural gas gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming, as well as the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware, and Permian basins. West also includes an NGL and natural gas marketing business, storage facilities, and an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, as well as our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system in the Permian basin, and a 50 percent equity-method investment in OPPL.
NGL & Petchem Services is comprised of previously owned operations, including an 88.5 percent undivided interest in an olefins production facility in Geismar, Louisiana, which was sold in July 2017 (see Note 2 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements), and a refinery grade propylene splitter in the Gulf
region, which was sold in June 2017. This operating area also included an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility, which were sold in September 2016.
Certain Equity-Method Investments
Discovery
We own a 60 percent interest in and operate the facilities of Discovery. Discovery’s assets include a 600 MMcf/d cryogenic natural gas processing plant near Larose, Louisiana, a 32 Mbbls/d NGL fractionator plant near Paradis, Louisiana, and a 614-mile offshore natural gas gathering and transportation system in the Gulf of Mexico. Discovery’s mainline has a gathering inlet capacity of 600 MMcf/d, while the Keathley Canyon Connector, a deepwater lateral pipeline in the central deepwater Gulf of Mexico has a gathering inlet capacity of 400 MMcf/d. Discovery’s assets also include a crude oil production handling platform with a crude oil/NGL handling capacity of 10 Mbbls/d and natural gas processing capacity of 75 MMcf/d.
Laurel Mountain
We own a 69 percent interest in a joint venture, Laurel Mountain, that includes a 2,053-mile gathering system that we operate in western Pennsylvania with the capacity to gather 0.7 Bcf/d of natural gas. Laurel Mountain has a long-term, dedicated, volumetric-based fee agreement, with exposure to natural gas prices, to gather the anchor customer’s production in the western Pennsylvania area of the Marcellus Shale.
Caiman II
We own a 58 percent interest in Caiman II, which owns a 50 percent interest in Blue Racer, a joint project to own, operate, develop and acquire midstream assets in the Utica Shale and certain adjacent areas in the Marcellus Shale. Blue Racer’s assets include 721 miles of gathering pipelines, and the Natrium complex in Marshall County, West Virginia, with a cryogenic processing capacity of 400 MMcf/d and fractionation capacity of approximately 120,000 Bbls/d. Blue Racer also owns the Berne complex in Monroe County, Ohio, with a cryogenic processing capacity of 400 MMcf/d, and NGL and condensate pipelines connecting Natrium to Berne.
Utica East Ohio Midstream
We own a 62 percent interest in UEOM, which includes infrastructure for the gathering, processing, and fractionation of natural gas and NGLs in the Utica Shale play in eastern Ohio. We operate a natural gas gathering pipeline, while our partner operates inlet compression, two processing plants with a total capacity of 800 MMcf/d, 41 Mbbls/d of condensate stabilization capacity, a 135 Mbbls/d NGL fractionation facility, approximately 950,000 barrels of NGL storage capacity and other ancillary assets, including loading and terminal facilities. These assets earn a fixed fee that escalates annually within a specified range.
Appalachia Midstream Investments
Through our Appalachia Midstream Investments, we operate 100 percent of and own an approximate average 66 percent interest in the Bradford Supply Hub gathering system and own an approximate average 68 percent interest in the Marcellus South gathering system, together which consist of approximately 987 miles of gathering pipeline in the Marcellus Shale region. The majority of our volumes in the region are gathered from northern Pennsylvania, southwestern Pennsylvania and the northwestern panhandle of West Virginia in core areas of the Marcellus Shale. Appalachia Midstream Investments operates the assets under long-term, 100 percent fixed-fee gathering agreements that include significant acreage dedications and cost of service mechanisms.
During the first quarter of 2017, we exchanged all of our 50 percent interest in the Delaware basin gas gathering system for an increased interest in the Bradford Supply Hub natural gas gathering system that is part of the Appalachia Midstream Investments and $155 million in cash. Following this exchange, we have an approximate average 66 percent interest in the Appalachia Midstream Investments. We continue to account for this investment under the equity-method due to the significant participatory rights of our partners such that we do not exercise control. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.)
Aux Sable
We also own a 15 percent interest in Aux Sable and its Channahon, Illinois, gas processing and NGL fractionation facility near Chicago. The facility is capable of processing up to 2.1 Bcf/d of natural gas from the Alliance Pipeline system and fractionating approximately 132 Mbbls/d of extracted liquids into NGL products. Additionally, Aux Sable owns an 80 MMcf/d gas conditioning plant and a 12-inch, 83-mile gas pipeline infrastructure in North Dakota that provides additional NGLs to Channahon from the Bakken Shale in the Williston basin.
Delaware basin gas gathering system
We previously owned a non-operated 50 percent interest in the Delaware basin gas gathering system in the Permian basin, which was sold in February 2017. The system was comprised of more than 450milesof gathering pipeline, located in west Texas.
Overland Pass Pipeline
We also operate and own a 50 percent interest in OPPL. OPPL is capable of transporting 255 Mbbls/d and includes approximately 1,096 miles of NGL pipeline extending from Opal, Wyoming, to the Mid-Continent NGL market center near Conway, Kansas, along with extensions into the Piceance and Denver-Julesberg basins in Colorado and the Bakken Shale in the Williston basin in North Dakota. Our equity NGL volumes from two of our three Wyoming plants and our Willow Creek facility in Colorado are dedicated for transport on OPPL under a long-term transportation agreement.
Operating Statistics
The following table summarizes our significant operating statistics for Williams Partners’ domestic midstream business:
|
| | | | | | | | |
| | 2017 | | 2016 | | 2015 |
Volumes: (1) | | | | | |
| Gathering (Bcf/d) | 8.15 |
| | 8.25 |
| | 8.34 |
|
| Plant inlet natural gas (Bcf/d) | 3.05 |
| | 3.50 |
| | 3.52 |
|
| NGL production (Mbbls/d) (2) | 148 |
| | 151 |
| | 131 |
|
| NGL equity sales (Mbbls/d) (2) | 39 |
| | 46 |
| | 31 |
|
| Crude oil transportation (Mbbls/d) (2) | 134 |
| | 113 |
| | 126 |
|
| Geismar ethylene sales (millions of pounds) | 566 |
| | 1,638 |
| | 1,066 |
|
__________
| |
(1) | Excludes volumes associated with equity-method investments. |
| |
(2) | Annual average Mbbls/d. |
Additional Business Segment Information
Our ongoing business segments are presented as continuing operations in the accompanying financial statements and Notes to Consolidated Financial Statements included in Part II.
We perform certain management, legal, financial, tax, consultation, information technology, administrative, and other services for our subsidiaries.
Our principal sources of cash are from dividends distributions, and advances from our subsidiaries, investments, payments by subsidiaries for services rendered, and, if needed, external financings, and net proceeds from asset sales. The terms of
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) |
| 2017 | |
| Service: |
|
|
| Regulated natural gas transportation and storage | $ | 2,148 |
|
| Gathering, processing, and production handling | 2,715 |
|
| 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 |
|
We have one customer, Chesapeake Energy Corporation, and its affiliates, that accounts for 10 percent of our total revenue in 2017. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements for additional details.)
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 transmission pipelines that are regulated by the FERC because they are deemed to transport gas in interstate commerce. Black Marlin Pipeline Company provides transportation service for offshore Texas production in the High Island area and redelivers that gas to intrastate pipeline interconnects near Texas City. Discovery provides transportation service for offshore Louisiana production from the South Timbalier,
Grand Isle, Ewing Bank, and Green Canyon (deepwater) areas to an onshore processing facility and downstream interconnect points with major interstate pipelines. In addition, Williams Partners ownswe own a 50 percent equity-method investment in and isare the operator of OPPL, which is an interstate natural gas liquids pipeline regulated by the FERC pursuant to the Interstate Commerce Act. OPPL provides transportation service pursuant to tariffs filed with the FERC. We also own an ethane pipeline in West Virginia and Pennsylvania (Williams Ohio Valley Pipeline LLC) and an ethane pipeline in Texas and Louisiana (Williams Bayou Ethane Pipeline) each of which provides interstate service subject to FERC jurisdiction under the Interstate Commerce Act.
Pipeline Safety
Our gas pipelines are subject to the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Improvement Act of 2002, the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011 (Pipeline Safety Act), and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016, which regulate safety requirements in the design, construction, operation, and maintenance of interstate natural gas transmission facilities.
The United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) administers federal pipeline safety laws.
Federal pipeline safety laws authorize PHMSA to establish minimum safety standards for pipeline facilities and persons engaged in the transportation of gas or hazardous liquids by pipeline. These safety standards apply to the design, construction, testing, operation, and maintenance of gas and hazardous liquids pipeline facilities affecting interstate or foreign commerce. PHMSA has also established reporting requirements for operators of gas and hazardous liquid pipeline facilities, as well as provisions for establishing the qualification of pipeline personnel and requirements for managing the integrity of gas transmission and distribution lines and certain hazardous liquid pipelines. To ensure compliance with these provisions, PHMSA performs pipeline safety inspections and has the authority to initiate enforcement actions.
Federal pipeline safety regulations contain an exemption that applies to gathering lines in certain rural locations. A substantial portion of our gathering lines qualify for that exemption and are currently not regulated under federal law.
States are largely preempted by federal law from regulating pipeline safety for interstate pipelines but most are certified by PHMSA to assume responsibility for enforcing intrastate pipeline safety regulations and inspecting intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, they vary considerably in their authority and capacity to address pipeline safety.
On January 3, 2012, the Pipeline Safety Act was enacted. The Pipeline Safety Act requires PHMSA to complete a number of reports in preparation for potential rulemakings. The issues addressed in these rulemaking provisions include, but are not limited to, the use of automatic or remotely controlled shut-off valves on new or replaced transmission line facilities, modifying the requirements for pipeline leak detection systems, and expanding the scope of the pipeline integrity management requirements for both gas and liquid pipeline systems. On June 22, 2016, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 was enacted, further strengthening PHMSA’s safety authority.
Pipeline Integrity Regulations
We have an enterprise-wide Gas Integrity Management Plan that we believe meets the PHMSA final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for gas transmission pipelines that could affect high-consequence areas in the event of pipeline failure. The integrity management program includes a baseline assessment plan along with periodic reassessments to be completed within required time frames. In meeting the integrity regulations, we have identified high-consequence areas and developed baseline assessment plans. Ongoing periodic reassessments and initial assessments of any new high-consequence areas have been completed. We estimate that the cost to be incurred in 20182019 associated with this program to be approximately $99$86 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 have an enterprise-wide Liquid Integrity Management Plan that we believe meets the PHMSA final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires liquid pipeline operators to develop an integrity management program for liquid transmission pipelines that could affect high-consequence areas in the event of pipeline failure. The integrity management program includes a baseline assessment plan along with periodic reassessments expected to be completed within required time frames. In meeting the integrity regulations, we utilized government defined high-consequence areas and developed baseline assessment plans. We completed assessments within the required time frames. We estimate that the cost to be incurred in 20182019 associated with this program will be approximately $4$3 million. Ongoing periodic reassessments and initial assessments of any new high-consequence areas are expected to be completed within the time frames required by the rule. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business.
State Gathering 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 Department of Environmental Quality,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.”
See Part II, Item 8. Financial Statements and Supplementary Data — Note 1718 – 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 our expectations,” and Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Environmental” and “Environmental Matters” in Part II, Item 8. Financial Statements and Supplementary Data — Note 1718 – 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 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 the position of our existing infrastructure, established strategic long-term contracts, and the fact that our pipelines have numerous receipt and delivery points along our systems provide us a competitive advantage, especially along the eastern seaboard and northwestern United States.
Midstream Business
Competition for natural gas gathering, processing, treating, transporting, and storing natural gas continues to increase as production from shales and other resource areas continues to grow. Our midstream services compete with similar facilities that are in the same proximity as our assets.
We face competition from major and independent natural gas midstream providers, private equity firms, and major integrated oil and natural gas companies that gather, transport, process, fractionate, store, and market natural gas and NGLs, as well as some larger exploration and production companies that are choosing to develop midstream services to handle their own natural gas.
Our gathering and processing agreements are generally long-term agreements that may include acreage dedication. We primarily face competition to the extent these agreements approach renewal and new volume opportunities arise. Competition for natural gas volumes is primarily based on reputation, commercial terms (products retained or fees charged), array of services provided, efficiency and reliability of services, location of gathering facilities, available capacity, downstream interconnects, and latent capacity. We believe our significant presence in traditional prolific
supply basins, our solid positions in growing shale plays, our reputation as a reliable operator, and our ability to offer integrated packages of services position us well against our competition.
For additional information regarding competition for our services or otherwise affecting our business, please refer to Part 1, Item 1A. “Risk 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, 2018,2019, we had approximately 5,4255,322 full-time employees.
FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS
See Part II, Item 8. Financial Statements and Supplementary Data — Note 18 – Segment Disclosures of Notes to Consolidated Financial Statements for amounts of revenues during the last three fiscal years from external customers attributable to the United States and all foreign countries. Also see Part II, Item 8. Financial Statements and Supplementary Data — Note 18 – Segment Disclosures of Notes to Consolidated Financial Statements for information relating to long-lived assets during the last three fiscal years, located in the United States and all foreign countries.
Item 1A. Risk Factors
FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT
FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
The reports, filings, and other public announcements of Williams may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act) and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act).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 facts, included in this report that address activities, events, or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “guidance,” “outlook,” “in-service date,” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:
Expected levels of cash distributions by WPZ with respect to limited partner interests;
Levels of dividends to Williams stockholders;
Future credit ratings of Williams WPZ, and 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 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 expected levels of cash distributions;
Whether we are able to pay current and expected levels of dividends;
Whether WPZ elects to pay expected levels of cash distributions and we elect to pay expected levels of dividends;
19
Whether we will be able to effectively execute our financing plan;
Availability of supplies, including lower than anticipated volumes from third parties served by our midstream business,market demand, and market demand;
Volatilityvolatility of pricing including the effect of lower than anticipated energy commodity prices and margins;prices;
Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);
The strength and financial resources of our competitors and the effects of competition;
Whether we are able to successfully identify, evaluate and timely execute our capital projects and other
investment opportunities in accordance with our forecasted capital expenditures budget;opportunities;
Our ability to acquire new businesses and assets and successfully integrate those operations and assets into existing businesses as well as successfully expand our facilities, and operations;to consummate asset sales on acceptable terms;
Development and rate of adoption of alternative energy sources;
The impact of operational and developmental hazards and unforeseen interruptions, and the availability of adequate insurance coverage;interruptions;
The impact of existing and future laws and regulations (including but not limited to the Tax Cuts and Job ActsJobs Act of 2017), regulations, the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate proceeding outcomes;
Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;
Changes in maintenance and construction costs;costs, as well as our ability to obtain sufficient construction related inputs including skilled labor;
Changes in the current geopolitical situation;
Our exposure to the credit risk of our customers and counterparties;
Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally recognized credit rating agencies, and the availability and cost of capital;
The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;
Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities;
Acts of terrorism, including cybersecurity threats,incidents, 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 to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.
Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. These factors are described in the following section.
RISK FACTORS
You should carefully consider the following risk factors in addition to the other information in this report. Each of these factors could adversely affect our business, prospects, financial condition, results of operations, cash flows, and, in some cases our reputation. The occurrence of any of such risks could also adversely affect the value of an investment in our securities.
Risks Related to Our Business
The financial condition of our natural gas transportation and midstream businesses is dependent on the continued availability of natural gas supplies in the supply basins that we access and demand for those supplies in the markets we serve.
Our ability to maintain and expand our natural gas transportation and midstream businesses depends on the level of drilling and production by third parties in our supply basins. Production from existing wells and natural gas supply basins with access to our pipeline and gathering systems will naturally decline over time. The amount of natural gas reserves underlying these existing wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. We do not obtain independent evaluations of natural gas reserves connected to our systems and processing facilities. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. In addition, low prices for natural gas, regulatory limitations, or the lack of available capital could adversely affect the development and production of additional natural gas reserves, the installation of gathering, storage, and pipeline transportation facilities and the import and export of natural gas supplies. Localized low natural gas prices in one or more of our existing supply basins, whether caused by a lack of infrastructure or otherwise, could also result in depressed natural gas production in such basins and limit the supply of natural gas made available to us. The competition for natural gas supplies to serve other markets could also reduce the amount of natural gas supply for our customers. A failure to obtain access to sufficient natural gas supplies will adversely impact our ability to maximize the capacities of our gathering, transportation, and processing facilities.
Demand for our services is dependent on the demand for gas in the markets we serve. Alternative fuel sources such as electricity, coal, fuel oils, or nuclear energy, as well as technological advances and renewable sources of energy, could reduce demand for natural gas in our markets and have an adverse effect on our business.
A failure to obtain access to sufficient natural gas supplies or a reduction in demand for our services in the markets we serve could result in impairments of our assets and have a material adverse effect on our business, financial condition, results of operations, and cash flows.
Prices for natural gas, NGLs, oil, and other commodities, are volatile and this volatility has and could continue to adversely affect our financial results, cash flows, access to capital, and ability to maintain our existing businesses.
Our revenues, operating results, future rate of growth, and the value of certain components of our businesses depend primarily upon the prices of natural gas, NGLs, oil, or other commodities, and the differences between prices of these commodities and could be materially adversely affected by an extended period of current low commodity prices, or a further decline in commodity prices. Price volatility has and could continue to impact both the amount we receive for our products and services and the volume of products and services we sell. Prices affect the amount of cash flow available
for capital expenditures and our ability to borrow money or raise additional capital. Price volatility has and could continue to have an adverse effect on our business, results of operations, financial condition, and cash flows.
The markets for natural gas, NGLs, oil, and other commodities are likely to continue to be volatile. Wide fluctuations in prices might result from one or more factors beyond our control, including:
Worldwide and domestic supplies of and demand for natural gas, NGLs, oil, and related commodities;
Turmoil in the Middle East and other producing regions;
The activities of the Organization of Petroleum Exporting Countries;
The level of consumer demand;
The price and availability of other types of fuels or feedstocks;
The availability of pipeline capacity;
Supply disruptions, including plant outages and transportation disruptions;
The price and quantity of foreign imports 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, including Chesapeake Energy Corporation and its affiliates, and our credit risk management will not be able to completely eliminate such risk.
We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business. Generally, our customers are rated investment grade, are otherwise considered creditworthy, or are required to make prepayments or provide security to satisfy credit concerns. However, our credit procedures and policies cannot completely eliminate customer and counterparty credit risk. Our customers and counterparties include industrial customers, local distribution companies, natural gas producers, and marketers whose creditworthiness may be suddenly and disparately impacted by, among other factors, commodity price volatility, deteriorating energy market conditions, and public and regulatory opposition to energy producing activities. In a low commodity price environment certain of our customers could be negatively impacted, causing them significant economic stress including, in some cases, to file for bankruptcy protection or to renegotiate contracts. To the extent one or more of our key customers commences bankruptcy proceedings, our contracts with the customers may be subject to rejection under applicable provisions of the United States Bankruptcy Code, or may be renegotiated. Further, during any such bankruptcy proceeding, prior to assumption, rejection or renegotiation of such contracts, the bankruptcy court may temporarily authorize the payment of value for our services less than contractually required, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows. For example, Chesapeake
Energy Corporation and its affiliates, which accounted for approximately 10 percent of our 2017 consolidated revenues, have experienced significant, negative financial results due to sustained low commodity prices. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties or otherwise do not take or are unable to take sufficient mitigating actions, including obtaining sufficient collateral, deterioration in their creditworthiness, and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off accounts receivable. Such write-downs or write-offs could negatively affect our operating results in the periods in which they occur, and, if significant, could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
We 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. In the current environment, we may face political opposition by landowners, environmental activists, and others resulting in the delay and/or denial of required governmental permits. Additional risks associated with construction may include the inability to obtain rights-of-way, skilled labor, equipment, materials, and other required inputs in a timely manner such that projects are completed, on time or at all, and the risk that construction cost overruns could cause total project costs to exceed budgeted costs. Additional risks associated with growing our business include, among others, that:
Changing circumstances and deviations in variables could negatively impact our investment analysis, including our projections of revenues, earnings, and cash flow relating to potential investment targets, resulting in outcomes which are materially different than anticipated;
We could be required to contribute additional capital to support acquired businesses or assets;
We may assume liabilities that were not disclosed to us, that exceed our estimates and for which contractual protections are either unavailable or prove inadequate;
Acquisitions could disrupt our ongoing business, distract management, divert financial and operational resources from existing operations and make it difficult to maintain our current business standards, controls, and procedures;
Acquisitions and capital projects may require substantial new capital, including 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 may face opposition to the construction and operation of our pipelines and facilities from various groups.
We may face opposition to the construction and operation of our pipelines and facilities from environmental groups, landowners, tribal groups, local groups and other advocates. Such opposition could take many forms, including organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving
our assets, or lawsuits or other actions designed to prevent, disrupt or delay the operation of our assets and business. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of our operations. Any such event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could adversely affect our financial condition and results of operations.
Holders of our common stock may not receive dividends in the amount expected or any dividends.
We may not have sufficient cash each quarter to pay dividends or maintain current or expected levels of dividends. The actual amount of cash we dividend may fluctuate from quarter to quarter and will depend on various factors, some of which are beyond our control, including:
The amount of cash that WPZ and our other subsidiaries distribute to us;
The amount of cash we generate from our operations, our working capital needs, our level of capital expenditures, and our ability to borrow;
The restrictions contained in our indentures and credit facility and our debt service requirements;
The cost of acquisitions, if any.
A failure either to pay dividends or to pay dividends at expected levels could result in a loss of investor confidence, reputational damage, and a decrease in the value of our stock price.
Our cash flow is heavily dependent on the earnings and distributions of WPZ.
Our partnership interest in WPZ is our largest cash-generating asset. Therefore, we are indirectly exposed to all of the risks to which WPZ is subject, as our cash flow is heavily dependent upon the ability of WPZ to make distributions to its partners. A significant decline in WPZ’s earnings and/or distributions would have a corresponding negative impact on us.
One of our subsidiaries acts as the general partner of a publicly traded limited partnership, Williams Partners L.P. As such, this subsidiary’s operations may involve a greater risk of liability than ordinary business operations.
One of our subsidiaries acts as the general partner of WPZ, a publicly traded limited partnership. This subsidiary may be deemed to have undertaken contractual obligations with respect to WPZ as the general partner and to the limited partners of WPZ. Activities, determined to involve such obligations to other persons or entities typically involve a higher standard of conduct than ordinary business operations and therefore may involve a greater risk of liability, particularly when a conflict of interest is found to exist. Our control of the general partner of WPZ may increase the possibility of claims of breach of such duties, including claims brought due to conflicts of interest (including conflicts of interest that may arise between WPZ, on the one hand, and its general partner and that general partner’s affiliates, including us, on the other hand). Any liability resulting from such claims could be material.
Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results.
We have numerous competitors in all aspects of our businesses, and additional competitors may enter our markets. Any current or future competitor that delivers natural gas, NGLs, or other commodities into the areas that we operate could offer transportation services that are more desirable to shippers than those we provide because of price, location, facilities or other factors. In addition, current or potential competitors may make strategic acquisitions or have greater financial resources than we do, which could affect our ability to make strategic investments or acquisitions. Our competitors may be able to respond more quickly to new laws or regulations or emerging technologies or to devote greater resources to the construction, expansion, or refurbishment of their facilities than we can. Failure to successfully
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 all100 percent of the equity interests inof certain subsidiaries, including the Partially Owned Entities, which could adversely affectmay limit our ability to operate and control these assets in a manner beneficial to us.
Because we do not controlsubsidiaries. Certain operations, including the Partially Owned Entities, weare conducted through arrangements that may have limited flexibilitylimit our ability to operate and control the operationthese operations.
The operations of or cash distributions received from these entities. The Partially Owned Entities’ organizational documents generally require distribution of their available cash to their members on a quarterly basis; however, in each case, available cash is reduced, in part, by reserves appropriate for operating the businesses. As of December 31, 2017, our investments incurrent non-wholly-owned subsidiaries, including the Partially Owned Entities, accounted for approximately 7 percent of our total consolidated assets. Conflicts of interest may ariseare conducted in the future between us, on the one hand, and ouraccordance 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, 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 ownersEntities. We may control the Partially Owned Entity’s actions with respect to such matter (subject to certain limitations), which could be detrimental to our business. Any future disagreements with the other co-owners of these assets could adversely affect our ability to respond to changing economic or industry conditions, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
We will conduct certain operations through joint ventures that may limit ourlimited operational flexibility or require us to make additional capital contributions.
Some of our operations are conducted through joint venturein such current and future arrangements and we may enter additional joint ventures innot be able to control the future. In a joint venture arrangement, we have less operational flexibility, as actions must be taken in accordance with the applicable governing provisionstiming or amount of the joint venture.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 with respect to these operations;
Weand 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.operations;
In addition, joint venture participantsWe may have additional obligations, such as required capital contributions, that are important to the success of the joint venture,operations.
In addition, conflicts of interest may arise between us, on the one hand, and other interest owners, on the other hand. If such asconflicts of interest arise, we may not have the obligationability to pay substantial carried costs pertainingcontrol the outcome with respect to the joint venture and to pay their share of capital and other costs of the joint venture, the performance of which is outside our control. Similarly, if we fail to make a required capital contribution under the applicable governing provisions of a joint venture arrangement, we could be deemed to bematter in default under the joint venture agreement. Joint venture partners may be in a position to take actions contrary to instructions or requests or contrary to our policies or objectives, and disputesquestion. Disputes between us and our joint venture partnersother interest owners may also result in delays, litigation or operational impasses.
The risks described above or the failure to continue joint ventures, or to resolve disagreements with joint venture partnerssuch arrangements could adversely affect our ability to conduct ourthe operations that are the subject of any joint venture,such arrangements which could, in turn, negatively affect our business, growth strategy, financial condition and results of operations.
We may not be able to replace, extend, or add additional customer contracts or contracted volumes on favorable terms, or at all, which could affect our financial condition, the amount of cash available to pay dividends, and our ability to grow.
We rely on a limited number of customers and producers for a significant portion of our revenues and supply of natural gas and NGLs. Although many of our customers and suppliers are subject to long-term contracts, if we are unable to replace or extend such contracts, add additional customers, or otherwise increase the contracted volumes of natural gas provided to us by current producers, in each case on favorable terms, if at all, our financial condition, growth plans, and the amount of cash available to pay dividends could be adversely affected. Our ability to replace, extend, or add additional customer or supplier contracts, or increase contracted volumes of natural gas from current producers, on favorable terms, or at all, is subject to a number of factors, some of which are beyond our control, including:
The level of existing and new competition in our businesses or from alternative sources, such as electricity, renewable resources, coal, fuel oils, or nuclear energy;
Natural gas and NGL prices, demand, availability, and margins in our markets. Higher prices for energy commodities related to our businesses could result in a decline in the demand for those commodities and, therefore, in customer contracts or throughput on our pipeline systems. Also, lower energy commodity prices could negatively impact our ability to maintain or achieve favorable contractual terms, including pricing, and could also result in a decline in the production of energy commodities resulting in reduced customer contracts, supply contracts, and throughput on our pipeline systems;
General economic, financial markets, and industry conditions;
The effects of regulation on us, our customers, and our contracting practices;
Our ability to understand our customers’ expectations, efficiently and reliably deliver high quality services and effectively manage customer relationships. The results of these efforts will impact our reputation and positioning in the market.
Certain of our gas pipeline services are subject to long-term, fixed-price contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.
Our gas pipelines provide some services pursuant to long-term, fixed-price contracts. It is possible that costs to perform services under such contracts will exceed the revenues our pipelines collect for their services. Although most of the services are priced at cost-based rates that are subject to adjustment in rate cases, under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” that may be above or below the FERC regulated cost-based rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs that could be produced by inflation or other factors relating to the specific facilities being used to perform the services.
Some of our businesses are exposed to supplier concentration risks arising from dependence on a single or a limited number of suppliers.
Some of our businesses may be dependent on a small number of suppliers for delivery of critical goods or services. If a supplier on which one of our businesses depends were to fail to timely supply required goods and services, such business may not be able to replace such goods and services in a timely manner or otherwise on favorable terms or at all. If our business is unable to adequately diversify or otherwise mitigate such supplier concentration risks and such risks were realized, such businesses could be subject to reduced revenues and increased expenses, which could have a material adverse effect on our financial condition, results of operation, and cash flows.
Failure of our service providers or disruptions to our outsourcing relationships might negatively impact our ability to conduct our business.
Certain of our accounting and information technology services are currently provided by third-party vendors, and sometimes from service centers outside of the United States. Services provided pursuant to these agreements could be disrupted. Similarly, the expiration of such agreements or the transition of services between providers could lead to loss of institutional knowledge or service disruptions. Our reliance on others as service providers could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
An impairment of our assets, including 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 methodequity-method investments. Additionally, any asset monetizations could result in impairments if any assets are sold or otherwise exchanged for amounts less than their carrying value. If we determine that an impairment has occurred, we would be required to take an immediate noncash charge to earnings.
Our operations are subject to operational hazards and unforeseen interruptions.
There are operational risks associated with the gathering, transporting, storage, processing, and treating of natural gas, the fractionation, transportation, and storage of NGLs, and crude oil transportation and production handling, including:
Aging infrastructure and mechanical problems;
Damages to pipelines and pipeline blockages or other pipeline interruptions;
Uncontrolled releases of natural gas (including sour gas), NGLs, crude oil, or other products;
Collapse or failure of storage caverns;
Operator error;
Damage caused by third-party activity, such as operation of construction equipment;
Pollution and other environmental risks;
Fires, explosions, craterings, and blowouts;
Security risks, including cybersecurity;
Operating in a marine environment.
Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations, loss of services to our customers, reputational damage, and substantial losses to us. The location of certain segments of our facilities in or near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks. An event such as those described above could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance.
We do not insure against all potential risks and losses and could be seriously harmed by unexpected liabilities or by the inability of our insurers to satisfy our claims.
In accordance with customary industry practice, we maintain insurance against some, but not all, risks and losses, and only at levels we believe to be appropriate. The occurrence of any risks not fully covered by our insurance could have a material adverse effect on our business, financial condition, results of operations, and cash flows and our ability to repay our debt.
Our assets and operations, as well as our customers’ assets and operations, can be adversely affected by weather and other natural phenomena.
Our assets and operations, especially those located offshore, and our customers’ assets and operations can be adversely affected by hurricanes, floods, earthquakes, landslides, tornadoes, fires, and other natural phenomena and weather conditions, including extreme or unseasonable temperatures, making it more difficult for us to realize the historic rates of return associated with our assets and operations. A significant disruption in our or our customers’ operations or a significant liability for which we are not fully insured could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
Our business could be negatively impacted by acts of terrorism and security threats, including cybersecurity threats, and related disruptions.
Given the volatile nature of the commodities we transport, process, store, and sell, our assets and the assets of our customers and others in our industry may be targets of terrorist activities. A terrorist attack could create significant price volatility, disrupt our business, limit our access to capital markets, or cause significant harm to our operations, such as full or partial disruption to our ability to produce, process, transport, or distribute natural gas, NGLs, or other commodities. Acts of terrorism, as well as events occurring in response to or in connection with acts of terrorism, could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
A breach of our information technology infrastructure, including a breach caused by a cybersecurity attack on us or third parties with whom we are interconnected, may interfere with the safe operation of our assets, result in the disclosure of personal or proprietary information, and harm our reputation.
We rely on our information technology infrastructure to process, transmit, and store electronic information, including information we use to safely operate our assets. 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.
If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas and NGLs or to treat natural gas, our revenues could be adversely affected.
We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our customers. Because we do not own these third-party pipelines or other facilities, their continuing operation is not within our control. If these pipelines or facilities were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines or facilities, reduced operating pressures, lack of capacity, increased credit requirements or rates charged by such pipelines or facilities or other causes, we and our customers would have reduced capacity to transport, store or deliver
natural gas or NGL products to end use markets or to receive deliveries of mixed NGLs, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnect or in operations on third-party pipelines or facilities that would cause a material reduction in volumes transported on our pipelines or our gathering systems or processed, fractionated, treated, or stored at our facilities could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
Our operating results for certain components of our business might fluctuate on a seasonal basis.
Revenues from certain components of our business can have seasonal characteristics. In many parts of the country, demand for natural gas and other fuels peaks during the winter. As a result, our overall operating results in the future might fluctuate substantially on a seasonal basis. Demand for natural gas and other fuels could vary significantly from our expectations depending on the nature and location of our facilities and pipeline systems and the terms of our natural gas transportation arrangements relative to demand created by unusual weather patterns.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and facilities have been constructed. As such, we are subject to the possibility of increased costs to retain necessary land use. In those instances in which we do not own the land on which our facilities are located, we obtain the rights to construct and operate our pipelines and gathering systems on land owned by third parties and governmental agencies for a specific period of time. In addition, some of our facilities cross Native American lands pursuant to rights-of-way of limited terms. We may not have the right of eminent domain over land owned by Native American tribes. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
Our business could be negatively impacted as a result of stockholder activism.
In recent years, stockholder activism, including threatened or actual proxy contests, has been directed against numerous public companies, including ours. During the latter part of fiscal year 2016, we were the target of a proxy contest from a stockholder activist, which resulted in our incurring significant costs. If stockholder activists were to again take or threaten to take actions against the Company or seek to involve themselves in the governance, strategic direction or operations of the Company, we could incur significant costs as well as the distraction of management,
which could have an adverse effect on our business or financial results. In addition, actions of activist stockholders may cause significant fluctuations in our stock price based on temporary or speculative market perceptions or other factors that do not necessarily reflect the underlying fundamentals and prospects of our business.
Litigation pertaining to the ETC Merger, including litigation related to Energy Transfer Equity, L.P.’s (ETE’s) termination of and failure to close the ETC Merger, may negatively impact our business and operations.
We have incurred and may continue to incur additional costs in connection with the prosecution, defense or settlement of the currently pending and any future litigation relating to the ETC Merger or ETE’s termination of and failure to close the ETC Merger. We cannot predict the outcome of this litigation. Such litigation may also create a distraction for our management team and board of directors and require time and attention. In addition, any litigation relating to the ETC Merger or ETE’s termination of and failure to close the ETC Merger could, among other things, adversely affect our financial condition and results of operations.
Our costs and funding obligations for our defined benefit pension plans and costs for our other postretirement benefit plans are affected by factors beyond our control.
We have defined benefit pension plans covering substantially all of our U.S. employees and other postretirement benefit plans covering certain eligible participants. The timing and amount of our funding requirements under the defined benefit pension plans depend upon a number of factors that we control, including changes to pension plan benefits, as well as factors outside of our control, such as asset returns, interest rates, and changes in pension laws.
Changes to these and other factors that can significantly increase our funding requirements could have a significant adverse effect on our financial condition and results of operations.
Failure to attract and retain an appropriately qualified workforce could negatively impact our results of operations.
Events such as an aging workforce without appropriate replacements, mismatch of skill sets to future needs, or unavailability of contract labor may lead to operating challenges such as lack of resources, loss of knowledge, and a lengthy time period associated with skill development, including with the workforce needs associated with projects and ongoing operations. Failure to hire and adequately obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect our ability to manage and operate the businesses. If we are unable to successfully attract and retain an appropriately qualified workforce, results of operations could be negatively impacted.
If there is a determination that the spin-off of WPX Energy, Inc. (WPX) stock to our stockholders is taxable for U.S. federal income tax purposes because the facts, representations or undertakings underlying a U.S. Internal Revenue Service (IRS) private letter ruling or a tax opinion are incorrect or for any other reason, then we and our stockholders could incur significant income tax liabilities.
In connection with our original separation plan that called for an initial public offering (IPO) of stock of WPX and a subsequent spin-off of our remaining shares of WPX to our stockholders, we obtained a private letter ruling from the IRS and an opinion of our outside tax advisor, to the effect that the distribution by us of WPX shares to our stockholders, and any related restructuring transaction undertaken by us, would not result in recognition for U.S. federal income tax purposes, of income, gain or loss to us or our stockholders under section 355 and section 368(a)(1)(D) of the U.S. Internal Revenue Code of 1986, as amended (Code), except for cash payments made to our stockholders in lieu of fractional shares of WPX common stock. In addition, we received an opinion from our outside tax advisor to the effect that the spin-off pursuant to our revised separation plan which was ultimately consummated on December 31, 2011, which did not involve an IPO of WPX shares, would not result in the recognition, for federal income tax purposes, of income, gain, or loss to us or our stockholders under section 355 and section 368(a)(1)(D) of the Code, except for cash payments made to our stockholders in lieu of fractional shares of WPX. The private letter ruling and opinion have relied on or will rely on certain facts, representations, and undertakings from us and WPX regarding the past and future conduct of the companies’ respective businesses and other matters. If any of these facts, representations, or undertakings are, or become, incorrect or are not otherwise satisfied, including as a result of certain significant changes in the stock ownership of us or WPX after the spin-off, or if the IRS disagrees with any such facts and representations upon audit, we and our stockholders may not be able to rely on the private letter ruling or the opinion of our tax advisor and could be subject to significant income tax liabilities.
The WPX spin-off may expose us to potential liabilities arising out of state and federal fraudulent conveyance laws and legal dividend requirements that we did not assume in our agreements with WPX.
The spin-off is subject to review under various state and federal fraudulent conveyance laws. A court could deem the spin-off or certain internal restructuring transactions undertaken by us in connection with the separation to be a fraudulent conveyance or transfer. Fraudulent conveyances or transfers are defined to include transfers made or obligations incurred with the actual intent to hinder, delay, or defraud current or future creditors or transfers made or obligations incurred for less than reasonably equivalent value when the debtor was insolvent, or that rendered the debtor insolvent, inadequately capitalized or unable to pay its debts as they become due. A court could void the transactions or impose substantial liabilities upon us, which could adversely affect our financial condition and our results of operations. Whether a transaction is a fraudulent conveyance or transfer will vary depending upon the jurisdiction whose law is being applied. Under the separation and distribution agreement between us and WPX, from and after the spin-off, each of WPX and we are responsible for the debts, liabilities, and other obligations related to the business or businesses which each owns and operates. Although we do not expect to be liable for any such obligations not expressly assumed by us pursuant to the separation and distribution agreement, it is possible that a court would disregard the allocation agreed to between the parties, and require that we assume responsibility for obligations allocated to WPX, particularly if WPX were to refuse or were unable to pay or perform the subject allocated obligations.
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 belowan investment-grade credit ratingsrating by each of the three credit ratings agencies.
Our ability to obtain credit in the future could be affected by WPZ’s credit ratings.
A substantial portion of our operations are conducted through, and our cash flows are substantially derived from, distributions paid to us by WPZ. Due to our relationship with WPZ, our ability to obtain credit will be affected by WPZ’s credit ratings. If WPZ were to experience a deterioration in its credit standing or financial condition, our access to capital, and our ratings could be adversely affected. Any future downgrading of a WPZ credit rating could also result in a downgrading of our credit rating. A downgrading of a WPZ credit rating could limit our ability to obtain financing in the future upon favorable terms, if at all.
Difficult conditions in the global financial markets and the economy in general could negatively affect our business and results of operations.
Our businesses may be negatively impacted by adverse economic conditions or future disruptions in global financial markets. Included among these potential negative impacts are industrial or economic contraction leading to reduced energy demand and lower prices for our products and services and increased difficulty in collecting amounts owed to us by our customers. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures. In addition, financial markets have periodically been affected by concerns over U.S. fiscal and monetary policies. These concerns, as well as actions taken by the U.S. federal government in response to these concerns, could significantly and adversely impact the global and U.S. economies and financial markets, which could negatively impact us in the manner described above.
Restrictions in our debt agreements and the amount of our indebtedness may affect our future financial and operating flexibility.
Our total outstanding long-term debt (including current portion) as of December 31, 2017,2018, was $20.9$22.4 billion.
The agreements governing our indebtedness contain covenants that restrict our and our material subsidiaries’ ability to incur certain liens to support indebtedness and our ability to merge or consolidate or sell all or substantially all of our assets in certain circumstances. In addition, certain of our debt agreements contain various covenants that restrict or limit, among other things, our ability to make certain distributions during the continuation of an event of default, the ability of our subsidiaries to incur additional debt, and our, and our material subsidiaries’, ability to enter into certain affiliate transactions and certain restrictive agreements. Certain of our debt agreements also contain, and those we enter into in the future may contain, financial covenants, and other limitations with which we will need to comply.
Our debt service obligations and the covenants described above could have important consequences. For example, they could:
Make it more difficult for us to satisfy our obligations with respect to our indebtedness, which could in turn result in an event of default on such indebtedness;
Impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes, or other purposes;
Diminish our ability to withstand a continued or future downturn in our business or the economy generally;
Require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, the payments of dividends, general corporate purposes, or other purposes;
Limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate, including limiting our ability to expand or pursue our business activities and preventing us from engaging in certain transactions that might otherwise be considered beneficial to us.
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 1314 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.
Increases in interest rates could adversely impact our share price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash dividends at our intended levels.
Interest rates may increase in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our share price will be impacted by the level of our dividends and implied dividend yield. The dividend yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our shares, and a rising interest rate environment could have an adverse impact on our share price and our ability to issue equity or incur debt for acquisitions or other purposes and to pay cash dividends at our intended levels.
Our hedging activities might not be effective and could increase the volatility of our results.
In an effort to manage our financial exposure related to commodity price and market fluctuations, we have entered, and may in the future enter into contracts to hedge certain risks associated with our assets and operations. In these hedging activities, we have used, and may in the future use, fixed-price, forward, physical purchase, and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. Nevertheless, no single hedging arrangement can adequately address all risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist. While we attempt to manage counterparty credit risk within guidelines established by our credit policy, we may not be able to successfully manage all credit risk and as such, future cash flows and results of operations could be impacted by counterparty default.
Risks Related to Regulations
The natural gas sales, transportation, and storage operations of our gas pipelines are subject to regulation by the FERC, which could have an adverse impact on their ability to establish transportation and storage rates that would allow them to recover the full cost of operating their respective pipelines, including a reasonable rate of return.
In addition to regulation by other federal, state, and local regulatory authorities, under the Natural Gas Act of 1938, interstate pipeline transportation and storage service is subject to regulation by the FERC. Federal regulation extends to such matters as:
Transportation and sale for resale of natural gas in interstate commerce;
Rates, operating terms, types of services, and conditions of service;
Certification and construction of new interstate pipelines and storage facilities;
Acquisition, extension, disposition, or abandonment of existing interstate pipelines and storage facilities;
Accounts and records;
Depreciation and amortization policies;
Relationships with affiliated companies who are involved in marketing functions of the natural gas business;
Market manipulation in connection with interstate sales, purchases, or transportation of natural gas.
Regulatory or administrative actions in these areas, including successful complaints or protests against the rates of the gas pipelines, can affect our business in many ways, including decreasing tariff rates and revenues, decreasing volumes in our pipelines, increasing our costs, and otherwise altering the profitability of our pipeline business.
The operation of our businesses might also be adversely affected by regulatory proceedings, changes in government regulations or in their interpretation or implementation, or the introduction of new laws or regulations applicable to our businesses or our customers.
Public and regulatory scrutiny of the energy industry has resulted in the proposal and/or implementation of increased regulations. Such scrutiny has also resulted in various inquiries, investigations, and court proceedings, including litigation of energy industry matters. Both the shippers on our pipelines and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.
Certain inquiries, investigations, and court proceedings are ongoing. Adverse effects may continue as a result of the uncertainty of ongoing inquiries, investigations, and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines and/or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our results of operations or increase our operating costs in other ways. Current legal proceedings or other matters, including environmental matters, suits, regulatory appeals, and similar matters might result in adverse decisions against us which, among other outcomes, could result in the imposition of substantial penalties and fines and could damage our reputation. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.
In addition, existing regulations, including those pertaining to financial assurances to be provided by our businesses in respect of potential asset decommissioning and abandonment activities, might be revised, reinterpreted, or otherwise enforced in a manner which differs from prior regulatory action. New laws and regulations, including those pertaining to oil and gas hedging and cash collateral requirements, might also be adopted or become applicable to us, our customers, or our business activities. If new laws or regulations are imposed relating to oil and gas extraction, or if additional or revised levels of reporting, regulation, or permitting moratoria are required or imposed, including those related to hydraulic fracturing, the volumes of natural gas and other products that we transport, gather, process, and treat could decline, our compliance costs could increase, and our results of operations could be adversely affected.
Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities, and expenditures that could exceed our expectations.
Our operations are subject to extensive federal, state, tribal, and local laws and regulations governing environmental protection, endangered and threatened species, the discharge of materials into the environment, and the security of industrial facilities. Substantial costs, liabilities, delays, and other significant issues related to environmental laws and regulations are inherent in the gathering, transportation, storage, processing, and treating of natural gas, fractionation, transportation, and storage of NGLs, and crude oil transportation and production handling as well as waste disposal practices and construction activities. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil and/or criminal penalties, the imposition of remedial obligations, the imposition of
stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, and delays or denials in granting permits.
Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, for the remediation of contaminated areas and in connection with spills or releases of materials associated with natural gas, oil, and wastes on, under or from our properties and facilities. Private parties, including the owners of properties through which our pipeline and gathering systems pass and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third-party hydrocarbon storage and processing or oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours.
We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.
In addition, climate change regulations and the costs associated with the regulation of emissions of greenhouse gases (GHGs) have the potential to affect our business. Regulatory actions by the Environmental Protection Agency or the passage of new climate change laws or regulations could result in increased costs to operate and maintain our facilities, install new emission controls on our facilities, or administer and manage our GHG compliance program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Climate change and GHG regulation could also reduce demand for our services.
We expect that certain aspects of the Tax Cuts and Jobs Act signed into law on December 22, 2017 (Tax Reform), including regulatory liabilities relating to reduced corporate federal income tax rates, could adversely impact our financial condition and our future financial results.
Certain ofTax Reform made significant changes to the U.S. federal income tax rules applicable to both individuals and entities, including among other things, a reduction in corporate federal income tax rates. The rates we charge to our customers are subject to the rate-making policies of the FERC. These policies permit us to include in our cost-of-service an income tax allowance that includes a deferred income tax component. The recently enacted Tax Reform makes significant changes to the U.S. federal income tax rules applicable to both individuals and entities, including among other things, a reduction in corporate federal income tax rates. Although we expect the decreased federal income tax rates will require us to return amounts to certain customers for this item through future rates and have recognized a regulatory liability, the details of any regulatory implementation guidance remain uncertain.
Item 1B. Unresolved Staff Comments
Not applicable.
Item 2. Properties
Please read “Business” for a description of the location and general character of our principal physical properties. We generally own our facilities, although a substantial portion of our pipeline and gathering facilities is constructed and maintained pursuant to rights-of-way, easements, permits, licenses, or consents on and across properties owned by others.
Item 3. Legal Proceedings
Environmental
Certain reportable legal proceedings involving governmental authorities under federal, state, and local laws regulating the discharge of materials into the environment are described below. While it is not possible for us to predict the final outcome of the proceedings which are still pending, we do not anticipate a material effect on our consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings.
On June 13, 2013, an explosion and fire occurred at our formerly owned Geismar olefins plant and rendered the facility temporarily inoperable (Geismar Incident). On October 21, 2013, the EPA, Region 6, issued an Inspection Report pursuant to the Clean Air Act’s Risk Management Program following its inspection of the facility on June 24 through June 28, 2013. The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating procedures, employee training, and other matters. On June 16, 2014, we received a request for information related to the Geismar Incident from the EPA under Section 114 of the Clean Air Act to which we responded on August 13, 2014. The EPA could issue penalties pertaining to final determinations.
On February 21, 2017, we received notice from the Environmental Enforcement Section of the United States Department of Justice (DOJ) regarding certain alleged violations of the Clean Air Act at our Moundsville facility as set forth in a Notice of Noncompliance issued by the EPA on January 14, 2016. The notice includes an offer to avoid further legal action on the alleged violations by paying $2 million. In discussion with the DOJ and the EPA, the EPA has indicated its belief that additional similar violations have occurred at our Oak Grove facility and has expressed interest in pursuing a global settlement. On January 19,July 23, 2018, we received an offer from the DOJ to globally settle the government’s claim for civil penalties associated with the alleged violations at both the Moundsville and the Oak Grove facilities for $1.955$1.6 million. We are currently evaluatingcontinuing to work with the penalty assessment and the proposed global settlement offer and will respondagencies to the agencies.resolve this matter.
On May 5, 2017, we entered into a Consent Order with the Georgia Department of Natural Resources, Environmental Protection Division (GADNR) pertaining to alleged violations of the Georgia Water Quality Control Act and associated rules arising from a permit issued by GADNR for construction of theTransco’s Dalton Project.expansion project. Pursuant to the Consent Order, we paid a fine of $168,750 and agreed to perform a Corrective Action Order to remedyPlan, the alleged violations.completion of which is pending.
On JanuaryMarch 19, 2018, we received noticea Notice of Violation from the PHMSAEPA, Region 8, regarding certain alleged violations of PHMSA regulations in connection with a fire and release of liquid ethane that occurredthe Clean Air Act at our Houston Meter Station located near Houston, Washington County, PA on December 24, 2014.Ignacio Gas Plant in Durango, Colorado, following a previous on-site inspection of the facility. We were subsequently informed that this matter has been referred to the DOJ for handling. The Notice of Probable Violation and Proposed Civil Penalty issued by PHMSA alleges failure to timely notify the National Response Center of a release of a hazardous
liquid resulting in a fire or explosion and failure to verify that the facility was constructed, inspected, tested, and calibrated in accordance with comprehensive written specifications or standards and proposes a total civildoes not contain an initial penalty of $174,100.assessment. We are currently evaluating the penalty assessment and will respondhave responded to the agency.alleged violations and continue to work with the agencies to resolve this matter.
On March 20, 2018, we also received a Notice of Violation from the EPA, Region 8, regarding certain alleged violations of the Clean Air Act at our Parachute Creek Gas Plant in Parachute, Colorado, following a previous on-site inspection of the facility. We were informed that this matter has been referred to the DOJ for handling. The Notice of Violation does not contain an initial penalty assessment. We have responded to the alleged violations and continue to work with the agencies to resolve this matter.
On August 27, 2018, Northwest Pipeline LLC received a Notice of Violation/Cease and Desist Order from the Colorado Department of Public Health & Environment regarding certain alleged violations of the Colorado Water Quality Control Act and its General Permit under the Colorado Discharge Permit System related to its stormwater management practices at two construction sites. The Notice of Violation does not contain an initial penalty assessment. We have responded to the alleged violations and continue to work with the agency to resolve this matter.
Other environmental matters called for by this Item are described under the caption “Environmental Matters” in Note 1718 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements included under Part II, Item 8 Financial Statements of this report, which information is incorporated by reference into this Item.
Other Litigation
The additional information called for by this Item is provided in Note 1718 – 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.
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, 2018,21, 2019, are listed below. Williams Partners L.P. merged with ACMP in February 2015 (the ACMP Merger). ACMP was the surviving entity in the ACMP Merger and changed its name to Williams Partners L.P. References in the biographical information below to (a) “Pre-merger WPZ” will mean Williams Partners L.P. prior to the ACMP Merger and (b) “ACMP/WPZ” will refer to both ACMP prior to and after the ACMP Merger, when it changed its name to Williams Partners L.P.
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| Name and Title | | Age | | Period of Service | | Business Experience in Past Five Years |
| Alan S. Armstrong | | 56 | | 2011 to present | | Director, Chief Executive Officer, and President, The Williams Companies, Inc. |
| Age: 55 |
| Position held since January 2011. |
| Mr. Armstrong has served as ourDirector, Chief Executive Officer, and President and a director
| | | | 2015 to 2018 | | Chairman of Williams since January 2011. Mr. Armstrong has served as a directorthe Board, ACMP/WPZ |
| | | | 2014 to 2018 | | Chief Executive Officer, ACMP/WPZ |
| | | | 2012 to 2018 | | Director of the general partner, of ACMP/WPZ since 2012, as Chief Executive Officer of ACMP/WPZ since December 31, 2014, and as Chairman of the Board of ACMP/WPZ since February 2, 2015. Mr. Armstrong also served as |
| | | | 2011 to 2015 | | Chairman of the Board and Chief Executive Officer of the general partner of Pre-merger WPZ from 2011 until the ACMP Merger, as Senior Vice President - Midstream of Pre-merger WPZ from 2010 to 2011, and a director and Chief Operating Officer of Pre-merger WPZ from 2005 to 2010. From 2002 to 2011, Mr. Armstrong served as Williams’ Senior Vice President - Midstream and acted as president of our midstream business. From 1999 to 2002, Mr. Armstrong was Vice President, Gathering and Processing in our midstream business and from 1998 to 1999 was Vice President, Commercial Development. Mr. Armstrong has served as a director of BOK Financial Corporation, a financial services company, since 2013.
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| Walter J. Bennett | | 49 | | 2015 to present | | Senior Vice President- West, The Williams Companies, Inc. |
| Senior Vice President - West |
| | Age: 48 |
| | Position held since January 2015.2013 to 2018 |
| | Mr. Bennett has served as our Senior Vice President - West since January 2015. Mr. Bennett has served as Senior Vice President - West of the general partner, ACMP/WPZ
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| | | | 2017 | | Director of the general partner, ACMP/WPZ since December 2013 and as |
| | | | 2015 | | Senior Vice President - West of the general partner, of Pre-merger WPZ from January 2015 until the ACMP Merger. Mr. Bennett previously served as a director |
| John D. Chandler | | 49 | | 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, of ACMP/WPZ from February 2017 through November 2017. Mr. Bennett was formerly |
| | | | 2009 to 2014 | | Senior Vice President and Chief OperatingFinancial Officer, of Chesapeake Midstream Development and served as Magellan GP, LLC |
| Debbie Cowan | | 41 | | 2018 to present | | Senior Vice President - Operations at BoardwalkChief 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 | | 53 | | 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, ACMP/WPZ |
| | | | 2015 to 2017 | | President / Executive Vice President, Questar Pipeline Partners.
/ Questar Corporation |
| | | | 2010 to 2015 | | President and Chief Executive Officer, PacifiCorp Energy |
| Scott A. Hallam | | 42 | | 2019 to present | | Senior Vice President - Atlantic-Gulf, The Williams Companies, Inc. |
| Senior Vice President - Atlantic-Gulf | | | | 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 | | 53 | | 2017 to present | | Senior Vice President - Engineering Services, The Williams Companies, Inc. |
| Senior Vice President - Engineering Services | | | | 2017 | | Vice President - Commercial - West, The Williams Companies, Inc. |
| | | | 2015 to 2017 | | Vice President - Commercial & Business Development, The Williams Companies, Inc. |
| | | | 2011 to 2015 | | General Manager - Eagle Ford, ACMP |
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John D. Chandler | Senior Vice President and Chief Financial Officer |
| Age: 48 |
| Position held since September 2017. |
| Mr. Chandler has served as our Senior Vice President and Chief Financial Officer since September 2017, and as a director of the general partner of ACMP/WPZ since November 2017. Mr. Chandler most recently served as Senior Vice President and Chief Financial Officer of Magellan GP, LLC, the general partner of Magellan Midstream Partners, LP from 2009 until his retirement in March 2014. From 2003 until 2009, he served as Senior Vice President and Chief Financial Officer for the general partner of Magellan Midstream Holdings, L.P. From 1992 until 2002, Mr. Chandler held various accounting and finance roles within Williams and MAPCO Inc., prior to its acquisition by Williams. Mr. Chandler has served as a director of Matrix Service Company since June 2017.
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Micheal G. Dunn | Executive Vice PresidentName and Chief Operating OfficerTitle |
| | Age: 52Age |
| | Position held since February 2017.Period of Service |
| | Mr. Dunn has served as our Executive Vice President and Chief Operating Officer and as a director of the general partner of ACMP/WPZ since February 2017. Previously, Mr. Dunn served as President of Questar Pipeline and as Executive Vice President of Questar Corporation from 2015 through 2017. Prior to that, Mr. Dunn served as President and Chief Executive Officer of PacifiCorp Energy from 2010 through 2015, a subsidiary of Berkshire Hathaway Energy. Earlier, Mr. Dunn was president of Kern River Gas Transmission Company, a Berkshire Hathaway Energy interstate natural gas pipeline subsidiary. He joined Kern RiverBusiness Experience in 1990, having served in various leadership roles in the areas of operations, construction, engineering and information technology before being named President of Kern River in 2007. Mr. Dunn began his career with Williams as an operations engineer and spent 14 years with the company in a variety of technical and leadership roles.
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Frank J. Ferazzi | Senior Vice President - Atlantic Gulf |
| Age: 61 |
| Position held since June 2017 |
| Mr. Ferazzi has served as our Senior Vice President - Atlantic-Gulf since June 2017. Previously, Mr. Ferazzi served as VP & GM Eastern Interstates from November 2014 through June 2017, and previously as VP & GM Transco from January 2013 through January 2015. Prior to that, Mr. Ferazzi served as VP Commercial Operations - Gas Pipeline from May 2010 through December 2012.
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John E. Poarch | Senior Vice President - Engineering Services |
| Age: 52 |
| Position held since November 2017. |
| Mr. Poarch has served as our Senior Vice President - Engineering Services since November 2017. Previously, he served as VP Commercial West OA from March 2017 through November 2017, and before that, as VP Commercial & Business Development from January 2015 through March 2017. Previously, Mr. Poarch was the general manager for Access Midstream’s Eagle Ford operations.
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| Past Five Years |
| James E. Scheel | Senior Vice President - Northeast G&P
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| 54 | | Age: 532014 to present |
| | Position held since January 2014. |
| Mr. Scheel has served as our Senior Vice President - Northeast G&P, since January 2014. Mr. Scheel served as a director of ACMP/WPZ from the ACMP Merger until November 2017. Mr. Scheel served as a directorThe Williams Companies, Inc.
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| Senior Vice President - Northeast G&P | | | | 2015 to 2017 | | Director of the Pre-merger WPZ general partner, from ACMP/WPZ |
| | | | 2012 until the ACMP Merger. Mr. Scheel served as a directorto 2015 | | Director of the Pre-merger ACMP general partner, from December Pre-merger WPZ |
| | | | 2012 to February 2014. Previously, Mr. Scheel served as 2014 | | Director of the general partner, Pre-merger ACMP |
| | | | 2012 to 2014 | | Senior Vice President - Corporate Strategic Development, The Williams Companies, Inc. |
| | | | 2012 to 2014 | | Senior Vice President - Corporate Strategic Development of Williams and the general partner, Pre-merger WPZ general partner from February 2012 to January 2014. Mr. Scheel served as Vice President of Business Development of Williams’ midstream business from January 2011 to February 2012.
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| Ted T. Timmermans | Vice President, Controller, and Chief Accounting Officer
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| 62 | | Age: 612005 to present |
| | Position held since July 2005. |
| Mr. Timmermans has served as our Vice President, Controller, and Chief Accounting Officer, since July 2005. Mr. Timmermans has served in the same roles forThe Williams Companies, Inc.
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| Vice President, Controller, and Chief Accounting Officer | | | | 2015 to 2018 | | Vice President, Controller, and Chief Accounting Officerof the general partner, of ACMP/WPZ since the ACMP Merger. Mr. Timmermans served as Chief Accounting Officer of WMZ from 2008 until its merger with Pre-Merger WPZ in 2010. Previously, Mr. Timmermans served as our Assistant Controller from 1998 to 2005.
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| T. Lane Wilson | | 52 | | 2018 to present | | Senior Vice President and General Counsel, and Chief Compliance Officer
The Williams Companies, Inc. |
| Senior Vice President and General Counsel | Age: 51 |
| | Position held since April 2017. |
| | Mr. Wilson has served as 2017 to 2018
| | Senior Vice President, General Counsel, and Chief Compliance Officer, since April 2017. PriorThe Williams Companies, Inc. |
| | | | 2009 to joining Williams, Mr. Wilson served as a 2017 | | United States Magistrate Judge for the Northern District of Oklahoma from 2009 until he joined Williams in April 2017. Mr. Wilson previously served as a shareholder and member of the board of directors of the Hall Estill law firm from 1994 through 2008.
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| Chad J. Zamarin | Senior Vice President - Corporate Strategic Development
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| 42 | | Age: 412017 to present |
| | Position held since June 2017. |
| Mr. Zamarin has served as our Senior Vice President - Corporate Strategic Development, since June 2017. Mr. Zamarin has served as a directorThe Williams Companies, Inc.
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| Senior Vice President - Corporate Strategic Development | | | | 2017 to 2018 | | Director of the general partner, of ACMP/WPZ since November 2017. Previously, he served as |
| | | | 2014 to 2017 | | President - Pipeline and Midstream, at Cheniere Energy from |
| | | | 2011 to 2014 through 2017. Prior to joining Cheniere, Mr. Zamarin served as the | | Chief Operating Officer, at NiSource Midstream, LLC and NiSource Energy Ventures, LLC as well as the President of Pennant Midstream, LLC, a joint venture with Hilcorp Energy.
|
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is listed on the New York Stock Exchange under the symbol “WMB.” At the close of business on February 19, 2018,15, 2019, we had approximately 6,9796,780 holders of record of our common stock. The high and low sales price ranges (New York Stock Exchange composite transactions) and dividends declared by quarter for each of the past two years are as follows:
|
| | | | | | | | | | | |
| | High | | Low | | Dividend |
| 2017 | | | | | |
| First Quarter | $ | 32.69 |
| | $ | 27.68 |
| | $ | 0.30 |
|
| Second Quarter | 31.25 |
| | 27.65 |
| | 0.30 |
|
| Third Quarter | 32.18 |
| | 28.76 |
| | 0.30 |
|
| Fourth Quarter | 30.72 |
| | 26.82 |
| | 0.30 |
|
| 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 |
|
Some of our subsidiaries’ borrowing arrangements may limit the transfer of funds to us. These terms have not impeded, nor are they expected to impede, our ability to pay dividends. On February 21, 2018, our board of directors approved a regular quarterly dividend of $0.34 per share payable on March 26, 2018.
Performance Graph
Set forth below is a line graph comparing our cumulative total stockholder return on our common stock (assuming reinvestment of dividends) with the cumulative total return of the S&P 500 Stock Index and the Bloomberg Americas Pipelines Index for the period of five fiscal years commencing January 1, 2013.2014. The Bloomberg Americas Pipelines Index is composed of Enbridge Inc., Kinder Morgan, Inc., TransCanada Corporation, ONEOK, Inc., Pembina Pipeline Corporation, Cheniere Energy, Inc., Targa Resources Corp., Inter Pipeline Ltd., Keyera Corp., AltaGas Ltd., Plains GP Holdings,Tallgrass Energy L.P., and Williams. The graph below assumes an investment of $100 at the beginning of the period.
| | | | 2012 | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 | 2013 | | 2014 | | 2015 | | 2016 | | 2017 | | 2018 |
| The Williams Companies, Inc. | 100.0 | | 122.8 | | 149.1 | | 90.6 | | 119.1 | | 121.5 | 100.0 | | 121.4 | | 73.8 | | 97.0 | | 98.9 | | 75.3 |
| S&P 500 Index | 100.0 | | 132.4 | | 150.5 | | 152.5 | | 170.8 | | 208.1 | 100.0 | | 113.7 | | 115.2 | | 129.0 | | 157.2 | | 150.3 |
| Bloomberg Americas Pipelines Index | 100.0 | | 111.0 | | 130.0 | | 71.5 | | 105.0 | | 104.7 | 100.0 | | 117.1 | | 64.4 | | 94.5 | | 94.3 | | 80.8 |
Item 6. Selected Financial Data
The following financial data at December 31, 20172018 and 2016,2017, and for each of the three preceding years in the period ended December 31, 2017,2018, should be read in conjunction with the other financial information included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, Financial Statements and Supplementary Data of this Form 10-K. All other financial data has been prepared from our accounting records.
| | | | 2017 | | 2016 | | 2015 | | 2014 | | 2013 | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| | (Millions, except per-share amounts) | (Millions, except per-share amounts) |
Revenues (1) | $ | 8,031 |
| | $ | 7,499 |
| | $ | 7,360 |
| | $ | 7,637 |
| | $ | 6,860 |
| $ | 8,686 |
| | $ | 8,031 |
| | $ | 7,499 |
| | $ | 7,360 |
| | $ | 7,637 |
|
| Income (loss) from continuing operations (2) | 2,509 |
| | (350 | ) | | (1,314 | ) | | 2,335 |
| | 679 |
| |
| Net income (loss) from continuing operations (1) | | 193 |
| | 2,509 |
| | (350 | ) | | (1,314 | ) | | 2,335 |
|
| Amounts attributable to The Williams Companies, Inc.: | | | | | | | | | | | | | | | | | | |
| Income (loss) from continuing operations (2) | 2,174 |
| | (424 | ) | | (571 | ) | | 2,110 |
| | 441 |
| |
| Net income (loss) from continuing operations (1) | | (155 | ) | | 2,174 |
| | (424 | ) | | (571 | ) | | 2,110 |
|
| Diluted earnings (loss) per common share: | | | | | | | | | | | | | | | | | | |
| Income (loss) from continuing operations (2) | 2.62 |
| | (.57 | ) | | (.76 | ) | | 2.91 |
| | .64 |
| |
| Net income (loss) from continuing operations (1) | | (.16 | ) | | 2.62 |
| | (.57 | ) | | (.76 | ) | | 2.91 |
|
Total assets at December 31 (3) | 46,352 |
| | 46,835 |
| | 49,020 |
| | 50,455 |
| | 27,065 |
| 45,302 |
| | 46,352 |
| | 46,835 |
| | 49,020 |
| | 50,455 |
|
Commercial paper and long-term debt due within one year at December 31 (4) | 501 |
| | 878 |
| | 675 |
| | 802 |
| | 226 |
| 47 |
| | 501 |
| | 878 |
| | 675 |
| | 802 |
|
Long-term debt at December 31 (3) | 20,434 |
| | 22,624 |
| | 23,812 |
| | 20,780 |
| | 11,276 |
| 22,367 |
| | 20,434 |
| | 22,624 |
| | 23,812 |
| | 20,780 |
|
| Stockholders’ equity at December 31 (3) (5) | 9,656 |
| | 4,643 |
| | 6,148 |
| | 8,777 |
| | 4,864 |
| |
| Stockholders’ equity at December 31 (2) | | 14,660 |
| | 9,656 |
| | 4,643 |
| | 6,148 |
| | 8,777 |
|
| Cash dividends declared per common share | 1.200 |
| | 1.680 |
| | 2.450 |
| | 1.958 |
| | 1.438 |
| 1.360 |
| | 1.200 |
| | 1.680 |
| | 2.450 |
| | 1.958 |
|
| |
| (1) | Revenues for 2014 increased reflecting the consolidation of ACMP beginning in third quarter and new Canadian construction management services. |
| |
(2) | IncomeNet income (loss) from continuing operations: |
For 2018 includes a $1.849 billion impairment of certain assets located in the Barnett Shale region, partially offset by a $591 million gain on the sale of our Four Corners area assets, a $141 million gain on the deconsolidation of certain Permian assets, and a $101 million gain from the sale of our Gulf Coast pipeline system assets;
For 2017 includes a $1.923 billion benefit for income taxes resulting from Tax Reform rate change, a $1.095 billion pre-tax gain on the sale of our Geismar Interest, partially offset by $1.248 billion of pre-tax impairments of certain assets, and $776 million of pre-tax regulatory charges resulting from Tax Reform;
For 2016 includes an $873 million impairment of certain assets and a $430 million impairment of certain equity-method investments;
For 2015 includes a $1.4 billion impairment of certain equity-method investments and a $1.1 billion impairment of goodwill;
For 2014 includes $2.5 billion pre-tax gain recognized as a result of remeasuring to fair value the equity-method investment we held before we acquired a controlling interest in ACMP, $246 million of insurance recoveries related to the 2013 Geismar Incident, and $154 million of cash received related to a contingency settlement. 2014 also includes $78 million of pre-tax equity losses from Bluegrass Pipeline and Moss Lake related primarily to the underlying write-off of previously capitalized project development costs and $76 million of pre-tax acquisition, merger, and transition expenses related to our acquisition of ACMP;
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.ACMP.
| |
(3)(2) | The increases in 2014 reflect assets acquired and debt assumed primarily related to our acquisition of ACMPin 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.
December 31: |
| |
(4) | The increase in 2014 reflects borrowings under WPZ’s commercial paper program, which was initiated in 2013. |
| |
(5) | The increase in 2017 includes our issuance of common stock as part of our Financial Repositioning. |
•The increase in 2018 reflects our merger with WPZ;
•The increase in 2017 includes our issuance of common stock as part of our Financial Repositioning.
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.NGLs through our gas pipeline and midstream business. Our operations are located principally in the United States. We have one reportable segment, Williams Partners. All remaining business activities are included in Other.
Williams Partners
Williams Partners consists of our consolidated master limited partnership, WPZ, which includes gas pipeline and midstream businesses. The gas pipeline businesses 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; and are comprised of several wholly owned and partially owned subsidiaries and joint project investments. As of December 31, 2017, we own 74 percent of the interests in WPZ.
Williams Partners’ gas pipeline businesses consist primarily of Transco and Northwest Pipeline. The gas pipeline business also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent equity-method investment in Gulfstream and a 41 percent interest in Constitution (a consolidated entity), which is developing a pipeline project. (See Note 3 – Variable Interest Entities of Notes to Consolidated Financial Statements.) As of December 31, 2017, Transco and Northwest Pipeline owned and operated a combined total of approximately 13,600 miles of pipelines with a total annual throughput of approximately 4,533 Tbtu of natural gas to large and peak-day delivery capacity of approximately 18.8 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 Note 2 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements.) The primary service areas are concentrated in major producing basins in Colorado, Texas, Oklahoma, Kansas, New Mexico, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio, which include the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, and Utica shale plays as well as the Mid-Continent region.
The midstream businesses include equity-method investments in natural gas gathering and processing assets and NGL fractionation and transportation assets, including a 62 percent equity-method investment in UEOM, a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, a 60 percent equity-method investment in Discovery, a 50 percent equity-method investment in OPPL, and Appalachia Midstream Services, LLC, which owns an approximate average 66 percent equity-method investment interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments), as well as our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see Note 5 – Investing Activities of Notes to Consolidated Financial Statements).
The midstream businesses previously included Canadian midstream operations, which were comprised of an oil sands offgas processing plant near Fort McMurray, Alberta and an NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, these Canadian operations were sold.
Williams Partners’ ongoing strategy is to safely and reliably operate large-scale, interstate natural gas transmission and midstream infrastructures where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers and investing in growing markets and areas of increasing natural gas demand.
Williams Partners’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.
OtherThe ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers. These services include natural gas gathering, processing, treating, and compression, NGL fractionation and transportation, crude oil production handling and transportation, marketing services for NGL, oil and natural gas, as well as storage facilities.
OtherPrior to our merger with Williams Partners L.P., our previously consolidated master limited partnership, in August 2018, we had one reportable segment, Williams Partners. Beginning in the third-quarter 2018, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are now presented within the following reportable segments: Northeast G&P, Atlantic-Gulf, and West. Prior period segment disclosures have been recast for the new segment presentation. Our reportable segments are comprised of the following businesses:
Northeast G&P is comprised of our midstream gathering and processing businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern Ohio, as well as a 66 percent interest in Cardinal (a consolidated entity), a 62 percent equity-method investment in UEOM, a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).
Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transco, and significant natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated entity), which is a proprietary floating production system, and various petrochemical and feedstock pipelines in the Gulf Coast region, as well as a 50 percent equity-method investment in Gulfstream, a 60 percent equity-method investment in Discovery, and a 41 percent interest in Constitution (a consolidated entity), which is developing a pipeline project (see Note 4 – Variable Interest Entities of Notes to Consolidated Financial Statements).
West is comprised of our interstate natural gas pipeline, Northwest Pipeline, and our gathering, processing, and treating operations in Colorado, Wyoming, and the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware, and Permian basins. This segment also includes our NGL and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in OPPL, a 50 percent interest in Jackalope (an equity-method investment following deconsolidation as of June 30, 2018), a 50 percent equity-method investment in RMM, a 15 percent equity-method investment in Brazos Permian II, and our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-
Continent region (see Note 6 – Investing Activities of Notes to Consolidated Financial Statements). West also included our former natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado (see Note 3 – Divestitures of Notes to Consolidated Financial Statements).
Other includes our previously owned operations, including an 88.5 percent undivided interest in an olefins production facility in Geismar, Louisiana, which was sold in July 2017 (see Note 3 – Divestituresof Notes to Consolidated Financial Statements),anda refinery grade propylene splitter in the Gulf region, which was sold in June 2017. This segment also included our previously owned Canadian assets, which included an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, these Canadian operations were sold. Other also includes minor business activities that are not operating segments, as well as corporate operations. Other also includes certain domestic olefins pipeline assets as well as certain Canadian assets, which included a liquids extraction plant located near Fort McMurray, Alberta, that began operations in March 2016, and a propane dehydrogenation facility which was under development. In September 2016, the Canadian assets were sold.
Financial Repositioning
In January 2017, we entered into agreements with WPZ, wherein we permanently waived the general partner’s IDRs and converted our 2 percent general partner interest in WPZ to a noneconomic interest in exchange for 289 million newly issued WPZ common units. Pursuant to this agreement, we also purchased approximately 277 thousand WPZ common units for $10 million. Additionally, we purchased approximately 59 million common units of WPZ at a price of $36.08586 per unit in a private placement transaction, funded with proceeds from our equity offering (see Note 14 – Stockholders’ Equity of Notes to Consolidated Financial Statements). According to the terms of this agreement, concurrent with WPZ’s quarterly distributions in February 2017 and May 2017, we paid additional consideration totaling $56 million to WPZ for these units. Subsequent to these transactions and as of December 31, 2017, we own a 74 percent limited partner interest in WPZ.
Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto included in Part II, Item 8 of this report.
Dividends
In December 2017,2018, we paid a regular quarterly dividend of $0.30$0.34 per share. On February 21, 2018,20, 2019, our board of directors approved a regular quarterly dividend of $0.34$0.38 per share payable on March 26, 2018.25, 2019.
Overview
Net income (loss) attributable to The Williams Companies, Inc., for the year ended December 31, 2017, changed favorably2018, decreased by $2.598$2.329 billion compared to the year ended December 31, 2016,2017, reflecting a $1.949$2.112 billion improvement inincrease to the provision (benefit) for income taxes primarily due to Tax Reform,driven by the absence of $430a 2017 benefit resulting from Tax Reform and a $159 million of impairments of equity-method investments incurred in 2016, a $219 million increase in Other investing income (loss) – net primarily associated with the disposition of certain equity-method investments in 2017, a $204 million increasedecrease in operating income and reduced interest expense, partially offset by a $261 million increase in net income attributable to noncontrolling interests primarily due to increased income at WPZ.income. The increasedecrease in operating income reflects a gainan increase of $1.095 billion$667 million in Impairment of certain assets and $403 million in lower gains from the sale of our Geismar Interest, increased service revenue from expansion projects, and lower costs and expenses,certain assets. These unfavorable changes were partially offset by athe absence of $674 million in regulatory chargecharges resulting from Tax Reform in 2017, and a $375$190 million increase in impairments of certain assets,service revenues primarily resulting from expansion projects placed into service in 2017 and a $184 million decrease in product margins primarily due2018.
WPZ Merger
On August 10, 2018, we completed our merger with Williams Partners L.P. (WPZ), pursuant to the loss of olefins volumes as a resultwhich we acquired all of the saleapproximately 256 million publicly held outstanding common units of WPZ in exchange for 382 million shares of our Gulf Olefins and Canadian operations.
Tax Reform
In December 2017,common stock in a noncash equity transaction. Williams continued as the Tax Cuts and Jobs Act was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent (Tax Reform). As a result, we have remeasured our existing deferred income tax assets and liabilities, to reflect the expected future realization of existing temporary differences at the lower income tax rate. This resulted in the recognition of a net income tax provision benefit of $1.923 billion for the year ended December 31, 2017. Certain adjustments within the provision benefit are considered provisional and are potentially subject to change in the future. (See Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements.)
Transco and Northwest Pipeline have recognized regulatory liabilities to reflect the probable return to customers through future rates of the future decrease in income taxes payable associated with Tax Reform. These liabilities represent an obligation to return amounts directly to our customers. The regulatory liabilities were recorded in December 2017 through regulatory charges to operating income totaling $674 million.surviving entity. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements.)
FERC Income Tax Policy Revision
On March 15, 2018, the FERC issued a revised policy statement (the revised policy statement) regarding the recovery of income tax costs in rates of natural gas pipelines. The timingFERC found that an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and actual amounta return on equity pursuant to the discounted cash flow methodology. As a result, the FERC will no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. One of the benefits of the recent WPZ Merger is to allow our FERC-regulated pipelines to continue to recover an income tax allowance in their cost of service rates.
On July 18, 2018, the FERC issued an order dismissing the requests for rehearing and clarification of the revised policy statement. In addition, the FERC provided guidance that an MLP pipeline (or other pass-through entity) no longer recovering an income tax allowance pursuant to the revised policy may eliminate previously accumulated deferred income taxes (ADIT) from its cost of service instead of flowing these ADIT balances to ratepayers. This guidance, if implemented, would significantly mitigate the impact of the revised policy statement. However, the FERC stated that the revised policy statement and such guidance do not establish a binding rule but are instead expressions of general
policy intent designed to provide guidance by notifying entities of the course of action the FERC intends to follow in future adjudications. To the extent the FERC addresses these issues in future proceedings, it will consider any arguments regarding not only the application of the revised policy to the facts of the case, but also any arguments regarding the underlying validity of the policy itself. The FERC’s guidance on ADIT likely will be challenged by customers and state commissions, which would result in a long period of revenue uncertainty for pipelines eliminating ADIT from their cost of service. The WPZ Merger has the additional benefit of eliminating this uncertainty.
On March 15, 2018, the FERC also issued a Notice of Proposed Rulemaking proposing a filing process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent reduction in the corporate income tax rate in the Tax Cuts and Jobs Act (Tax Reform) and the revised policy statement. On July 18, 2018, the FERC issued a Final Rule, retaining the filing requirement and reaffirming the options that pipelines have to either reflect the reduced tax rate or explain why no rate change is necessary. The FERC also clarified that a natural gas company organized as a pass-through entity and all of whose income or losses are consolidated on the federal income tax return willof its corporate parent is considered to be subject to the federal corporate income tax and is thus eligible for a tax allowance. We believe this Final Rule and the previously discussed WPZ Merger allow for the continued recovery of income tax allowances in Transco’s and Northwest Pipeline’s rates. Transco’s August 31, 2018, general rate case filing reflects a tax allowance based on this clarification, and the FERC’s September 28, 2018, order in that rate case proceeding finds that Transco is exempt from the Final Rule’s Form 501-G filing requirement. In addition, on October 19, 2018, Northwest Pipeline filed a petition requesting that the FERC waive its Form 501-G filing requirement under this Final Rule because (i) the reduction in the corporate income tax is already addressed in Northwest Pipeline’s 2017 rate settlement, and (ii) as discussed above, the WPZ Merger allows for the continued recovery of income tax allowances in Northwest Pipeline’s rates. The FERC agreed and granted Northwest Pipeline’s petition for waiver on November 19, 2018. On October 11, 2018 and December 6, 2018, Discovery Gas Transmission, LLC and Pine Needle LNG Company, LLC, respectively, filed their Form 501-Gs, including explanations as to why no adjustments to rates are needed.
On March 15, 2018, the FERC also issued a Notice of Inquiry seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to ADIT amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action. We are evaluating the impact of these developments on our interstate natural gas pipelines and currently expect any associated impacts would be prospective and determined through subsequent rate proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform. It is reasonably possible that future negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing service.tariff-based rates collected by our interstate natural gas pipelines may be adversely impacted.
Revenue Recognition
As a result of the adoption of Accounting Standards Update 2014-09, Revenues from Contracts with Customers (ASC 606), in January 2018, we expect that our 2018now record revenues will increase in situationsfor transactions where we receive noncash consideration, which exists primarily in certain of our gas processing contracts where we receivethat provide commodities as full or partial consideration for services provided. This increaseThese revenues are reflected as Service revenues - commodity consideration in the Consolidated Statement of Operations. The costs associated with these revenues, will be offset by a similar increase in costs andprimarily related to natural gas shrink replacement, are reported as Processing commodity expenses when the commodities received are subsequently sold. Based on commodities received during 2017 as consideration for services and market prices during 2017, we estimate the impact to. The revenues and costs wouldassociated with the subsequent sale of the commodity consideration received is reflected within Product sales and Product costs in the Consolidated Statement of Operations. Service revenues - commodity consideration plus Product sales, less Product costs and Processing commodity expenses represents the margin that we have been approximately $350 million.historically characterized as commodity margin. This presentation is being reflected prospectively in the Consolidated Statement of Operations. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements.)
Additionally, we expect future revenues will beare impacted by application of the new accounting standard to certain contracts for which we received prepayments for services and have recorded deferred revenue (contract liabilities). For these contracts, which underwent modifications in periods prior to January 1, 2018, the modification is treated as a termination of the existing contract and the creation of a new contract. The new accounting guidance requires that the transaction price, including any remaining deferred revenue from the old contract, be allocated to the performance obligations over
the term of the new contract. As a result, we will recognize the deferred revenue over longer periods than application of revenue recognition under accounting guidance prior to January 1, 2018.
Filing of Rate Case
On August 31, 2018, Transco filed a general rate case with the FERC for an overall increase in rates. In September 2018, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general rate filing to be effective March 1, 2019, subject to refund and the outcome of a hearing. The application of ASC 606specific rates that reflected a rate decrease were accepted, without suspension, to prior periods related to these contracts would have resulted in lower revenues in 2016 and 2017. Revenues will also be lower in 2018 and 2019 than what would have been recorded under the previous guidance, offset by increased revenues in later reporting periods given the longer period of recognition.
We are adopting ASC 606 utilizing the modified retrospective transition approach, effective JanuaryOctober 1, 2018, as requested by recognizingTransco, and will not be subject to refund. The impact of these specific new rates is expected to reduce revenues by approximately $2 million per month beginning October 1, 2018.
RMM Equity-Method Investment
During the cumulative effectthird quarter of initially applying ASC 606 for periods prior2018, our joint venture, RMM, purchased a natural gas and oil gathering and natural gas processing business in Colorado’s Denver-Julesburg basin. Our initial economic ownership was 40 percent, which has since increased to January 1,50 percent at December 31, 2018, which we expect to result in a decrease of approximately $255 million, net of tax, tobased on additional capital contributions made since the opening balance of Total equityinitial purchase. This investment is reported in the Consolidated Balance Sheet. This adjustment is primarily associated with the impact to the timingWest segment.
Sale of deferred revenue (contract liabilities) for certain contracts as noted above.
Pension Deferred Vested Benefit Early Payout ProgramFour Corners Assets
In September 2017,October 2018, we initiated a programcompleted the sale of our natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado for total consideration of $1.125 billion, subject to pay out certain deferred vested pension benefits to reduce investment risk, cash funding volatility, and administrative costs. In December 2017,customary working capital adjustments. These assets were designated as held for sale during the lump-sum payments were made and the annuity payments were commenced in relation to this program.third quarter of 2018. As a result of these lump-sum payments, as well as lump-sum benefit payments made throughout 2017, settlement accounting was required. We settled $261this sale, we recorded a gain of approximately $591 million within the West segment in liabilities and recognized a pre-tax, non-cash settlement chargethe fourth quarter of $71 million. (See2018 (see Note 93 – Employee Benefit PlansDivestitures of Notes to Consolidated Financial Statements.)Statements).
Sale of Gulf Coast Pipeline Systems
In November 2018, we completed the sale of certain assets and operations located in the Gulf Coast area for $177 million in cash. These assets were designated as held for sale during the third quarter of 2018. As a result of this sale, we recorded a gain of approximately $101 million in the fourth quarter of 2018, consisting of $81 million in our Atlantic-Gulf segment and $20 million in Other (see Note 3 – Divestitures of Notes to Consolidated Financial Statements).
Brazos Permian II Equity-Method Investment
In December 2018, we entered into a joint venture partnership in the Delaware basin. Under the terms of the agreement, we contributed the majority of our existing Delaware basin assets in the West segment and $27 million in cash to the partnership in exchange for a 15 percent interest. Our partner operates the partnership, which consists of approximately 725 miles of gas gathering pipelines, 260 MMcf/d of natural gas processing, 75 miles of crude oil gathering pipelines, and 75 thousand barrels of oil storage. The partnership anticipates processing capacity in the Delaware basin to reach 460 MMcf/d and will be supported by over 500,000 acres of long-term dedications from major and independent oil and gas producers. We recorded our interest in the partnership as an equity-method investment and recognized a gain on the deconsolidation of our contributed assets of $141 million (see Note 6 – Investing Activities of Notes to Consolidated Financial Statements).
Expansion Project CompletionsUpdates
Virginia Southside II
In December 2017, the Virginia Southside IISignificant expansion project toupdates for the Transco system wasperiod, including projects placed into service.service are described below. Ongoing major expansion projects are discussed later in Company Outlook.
Northeast G&P
Susquehanna Supply Hub
During the first quarter of 2018, the remaining facilities that comprise the Susquehanna Supply Hub Expansion were fully commissioned. The project expanded Transco’s existing natural gas transmission system togetheradded two new compression facilities with greenfield facilities to provide incremental firm transportation capacity from our Station 210 in New Jersey and our Station 165 in Virginia to a new lateral extending from our Brunswick Lateral in Virginia. The project increased capacity by 250 Mdth/d.an additional 49,000 horsepower
New York Bay Expansionand 59 miles of 12- to 24-inch pipeline, and increased gathering capacity, allowing a certain producer to fulfill its commitment to deliver 850 Mdth/d to our Atlantic Sunrise development.
Atlantic-Gulf
Gulf Connector
In October 2017,January 2019, the New York Bay expansion to the Transco systemGulf Connector project was placed into service. TheThis project expanded Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 19565 in PennsylvaniaLouisiana to the Rockaway Delivery Lateral transfer pointdelivery points in Wharton and the Narrows meter station in New York.San Patricio Counties, Texas. The project increased capacity by 115475 Mdth/d.
DaltonAtlantic Sunrise
In August 2017,October 2018, the Dalton expansion to the Transco systemAtlantic Sunrise project was placed into service. This project expanded Transco’s existing natural gas transmission system togetheralong with greenfield facilities to provide incremental firm transportation capacity from ourthe northeastern Marcellus producing area to markets along Transco’s mainline as far south as Station 85 in west central Alabama. We placed a portion of the mainline project facilities into service in September 2017, which increased capacity by 400 Mdth/d. We placed additional mainline facilities into service in June 2018, which increased capacity by an additional 150 Mdth/d. In total, the project increased Transco’s capacity by 1,700 Mdth/d.
Garden State
In March 2018, Phase 2 of the Garden State Expansion project was placed into service. This project expanded Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 210 in New Jersey to marketsa new interconnection on our Trenton Woodbury Lateral in northwest Georgia. On AprilNew Jersey. Phase 1 2017, we began providing firm transportation service through the mainline portion of the project on an interim basis and wewas placed the full project into service in August 2017. The projectSeptember 2017, and together Phases 1 and 2 increased capacity by 448180 Mdth/d.
Hillabee
In July 2017, Phase I of the Hillabee Expansion Project was placed into service. The project involves an expansion of Transco’s existing natural gas transmission system from our Station 85 in west central Alabama to a new interconnection with the Sabal Trail pipeline in Alabama. The project will be constructed in phases, and all of the project expansion capacity is dedicated to Sabal Trail pursuant to a capacity lease agreement. We placed a portion of Phase I into service in June of 2017 and the remainder of Phase I into service in July of 2017. Phase I increased capacity by 818 Mdth/d. The in-service date of Phase II is planned for the second quarter of 2020 and together they are expected to increase capacity by 1,025 Mdth/d.
In March 2016, WPZ entered into an agreement with the member-sponsors of Sabal Trail to resolve several matters. In accordance with the agreement, the member-sponsors paid us an aggregate amount of $240 million in three equal installments as certain milestones of the project were met. The first $80 million payment was received in March 2016, the second installment was received in September 2016 and the third installment was received in July 2017. WPZ expects to recognize income associated with these receipts over the term of the capacity lease agreement.
In August 2017, the Court of Appeals for the District of Columbia Circuit granted an appeal of the FERC certificate order for the Southeast Market Pipelines projects (a group of related projects, including the Hillabee Expansion Project) filed by certain non-governmental organizations. In doing so, the court (i) remanded the matter to the FERC for preparation of an Environmental Impact Statement (EIS) that conforms with the court’s opinion regarding quantifying certain greenhouse gas emissions, and (ii) vacated the FERC’s certificate order for the projects, which would be effective following the court’s mandate (by court order, the mandate will not issue until after disposition of all petitions for rehearing). We, along with other intervenors, and the FERC filed petitions for rehearing with the court to overturn the remedy that would involve vacating the FERC certificate order, but on January 31, 2018 the court denied the petitions. In compliance with the court’s directive, on February 5, 2018, the FERC issued a Final Supplemental EIS for the projects, reaffirming that while the projects would result in temporary and permanent impacts on the environment, those impacts would not be significant. On February 6, 2018, we, along with other intervenors, and the FERC filed motions with the court to stay the issuance of the mandate in order to give the FERC time to re-issue the authorizations for the projects. The filing of the motions automatically stays the effectiveness of the court’s mandate. If the court’s mandate is issued prior to the FERC re-issuing the authorizations for the projects, we believe that the FERC will take the necessary steps (which may include issuing temporary certificate authority) to avoid any lapse in federal authorization for the projects.
Geismar olefins facility monetization
In July 2017, WPZ completed the sale of its Geismar Interest for $2.084 billion in cash. WPZ received a final working capital adjustment of $12 million in October 2017. Additionally, WPZ entered into a long-term supply and transportation agreement with the purchaser to provide feedstock to the plant via its Bayou Ethane pipeline system, which is expected to provide a long-term, fee-based revenue stream. (SeeNote 2 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements.)
Following this sale, the cash proceeds were used to repay WPZ’s $850 million term loan. WPZ has also been using these proceeds to fund a portion of the capital and investment expenditures that are a part of its growth portfolio.
Acquisition of additional interests in Appalachia Midstream Investments
During the first quarter of 2017, WPZ exchanged all of its 50 percent interest in DBJV for an increased interest in two natural gas gathering systems that are part of the Appalachia Midstream Investments and $155 million in cash. Following this exchange, WPZ has an approximate average 66 percent interest in the Appalachia Midstream Investments. WPZ also sold all of its interest in Ranch Westex JV LLC for $45 million. These transactions resulted in a total gain of $269 million reflected in Other investing income (loss) – net in the Consolidated Statement of Operations within the Williams Partners segment. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.)
Commodity Prices
NGL per-unit margins were approximately 6219 percent higher in 20172018 compared to 20162017 primarily due to a 4222 percent increase in realized per-unit non-ethane prices. The per-unit margin increase also reflects the absence of our former Canadian operations which had lower per-unit non-ethane margins in the prior year compared to our domestic operations. These favorable impacts were partially offset byprices and an approximate 269 percent increasedecrease in per-unit natural gas feedstock prices.
NGL margins are defined as NGL revenues less any applicable Btu replacement cost, plant fuel, and third-party transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. Our equity volumes include NGLs where we own the rights to the value from NGLs recovered at our plants under both “keep-whole” processing agreements, where we have the obligation to replace the lost heating value with natural gas, and “percent-of-liquids” agreements whereby we receive a portion of the extracted liquids with no obligation to replace the lost heating value.
The following graph illustrates the NGL production and sales volumes, as well as the margin differential between ethane and non-ethane products and the relative mix of those products.
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 20182019 includes a continued focus on growing our fee-based businesses, executing growth projects, including through joint ventures, and accomplishing cost discipline initiatives to ensure operations support our strategy. We anticipate operating results will increase through organic business growth driven primarily by Transcocontinued expansion projects and continued growth in the Northeast region. WPZ intends to fund planned growth capital with retained cash flowregion and debt, and based on currently forecasted projects, does not expect to access public equity markets for the next several years.Transco expansion projects.
Our growth capital and investment expenditures in 20182019 are expected to be approximatelyin a range from $2.7 billion to $2.9 billion. Approximately $1.7 billion of our growthGrowth capital funding needs includespending in 2019 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 2018 primarily reflects investment inagreements, and continuing to develop our gathering and processing systemsinfrastructure in the Northeast region limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project.G&P and West segments. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.
As a result of our significant continued capital and investment expenditures on Transco expansionsexpansion projects and fee-based gathering and processing projects, fee-based businesses are a significant component of our portfolio and serve to reduce the influence of commodity price fluctuations on our operating results and cash flows. We expect to benefit as continued growth in demand for low-cost natural gas is driven by increases in LNG exports, industrial demand and power generation. For 2018,2019, current forward market prices indicate oil, prices are expected to be higher compared to 2017, while natural gas, and NGL prices are expected to be lower or comparable with 2017.compared to 2018. We continue to address certain pricing risks through the utilization of commodity hedging strategies. However, some of our customers may continue to curtail or delay drilling plans until there is a more sustained recovery in prices, which may negatively impact our gathering and processing volumes. The credit profiles of certain of our producer customers have been, and may continue to be, challenged as a result of lower energy commodity prices. Unfavorable changes in energy commodity prices or the credit profile of our producer customers may also result in noncash impairments of our assets.
In 2018,2019, our operating results are expected to include increases from our regulated Transco fee-based business, primarily related to projects recently placed in-service or expected to be placed in-service in 2018 including the Atlantic Sunrise project.in-service. For our non-regulated businesses, we anticipate increases in fee-based revenue in the Northeast region,G&P segment associated with recent expansion projects, partially offset by lower fee-based revenuewith a decrease in the West region. As previously discussed, under the new accounting guidance for revenue recognition, deferred revenue under certain contracts will be recognized over longer periods than under the prior guidance, resulting in a decrease in revenue for the West region.segment primarily due to recent asset divestitures. We expect overall gathering and processing volumes to grow in 20182019 for our continuing businesses and anticipate an increase thereafter to meet the growing demand for natural gas and natural gas products. We also anticipate lowerin our equity earnings primarily associated with new investments. Additionally, we believe general and administrative expenses will be slightly lower due to recent asset divestitures and the full year impacteffect of prior year cost reduction initiatives.the WPZ merger.
Potential risks and obstacles that could impact the execution of our plan include:
Certain aspects of Tax Reform, including regulatory liabilities relatingOpposition to, reduced corporate federal income tax rates, could adversely impact the rates we can charge onand legal regulations affecting, our regulated pipelines;
Opposition to infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects;
Unexpected significant increases in capital expenditures or delays in capital project execution;
Counterparty credit and performance risk, including that of Chesapeake Energy Corporationrisk;
Unexpected changes in customer drilling and its affiliates;production activities, which could negatively impact gathering and processing volumes;
Lower than anticipated demand for natural gas and natural gas products which could result in lower than expected volumes, energy commodity prices, and margins;
General economic, financial markets, or further industry downturn, including increased interest rates;
Physical damages to facilities, including damage to offshore facilities by named windstorms;
Lower than expected distributions from WPZ;
Production issues impacting offshore gathering volumes;
Other risks set forth under Part I, Item 1A. Risk Factors in this report.
We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of energy infrastructure assets which continue to serve key growth markets and supply basins in the United States.
Expansion Projects
Williams Partners’Our ongoing major expansion projects include the following:
Atlantic SunriseNortheast G&P
In February 2017, we received approval from the FERCOhio River Supply Hub Expansion
We agreed to expand Transco’s existing natural gas transmission system along with greenfield facilitiesour services for certain customers to provide incremental firm transportationadditional rich gas processing capacity in the Marcellus and Upper Devonian Shale in West Virginia and Pennsylvania. Associated with these agreements, we plan to further expand the processing capacity of our Oak Grove facility up to 400 MMcf/d. With one of these customers, we secured a gathering dedication agreement to gather dry gas in this same region. Additionally, we will be constructing a new NGL pipeline from Moundsville to the northeastern Marcellus producing areaHarrison Hub fractionation facility to markets along Transco’s mainline as far south as Station 85provide a new outlet for NGLs. These expansions will be supported by long-term, fee-based agreements and volumetric commitments.
Susquehanna Supply Hub Expansion
We continue to expand the gathering systems in west central Alabama. We placed a portionthe Susquehanna Supply Hub that are needed to meet our customers’ production plans by 2020. This next expansion of the mainline project facilities into service in September 2017gathering infrastructure includes an additional 40,000 horsepower of new compression and it increasedgathering pipelines to bring the capacity by 400 Mdth/d. We plan to place the full project into service during mid-2018, assuming timely receipt of all remaining regulatory approvals. The full project is expected to increase capacity by 1,700 Mdth/approximately 4.5 Bcf/d.
Atlantic-Gulf
Constitution Pipeline
We currently own 41 percent of Constitution with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We are the operator of Constitution. The 126-mile Constitution pipeline is proposed to connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York, as well as to a local distribution company serving New York and Pennsylvania.
In December 2014, Constitution received approval from the FERC to construct and operate its proposed pipeline, which will have an expected capacity of 650 Mdth/d. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied the necessary water quality certification under Section 401 of the Clean Water Act for the New York portion of the pipeline. In May 2016, Constitution appealed the NYSDEC’s denial of the Section 401 certification to the United States Court of Appeals for the Second Circuit and in August 2017, the court issued a decision denying in part and dismissing in part Constitution’s appeal. The court expressly declined to rule on Constitution’s argument that the delay in the NYSDEC’s decision on Constitution’s Section 401 application constitutes a waiver of the certification requirement. The court determined that it lacked jurisdiction to address that contention and found that jurisdiction over the waiver issue lies exclusively with the United States Court of Appeals for the District of Columbia Circuit.Circuit (D.C. Circuit). As to the denial itself, the court determined that NYSDEC’s action was not arbitrary or capricious. Constitution filed a petition for rehearing with the Second Circuit Court of Appeals, but in October 2017 the court denied our petition.
In October 2017, we filed a petition for declaratory order requesting the FERC to find that, by operation of law, the Section 401 certification requirement for the New York State portion of Constitution’s pipeline project was waived due to the failure by the NYSDEC to act on Constitution’s Section 401 application within a reasonable period of time as required by the express terms of such statute. In January 2018, the FERC denied our petition, finding that Section 401 provides that a state waives certification only when it does not act on an application within one year from the date of the application. We filed a request for rehearing of the FERC’s decision, but in July 2018 the FERC denied our request.
The project’s sponsors remain committed to the project,project. On November 5, 2018, the FERC granted our request for an extension of time to December 2, 2020, to construct and place into service the Constitution pipeline. And, in that regard, we are pursuing two separate and independent paths in order to overturn the NYSDEC’s denial of the Section 401 certification. In JanuarySeptember 2018, we filed a petition with the United States Supreme Court toD.C. Circuit for review the decision of the Second Circuit Court of Appeals that upheld the merits of the NYSDEC’sFERC’s denial of the Section 401 certification. And, in February 2018, we filed a request with the FERC for rehearing of its finding that the NYSDEC did not waive the Section 401 certification requirement. If the FERC denies such request, we will file aour petition for review with the D.C. Circuit Court of Appeals.
We estimate that the target in-service date for the project would be approximately 10 to 12 months following any court or FERC decision that the NYSDEC denial order was improper or that the NYSDEC waived the Section 401 certification requirement. (Seedeclaratory order.(See Note 34 – Variable Interest Entities of Notes to Consolidated Financial Statements.)
Garden State
In April 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 210 in New Jersey to a new interconnection
on our Trenton Woodbury Lateral in New Jersey. The project will be constructed in phases and is expected to increase capacity by 180 Mdth/d. We placed the initial phase of the project into service in September 2017 and plan to place the remaining portion of the project into service during the first quarter of 2018.
Gateway
In November 2017,December 2018, we filed an application withreceived approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from PennEast Pipeline Company's proposed interconnection with Transco’s mainline south of Station 205 in New Jersey to other existing Transco meter stations within New Jersey. We plan to place the project into service in the first quarter of 2021, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 65 Mdth/d.
Gulf Connector
In November 2017, we received approval from the FERC allowing Transco to expand its existing natural gas transmission system to provide incremental firm transportation capacity from Station 65 in Louisiana to delivery points in Wharton and San Patricio Counties, Texas. The project will be constructed in two phases and we plan to place both phases into service during the first half of 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 475 Mdth/d.
Hillabee
In February 2016, the FERC issued a certificate order for the initial phases of Transco’s Hillabee Expansion Project. The project involves an expansion of Transco’s existing natural gas transmission system from Station 85 in west central Alabama to a new interconnection with the Sabal Trail pipeline in Alabama. The project will beis being constructed in phases, and all of the project expansion capacity will be leasedis dedicated to Sabal Trail.Trail pursuant to a capacity lease agreement. We placed a portion of Phase I into service in June of 2017 and the remainder of Phase I into service in July of 2017. Phase I increased capacity by 818 Mdth/d. The in-service date of Phase II is planned for the second quarter of 2020, and together theyPhases I and II are expected to increase capacity by 1,025 Mdth/d. See Expansion Project Completions within Overview.
Norphlet Project
In March 2016, we announced that we have reached an agreement to provide deepwater gas gathering services to the Appomattox development in the Gulf of Mexico. The project will provide offshore gas gathering services to our existing Transco lateral, which will provide transmission services onshore to our Mobile Bay processing facility. We also plan to makecompleted modifications to our Main Pass 261 Platform to install an alternate delivery route from the platform, as well as modifications to our Mobile Bay processing facility. The project is scheduled to go into service during the second half of 2019.
North Seattle Lateral Upgrade
In May 2017, we filed an application with the FERC to expand delivery capabilities on Northwest Pipeline’s North Seattle Lateral. The project consists of the removal and replacement of approximately 5.9 miles of 8-inch diameter pipeline with new 20-inch diameter pipeline. We plan to place the project into service as early as the fourth quarter of 2019. The project is expected to increase capacity by up to 159 Mdth/d.
Northeast Supply Enhancement
In March 2017, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point in New York. On April 20, 2018, the NYSDEC denied, without prejudice, Transco’s application for certain permits required for the project. We addressed the technical issues identified by NYSDEC and in May 2018, we refiled our application for the permits. We plan to place the project into service in late 2019 or during the first halffourth quarter of 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 400 Mdth/d.
Ohio River Supply Hub Expansion
We agreed to expand our services to a customer to provide 660 MMcf/d of processing wet gas capacity in the Marcellus and Upper Devonian Shale in West Virginia. Associated with this agreement, we expect to further expand the processing capacity of our Oak Grove facility, which has the ability to increase capacity by an additional 1.8 Bcf/d. Additionally, with the same customer, we secured a gathering dedication agreement to gather dry gas in this same region. These expansions will be supported by long-term, fee-based agreements and volumetric commitments.
Rivervale South to Market
In August 2017,2018, we filed an application withreceived approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the existing Rivervale interconnection with Tennessee Gas Pipeline on Transco’s North New Jersey Extension to other existing Transco locations within New Jersey. We plan to place the project into service as early as the fourth quarter of 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 190 Mdth/d.
Susquehanna Supply Hub ExpansionSoutheastern Trail
In April 2018, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the Pleasant Valley interconnect with Dominion’s Cove Point Pipeline in Virginia to the Station 65 pooling point in Louisiana. We plan to place the project into service in late 2020, assuming timely receipt of all necessary regulatory approvals. The Susquehanna Supply Hub Expansion, which involves two new compression facilities with an additional 49,000 horsepower and 59 miles of 12 inch to 24 inch pipeline,project is expected to increase gathering capacity allowing a certain producerby 296 Mdth/d.
West
North Seattle Lateral Upgrade
In July 2018, we received approval from the FERC to fulfill its commitmentexpand delivery capabilities on Northwest Pipeline’s North Seattle Lateral. The project consists of the removal and replacement of approximately 5.9 miles of 8-inch diameter pipeline with new 20-inch diameter pipeline. We plan to deliver 850 Mdth/d to our Atlantic Sunrise development. We placed a portion of thisplace the project into service as early as the fourth quarter of 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase delivery capacity by approximately 159 Mdth/d.
Wamsutter Expansion
We are expanding our gathering and processing infrastructure in January 2018the Wamsutter region of Wyoming in order to meet our customers’ production plans. The expansion includes the addition of approximately 60 miles of gathering pipelines and anticipate this expansion will be fully commissioned incompression, and modifications to existing treating and processing facilities. We plan to place the first phase of the project into service during the first quarter of 2018.2019.
Project Bluestem
We are expanding our presence in the Mid-Continent region through building a 188-mile pipeline from our fractionator in Conway, Kansas to an interconnect with a third-party NGL pipeline system in Oklahoma, providing us with firm access to Mt. Belvieu pricing. As part of the project, the third-party intends to construct a 110-mile pipeline extension of their existing NGL pipeline system that will have an initial capacity of 120 Mbbls/d. Further, we will have an option to purchase a 20 percent equity interest in a Mt. Belvieu fractionation train developed by the third party. The pipeline and extension projects are expected to be placed into service during the first quarter of 2021.
Critical Accounting Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.
Pension and Postretirement Obligations
We have employee benefit plans that include pension and other postretirement benefits. Net periodic benefit cost and obligations for these plans are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, cash balance interest crediting rate, expected rate of compensation increase, 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 910 – Employee Benefit Plans of Notes to Consolidated Financial Statements.
The following table presents the estimated increase (decrease) in net periodic benefit cost and obligations resulting from a one-percentage-point change in the specific assumption.
|
| | | | | | | | | | | | | | | |
| | Benefit Cost | | Benefit Obligation |
| | One- Percentage- Point Increase | | One- Percentage- Point Decrease | | One- Percentage- Point Increase | | One- Percentage- Point Decrease |
| | (Millions) |
| Pension benefits: | | | | | | | |
| Discount rate | $ | (8 | ) | | $ | 9 |
| | $ | (118 | ) | | $ | 140 |
|
| Expected long-term rate of return on plan assets | (12 | ) | | 12 |
| | — |
| | — |
|
| Rate of compensation increase | 2 |
| | (1 | ) | | 9 |
| | (6 | ) |
| Other postretirement benefits: | | | | | | | |
| Discount rate | 1 |
| | 1 |
| | (22 | ) | | 27 |
|
| Expected long-term rate of return on plan assets | (2 | ) | | 2 |
| | — |
| | — |
|
| Assumed health care cost trend rate | — |
| | — |
| | 5 |
| | (5 | ) |
|
| | | | | | | | | | | | | | | |
| | Benefit Cost | | Benefit Obligation |
| | One- Percentage- Point Increase | | One- Percentage- Point Decrease | | One- Percentage- Point Increase | | One- Percentage- Point Decrease |
| | (Millions) |
| Pension benefits: | | | | | | | |
| Discount rate | $ | (7 | ) | | $ | 8 |
| | $ | (101 | ) | | $ | 119 |
|
| Expected long-term rate of return on plan assets | (12 | ) | | 12 |
| | — |
| | — |
|
| Cash balance interest crediting rate | 16 |
| | (13 | ) | | 76 |
| | (64 | ) |
| Rate of compensation increase | 1 |
| | (1 | ) | | 5 |
| | (4 | ) |
| Other postretirement benefits: | | | | | | | |
| Discount rate | 1 |
| | 1 |
| | (19 | ) | | 23 |
|
| Expected long-term rate of return on plan assets | (2 | ) | | 2 |
| | — |
| | — |
|
Our expected long-term rates of return on plan assets, as determined at the beginning of each fiscal year, are based on the average rate of return expected on the funds invested in the plans. We determine our long-term expected rates of return on plan assets using our expectations of capital market results, which include an analysis of historical results as well as forward-looking projections. These capital market expectations are based on a period of at least 10 years and take into account our investment strategy and mix of assets. We develop our expectations using input from our third-party independent investment consultant. The forward-looking capital market projections start with current conditions of interest rates, equity pricing, economic growth, and inflation and those are overlaid with forward looking projections of normal inflation, growth, and interest rates to determine expected returns. The capital market return projections for specific asset classes in the investment portfolio are then applied to the relative weightings of the asset classes in the investment portfolio. The resulting rates are an estimate of future results and, thus, likely to be different than actual results.
In 2017, the benefit plans’Our expected long-term rate of return on plan assets outperformed their respective benchmarksused for fixed income strategies, but generally underperformed the respective benchmarksour pension plans was 5.34 percent in 2018. The 2018 actual return on plan assets for equity strategies.our pension plans was a loss of approximately 3.6 percent. The 10-year average rate of return on pension plan assets through December 2018 was approximately 8.3 percent. While the 20172018 investment performance was greaterless than our expected rates of return, the expected rates of return on plan assets are long-term in nature and are not significantly impacted by short-term market performance. Changes to our asset allocation would also impact thesethe expected rates of return. Our expected long-term rate of return on plan assets used for our pension plans was 6.45 percent in 2017. The 2017 actual return on plan assets for our pension plans was approximately 15.5 percent. The 10-year average rate of return on pension plan assets through December 2017 was approximately 4.3 percent.
The discount rates are used to measure the benefit obligations of our pension and other postretirement benefit plans. The objective of the discount rates is to determine the amount, if invested at the December 31 measurement date in a portfolio of high-quality debt securities, that will provide the necessary cash flows when benefit payments are due. Increases in the discount rates decrease the obligation and, generally, decrease the related cost. The discount rates for our pension and other postretirement benefit plans are determined separately based on an approach specific to our plans and their respective expected benefit cash flows as described in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies and Note 910 – Employee Benefit Plans of Notes to Consolidated Financial Statements. Our discount rate assumptions are impacted by changes in general economic and market conditions that affect interest rates on long-term, high-quality debt securities as well as by the duration of our plans’ liabilities.
The cash balance interest crediting rate assumption represents the average long-term rate by which the pension plans’ cash balance accounts are expected to grow. Interest on the cash balance accounts is based on the 30-year U.S. Treasury securities rate and is credited to the accounts quarterly. An increase in this rate causes the pension obligation and cost to increase.
The expected rate of compensation increase represents average long-term salary increases. An increase in this rate causes the pension obligation and cost to increase.
The assumed health care cost trend rates are based on national trend rates adjusted for our actual historical cost rates and plan design. An increase in this rate causes the other postretirement benefit obligation and cost to increase.
Property, Plant, and Equipment and Other Identifiable Intangible Assets
We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events or changes in circumstances indicate, in our judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred, and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.
Certain of our contractual gathering rates, primarily those in the Barnett Shale, are based on a percentage of the New York Mercantile Exchange (NYMEX) natural gas prices. During the fourth quarter of 2018, we determined there was a sustained decline in the forward price curves for natural gas. During this same period, a large producer customer in the Barnett Shale removed their remaining drilling rig. These factors gave rise to an impairment evaluation of these assets. The historical carrying value of our Barnett assets was initially recorded based on the estimated fair value during the third quarter of 2017, we received solicitations and engaged2014 in negotiations forconjunction with the saleacquisition of certain gas gathering assets within the Mid-Continent region. As a result of these events, we evaluated the Mid-Continent asset group, which includes property, plant, and equipment and intangible assets, for impairment. ACMP.
Our evaluation consideredincorporated management’s projections of future drilling levels and gathering rates, taking into consideration the likelihood of divesting certain assets within the Mid-Continent regioninformation noted above as well as recently available information developed from the negotiation process that impacted ourregarding producer drilling cost assumptions in this basin. The resulting estimate of future undiscounted cash flows associated withwas less than our carrying value, necessitating the estimation of the fair value of these assets. The estimated undiscounted future cash flows were determined to be belowIn arriving at the carrying amount for these assets. We computed the
estimated fair value, usingwe utilized an income approach and incorporated market inputs based on ongoing negotiations for the potential sale of a portion of the underlying assets. For the income approach, we utilizedwith a discount rate of 10.28.5 percent, reflecting an estimated cost of capital and risks associated with the underlying assets. As a result, of this evaluation, we recorded an impairment charge of $1.019$1.849 billion forto reduce the difference betweencarrying value to our estimate of fair value. A one-percentage-point increase in the estimateddiscount rate would decrease our estimate of fair value and carrying amount of these assets.by approximately $37 million.
Judgments and assumptions are inherent in estimating undiscounted future cash flows, fair values, and the probability-weighting of possible outcomes. The use of alternate judgments and assumptions could result in a different determination affecting the consolidated financial statements.
Equity-Method Investments
At December 31, 2017, our Consolidated Balance Sheet includes approximately $6.6 billion of investments that are accounted for under the equity-method of accounting. We evaluate these investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. We continue to monitor our equity-method investments for any indications that the carrying value may have experienced an other-than-temporary decline in value. When evidence of a loss in value has occurred, we compare our estimate of the fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We generally estimate the fair value of our investments using an income approach where significant judgments and assumptions include expected future cash flows and the appropriate discount rate. In some cases, we may utilize a form of market approach to estimate the fair value of our investments.
If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge. Events or changes in circumstances that may be indicative of an other-than-temporary decline in value will vary by investment, but may include:
A significant or sustained decline in the market value of an investee;
Lower than expected cash distributions from investees;
Significant asset impairments or operating losses recognized by investees;
Significant delays in or lack of producer development or significant declines in producer volumes in markets served by investees;
Significant delays in or failure to complete significant growth projects of investees.
As of December 31, 2017, the carrying value of our equity-method investment in Discovery is $534 million. During the fourth quarter of 2017, certain customers of Discovery terminated a significant offshore gas gathering agreement following the shut-in of production after the associated wells ceased flowing. As a result, we evaluated this investment for impairment and determined that no impairment was necessary.
We estimated the fair value of our investment in Discovery using an income approach that primarily considered probability-weighted assumptions of additional commercial development, the continued operation of the business under existing contracts, and a discount rate of 11.3 percent. Higher probabilities were generally assigned to those commercial development opportunities that were more advanced in the discussion and contracting process, utilizing existing infrastructure due to producer capital constraints, and/or we believe Discovery has a competitive advantage due to geographical proximity to the prospect. The estimated fair value of our investment in Discovery exceeded its carrying value by approximately 6 percent and thus no impairment was necessary.
Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and additional development probabilities. It is reasonably possible that an impairment could be required in the future if commercial development activities are not as successful or as timely as assumed. The use of alternate judgments and assumptions
could result in a different calculation of fair value, which could ultimately result in the recognition of an impairment charge in the consolidated financial statements.
Constitution Pipeline Capitalized Project Costs
As of December 31, 2017,2018, Property, plant, and equipment – net in our Consolidated Balance Sheet includes approximately $381$377 million of capitalized project costs for Constitution, for which we are the construction manager and own a 41 percent consolidated interest. As a result of the events discussed in Company Outlook, we evaluated the capitalized project costs for impairment as recently asat December 31, 2017, and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including scenarios assuming construction of the pipeline, as well as a scenario where the project does not proceed. These scenarios included our most recent estimate of total construction costs. The probability-weighted scenarios also consideredSubsequently, there have been no events or changes in circumstances that impact our assessment of the likelihood of success of the two separate and independent paths to obtain necessary certification, as described in Company Outlook.conclusion. It is reasonably possible that future unfavorable developments, such as a reduced likelihood of success, increased estimates of construction costs, or further significant delays, could result in a future impairment.
Regulatory Liabilities resulting from Tax Reform
In December 2017, Tax Reform was enacted, which, among other things, reduced the corporate income tax rate from 35 percent to 21 percent. Rates charged to customers of our regulated natural gas pipelines are subject to the rate-making policies of the FERC, which permithave historically permitted the recovery of an income tax allowance that includes a deferred income tax component. As a result ofDue to the reduced income tax rate from Tax Reform and the collection of historical rates that reflected historical federal income tax rates, we expect that our regulated natural gas pipelines will be required to return amounts to certain customers through future rates and haverates. As a result, we established regulatory liabilities accordingly. Theseduring 2017 and at December 31, 2018, these liabilities were recorded in December 2017 through regulatory charges to operating income totaling $674total $657 million. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements.) The timing and actual amount of such return will be subject to future negotiations regarding this matter and many other elements of cost–of–servicecost-of-service rate proceedings, including other costs of providing service.
Our estimation of these regulatory liabilities incorporated the following significant judgments and assumptions involving income taxes collected from our customers.
We utilized current FERC guidance for the default income tax rate for non-corporate taxpayers, which is an element of our overall effective tax rate. It is possible that the FERC will provide updated implementation guidance in the future, including an updated default income tax rate for non-corporate taxpayers. We estimate that a decline of one percentage point in our assumed overall effective tax rate would increase our regulatory liabilities by approximately $42 million.
We made assumptions regarding the allocation of WPZ taxable income between corporate and non-corporate taxpayers. This allocation is subject to annual variation that could impact the weighted average federal tax component of the overall income tax allowance rate.
We made assumptions regarding the allocation of WPZ taxable income among the states in which WPZ conducts business. This allocation is subject to annual variation that could impact the weighted average state tax component of the overall income tax allowance rate. It is possible that certain states may change their income tax laws and/or rates in the future in response to Tax Reform.
In determining the estimated liability that we currently believe is probable of return to customers through future rates, we considered the mix of services provided by our regulated natural gas pipelines, taking into consideration that certain of these services are provided under contractually-based rates, in lieu of recourse-based rates. The contractually-based rates are designed to recover the cost of providing those services, with
no expected future rate adjustment for the term of those contracts. We estimate that a one percent change in the relative mix of services would change the regulatory liability by approximately $8 million.
The use of alternative judgments and assumptions could result in the recognition of different regulatory liabilities and associated charges in the consolidated financial statements.
Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2017.2018. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
| | | | Years Ended December 31, | Years Ended December 31, |
| | 2017 | | $ Change from 2016* | | % Change from 2016* | | 2016 | | $ Change from 2015* | | % Change from 2015* | | 2015 | 2018 | | $ Change from 2017* | | % Change from 2017* | | 2017 | | $ Change from 2016* | | % Change from 2016* | | 2016 |
| | (Millions) | (Millions) |
| Revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Service revenues | $ | 5,312 |
| | +141 |
| | +3 | % | | $ | 5,171 |
| | +7 |
| | — | % | | $ | 5,164 |
| $ | 5,502 |
| | +190 |
| | +4 | % | | $ | 5,312 |
| | +141 |
| | +3 | % | | $ | 5,171 |
|
| Service revenues - commodity consideration | | 400 |
| | +400 |
| | NM |
| | — |
| | — |
| | NM |
| | — |
|
| Product sales | 2,719 |
| | +391 |
| | +17 | % | | 2,328 |
| | +132 |
| | +6 | % | | 2,196 |
| 2,784 |
| | +65 |
| | +2 | % | | 2,719 |
| | +391 |
| | +17 | % | | 2,328 |
|
| Total revenues | 8,031 |
| | | | | | 7,499 |
| | | | | | 7,360 |
| 8,686 |
| | | | | | 8,031 |
| | | | | | 7,499 |
|
| Costs and expenses: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Product costs | 2,300 |
| | -575 |
| | -33 | % | | 1,725 |
| | +54 |
| | +3 | % | | 1,779 |
| 2,707 |
| | -407 |
| | -18 | % | | 2,300 |
| | -575 |
| | -33 | % | | 1,725 |
|
| Processing commodity expenses | | 137 |
| | -137 |
| | NM |
| | — |
| | — |
| | NM |
| | — |
|
| Operating and maintenance expenses | 1,585 |
| | -5 |
| | — | % | | 1,580 |
| | +75 |
| | +5 | % | | 1,655 |
| 1,507 |
| | +69 |
| | +4 | % | | 1,576 |
| | +16 |
| | +1 | % | | 1,592 |
|
| Depreciation and amortization expenses | 1,736 |
| | +27 |
| | +2 | % | | 1,763 |
| | -25 |
| | -1 | % | | 1,738 |
| 1,725 |
| | +11 |
| | +1 | % | | 1,736 |
| | +27 |
| | +2 | % | | 1,763 |
|
| Selling, general, and administrative expenses | 608 |
| | +115 |
| | +16 | % | | 723 |
| | +18 |
| | +2 | % | | 741 |
| 569 |
| | +25 |
| | +4 | % | | 594 |
| | +128 |
| | +18 | % | | 722 |
|
| Impairment of goodwill | — |
| | — |
| | — | % | | — |
| | +1,098 |
| | +100 | % | | 1,098 |
| |
| Impairment of certain assets | 1,248 |
| | -375 |
| | -43 | % | | 873 |
| | -664 |
| | NM |
| | 209 |
| 1,915 |
| | -667 |
| | -53 | % | | 1,248 |
| | -375 |
| | -43 | % | | 873 |
|
| Gain on sale of Geismar Interest | (1,095 | ) | | +1,095 |
| | NM |
| | — |
| | — |
| | — | % | | — |
| |
| Gain on sale of certain assets | | (692 | ) | | -403 |
| | -37 | % | | (1,095 | ) | | +1,095 |
| | NM |
| | — |
|
| Regulatory charges resulting from Tax Reform | 674 |
| | -674 |
| | NM |
| | — |
| | — |
| | — | % | | — |
| (17 | ) | | +691 |
| | NM |
| | 674 |
| | -674 |
| | NM |
| | — |
|
| Insurance recoveries – Geismar Incident | (9 | ) | | +2 |
| | +29 | % | | (7 | ) | | -119 |
| | -94 | % | | (126 | ) | |
| Other (income) expense – net | 80 |
| | +62 |
| | +44 | % | | 142 |
| | -102 |
| | NM |
| | 40 |
| 67 |
| | +4 |
| | +6 | % | | 71 |
| | +64 |
| | +47 | % | | 135 |
|
| Total costs and expenses | 7,127 |
| | | | | | 6,799 |
| | | | | | 7,134 |
| 7,918 |
| | | | | | 7,104 |
| | | | | | 6,810 |
|
| Operating income (loss) | 904 |
| | | | | | 700 |
| | | | | | 226 |
| 768 |
| | | | | | 927 |
| | | | | | 689 |
|
| Equity earnings (losses) | 434 |
| | +37 |
| | +9 | % | | 397 |
| | +62 |
| | +19 | % | | 335 |
| 396 |
| | -38 |
| | -9 | % | | 434 |
| | +37 |
| | +9 | % | | 397 |
|
| Impairment of equity-method investments | — |
| | +430 |
| | +100 | % | | (430 | ) | | +929 |
| | +68 | % | | (1,359 | ) | (32 | ) | | -32 |
| | NM |
| | — |
| | +430 |
| | +100 | % | | (430 | ) |
| Other investing income (loss) – net | 282 |
| | +219 |
| | NM |
| | 63 |
| | +36 |
| | +133 | % | | 27 |
| 219 |
| | -63 |
| | -22 | % | | 282 |
| | +219 |
| | NM |
| | 63 |
|
| Interest expense | (1,083 | ) | | +96 |
| | +8 | % | | (1,179 | ) | | -135 |
| | -13 | % | | (1,044 | ) | (1,112 | ) | | -29 |
| | -3 | % | | (1,083 | ) | | +96 |
| | +8 | % | | (1,179 | ) |
| Other income (expense) – net | (2 | ) | | -76 |
| | NM |
| | 74 |
| | -28 |
| | -27 | % | | 102 |
| 92 |
| | +117 |
| | NM |
| | (25 | ) | | -110 |
| | NM |
| | 85 |
|
| Income (loss) before income taxes | 535 |
| | | | | | (375 | ) | | | | | | (1,713 | ) | 331 |
| | | | | | 535 |
| | | | | | (375 | ) |
| Provision (benefit) for income taxes | (1,974 | ) | | +1,949 |
| | NM |
| | (25 | ) | | -374 |
| | -94 | % | | (399 | ) | 138 |
| | -2,112 |
| | NM |
| | (1,974 | ) | | +1,949 |
| | NM |
| | (25 | ) |
| Net income (loss) | 2,509 |
| | | | | | (350 | ) | | | | | | (1,314 | ) | 193 |
| | | | | | 2,509 |
| | | | | | (350 | ) |
| Less: Net income (loss) attributable to noncontrolling interests | 335 |
| | -261 |
| | NM |
| | 74 |
| | -817 |
| | NM |
| | (743 | ) | 348 |
| | -13 |
| | -4 | % | | 335 |
| | -261 |
| | NM |
| | 74 |
|
| Net income (loss) attributable to The Williams Companies, Inc. | $ | 2,174 |
| | | | | | $ | (424 | ) | | | | | | $ | (571 | ) | $ | (155 | ) | | | | | | $ | 2,174 |
| | | | | | $ | (424 | ) |
_______
| |
| * | + = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200. |
2018 vs. 2017
Service revenues increased primarily due to higher transportation fee revenues at Transco associated with expansion projects placed in-service in 2017 and 2018, as well as higher gathering volumes at the Susquehanna Supply Hub and
Ohio River Supply Hub. These increases are partially offset by a change in the rate of deferred revenue recognition resulting from implementing ASC 606, reduced revenues from our Four Corners area operations that were sold in October 2018, a reduction of rates resulting from a Northwest Pipeline rate case settlement, and a decrease following the Jackalope deconsolidation.
Service revenues - commodity considerationincreased as the result of implementing ASC 606 using a modified retrospective approach, effective January 1, 2018. Therefore, prior periods have not been recast under the new guidance. These revenues represent consideration we receive in the form of commodities as full or partial payment for gathering and processing services provided. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements.) Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.
Product sales increased primarily due to higher marketing revenues and higher system management gas sales, which are offset in Product costs, and higher sales from the production of our equity NGLs, reflecting higher NGL prices. These increases are partially offset by the absence of $269 million in olefin sales revenue associated with our former Gulf Olefins operations in 2017.
The increase in Product costs is primarily due to the impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services, as well as higher marketing and system management gas costs. This increase is partially offset by the absence of $147 million of olefin feedstock costs due to the sale of our former Gulf Olefins operations, as well as the absence of natural gas purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606.
Processing commodity expenses presents the natural gas purchases associated with the production of equity NGLs as previously described in conjunction with the implementation of ASC 606.
Operating and maintenance expenses decreased primarily due to the absence of $80 million of costs associated with our former Gulf Olefins and Four Corners area operations.
Depreciation and amortization expenses decreased primarily due to the absence of our former Gulf Olefins and Four Corners area operations, partially offset by new assets placed in-service.
Selling, general, and administrative expenses decreased primarily due to the absence of severance-related, organizational realignment, and Financial Repositioning costs incurred in 2017, $25 million in reduced costs associated with our former Gulf Olefins and Four Corners area operations, and ongoing cost containment efforts. These decreases are partially offset by a charitable contribution of preferred stock to The Williams Companies Foundation, Inc. (see Note 15 – Stockholders' Equity of Notes to Consolidated Financial Statements) and fees associated with the WPZ Merger.
The unfavorable change in Impairment of certain assetsincludes 2018 impairments on certain assets in the Barnett Shale region and certain idle pipelines, partially offset by the absence of 2017 impairments associated with certain assets in the Mid-Continent, Marcellus South, and Houston Ship Channel areas (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
The unfavorable change in Gain on sale of certain assets reflects the absence of a gain recognized on the sale of our Geismar Interest in July 2017, partially offset by gains recognized on the sales of our Four Corners area in October 2018 and our Gulf Coast pipeline systems in December 2018 (see Note 3 – Divestitures of Notes to Consolidated Financial Statements).
Regulatory charges resulting from Tax Reform relates to the 2017 recognition of regulatory liabilities for the probable return to customers through future rates of the future decrease in income taxes payable associated with Tax Reform. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements).
The favorable change in Other (income) expense – net within Operating income (loss) includes the benefit of establishing a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the WPZ Merger, substantially offset by the absence of gains from certain contract settlements and terminations in 2017, the absence of a gain on the sale of our RGP Splitter in 2017, and 2018 charges establishing a regulatory liability associated with a decrease in Northwest Pipeline's estimated deferred state income tax rate following the WPZ Merger.
Operating income (loss) changed unfavorably primarily due to higher impairments of assets, lower gains on sales of assets, and the absence of operating income associated with our former Gulf Olefins and Four Corners area operations, partially offset by the absence of regulatory charges resulting from Tax Reform, higher Service revenues primarily from expansion projects, and an increase in NGL margins.
The unfavorable change in Equity earnings (losses) is primarily due to a decrease in volumes at Discovery, partially offset by improved results at our Appalachia Midstream Investments and the deconsolidation of our Jackalope interest, which is now accounted for as an equity-method investment beginning in the second quarter of 2018.
The Impairment of equity-method investments in 2018 reflects an impairment related to our investment in UEOM.
Other investing income (loss) – net reflects the absence of the gain on disposition of our investments in DBJV and Ranch Westex JV LLC in 2017, partially offset by gains on the 2018 deconsolidations of certain Permian basin assets and of our interest in Jackalope. (See Note 6 – Investing Activities of Notes to Consolidated Financial Statements.)
Interest expense increased primarily due to an increase in other financing obligations associated with Transco's Dalton and Atlantic Sunrise projects, as well as expense related to the deemed financing component of certain contract liabilities resulting from our implementation of ASC 606 in 2018, offset by lower interest rates on our outstanding debt in 2018 and lower borrowings on our credit facilities in 2018. (See Note 14 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)
Other income (expense) – net below Operating income (loss) changed favorably primarily due to a decrease in charges reducing regulatory assets related to deferred taxes on the allowance for funds used during construction (AFUDC) resulting from Tax Reform, an increase in equity AFUDC, and a lower settlement charge from the pension early payout program, partially offset by a decrease due to the absence of a net gain on early retirement of debt in 2017 and a loss on early retirement of debt in 2018. (See Note 7 – Other Income and Expensesof Notes to Consolidated Financial Statements.)
Provision (benefit) for income taxes changed unfavorably primarily due to the absence of a $1.923 billion tax provision benefit associated with Tax Reform and releasing a $127 million valuation allowance in 2017. The unfavorable change also reflects a $105 million valuation allowance in 2018 associated with certain foreign tax credits. See Note 8 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily related to WPZ, reflective of both our acquisition of the publicly held interests in WPZ associated with the WPZ Merger and a fourth quarter 2017 net loss incurred by WPZ, partially offset by lower operating results at Gulfstar.
2017 vs. 2016
Service revenues increased due to higher transportation fee revenues at Transco and in the eastern Gulf reflecting expansion projects placed in-service in 2016 and 2017; partially offset by a decrease in gathering, processing, and fractionation revenue including lower rates, primarily in the Barnett Shale region associated with the restructuring of
contracts in the fourth quarter of 2016; lower volumes in the western regions, driven by natural declines and extreme weather conditions in the Rocky Mountains in 2017; and the sale of our former Canadian and Gulf Olefins operations.
Product sales increased primarily due to higher marketing revenues reflecting significantly higher prices and volumes. Revenues from the sale of our equity NGLs increased primarily due to higher non-ethane NGL prices, partially offset by lower volumes. These increases were partially offset by lower olefin production sales due to lower volumes resulting from the sale of our former Gulf Olefins and Canadian operations.
The increase in Product costs is primarily due to the same factors that increased marketing sales, partially offset by lower olefin feedstock purchases associated with the sale of our Gulf Olefins and Canadian operations.
Operating and maintenance expenses increaseddecreased primarily due to higher pipeline integrity testing and general maintenance at Transco and a settlement charge from a pension early payout program (see Note 9 – Employee Benefit Plans of Notes to Consolidated Financial Statements), partially offset by the absence of costs associated with our former Canadian and Gulf Olefins operations and lower labor-related costs resulting from our workforce reductions that occurred late in first-quarter 2016, and ongoing cost containment efforts.efforts, partially offset by higher pipeline integrity testing and general maintenance at Transco.
Depreciation and amortization expenses decreased primarily due to the absence of our former Canadian and Gulf Olefins operations, partially offset by new assets placed in-service.
Selling, general, and administrative expenses(SG&A) decreased primarily due to the absence of certain project development costs associated with the Canadian PDH facility that were expensed in 2016, lower labor-related costs resulting from our workforce reductions that occurred late in first-quarter 2016, ongoing cost containment efforts, lower strategic development costs, and the absence of costs associated with our former Canadian and Gulf CoastOlefins operations. These decreases were partially offset by higher severance and organizational realignment costs in 2017 (see Note 67 – Other Income and Expenses of Notes to Consolidated Financial Statements) and a settlement charge from a pension early payout program..
The unfavorable change in Impairment of certain assets reflects 2017 impairments of certain gathering operations in the Mid-Continent and Marcellus South regions, certain NGL pipeline assets, and an olefins pipeline project in the Gulf coast region. These 2017 impairments are partially offset by the absence of 2016 impairments of our former Canadian operations and certain Mid-Continent assets (see Note 1617 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
The Gain on sale of Geismar Interestcertain assets reflects the gain recognized on the sale of our Geismar Interest in July 2017. (See Note 23 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements.)
Regulatory charges resulting from Tax Reform relates to the recognition of regulatory liabilities for the probable return to customers through future rates of the future decrease in income taxes payable associated with Tax Reform. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements).Statements.)
The favorable change in Other (income) expense – net within Operating income (loss) includes the absence of the 2016 loss on the sale of our Canadian operations, gains from certain contract settlements and terminations in 2017, a gain on the sale of our RGP Splitter in 2017, and the absence of an unfavorable change in foreign currency exchange associated with our former Canadian operations. These favorable changes are partially offset by additional expense associated with an annual revision to the ARO liability, accrual of additional expenses in 2017 related to the Geismar Incident, as well as the absence of a gain in first-quarter 2016 associated with the sale of unused pipe.
Operating income (loss) changed favorably primarily due to the Gain on sale of Geismar Interestcertain assets, the absence of the 2016 impairments of certain Mid-Continent assets and our former Canadian operations, higher service revenues primarily from expansion projects placed in-service in 2016 and 2017, the absence of expensed Canadian PDH facility project development costs in 2016, as well as ongoing cost containment efforts, including workforce reductions in first-quarter 2016. Operating income (loss) also improved due to the absence of a 2016 loss on the sale of our Canadian operations, the absence of an operating loss associated with our former Canadian operations, gains from certain contract settlements and the sale of our RGP Splitter. These favorable changes were partially offset by 2017 impairments of
certain gathering operations in the Mid-Continent and Marcellus South regions and certain NGL pipeline assets, and regulatory charges resulting from Tax Reform, and certain NGL pipeline assets, as well as the absence of operating income associated with our former Gulf Olefins operations, and a settlement charge from a pension early payout program.operations.
The favorable change in Equity earnings (losses) is due to an increase in ownership of our Appalachia Midstream Investments and improved results at Aux Sable due to favorable pricing and higher volumes, partially offset by lower UEOM results driven by lower processing volumes from the Utica gathering system and lower Discovery results due to lower volumes.
The decrease in Impairment of equity-method investments reflects the absence of 2016 impairment charges associated with our Appalachia Midstream Investments, DBJV, Laurel Mountain, and Ranch Westex equity-method investments. (See Note 1617 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)
Other investing income (loss) – net reflects the gain on disposition of our investments in DBJV and Ranch Westex JV LLC in 2017, partially offset by the absence of interest income received in 2016 associated with a receivable related to the sale of certain former Venezuelan assets and the absence of a 2016 gain on the sale of an equity-method investment interest in a gathering system that was part of our Appalachia Midstream Investments. (See Note 56 – Investing Activities of Notes to Consolidated Financial Statements).Statements.)
Interest expense decreased primarily due to lower Interest incurred primarily attributable to debt retirements in 2017 and lower borrowings on our credit facilities in 2017. (See Note 1314 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)
Other income (expense) – net below Operating income (loss) changed unfavorably primarily due to charges reducing regulatory assets related to deferred taxes on equity funds used during construction (AFUDC) resulting from Tax Reform and a settlement charge from a pension early payout program (see Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements), partially offset by a net gain on early debt retirements in 2017, and other favorable changes related to AFUDC. (See Note 57 – Other Income and Expenses of Notes to Consolidated Financial Statements.)
Provision (benefit) for income taxes changed favorably primarily due to a reduction in the federal statutory rate from 35 percent to 21 percent with the enactment of Tax Reform. The remeasurement of our existing deferred tax assets and liabilities at the reduced rate resulted in the recognition of a net income tax provision benefit of $1.923 billion. Adjustments within this provision benefit are considered provisional and are potentially subject to change in the future. See Note 78 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to the impact of decreased income allocated to us driven by the permanent waiver of IDRs and higher operating results at WPZ, partially offset by a decrease in the ownership of the noncontrolling interests. Both the permanent waiver of IDRs and the change in ownership are associated with the first-quarter 2017 Financial Repositioning (see Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements). In addition, improved results in our Gulfstar operations also contributed to the increase in Net income (loss) attributable to noncontrolling interests, partially offset by lower results for our Cardinal gathering system.
2016 vs. 2015
Service revenuesincreased slightly primarily due toexpansion projects placed in service in 2015 and 2016, partially offset by a decrease in gathering, processing, and fractionation revenue primarily due to lower volumes in the Barnett Shale and Anadarko basin.
Product sales increased primarily due to higher olefin sales reflecting increased volumes at our former Geismar plant as a result of the plant operating at higher production levels in 2016, partially offset by a decrease from our other olefin operations associated with lower volumes and per-unit sales prices. Product sales also reflect higher marketing revenues associated with higher NGL and propylene prices and natural gas and crude oil volumes, partially offset by lower NGL volumes, and crude oil prices.
The decrease in Product costs includes lower olefin feedstock purchases and lower costs associated with other product sales, partially offset by higher marketing purchases primarily due to the same factors that increased marketing sales. The decline in olefin feedstock purchases is primarily associated with lower per-unit feedstock costs and volumes at our other olefin operations, partially offset by an increase in olefin feedstock purchases at our former Geismar plant reflecting increased volumes resulting from higher production levels in 2016.
Operating and maintenance expenses decreased primarily due to lower labor-related and outside service costs resulting from our first-quarter 2016 workforce reductions and cost containment efforts and lower costs associated with general maintenance activities in the Marcellus Shale, as well as the absence of ACMP transition-related costs recognized in 2015. These decreases are partially offset by $16 million of severance and related costs recognized in 2016 and higher pipeline testing and general maintenance costs at Transco.
Depreciation and amortization expenses increased primarily due to depreciation on new assets placed in service, including Transco pipeline projects, partially offset by lower depreciation related to Canadian operations sold in 2016.
SG&A decreased primarily due to lower merger and transition costs associated with the ACMP merger and lower labor-related costs resulting from our first-quarter 2016 workforce reductions and cost containment efforts. These decreases were partially offset by certain project development costs associated with the Canadian PDH facility that we began expensing in 2016, as well as $26 million of severance and related costs recognized in 2016 and $17 million of higher costs associated with our evaluation of strategic alternatives.
Impairment of goodwill decreased due to the absence of a 2015 impairment charge associated with certain goodwill. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)
Impairment of certain assets reflects 2016 impairments of our Canadian operations and certain Mid-Continent assets, and other assets. Impairments recognized in 2015 relate primarily to previously capitalized development costs and surplus equipment write-downs. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)
Insurance recoveries – Geismar Incident changed unfavorably reflecting the receipt of $126 million of insurance proceeds in the second quarter of 2015, as compared to the receipt of $7 million of proceeds in the fourth quarter of 2016.
The unfavorable change inOther (income) expense – net within Operating income (loss) includes a loss on the sale of our Canadian operations that were sold in September 2016, project development costs at Constitution as we discontinued capitalization of these costs in April 2016, and an unfavorable change in foreign currency exchange that primarily relates to losses incurred on foreign currency transactions and the remeasurement of the U.S. dollar-denominated current assets and liabilities within our former Canadian operations, partially offset by a $10 million gain on the sale of idle pipe in 2016.
Operating income (loss) changed favorably primarily due to the absence of a goodwill impairment in 2015, higher olefin margins related to the Geismar plant operating at higher production levels in 2016, lower costs related to the merger and integration of ACMP, and lower costs and expenses primarily associated with cost containment efforts. These favorable changes are partially offset by impairments and loss on sale of certain assets in 2016, a decrease in insurance proceeds received, expensed Canadian PDH facility project development costs, and higher depreciation expenses related to new projects placed in service.
Equity earnings (losses) changed favorably primarily due to a $30 million increase at Discovery driven by the completion of the Keathley Canyon Connector in the first quarter of 2015. Additionally, OPPL, Laurel Mountain, and DBJV improved $16 million, $11 million, and $10 million, respectively.
Impairment of equity-method investments reflects 2016 impairment charges associated with our Appalachia Midstream Investments, DBJV, Laurel Mountain, and Ranch Westex equity-method investments, while the 2015 impairment charges relate to our equity-method investments in Appalachia Midstream Investments, DBJV, UEOM, and Laurel Mountain. (See Note 5 – Investing Activitiesof Notes to Consolidated Financial Statements.)
Other investing income (loss) – net changed favorably due to a 2016 gain on the sale of an equity-method investment interest in a gathering system that was part of our Appalachia Midstream Investments and higher interest income associated with a receivable related to the sale of certain former Venezuela assets. (See Note 5 – Investing Activitiesof Notes to Consolidated Financial Statements.)
Interest expense increased due to higher Interest incurred of $99 million primarily attributable to new debt issuances in 2016 and 2015 and lower Interest capitalized of $36 million primarily related to construction projects that have been placed into service, partially offset by lower interest due to 2015 and 2016 debt retirements. (See Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)
Other income (expense) – net below Operating income (loss) changed unfavorably primarily due to a decrease in AFUDC due to decreased spending on Constitution and the absence of a $14 million gain on early debt retirement in 2015.
Provision (benefit) for income taxes changed unfavorably primarily due to a decrease in pre-tax loss in 2016. See Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both years.
The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to higher operating results at WPZ, the impact of decreased income allocated to the WPZ general partner driven by the impact of reduced incentive distributions from WPZ, and the absence of the accelerated amortization of a beneficial conversion feature from the first quarter of 2015. These changes are partially offset by a favorable change primarily related to our partners’ share of Constitution project development costs in 2016.
Year-Over-Year Operating Results – Segments
We evaluate segment operating performance based upon Modified EBITDA. Note 1819 – 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.
Northeast G&P
| | | | Years Ended December 31, | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (Millions) | (Millions) |
| Service revenues | $ | 5,292 |
| | $ | 5,173 |
| | $ | 5,135 |
| $ | 976 |
| | $ | 872 |
| | $ | 870 |
|
| Service revenues - commodity consideration | | 20 |
| | — |
| | — |
|
| Product sales | 2,718 |
| | 2,318 |
| | 2,196 |
| 287 |
| | 291 |
| | 162 |
|
| Segment revenues | 8,010 |
| | 7,491 |
| | 7,331 |
| 1,283 |
| | 1,163 |
| | 1,032 |
|
| | | | | | | | | | | |
| Product costs | (2,300 | ) | | (1,728 | ) | | (1,779 | ) | (289 | ) | | (286 | ) | | (159 | ) |
| Processing commodity expenses | | (9 | ) | | — |
| | — |
|
| Other segment costs and expenses | (2,124 | ) | | (2,203 | ) | | (2,229 | ) | (392 | ) | | (386 | ) | | (364 | ) |
| Net insurance recoveries – Geismar Incident | 9 |
| | 7 |
| | 126 |
| |
| Gain on sale of Geismar Interest | 1,095 |
| | — |
| | — |
| |
| Impairment of certain assets | (1,156 | ) | | (457 | ) | | (145 | ) | — |
| | (124 | ) | | (13 | ) |
| Regulatory charges resulting from Tax Reform | (713 | ) | | — |
| | — |
| |
| Proportional Modified EBITDA of equity-method investments | 795 |
| | 754 |
| | 699 |
| 493 |
| | 452 |
| | 357 |
|
| Williams Partners Modified EBITDA | $ | 3,616 |
| | $ | 3,864 |
| | $ | 4,003 |
| |
| | | | | | | |
| NGL margin | $ | 203 |
| | $ | 169 |
| | $ | 159 |
| |
| Olefin margin | 126 |
| | 337 |
| | 226 |
| |
| Northeast G&P Modified EBITDA | | $ | 1,086 |
| | $ | 819 |
| | $ | 853 |
|
2018 vs. 2017
Northeast G&P Modified EBITDA increased primarily due to the absence of Impairment of certain assets in 2017, and higher Service revenues and Proportional Modified EBITDA of equity-method investments.
Service revenues increased due to:
A $65 million increase in gathering fee revenues at Susquehanna Supply Hub due to 13 percent higher gathering volumes reflecting increased customer production;
A $24 million increase at Ohio River Supply Hub reflecting higher gathering volumes due to increased customer production;
An $11 million increase in Utica gathering fee revenues reflecting higher rates and volumes.
Service revenues - commodity consideration increased as a result of implementing ASC 606 using a modified retrospective approach. These revenues represent consideration we receive in the form of commodities as full or partial payment for gathering and processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Processing commodity expenses below.
Product sales decreased primarily due to $31 million lower marketing sales, driven by lower non-ethane volumes and prices. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as Product costs. The decrease in Product sales is partially offset by $21 million in higher system management gas sales. System management gas sales are offset in Product costs and therefore have no impact on Modified EBITDA.
Impairment of certain assets reflects the absence of a $115 million impairment of certain gathering operations in the Marcellus South region in 2017.
Proportional Modified EBITDA of equity-method investments increased primarily due to a $33 million increase at Appalachia Midstream Investments reflecting our increased ownership acquired in late first-quarter 2017 and higher volumes. Improvements at Aux Sable and Caiman II also contributed to the increase.
2017 vs. 2016
Northeast G&P Modified EBITDA decreased primarily due to higher Impairment of certain assets and Other segment costs and expenses, partially offset by higher Proportional Modified EBITDA of equity-method investments.
2017 vs.Service revenues increased slightly reflecting:
A $38 million increase in gathering fee revenue at Susquehanna Supply Hub driven by 11 percent higher gathered volumes reflecting increased customer production;
A $23 million increase in fee revenue at Ohio Valley Midstream reflecting the absence of shut-in volumes from the first half of 2016, as well as new production coming online;
Modified EBITDA decreasedA $56 million decrease in Utica gathering fee revenues primarily due to $713 million of regulatory charges associated with14 percent lower gathered volumes driven by natural declines in the impact of Tax Reform for Transco and Northwest Pipeline, impairments of certain gathering operationswet gas areas, partially offset by higher volumes from new development in 2017 and lower olefin marginsthe dry gas areas.
Product sales increased primarily due to the sale ofhigher non-ethane and ethane prices and higher non-ethane volumes within our Gulf Olefins operations earlymarketing activities. The changes in the third quarter of 2017marketing revenues are offset by similar changes in marketing purchases, reflected above as Product costs.
Other segment costs and $35expenses increased due to a $31 million of expenseincrease in 2017operating and maintenance expenses primarily resulting from higher costs related to various maintenance expenses and ad valorem taxes, and $7 million related to a settlement charge from a pension early payout program (see Note 910 – Employee Benefit Plans of Notes to Consolidated Financial Statements). These decreasesincreases are partially offset by $16 million lower general and administrative expenses primarily due to a reduced share of allocated support costs, ongoing cost containment efforts, and 2016 workforce reductions.
Impairment of certain assets increased primarily due to a $115 million impairment of certain gathering operations in the $1.095 billion gain onMarcellus South region.
Proportional Modified EBITDA of equity-method investments changed favorably primarily due to a $100 million increase at Appalachia Midstream Investments reflecting our increased ownership acquired late in the salefirst quarter of our Geismar Interest in third-quarter 2017 and higher gathering volumes reflecting the absence of impairments of our former Canadian operationsshut-in volumes from 2016 and certain gathering assets in the Mid-Continent region in 2016,increased customer production, a $20 million increase at Aux Sable due to increased customer production and the absence of the $9 million impairment in 2016, an $8 million increase at Laurel Mountain Midstream associated with higher gathering revenue due to higher rates reflecting higher natural gas prices, partially offset by a loss$34 million decrease at UEOM driven by lower processing volumes from the wet gas areas of the Utica gathering system as noted above.
Atlantic-Gulf
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | (Millions) |
| Service revenues | $ | 2,509 |
| | $ | 2,239 |
| | $ | 1,998 |
|
| Service revenues - commodity consideration | 59 |
| | — |
| | — |
|
| Product sales | 435 |
| | 484 |
| | 450 |
|
| Segment revenues | 3,003 |
| | 2,723 |
| | 2,448 |
|
| | | | | | |
| Product costs | (438 | ) | | (437 | ) | | (405 | ) |
| Processing commodity expenses | (16 | ) | | — |
| | — |
|
| Other segment costs and expenses | (799 | ) | | (819 | ) | | (707 | ) |
| Impairment of certain assets | — |
| | — |
| | (2 | ) |
| Gain on sale of certain assets | 81 |
| | — |
| | — |
|
| Regulatory charges resulting from Tax Reform | 9 |
| | (493 | ) | | — |
|
| Proportional Modified EBITDA of equity-method investments | 183 |
| | 264 |
| | 287 |
|
| Atlantic-Gulf Modified EBITDA | $ | 2,023 |
| | $ | 1,238 |
| | $ | 1,621 |
|
| | | | | | |
| NGL margin | $ | 39 |
| | $ | 41 |
| | $ | 38 |
|
2018 vs. 2017
Atlantic-Gulf Modified EBITDA increased primarily due to the absence of regulatory charges associated with the impact of Tax Reform at Transco, higher Service revenues, and a 2018 Gain on the sale of our former Canadian operations in third-quarter 2016, higher service revenues,certain assets;partially offset by lower segment costs and expenses, and higher Proportional Modified EBITDA of equity-method investments.
Service revenues increased primarily due to:
to a $253 million increase in Transco’s natural gas transportation fee revenues primarily due to a $241 million increase associated with expansion projects placed in-service in 2017 and 2018.
Service revenues – commodity considerationincreased as a result of implementing ASC 606 using a modified retrospective approach. These revenues represent consideration we receive in the form of commodities as full or partial payment for gathering and processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.
The decrease in Product sales includes:
A $90 million decrease in commodity marketing revenues driven by a $149 million decrease in crude oil revenues as this activity is now presented on a net basis within Product costs in conjunction with the adoption of ASC 606, partially offset by a $59 million increase in NGL marketing revenues primarily reflecting 20 percent higher non-ethane prices;
A $14 million decrease in revenues associated with our equity NGLs, as further described below as part of our commodity product margins;
A $57 million increase in system management gas sales. System management gas sales are offset in Product costs and therefore have little impact to Modified EBITDA.
Product costs slightly increased primarily due to a $59 million increase in system management gas costs (substantially offset in Product sales) and the impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services. This increase was partially offset by an $87 million decrease in marketing purchases (more than offset in Product sales) and the absence of natural gas
purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606.
Processing commodity expenses presents the natural gas purchases associated with the production of equity NGLs as previously described in conjunction with the implementation of ASC 606.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity product margins.
Other segment costs and expenses decreased primarily due to a $17 million increase in Transco’s equity AFUDC as a result of projects placed in service in 2018.
Gain on sale of certain assets reflects an $81 million gain from the sale of our Gulf Coast pipeline system assets in fourth quarter 2018.
The decrease in Regulatory charges resulting from Tax Reform reflects the absence of $493 million of regulatory charges in 2017 associated with the impact of Tax Reform at Transco (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements).
The decrease in Proportional Modified EBITDA of equity-method investments is due to an $89 million decrease at Discovery, primarily related to a $76 million decrease associated with production ending on certain wells.
2017 vs. 2016
Atlantic-Gulf Modified EBITDA decreased primarily due to regulatory charges associated with the impact of Tax Reform at our regulated entities, higher Other segment costs and expenses, and lower Proportional Modified EBITDA from Discovery,partially offset by higher Service revenues.
Service revenues increased primarily due to:
A $135 million increase in Transco’s natural gas transportation fee revenues primarily due to a $150 million increase associated with expansion projects placed in-service in 2016 and 2017, partially offset by lower volume-based transportation services revenues;
HigherA $103 million increase in eastern Gulf Coast region revenue of $103 million associatedfee revenues primarily with higher volumes, includingrelated to the impact of new volumes at Gulfstar One related to the Gunflint expansion placed in-service in the third quarter of 2016, the absence of the temporary shut-down and subsequent ramp-up of Gulfstar One in the second and third quarters of 2016 to tie-in Gunflint, and the absence of producers’ operational issues in the Tubular Bells field during the first quarter of 2016. This increase is2016, partially offset by lower volumes as a result of a temporary increase in 2016 due to disrupted operations of a competitor;
A $39$15 million increase in Transco’s storage revenue primarily related to the absence of an accrual for potential refunds associated with a ruling received in certain rate case litigation in 2016;
A $15 million decrease in western Gulf Coast region fee revenues due to lower volumes primarily associated with producer maintenance.
Product sales increased primarily due to:
A $31 million increase in NGL and crude oil marketing revenues primarily due to a $72 million increase driven by higher prices, partially offset by a $41 million decrease driven by lower volumes. Average realized non-ethane prices were 47 percent higher and average realized crude prices were 18 percent higher. Non-ethane volumes were 16 percent lower and crude volumes were 13 percent lower driven by shut-ins of certain wells behind Devils Tower as a result of production issues and temporary hurricane-related shut-ins. (Increases in marketing revenues are substantially offset by higher Product costs);
A $12 million increase in system management gas sales from Transco. System management gas sales are offset in Product costs and, therefore, have no impact on Modified EBITDA;
A $5 million decrease in revenues associated with our equity NGLs due to a $19 million decrease driven by lower volumes, partially offset by a $14 million increase driven by higher prices. Realized non-ethane prices increased by 32 percent. Non-ethane volumes decreased by 31 percent primarily as a result of a temporary increase in 2016 due to disrupted operations of a competitor.
Product costs increased primarily due to:
A $28 million increase in marketing purchases (more than offset in Product sales);
A $12 million increase in system management gas costs (offset in Product sales);
An $8 million decrease in natural gas purchases associated with the production of equity NGLs primarily due to lower volumes.
Other segment costs and expenses increased primarily due to $89 million higher operating costs, primarily associated with Transco pipeline integrity testing and general maintenance, a $17 million increase in expense associated with an annual revision to the ARO liability, $9 million of higher general and administrative costs due to an increased share of allocated support costs, and a $15 million expense in 2017 related to a settlement charge from a pension early payout program (see Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements). These increases are partially offset by a $14 million favorable change in equity AFUDC associated with an increase in Transco’s capital spending, which is offset by an $8 million decrease in Constitution’s equity AFUDC. Other favorable changes include $12 million lower project development costs at Constitution and favorable impactsrelated to gains on asset retirements.
Regulatory charges resulting from Tax Reform reflects $493 million of regulatory charges associated with the impact of Tax Reform at Transco (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements).
The decrease in Proportional Modified EBITDA of equity-method investments includes a $12 million decrease from Discovery, a $7 million decrease in Cardinal Pipeline Company, LLC and a $5 million decrease in Pine Needle LNG Company, LLC. The decrease in Discovery is primarily associated with lower fee revenue driven by significant production issues at certain wells, higher turbine maintenance expenses, temporary hurricane-related shut-ins, and maintenance on the Keathley Canyon connector pipeline. The decrease in Cardinal Pipeline Company, LLC and Pine Needle LNG Company, LLC is primarily due to $11 million of regulatory charges associated with the impact of Tax Reform.
West
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | (Millions) |
| Service revenues | $ | 2,085 |
| | $ | 2,246 |
| | $ | 2,328 |
|
Service revenues – commodity consideration | 321 |
| | — |
| | — |
|
| Product sales | 2,448 |
| | 2,013 |
| | 1,380 |
|
| Segment revenues | 4,854 |
| | 4,259 |
| | 3,708 |
|
| | | | | | |
| Product costs | (2,448 | ) | | (1,842 | ) | | (1,256 | ) |
| Processing commodity expenses | (116 | ) | | — |
| | — |
|
| Other segment costs and expenses | (825 | ) | | (832 | ) | | (918 | ) |
| Impairment of certain assets | (1,849 | ) | | (1,032 | ) | | (100 | ) |
| Gain on sale of certain assets | 591 |
| | — |
| | — |
|
| Regulatory charges resulting from Tax Reform | 7 |
| | (220 | ) | | — |
|
| Proportional Modified EBITDA of equity-method investments | 94 |
| | 79 |
| | 110 |
|
| West Modified EBITDA | $ | 308 |
| | $ | 412 |
| | $ | 1,544 |
|
| | | | | | |
| NGL margin | $ | 194 |
| | $ | 154 |
| | $ | 112 |
|
2018 vs. 2017
West Modified EBITDA decreased primarily due to the increase in Impairment of certain assets and lower Service revenues. These decreases were partially offset by the Gain on sale of certain assets in 2018, the absence of regulatory charges associated with the impact of Tax Reform, and higher NGL margins driven by higher NGL prices and lower realized natural gas prices, partially offset by lower NGL volumes.
Service revenues decreased primarily due to:
A $64 million decrease primarily associated with implementing the new revenue guidance under ASC 606 including a $118 million decrease related to lower amortization of deferred revenue associated with the up-front cash payments received in conjunction with the fourth quarter 2016 Barnett Shale and Mid-Continent contract restructurings, partially offset by a $54 million increase related to other deferred revenue amortization primarily in the Permian basin;
A $42 million decrease associated with the sale of our Four Corners area assets in October 2018;
A $30 million decrease at Northwest Pipeline primarily due to the reduction of its rates as a result of a rate case settlement that became effective January 1, 2018;
A $29 million decrease following the Jackalope deconsolidation in second quarter 2018;
A $15 million decrease driven by lower gathering volumes primarily in the Eagle Ford Shale, Barnett Shale, and Mid-Continent regions, partially offset by higher volumes in the Niobrara (prior to the Jackalope deconsolidation), Piceance, and Permian regions;
A $21 million increase associated with higher gathering and processing rates in the Piceance region driven by higher NGL prices as well as higher average gathering and processing rates across most other areas, partially offset by lower contract rates primarily in the Haynesville Shale region.
Service revenues – commodity consideration increased as a result of implementing ASC 606 using a modified retrospective approach. These revenues represent consideration we receive in the form of commodities as full or partial
payment for gathering and processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.
The increase in Product sales includes:
A $373 million increase in marketing revenues primarily due to increases in realized NGL prices including a 14 percent increase in average non-ethane per-unit sales prices and a 25 percent increase in ethane prices, in addition to a 15 percent increase in ethane volumes (more than offset by higher Product costs);
A $47 million increase associated with sales of our equity NGLs, as further described below as part of our commodity product margins;
An $18 million increase in system management gas sales due to a change in presentation in accordance with ASC 606, which are more than offset in Product costs and, therefore, have little impact on Modified EBITDA.
The increase in Product costs includes the impact of ASC 606 in which costs reflected in this line item for 2018 include volumes acquired as commodity consideration for NGL processing services, a $381 million increase in marketing purchases (substantially offset in Product sales), a $19 million increase in system management gas costs (substantially offset in Product sales), partially offset by the absence of natural gas purchases associated with the production of equity NGLs, which are now reported in Processing commodity expenses in conjunction with the implementation of ASC 606.
Processing commodity expenses presents the natural gas purchases associated with the production of equity NGLs as previously described in conjunction with the implementation of ASC 606.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity product margins. Our commodity product margins increased primarily due to a $40 million increase in NGL product margins partially offset by an $8 million decrease in marketing margins. NGL margins are driven by $56 million in higher ethane and non-ethane per-unit prices, reflecting 19 percent higher realized non-ethane per-unit sales prices and 50 percent higher realized ethane per-unit sales prices. These increases were partially offset by $18 million in lower volumes primarily due to the sale of our Four Corners area assets in October 2018.
Other segment costs and expenses decreased primarily due to $57 million lower operating and maintenance and general and administrative costs. This reduction in costs is due primarily to the Four Corners area sale in October 2018, ongoing cost containment efforts, and the deconsolidation of our Jackalope interest in second quarter 2018. These reductions are partially offset by a $24 million regulatory charge associated with Northwest Pipeline’s approved rates related to Tax Reform, the absence of a $15 million gain from contract settlements and terminations in 2017, and a $12 million charge for a regulatory liability associated with a decrease in Northwest Pipeline’s estimated deferred state income tax rate following the WPZ Merger.
Impairment of certain assets increased primarily due to the $1.849 billion impairment of certain assets in the Barnett Shale region in 2018, partially offset by the absence of a $1.019 billion impairment of certain gathering operations in the Mid-Continent region in 2017 (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
Gain on sale of certain assets reflects a gain from the sale of our Four Corners area assets in fourth quarter 2018.
Regulatory charges resulting from Tax Reform decreased primarily due to the absence of the $220 million initial regulatory charge associated with the impact of Tax Reform at Northwest Pipeline (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements).
Proportional Modified EBITDA of equity-method investments increased primarily due to the deconsolidation of our Jackalope interest, which is accounted for as an equity-method investment beginning in the second quarter of 2018.
2017 vs. 2016
West Modified EBITDA decreased primarily due to higher Impairment of certain assets, regulatory charges associated with the impact of Tax Reform at Northwest Pipeline, lower gathering rates, and lower volumes as a result of natural declines, partially offset by lower segment costs and expenses, higher per-unit NGL margins, and higher amortization of deferred revenue associated with the up-front cash payment received in conjunction with the fourth quarter 2016 Barnett Shale contract restructuring;restructuring.
A $15 million increase in Transco’s storage revenue primarily reflecting the absence of an accrual for potential refunds associated with a ruling received in certain rate case litigation in 2016;
In the Northeast region, a slight increase reflecting a $38 million increase in gathering fee revenue at Susquehanna Supply Hub driven by 11 percent higher gathered volumes reflecting increased customer production and a $23 million increase in fee revenue at Ohio Valley Midstream reflecting the absence of shut-in volumes from the first half of 2016, as well as new production coming online. The increases were substantially offset by a $56 million decrease in the Utica gathering systemService revenues decreased primarily due to 14 percent lower gathered volumes driven by natural declines in the wet gas areas which are partially offset by higher volumes from new development in the dry gas areas;to:
A $79 million decrease in the West region related to net lower gathering rates, primarily in the Barnett Shale area primarily due to the fourth quarter 2016 contract restructuring, along withas well as lower rates recognized in the Niobrara, Eagle Ford Shale, and Haynesville Shale regions. These rate decreases are offset by higher commodity-based fee revenues in the Piceance area primarily due to higher per-unit NGL margins and higher rates in the Wamsutter area as a result of renegotiated rates in conjunction with infrastructure expansions. Rates recognized in the Niobrara region represent a portion of the total contractual rate that is received, with the difference reflected as deferred revenue;
A $34 million decrease driven by lower volumes in the West regionmost gathering and processing regions primarily as a result of natural declines and more extreme weather conditions in the Rocky Mountains in the first quarter of 2017, partially offset by higher volumes in the Haynesville Shale region as a result of increased drilling in certain areas;
A $36$39 million increase related to the rate of amortization of deferred revenue associated with the up-front cash payment received in conjunction with the fourth quarter 2016 Barnett Shale contract restructuring.
Product sales increased primarily due to:
A $532 million increase in marketing revenues primarily due to a $450 million increase driven by higher prices and an $82 million increase driven by higher volumes. The average non-ethane per-unit sales price increased by 43 percent, the average ethane per-unit sales prices increased by 30 percent, and the average natural gas per-unit sales price increased by 13 percent. Ethane and non-ethane sales volumes were 28 percent and six percent higher, respectively, partially offset by 17 percent lower natural gas sales volumes. (Higher marketing sales revenues are substantially offset by higher Product costs);
A $72 million increase in revenues associated with our equity NGLs primarily due to an $80 million increase driven by higher prices, partially offset by an $8 million decrease driven by lower volumes. Realized non-ethane prices increased by 42 percent and realized ethane prices increased by 46 percent. Non-ethane volumes decreased by six percent primarily due to natural declines and to severe winter conditions in the absencefirst quarter of revenue generated2017;
A $24 million increase in other product sales related to certain fabricated equipment sales to affiliates (more than offset by our former Canadian operations that were soldhigher other Product costs).
Product costs increased primarily due to:
A $529 million increase in September 2016;marketing purchases (more than offset in Product sales);
A $30 million increase in natural gas purchases associated with the production of equity NGLs primarily due to a 26 percent increase in per-unit natural gas prices;
A $25 million increase in other product costs related to certain fabricated equipment sales to affiliates (offset by higher other Product sales).
A $15 million decrease in western Gulf Coast region fee revenues due to lower volumes primarily associated with producer maintenance.
Product sales increased primarily due to:
A $735 million increase in marketing revenues primarily due to significantly higher prices across all products and higher NGL volumes (substantially offset in marketing purchases);
A $32 million increase in revenues from our equity NGLs including a $102 million increase driven primarily by higher non-ethane prices, partially offset by a $36 million decrease due to the absence of NGL production revenues associated with our former Canadian operations and a $34 million decrease primarily related to lower non-ethane volumes at our domestic plants driven by the absence of temporary volumes in 2016 related to disrupted operations of a competitor, severe winter conditions in the first quarter of 2017, and natural declines;
A $12 million increase in system management gas sales from Transco. System management gas sales are offset in Product costs and, therefore, have no impact on Modified EBITDA;
A $380 million decrease in olefin sales primarily due to a $343 million decrease reflecting the absence of third- and fourth-quarter sales of our Gulf Olefins operations, a $29 million decrease due to the sale of the Canadian operations in 2016, and a $16 million decrease at our Geismar plant in the first half of 2017 primarily due to lower volumes associated with the electrical outage in second-quarter 2017, as well as planned maintenance downtime in first-quarter 2017. These items were partially offset by $8 million higher sales at the RGP Splitter in the first half 2017 primarily due to higher propylene prices.
Product costs increased primarily due to:
A $725 million increase in marketing purchases primarily due to the same factors that increased marketing sales (more than offset in marketing revenues). The increase in marketing costs does not reflect the intercompany costs associated with certain gathering and processing services performed by an affiliate;
A $12 million increase in system management gas costs (offset in Product sales);
A $166 million decrease in olefin feedstock purchases primarily due to the absence of $163 million in feedstock purchases in the second half of 2017 reflecting the sale of the Gulf Olefins operations, as well as the absence of $9 million in costs associated with our former Canadian operations, partially offset by $6 million higher feedstock costs in the first half of 2017.
A $2 million decrease in costs from our equity NGLs including a $35 million increase driven primarily by higher gas prices, partially offset by a $24 million decrease due to the absence of NGL production revenues associated with our former Canadian operations and a $13 million decrease primarily related to lower volumes at our domestic plants driven by severe winter conditions in the first quarter of 2017, and the absence of temporary volumes in 2016 related to disrupted operations of a competitor and natural declines.
The favorable change in Other segment costs and expenses includes a decrease in labor-related expenses primarily due to our first quarter 2016 workforce reduction and ongoing cost containment efforts; the absence of $117 million of operating and other expenses associated with our Gulf Olefins and Canadian operations; and the absence of a $34 million loss on the sale of our former Canadian operations. Additional favorable changes in Other segment costs and expenses includereflects a $56 million decline in operating expenses, a $27 million net gain associated with early debt retirement; a $15reduction in general and administrative expenses, and $15 million gain related to favorableof gains from contract settlements and terminations;terminations in Other (income) expense – netwithin Operating income (loss). The reductions in operating and general and administrative expenses are primarily due to the 2016 workforce reductions, ongoing cost containment efforts, lower compression expenses, favorable system gains and gas imbalance revaluations, and a favorable change in equity AFUDC, primarily associated with an increase in Transco’s capital spending, which isreduced share of allocated support costs. These items are partially offset by a decrease in capital spending at Constitution; and a $12$13 million gain on the sale of the RGP Splitter. These decreases are partially offset by $35 million of expense in 2017 related to a settlement charge from a pension early payout program (see(See Note 910 – Employee Benefit Plans of Notes to Consolidated Financial Statements), higher various maintenance expenses, an increase in pipeline integrity testing on Transco, and higher Geismar selling expenses and repairs related to a Geismar electrical outage.
Gain on sale of Geismar Interest reflects the gain recognized on the sale of our Geismar Interest in July 2017. (See Note 2 - Acquisitions and Divestitures of Notes to Consolidated Financial Statements.).
Impairment of certain assets increased primarily due to athe $1.032 billion impairment of certain gathering operations primarily in the Mid-Continent region and a $115 million impairment of certain gathering operations in the Marcellus South region,2017, partially offset by the absence of a $341 million impairment of our former Canadian operations and a $100 million impairmentin impairments of certain Mid-Continent gathering assets and impairments or write-downs of other certain assets that may no longer be in use or are surplus in nature duringin 2016. (See Note 16 - Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)
Regulatory charges resulting from Tax Reform reflects $713$220 million of regulatory charges associated with the impact of Tax Reform at Transco and Northwest Pipeline with $674 million presented as(See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies Regulatory charges resulting from Tax Reform of Notes to Consolidated Financial Statementsand $39 million included within Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations.).
The increase in Proportional Modified EBITDA of equity-method investments includes a $100 million increase at Appalachia Midstream Investments reflecting our increased ownership acquired late in the first quarter of 2017, higher gathering volumes reflecting the absence of shut-in volumes from 2016 and increased customer production, and a $20 million increase at Aux Sabledecreased primarily due to increased customer production. These increases are partially offset by a $34 million decrease at UEOM reflecting lower processing volumes from the wet gas areas of the Utica gathering system, the divestiture of our interests inof DBJV and Ranch Westex JV LLC late in the first quarter of 2017, a $12 million decrease from Discovery primarily attributable to lower fee revenue driven by production issues at certain wells and higher turbine maintenance expenses.2017.
Other
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | (Millions) |
| Other Modified EBITDA | $ | (29 | ) | | $ | 997 |
| | $ | (696 | ) |
2018 vs. 20152017
Modified EBITDA decreased primarily due to higher impairments, lower insurance recoveries associated with the Geismar Incident, and loss on sale associated with our Canadian operations. These decreases were partially offset by higher olefin margins related to the Geismar plant operating at higher production levels in 2016, lower segment costs and expenses, and higher earnings related to our equity-method investments, including the completion of the Keathley Canyon Connector at Discovery in the first quarter of 2015. Additionally, higher marketing margins, higher service revenues related to projects placed in service, and higher NGL margins improved Modified EBITDA.
The increase in Service revenues is primarily due to a $79 million increase in Transco’s natural gas transportation fee revenues primarily associated with expansion projects placed in service in 2015 and 2016 and a $31 million transportation and fractionation revenue increase associated with Williams’ Horizon liquids extraction plant in Canada. The Canadian operations were sold in late September 2016. These increases were partially offset by a decrease in gathering, processing, and fractionation revenue primarily due to lower volumes primarily in the Barnett Shale and Anadarko basin and a $15 million decrease in Transco’s storage revenue related to potential refunds associated with a ruling received in certain rate case litigation in 2016.
Product sales increasedchanged unfavorably primarily due to:
A $94 million increase in olefin sales comprisedThe absence of a $170$1.095 billion gain on the sale of our Geismar Interest in 2017 (see Note 3 – Divestitures of Notes to Consolidated Financial Statements);
The absence of $54 million increase from the Geismar plant that returned to service in late March 2015, partially offset by a $76 million decrease from our other former olefin operations. The increase at Geismar includes $153 millionof Modified EBITDA associated with increased volumes as a resultthe results of the plant operating at higher production levelsour former Geismar Olefins and RGP Splitter plants subsequent to their sale in 2016 than when production resumedJuly 2017;
A $35 million charge in March 2015 following the Geismar Incident and $17 million primarily2018 associated with higher ethylene per-unit sales prices.a charitable contribution of preferred stock to The decrease in other olefin sales includes a $14Williams Companies Foundation, Inc. (a not-for-profit corporation) (see Note 15 – Stockholders' Equity of Notes to Consolidated Financial Statements);
A $34 million reductiondecrease due to the absence of our former Canadian operationsa net gain on early retirement of debt in the fourth quarter2017 and a loss on early retirement of 2016, as well as lower volumesdebt in 2018 (see Note 7 – Other Income and lower per-unit sales prices within our other olefin operations;Expenses of Notes to Consolidated Financial Statements);
A $70$26 million increasedecrease in marketing revenues primarily dueincome associated with a regulatory asset related to higher NGLdeferred taxes on equity funds used during construction;
$20 million in costs in 2018 associated with the WPZ Merger (see Note 1 – General, Description of Business, Basis of Presentation, and propylene pricesSummary of Significant Accounting Policies of Notes to Consolidated Financial Statements);
The absence of a $12 million gain on the sale of the Refinery Grade Propylene Splitter in 2017 (see Note 7 – Other Income and natural gas and crude oil volumes, partially offset by lower NGL volumes and crude oil prices (partially offset in marketing purchases);Expenses of Notes to Consolidated Financial Statements).
A $6 million increase in revenues from our equity NGLs due to a $10 million increase associated with higher volumes,These decreases were partially offset by a $4 million decrease associated with lower NGL prices;
A $39 million decrease in system management gas sales from Transco. System management gas sales are offset in Product costs and, therefore, have no impact on Modified EBITDA.
The decrease in Product costs includes:
A $39 million decrease in system management gas costs (offset in Product sales);
A $17 million decrease in olefin feedstock purchases is primarily comprised of $78 million in lower purchases at our former other olefins operations, partially offset by $61 million of higher purchases due primarily to increased volumes at the Geismar plant resulting from higher productions levels. The lower costs at our former other olefin operations are comprised of $54 million in lower per-unit feedstock costs and $24 million in primarily lower propylene volumes;
A $4 million decrease in natural gas purchases associated with the production of equity NGLs reflecting a decrease of $13 million due to lower natural gas prices, partially offset by a $9 million increase associated with higher volumes;
Lower costs associated with various other products, primarily condensate;
A $22 million increase in marketing purchases primarily due to the same factors that increased marketing sales (more than offset in marketing revenues). The increase in marketing costs does not reflect the intercompany costs associated with certain gathering and processing services performed by an affiliate.
The decrease in Other segment costs and expenses is primarily due to lower operating costs and general and administrative expenses reflecting decreases in primarily labor-related and outside services costs resulting from our first-quarter 2016 workforce reductions and ongoing cost containment efforts and lower costs associated with general maintenance activities in the Marcellus Shale, as well as $43 million of lower ACMP Merger and transition-related expenses. Other items partially offsetting these decreases are as follows:
$37 million increase for severance and related costs associated with workforce reductions incurred in the first quarter of 2016 and the organizational realignment in the fourth quarter of 2016;
$34 million increase related to the 2016 loss on sale of our Canadian operations;
$28 million higher project development costs at Constitution as we discontinued capitalization of development costs related to this project beginning in April 2016;
$22 million higher contract services for pipeline testing and general maintenance at Transco;
$20 million unfavorable change in foreign currency exchange that primarily relates to losses incurred on foreign currency transactions and the remeasurement of the U.S. dollar-denominated current assets and liabilities within our former Canadian operations;
$19 million unfavorable change in AFUDC associated with a decrease in spending on Constitution;by:
The absence of a $14$68 million gain recognizedimpairment for a certain NGL pipeline asset in second-quarter 2015 resulting from the early retirementthird quarter of certain debt.
Net insurance recoveries – Geismar Incident decreased reflecting $72017 and a$23 million impairment of insurance proceeds receivedan olefins pipeline project in 2016 compared to $126 million receivedthe Gulf Coast region in 2015.
Impairmentthe second quarter of certain assets increased primarily due to 2016 impairments of $341 million associated with our Canadian operations and $63 million associated with certain Mid-Continent gathering assets as well as impairments or write-downs of other certain assets that may no longer be in use or are surplus in nature,2017, partially offset by a $66 million impairment of certain idle pipelines in the absencesecond quarter of 2015 impairments of $94 million associated with previously capitalized project development costs for a gas processing plant and $20 million associated with certain surplus equipment within our Ohio Valley Midstream business. (See2018 (see Note 1617 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)Statements);
The increase in Proportional Modified EBITDAA decrease of equity-method investments is primarily due$62 million for charges reducing regulatory assets related to a $30deferred taxes on AFUDC resulting from Tax Reform (see Note 7 – Other Income and Expenses of Notes to Consolidated Financial Statements);
$40 million of lower costs, driven by the absence of expenses associated with severance and related costs, Financial Repositioning, and strategic alternative costs (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements);
A $37 million increase from Discovery primarily associated with higher fee revenues attributable to the completionbenefit of the Keathley Canyon Connector in the first quarter of 2015. Additionally, Caiman II contributedestablishing 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 primarilyregulatory asset associated with an increase in our ownership percentage. These increases were partially offset by a $29Transco’s estimated deferred state income tax rate following the WPZ Merger;
A $30 million decrease from Appalachia Midstream Investments primarily duefavorable change in the settlement charge expense related to lower fee revenues driven by lower rates, partially offset by lower impairmentsthe program to pay out certain deferred vested pension benefits of employees associated with former operations (see Note 10 – Employee Benefit Plans of Notes to Consolidated Financial Statements);
A $20 million gain on the sale of certain assets and higher volumes.operations located in the Gulf Coast area (see Note 3 – Divestitures of Notes to Consolidated Financial Statements).
Other
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (Millions) |
| Other Modified EBITDA | $ | (150 | ) | | $ | (542 | ) | | $ | (112 | ) |
2017 vs. 2016
The favorable change in Modified EBITDA is primarily due to:
A $1.095 billion gain recognized on the sale of our Geismar Interest in July 2017. (See Note 3 – Divestitures of Notes to Consolidated Financial Statements);
The absence of the $406$747 million 2016 impairment of our Canadian operations, partially offset by the $23 million impairment of an olefins pipeline project in the Gulf Coast region in the second quarter of 2017 and the $68 million impairment of a certain NGL pipeline asset in the third quarter of 2017 (see Note 1617 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements);
The absence of $61 million of certain project development costs associated with the Canadian PDH facility that we expensed in 2016;
A $31$65 million favorable change in the loss on the sale of our Canadian operations in September 2016;
A $38 million decrease in costs related to our evaluation of strategic alternatives;
The absence of $32 million of transportation and fractionation fees incurred in 2016 related to the Redwater fractionation facility, which was included in the sale of our Canadian operations in September 2016;
A $38 million decrease in costs related to our evaluation of strategic alternatives;
A $29 million increase in income associated with an increase in a regulatory asset primarily driven by our increased ownership in WPZ.
These favorable changes are partially offset by:
A $164 million decrease due to the absence of results from our former Geismar Olefins and RGP Splitter plants subsequent to their sale in July 2017;
A $63 million charge reducing regulatory assets related to deferred taxes on AFUDC resulting from Tax Reform (see Note 67 – Other Income and Expenses of Notes to Consolidated Financial Statements);
A $35 million settlement charge expense related to the program to pay out certain deferred vested pension benefits of employees associated with former operations. (See Note 910 – Employee Benefit Plans of Notes to Consolidated Financial Statements);
A reduction in revenues associated with an NGL pipeline near the Houston Ship Channel region;
The absence of a $10 million gain on the sale of unused pipe in 2016.
2016 vs. 2015
The unfavorable change in Modified EBITDA is primarily due to:
The impairment and loss on sale of our Canadian operations totaling $438 million in 2016;
An increase of $61 million of certain project development costs associated with the Canadian PDH facility that we began expensing in 2016;
A $17 million increase in costs related to our evaluation of strategic alternatives.
These unfavorable changes are partially offset by:
A $10 million gain on the sale of unused pipe in 2016;
A $31 million decrease in ACMP merger and transition related costs;
The absence of a $64 million write-off of previously capitalized project development costs for an olefins pipeline project in 2015.
Management’s Discussion and Analysis of Financial Condition and Liquidity
Overview
In 2017,2018, through the WPZ Merger, we exceededstreamlined our targetcorporate structure and governance while improving our credit ratings to investment-grade. Additionally, we monetized assets, through sales of the Four Corners area assets and certain Gulf Coast pipeline systems which were not core to our business strategy, into a source for asset sales, significantly improvedgrowth capital for acquisitions such as our balance sheetRMM equity-method investment and a driver for improving credit metrics while continuing to provide ample available liquidity, and continued to focus on growth inreduce our businesses by identifying, contracting, permitting, and constructing attractive expansion projects. Examples of this activity included:
Sale of our Geismar Interest (see Note 2 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).
Repayment of WPZ’s $850 million variable interest rate term loan that was due December 2018, and early retirement of WPZ’s $750 million of 6.125 percent senior unsecured notes that were due in 2022;
Repayment of WPZ’s $1.4 billion of 4.875 percent senior unsecured notes that were due in 2023 with proceeds from the issuance of WPZ’s $1.45 billion of 3.75 percent senior unsecured notes due in 2027;
Extension to 2021 for the maturity dates of our long-term credit facility and WPZ’s long-term credit facility;
Expansion of WPZ’s interstate natural gas pipeline system through completion of 2017 strategic projects (Gulf Trace, Hillabee Phase 1, Dalton, New York Bay, and Virginia Southside II) to meet the demand of growth markets.direct commodity exposure.
Outlook
Fee-based businesses are a significant component of our portfolio and serve to reduce the influence of commodity price fluctuations on our cash flows. We expect to benefit as continued growth in demand for low-cost natural gas is driven by increases in LNG exports, industrial demand, and power generation.
As previously discussed in Company Outlook, our consolidated growth capital and investment expenditures in 20182019 are currently expected to be approximatelyin a range from $2.7 billion to $2.9 billion. Approximately $1.7 billion of our growthGrowth capital funding needs includespending in 2019 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 2018 primarily reflects investment inagreements, and continuing to develop our gathering and processing systemsinfrastructure in the Northeast region limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project.G&P and West segments. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments. WPZ intendsWe intend to fund theirour planned 20182019 growth capital with retained cash flow and debt.certain sources of available liquidity described below. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities.
Liquidity
Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2018. WPZ expects to be self-funding and maintain separate bank accounts and credit facilities, including its commercial paper program.2019. Our potential material internal and external sources and uses of consolidated liquidity for 20182019 are as follows:
|
| |
| | | |
| | | | Applicable To: |
| | | WPZ | | WMB |
| Sources: | | | | | |
| | Cash and cash equivalents on hand | | ü | | ü |
| | Cash generated from operations | | ü | | |
| | Distributions from investment in WPZ | | | | ü |
| Distributions fromour equity-method investees | | ü | | |
| | Utilization of our credit facilitiesfacility and/or commercial paper program | | ü | | ü |
| | Cash proceeds from issuance of debt and/or equity securities | | ü | | ü |
| | Proceeds from asset monetizations | | ü | | |
| | | | | |
| Uses: | | | | | |
| | Working capital requirements | | ü | | ü |
| | Capital and investment expenditures | | ü | | |
| Investment in WPZ | | | | ü |
| Quarterly distributions to unitholders | | ü | | |
| | Quarterly dividends to our shareholders | | | | ü |
| | Debt service payments, including payments of long-term debt | | ü | | ü |
Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook.
As of December 31, 2017,2018, we had a working capital deficit of $467 million.$347 million, including cash and cash equivalents. Our available liquidity is as follows:
| | | | | December 31, 2017 | | | |
| Available Liquidity | | WPZ | | WMB | | Total | | December 31, 2018 |
| | | (Millions) | | (Millions) |
| Cash and cash equivalents | | $ | 881 |
| | $ | 18 |
| | $ | 899 |
| | $ | 168 |
|
| Capacity available under our $1.5 billion credit facility (1) | | | | 1,230 |
| | 1,230 |
| |
| Capacity available to WPZ under its $3.5 billion credit facility, less amounts outstanding under its $3 billion commercial paper program (2) | | 3,500 |
| | | | 3,500 |
| |
| Capacity available under our $4.5 billion credit facility, less amounts outstanding under our $4 billion commercial paper program (1) | | | 4,340 |
|
| | | $ | 4,381 |
| | $ | 1,248 |
| | $ | 5,629 |
| | $ | 4,508 |
|
__________
| |
| (1) | The highest amount outstanding under our credit facility during 2017 was $805 million. At December 31, 2017, we were in compliance with the financial covenants associated with this credit facility. See Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements for additional information on our credit facility. Borrowing capacity available under this facility as of February 20, 2018, was $1.5 billion. |
| |
(2) | In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of WPZ’sour credit facility inclusive of any outstanding amounts under itsour commercial paper program. AsThrough completion of December 31, 2017, no Commercial paper was outstanding under WPZ’s commercial paper program. Thethe WPZ Merger on August 10, 2018, the highest combined amount outstanding under WPZ’s commercial paper program and credit facility and our former credit facility during 20172018 was $178$1.325 billion. In July 2018, we along with Transco and Northwest Pipeline entered into a new unsecured revolving credit agreement with aggregate commitments available of $4.5 billion under the credit facility, which became effective upon completion of the WPZ Merger. The highest amount outstanding under our current commercial paper program and credit facility during 2018 was $886 million. At December 31, 2017, WPZ was2018, we were in compliance with the financial covenants associated with thisour credit facility. See Note 1314 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements for additional information on WPZ’sour credit facility and WPZ’s commercial paper program. Borrowing capacity available under WPZ’s $3.5 billionour credit facility as of February 20, 2018,19, 2019, was $3.5$4.5 billion. |
As described in Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements, we have determined that we have net assets that are technically considered restricted in accordance with Rule 4-08(e) of Regulation S-X of the Securities and Exchange Commission in excess of 25 percent of our consolidated net assets. We do not expect this determination will impact our ability to pay dividends or meet future obligations as the terms of WPZ’s partnership agreement require it to make quarterly distributions of all available cash, as defined, to its unitholders.
Dividends
As part of the Financial Repositioning, weWe increased our regular quarterly cash dividend by 50approximately 13 percent from the previous quarterly dividendcash dividends of $0.20$0.30 per share paid in December 2016,each quarter of 2017, to $0.30$0.34 per share for the quarterly cash dividends paid in each quarter of 2017.2018.
Registrations
In September 2016, WPZ filed a registration statement for its distribution reinvestment program.
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, registering common units representing limited partner interests and debt securities. Also in February 2015, WPZ 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; therethe sale. There was no activity during 2017.2018.
Distributions from Equity-Method Investees
The organizational documents of entities in which we have an equity-method investment generally require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses. (See Note 56 – 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 is 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+ | | BB+ |
| Moody’s Investors Service | | Positive | | Ba2 | | N/A |
| Fitch Ratings | | Stable | | BB+ | | N/A |
| | | | | | | |
WPZ: | S&P Global Ratings | | StableNegative | | BBB | | BBB |
| Moody’s Investors Service | | PositiveStable | | Baa3 | | N/A |
| Fitch Ratings | | Positive | | BBB- | | N/A |
During March 2017, S&P Global Ratings upgraded its rating for both WMB and WPZ.
68
These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our or WPZ’s securities, and each rating should be evaluated independently of any other rating. No assurance can be given that the credit rating agencies will continue to assign us or WPZ theinvestment-grade ratings shown above even if we or WPZ meet or exceed their current criteria.criteria for investment-grade ratios. A downgrade of our credit ratings or the credit ratings of WPZ might increase our future cost of borrowing and would require us to provide additional collateral to third parties, negatively impacting our available liquidity.
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 | | 2017 | | 2016 | | 2015 |
| | | | (Millions) |
| Sources of cash and cash equivalents: | | | | | | | |
Operating activities – net | Operating | | $ | 2,556 |
| | $ | 3,680 |
| | $ | 2,708 |
|
| Proceeds from equity offerings | Financing | | 2,131 |
| | 123 |
| | 86 |
|
| Proceeds from sale of businesses, net of cash divested (see Note 2) | Investing | | 2,067 |
| | 1,020 |
| | — |
|
| Proceeds from long-term debt (see Note 13) | Financing | | 1,698 |
| | 998 |
| | 3,842 |
|
| Proceeds from our credit-facility borrowings | Financing | | 1,635 |
| | 2,280 |
| | 2,097 |
|
| Distributions from unconsolidated affiliates in excess of cumulative earnings | Investing | | 529 |
| | 472 |
| | 404 |
|
| Contributions in aid of construction | Investing | | 426 |
| | 218 |
| | 87 |
|
| Proceeds from dispositions of equity-method investments (see Note 5) | Investing | | 200 |
| | 34 |
| | — |
|
| Contributions from noncontrolling interests | Financing | | 17 |
| | 29 |
| | 111 |
|
| Proceeds from WPZ’s credit-facility borrowings | Financing | | — |
| | 3,250 |
| | 3,832 |
|
| Special distribution from Gulfstream (see Note 5) | Financing | | — |
| | — |
| | 396 |
|
| | | | | | | | |
| Uses of cash and cash equivalents: | | | | | | | |
| Payments of long-term debt (see Note 13) | Financing | | (3,785 | ) | | (375 | ) | | (1,533 | ) |
| Capital expenditures | Investing | | (2,399 | ) | | (2,051 | ) | | (3,167 | ) |
| Payments on our credit-facility borrowings | Financing | | (2,140 | ) | | (2,155 | ) | | (1,817 | ) |
| Dividends paid | Financing | | (992 | ) | | (1,261 | ) | | (1,836 | ) |
| Dividends and distributions paid to noncontrolling interests | Financing | | (822 | ) | | (940 | ) | | (942 | ) |
| Purchases of and contributions to equity-method investments | Investing | | (132 | ) | | (177 | ) | | (595 | ) |
Payments of WPZ’s commercial paper – net | Financing | | (93 | ) | | (409 | ) | | (306 | ) |
| Payments on WPZ’s credit-facility borrowings | Financing | | — |
| | (4,560 | ) | | (3,162 | ) |
| Contribution to Gulfstream for repayment of debt (see Note 5) | Financing | | — |
| | (148 | ) | | (248 | ) |
| Purchases of businesses, net of cash acquired | Investing | | — |
| | — |
| | (112 | ) |
| | | | | | | | |
Other sources / (uses) – net | Financing and Investing | | (167 | ) | | 42 |
| | 15 |
|
| Increase (decrease) in cash and cash equivalents | | | $ | 729 |
| | $ | 70 |
| | $ | (140 | ) |
|
| | | | | | | | | | | | | |
| | Cash Flow | | Years Ended December 31, |
| | Category | | 2018 | | 2017 | | 2016 |
| | | | (Millions) |
| Sources of cash and cash equivalents: | | | | | | | |
Operating activities – net | Operating | | $ | 3,293 |
| | $ | 3,089 |
| | $ | 4,155 |
|
| Proceeds from long-term debt (see Note 14) | Financing | | 2,086 |
| | 1,698 |
| | 998 |
|
| Proceeds from credit-facility borrowings | Financing | | 1,840 |
| | 1,635 |
| | 5,530 |
|
| Proceeds from sale of businesses, net of cash divested (see Note 3) | Investing | | 1,296 |
| | 2,067 |
| | 1,020 |
|
| Contributions in aid of construction | Investing | | 411 |
| | 426 |
| | 218 |
|
| Proceeds from equity offerings | Financing | | 15 |
| | 2,131 |
| | 123 |
|
| Proceeds from dispositions of equity-method investments (see Note 6) | Investing | | — |
| | 200 |
| | 34 |
|
| | | | | | | | |
| Uses of cash and cash equivalents: | | | | | | | |
| Capital expenditures | Investing | | (3,256 | ) | | (2,399 | ) | | (2,051 | ) |
| Payments on credit-facility borrowings | Financing | | (1,950 | ) | | (2,140 | ) | | (6,715 | ) |
| Common dividends paid | Financing | | (1,386 | ) | | (992 | ) | | (1,261 | ) |
| Payments of long-term debt (see Note 14) | Financing | | (1,254 | ) | | (3,785 | ) | | (375 | ) |
| Purchases of and contributions to equity-method investments | Investing | | (1,132 | ) | | (132 | ) | | (177 | ) |
| Dividends and distributions paid to noncontrolling interests | Financing | | (591 | ) | | (822 | ) | | (940 | ) |
Payments of commercial paper – net | Financing | | (2 | ) | | (93 | ) | | (409 | ) |
| Contribution to Gulfstream for repayment of debt (see Note 6) | Financing | | — |
| | — |
| | (148 | ) |
| | | | | | | | |
Other sources / (uses) – net | Financing and Investing | | (101 | ) | | (154 | ) | | 68 |
|
| Increase (decrease) in cash and cash equivalents | | | $ | (731 | ) | | $ | 729 |
| | $ | 70 |
|
Operating activities
The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash items such as Depreciation and amortization, Provision (benefit) for deferred income taxes, Equity (earnings) losses, Net (gain) loss on disposition of equity-method investments, Impairment of goodwillequity-method investments, ImpairmentGain on sale of equity-method investmentscertain assets, Impairment of and net (gain) loss on sale of other assets and businesses, Gain on saledeconsolidation of Geismar Interestbusinesses, and Regulatory charges resulting from Tax Reform.
Our Net cash provided (used) by operating activities in 2018 increased from 2017 primarily due to higher operating income (excluding noncash items as previously discussed) in 2018, partially offset by the impact of decreased distributions from unconsolidated affiliates in 2018.
Our Net cash provided (used) by operating activities in 2017 decreased from 2016 primarily due to the absence in 2017 of receipts from 2016 contract restructurings, partially offset by higher operating income and increased distributions from unconsolidated affiliates in 2017.
Our Net cash provided (used) by operating activities in 2016 increased from 2015 primarily due to the impact of net favorable changes in operating working capital and receipts from contract restructurings.
Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments
We have various other guarantees and commitments which are disclosed in Note 34 – Variable Interest Entities, Note 1011 – Property, Plant, and Equipment, Note 1314 – Debt, Banking Arrangements, and Leases, Note 1617 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk, and Note 1718 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements. We do not believe these guarantees and commitments or the possible fulfillment of them will prevent us from meeting our liquidity needs.
Contractual Obligations
The table below summarizes the maturity dates of our contractual obligations at December 31, 2017:2018:
| | | | 2018 | | 2019 - 2020 | | 2021 - 2022 | | Thereafter | | Total | 2019 | | 2020 - 2021 | | 2022 - 2023 | | Thereafter | | Total |
| | | | | | (Millions) | | | | | | | | | (Millions) | | | | |
| Long-term debt: (1) | | | | | | | | | | | | | | | | | | |
| Principal | $ | 502 |
| | $ | 2,156 |
| | $ | 3,146 |
| | $ | 15,277 |
| | $ | 21,081 |
| $ | 47 |
| | $ | 3,028 |
| | $ | 3,654 |
| | $ | 15,878 |
| | $ | 22,607 |
|
| Interest | 1,049 |
| | 1,995 |
| | 1,743 |
| | 7,795 |
| | 12,582 |
| 1,170 |
| | 2,147 |
| | 1,868 |
| | 9,410 |
| | 14,595 |
|
| Operating leases | 44 |
| | 74 |
| | 62 |
| | 137 |
| | 317 |
| 34 |
| | 59 |
| | 39 |
| | 86 |
| | 218 |
|
| Purchase obligations (2) | 1,171 |
| | 914 |
| | 632 |
| | 277 |
| | 2,994 |
| 1,194 |
| | 819 |
| | 457 |
| | 363 |
| | 2,833 |
|
| Other obligations (3)(4) | 1 |
| | 2 |
| | 1 |
| | 1 |
| | 5 |
| 2 |
| | 4 |
| | 1 |
| | — |
| | 7 |
|
| Total | $ | 2,767 |
| | $ | 5,141 |
| | $ | 5,584 |
| | $ | 23,487 |
| | $ | 36,979 |
| $ | 2,447 |
| | $ | 6,057 |
| | $ | 6,019 |
| | $ | 25,737 |
| | $ | 40,260 |
|
______________
| |
| (1) | Includes the borrowings outstanding under credit facilities, but does not include any related variable-rate interest payments. |
| |
| (2) | Includes approximately $348$480 million in open property, plant, and equipment purchase orders. Includes an estimated $314$329 million long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at December 31, 20172018 prices. This obligation is part of an overall exchange agreement whereby volumes we transport on OPPL are sold at a third-party fractionator near Conway, Kansas, and we are subsequently obligated to purchase ethane volumes at Mont Belvieu. The purchased ethane volumes may be utilized or sold at comparable prices in the Mont Belvieu market. Includes an estimated $454$453 million long-term ethane purchase obligation with index-based pricing terms that primarily supplies third parties at their plants and is valuedreflected in this table at a pricevalue calculated using December 31, 20172018 prices. Any excess purchased volumes may be sold at comparable market prices. Includes an estimated $765$211 million long-term mixed NGLs purchase obligation with index-based pricing terms that is reflected in this table at December 31, 20172018 prices. Includes an estimated $278$312 million long-term ethane purchase obligation with index-based pricing terms that primarily supplies a third party for consumption at their plant and is reflected in this table at a pricevalue calculated using December 31, 20172018 prices. Any excess purchased volumes may be sold at comparable market prices. Includes an estimated $332 million long-term mixed NGLs purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2018 prices. In addition, we have not included certain natural gas life-of-lease contracts for which the future volumes are indeterminable. We have not included commitments, beyond purchase orders, for the acquisition or construction of property, plant, and equipment or expected contributions to our jointly owned investments. (See Company Outlook — Expansion Projects.) |
| |
| (3) | Does not include estimated contributions to our pension and other postretirement benefit plans. We made contributions to our pension and other postretirement benefit plans of $93 million in 2018 and $90 million in 2017 and $72 million in 2016.2017. In 2018,2019, we expect to contribute approximately $91$69 million to these plans (see Note 910 – Employee Benefit Plans of Notes to Consolidated Financial Statements). Tax-qualified pension plans are required to meet minimum contribution requirements. In the past, we have contributed amounts to our tax-qualified pension plans in excess of the minimum required contribution. These excess amounts can be used to offset future minimum contribution requirements. During 2017,2018, we contributed $80 million to our tax-qualified pension plans. In addition to these contributions, a portion of the excess contributions was used to meet the minimum contribution requirements. During 2018,2019, we expect to contribute approximately $80$60 million to our tax-qualified pension plans and use excess amounts to satisfy minimum contribution requirements, if needed. Additionally, estimated future minimum funding requirements may vary significantly from historical requirements if actual results differ significantly from estimated |
results for assumptions such as returns on plan assets, interest rates, retirement rates, mortality, and other significant assumptions or by changes to current legislation and regulations.
| |
| (4) | We have not included income tax liabilities in the table above. See Note 78 – 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 4350 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 1718 – 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$35 million, all of which are included in Accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet at December 31, 2017.2018. We will seek recovery of the accrued costs related to remediation activities by our interstate gas pipelines totaling approximately $7$6 million through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2017,2018, we paid approximately $64 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $10$11 million in 20182019 for these activities. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At December 31, 2017,2018, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.
The EPA and various state regulatory agencies routinely promulgate and propose new rules and issue updated guidance to existing rules. More recent rules andThese rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, 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 rule regarding National Ambient Air Quality Standards for ground-level ozone, setting a stricter standard of 70 parts per billion.ozone. We are monitoring the rule's implementation as the reductionit will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.
Our interstate natural gas pipelines consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates.
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 1314 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)
The tables below provide information by maturity date about our interest rate risk-sensitive instruments as of December 31, 20172018 and 2016. The2017. See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements for the methods used in determining the fair value of our 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.
| | | | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | Thereafter (1) | | Total | | Fair Value December 31, 2017 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | Thereafter (1) | | Total | | Fair Value December 31, 2018 |
| | (Millions) | (Millions) |
| Long-term debt, including current portion: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed rate | | $ | 502 |
| | $ | 33 |
| | $ | 2,123 |
| | $ | 873 |
| | $ | 2,003 |
| | $ | 15,131 |
| | $ | 20,665 |
| | $ | 22,735 |
| | $ | 47 |
| | $ | 2,138 |
| | $ | 890 |
| | $ | 2,021 |
| | $ | 1,473 |
| | $ | 15,685 |
| | $ | 22,254 |
| | $ | 23,170 |
|
| Weighted-average interest rate | | 5.1 | % | | 5.1 | % | | 5.1 | % | | 5.1 | % | | 5.2 | % | | 5.7 | % | | | | | | 5.2 | % | | 5.2 | % | | 5.2 | % | | 5.3 | % | | 5.5 | % | | 5.7 | % | | | | |
| Variable rate (2) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 270 |
| | $ | — |
| | $ | — |
| | $ | 270 |
| | $ | 270 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 160 |
| | $ | — |
| | $ | 160 |
| | $ | 160 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | Thereafter (1) | | Total | | Fair Value December 31, 2016 | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | Thereafter (1) | | Total | | Fair Value December 31, 2017 |
| | (Millions) | (Millions) |
| Long-term debt, including current portion: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed rate | | $ | 785 |
| | $ | 500 |
| | $ | 32 |
| | $ | 2,121 |
| | $ | 871 |
| | $ | 17,475 |
| | $ | 21,784 |
| | $ | 22,465 |
| | $ | 502 |
| | $ | 33 |
| | $ | 2,123 |
| | $ | 873 |
| | $ | 2,003 |
| | $ | 15,131 |
| | $ | 20,665 |
| | $ | 22,735 |
|
| Weighted-average interest rate | | 5.2 | % | | 5.2 | % | | 5.2 | % | | 5.2 | % | | 5.2 | % | | 5.6 | % | | | | | | 5.1 | % | | 5.1 | % | | 5.1 | % | | 5.1 | % | | 5.2 | % | | 5.7 | % | | | | |
| Variable rate (3) | | $ | — |
| | $ | 850 |
| | $ | — |
| | $ | 775 |
| | $ | — |
| | $ | — |
| | $ | 1,625 |
| | $ | 1,625 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 270 |
| | $ | — |
| | $ | — |
| | $ | 270 |
| | $ | 270 |
|
| Commercial paper: | | | | | | | | | | | | | | | | | |
| Variable rate (4) | | $ | 93 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 93 |
| | $ | 93 |
| |
__________________
| |
| (1) | Includes unamortized discount / premium and debt issuance costs. |
| |
| (2) | The weighted-average interest rate for our $160 million credit facility borrowing at December 31, 2018 was 3.77 percent. |
| |
| (3) | The weighted-average interest rate for our $270 million credit facility borrowing at December 31, 2017 was 3.16 percent. |
| |
(3) | The weighted-average interest rates for WPZ’s $850 million term loan and our $775 million credit facility borrowing at December 31, 2016 were 2.50 percent and 2.51 percent, respectively. |
| |
(4) | The weighted-average interest rate was 1.06 percent at December 31, 2016. |
Commodity Price Risk
We are exposed to the impact of fluctuations in the market price of NGLs and natural gas, as well as other market factors, such as market volatility and energy commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets, our long-term energy-related contracts, and limited proprietary trading activities. Our management of the risks associated with these market fluctuations includes maintaining sufficient liquidity, as well as using various derivatives and nonderivative energy-related contracts. The fair value of derivative contracts is subject
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, 20172018 and 2016,2017, our derivative activity was not material. (See Note 1617 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk 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 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”)Company) as of December 31, 20172018 and 2016,2017, the related consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2017,2018, 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”). In our opinion, based on our audits and the reports of other auditors, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company at December 31, 20172018 and 2016,2017, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2018, in conformity with U.S. generally accepted accounting principles.
We did not audit the financial statements of Gulfstream Natural Gas System, L.L.C. (“Gulfstream”)(Gulfstream), a limited liability corporation in which the Company has a 50 percent interest. In the consolidated financial statements, the Company’s investment in Gulfstream was $244$225 million and $261$244 million as of December 31, 20172018 and 2016,2017, respectively, and the Company’s equity earnings in the net income of Gulfstream were $75 million in 2017, $692018, $75 million in 20162017 and $65$69 million in 2015.2016. Gulfstream’s financial statements were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Gulfstream, is based solely on the reports of the other auditors.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”)(PCAOB), the Company’sCompany's internal control over financial reporting as of December 31, 2017,2018, based on criteria established in Internal Control - IntegratedControl-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 22, 201821, 2019 expressed an unqualified opinion thereon.
Adoption of New Accounting Standards
As discussed in Note 1 and Note 2 to the consolidated financial statements, the Company changed its method for accounting for revenue in 2018.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’sCompany's management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits and the reports of other auditors provide a reasonable basis for our opinion.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 1962.
Tulsa, Oklahoma
February 22, 2018
21, 2019
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 sheetsheets of Gulfstream Natural Gas System, L.L.C. (the “Company”) as of December 31, 2018 and 2017, and the related statements of operations, comprehensive income, cash flows, and members’ equity for the yearyears then ended, including the related notes (collectively referred to as the “financial statements;” not presented herein). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for the yearyears then ended in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audit.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 auditaudits of these financial statements in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud.
Our auditaudits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our auditaudits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit providesaudits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 22, 201821, 2019
We have served as the Company’s auditor since 2018.
Report of Independent Registered Public Accounting Firm
To the Members of Gulfstream Natural Gas System, L.L.C.
We have audited the balance sheet of Gulfstream Natural Gas System, L.L.C. (the "Company") as of December 31, 2016, and the related statement of operations, comprehensive income, cash flows, and members’ equity for each of the two years inGulfstream Natural Gas System, L.L.C. (the "Company") for the period ended December 31, 2016. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.audit.
We conducted our auditsaudit in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our auditsaudit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provideaudit provides a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial positionresults of operations of Gulfstream Natural Gas System, L.L.C. as of December 31, 2016, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 22, 2017
The Williams Companies, Inc.
Consolidated Statement of Operations
| | | | | Years Ended December 31, | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| | (Millions, except per-share amounts) | (Millions, except per-share amounts) |
| Revenues: | | | | | | | | | | | | |
| Service revenues | | $ | 5,312 |
|
| $ | 5,171 |
| | $ | 5,164 |
| | $ | 5,502 |
|
| $ | 5,312 |
| | $ | 5,171 |
|
| Service revenues - commodity consideration (Note 1) | | | 400 |
| | — |
| | — |
|
| Product sales | | 2,719 |
|
| 2,328 |
| | 2,196 |
| | 2,784 |
|
| 2,719 |
| | 2,328 |
|
| Total revenues | | 8,031 |
|
| 7,499 |
| | 7,360 |
| | 8,686 |
|
| 8,031 |
| | 7,499 |
|
| Costs and expenses: | |
|
|
| | | |
|
|
| | |
| Product costs | | 2,300 |
|
| 1,725 |
| | 1,779 |
| | 2,707 |
|
| 2,300 |
| | 1,725 |
|
| Processing commodity expenses (Note 1) | | | 137 |
| | — |
| | — |
|
| Operating and maintenance expenses | | 1,585 |
|
| 1,580 |
| | 1,655 |
| | 1,507 |
|
| 1,576 |
| | 1,592 |
|
| Depreciation and amortization expenses | | 1,736 |
|
| 1,763 |
| | 1,738 |
| | 1,725 |
|
| 1,736 |
| | 1,763 |
|
| Selling, general, and administrative expenses | | 608 |
|
| 723 |
| | 741 |
| | 569 |
|
| 594 |
| | 722 |
|
| Impairment of goodwill (Note 16) | | — |
| | — |
| | 1,098 |
| |
| Impairment of certain assets (Note 16) | | 1,248 |
| | 873 |
| | 209 |
| |
| Gain on sale of Geismar Interest (Note 2) | | (1,095 | ) | | — |
| | — |
| |
| Impairment of certain assets (Note 17) | | | 1,915 |
| | 1,248 |
| | 873 |
|
| Gain on sale of certain assets (Note 3) | | | (692 | ) | | (1,095 | ) | | — |
|
| Regulatory charges resulting from Tax Reform (Note 1) | | 674 |
| | — |
| | — |
| | (17 | ) | | 674 |
| | — |
|
| Insurance recoveries – Geismar Incident | | (9 | ) | | (7 | ) | | (126 | ) | |
| Other (income) expense – net | | 80 |
|
| 142 |
| | 40 |
| | 67 |
|
| 71 |
| | 135 |
|
| Total costs and expenses | | 7,127 |
|
| 6,799 |
| | 7,134 |
| | 7,918 |
|
| 7,104 |
| | 6,810 |
|
| Operating income (loss) | | 904 |
|
| 700 |
| | 226 |
| | 768 |
|
| 927 |
| | 689 |
|
| Equity earnings (losses) | | 434 |
|
| 397 |
| | 335 |
| | 396 |
|
| 434 |
| | 397 |
|
| Impairment of equity-method investments (Note 16) | | — |
| | (430 | ) | | (1,359 | ) | |
| Impairment of equity-method investments (Note 17) | | | (32 | ) | | — |
| | (430 | ) |
| Other investing income (loss) – net | | 282 |
| | 63 |
| | 27 |
| | 219 |
| | 282 |
| | 63 |
|
| Interest incurred |
| (1,116 | ) |
| (1,217 | ) | | (1,118 | ) |
| (1,160 | ) |
| (1,116 | ) | | (1,217 | ) |
| Interest capitalized |
| 33 |
|
| 38 |
| | 74 |
|
| 48 |
|
| 33 |
| | 38 |
|
| Other income (expense) – net | | (2 | ) |
| 74 |
| | 102 |
| | 92 |
|
| (25 | ) | | 85 |
|
| Income (loss) before income taxes | | 535 |
|
| (375 | ) | | (1,713 | ) | | 331 |
|
| 535 |
| | (375 | ) |
| Provision (benefit) for income taxes | | (1,974 | ) |
| (25 | ) | | (399 | ) | | 138 |
|
| (1,974 | ) | | (25 | ) |
| Net income (loss) | | 2,509 |
|
| (350 | ) | | (1,314 | ) | | 193 |
|
| 2,509 |
| | (350 | ) |
| Less: Net income (loss) attributable to noncontrolling interests | | 335 |
|
| 74 |
| | (743 | ) | | 348 |
|
| 335 |
| | 74 |
|
| Net income (loss) attributable to The Williams Companies, Inc. | | $ | 2,174 |
|
| $ | (424 | ) | | $ | (571 | ) | | (155 | ) |
| 2,174 |
| | (424 | ) |
| Preferred stock dividends (Note 15) | | | 1 |
| | — |
| | — |
|
| Net income (loss) available to common stockholders | | | $ | (156 | ) | | $ | 2,174 |
| | $ | (424 | ) |
| Basic earnings (loss) per common share: | | | | | | | | | | | | |
| Net income (loss) | | $ | 2.63 |
| | $ | (.57 | ) | | $ | (.76 | ) | | $ | (.16 | ) | | $ | 2.63 |
| | $ | (.57 | ) |
| Weighted-average shares (thousands) | | 826,177 |
| | 750,673 |
| | 749,271 |
| | 973,626 |
| | 826,177 |
| | 750,673 |
|
| Diluted earnings (loss) per common share: | | | | | | | | | | | | |
| Net income (loss) | | $ | 2.62 |
| | $ | (.57 | ) | | $ | (.76 | ) | | $ | (.16 | ) | | $ | 2.62 |
| | $ | (.57 | ) |
| Weighted-average shares (thousands) | | 828,518 |
| | 750,673 |
| | 749,271 |
| | 973,626 |
| | 828,518 |
| | 750,673 |
|
See accompanying notes.
The Williams Companies, Inc.
Consolidated Statement of Comprehensive Income (Loss)
| | | | | Years Ended December 31, | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| | | (Millions) | | (Millions) |
| Net income (loss) | | $ | 2,509 |
| | $ | (350 | ) | | $ | (1,314 | ) | | $ | 193 |
| | $ | 2,509 |
| | $ | (350 | ) |
| Other comprehensive income (loss): | | | | | | | | | | | | |
| Cash flow hedging activities: | | | | | | | | | | | | |
| Net unrealized gain (loss) from derivative instruments, net of taxes of $2, ($1), and $0 in 2017, 2016, and 2015, respectively | | (9 | ) | | 4 |
| | 6 |
| |
| Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of ($1) in 2017, and $1 in 2016 and 2015 | | 6 |
| | (2 | ) | | (6 | ) | |
| Net unrealized gain (loss) from derivative instruments, net of taxes of $1, $2, and ($1) in 2018, 2017, and 2016, respectively | | | (7 | ) | | (9 | ) | | 4 |
|
| Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of ($1), ($1), and $1 in 2018, 2017, and 2016, respectively | | | 8 |
| | 6 |
| | (2 | ) |
| Foreign currency translation activities: | | | | | | | | | | | | |
| Foreign currency translation adjustments, net of taxes of $0, ($37), and $31 in 2017, 2016, and 2015, respectively | | 1 |
| | 50 |
| | (204 | ) | |
| Foreign currency translation adjustments, net of taxes of ($37) in 2016 | | | — |
| | 1 |
| | 50 |
|
| Reclassification into earnings upon sale of foreign entities, net of taxes of ($36) in 2016 | | — |
| | 119 |
| | — |
| | — |
| | — |
| | 119 |
|
| Pension and other postretirement benefits: | | | | | | | | | | | | |
| Amortization of prior service cost (credit) included in net periodic benefit cost (credit), net of taxes of $2, $2, and $3 in 2017, 2016, and 2015, respectively | | (3 | ) | | (4 | ) | | (3 | ) | |
| Net actuarial gain (loss) arising during the year, net of taxes of ($15), $8, and ($5) in 2017, 2016 and 2015, respectively | | 44 |
| | (15 | ) | | 8 |
| |
| Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($37), ($12), and ($18) in 2017, 2016, and 2015, respectively (Note 9) | | 61 |
| | 20 |
| | 28 |
| |
| Amortization of prior service cost (credit) included in net periodic benefit cost (credit), net of taxes of $2 and $2 in 2017, and 2016, respectively | | | — |
| | (3 | ) | | (4 | ) |
| Net actuarial gain (loss) arising during the year, net of taxes of $3, ($15), and $8 in 2018, 2017 and 2016, respectively | | | (6 | ) | | 44 |
| | (15 | ) |
| Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($11), ($37), and ($12) in 2018, 2017, and 2016, respectively (Note 10) | | | 35 |
| | 61 |
| | 20 |
|
| Other comprehensive income (loss) | | 100 |
| | 172 |
| | (171 | ) | | 30 |
| | 100 |
| | 172 |
|
| Comprehensive income (loss) | | 2,609 |
| | (178 | ) | | (1,485 | ) | | 223 |
| | 2,609 |
| | (178 | ) |
| Less: Comprehensive income (loss) attributable to noncontrolling interests | | 334 |
| | 143 |
| | (813 | ) | | 346 |
| | 334 |
| | 143 |
|
| Comprehensive income (loss) attributable to The Williams Companies, Inc. | | $ | 2,275 |
| | $ | (321 | ) | | $ | (672 | ) | | $ | (123 | ) | | $ | 2,275 |
| | $ | (321 | ) |
See accompanying notes.
The Williams Companies, Inc.
Consolidated Balance Sheet
| | | | | December 31, | | December 31, |
| | | 2017 | | 2016 | | 2018 | | 2017 |
| | | (Millions, except per-share amounts) | | (Millions, except per-share amounts) |
| ASSETS | | | | | | | | |
| Current assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 899 |
| | $ | 170 |
| | $ | 168 |
| | $ | 899 |
|
| Trade accounts and other receivables (net of allowance of $9 at December 31, 2017 and $6 at December 31, 2016) | | 976 |
| | 938 |
| |
| Trade accounts and other receivables (net of allowance of $9 at December 31, 2018 and $9 at December 31, 2017) | | | 992 |
| | 976 |
|
| Inventories | | 113 |
| | 138 |
| | 130 |
| | 113 |
|
| Other current assets and deferred charges | | 191 |
| | 216 |
| | 174 |
| | 191 |
|
| Total current assets | | 2,179 |
| | 1,462 |
| | 1,464 |
| | 2,179 |
|
| | | | | | | | | |
| Investments | | 6,552 |
| | 6,701 |
| | 7,821 |
| | 6,552 |
|
| Property, plant, and equipment – net | | 28,211 |
| | 28,428 |
| | 27,504 |
| | 28,211 |
|
| Intangible assets – net of accumulated amortization | | 8,791 |
| | 9,663 |
| | 7,767 |
| | 8,791 |
|
| Regulatory assets, deferred charges, and other | | 619 |
| | 581 |
| | 746 |
| | 619 |
|
| Total assets | | $ | 46,352 |
| | $ | 46,835 |
| | $ | 45,302 |
| | $ | 46,352 |
|
| | | | | | | | | |
| LIABILITIES AND EQUITY | | | | | | | | |
| Current liabilities: | | | | | | | | |
| Accounts payable | | $ | 978 |
| | $ | 623 |
| | $ | 662 |
| | $ | 978 |
|
| Accrued liabilities | | 1,167 |
| | 1,448 |
| | 1,102 |
| | 1,167 |
|
| Commercial paper | | — |
| | 93 |
| |
| Long-term debt due within one year | | 501 |
| | 785 |
| | 47 |
| | 501 |
|
| Total current liabilities | | 2,646 |
| | 2,949 |
| | 1,811 |
| | 2,646 |
|
| | | | | | | | | |
| Long-term debt | | 20,434 |
| | 22,624 |
| | 22,367 |
| | 20,434 |
|
| Deferred income tax liabilities | | 3,147 |
| | 4,238 |
| | 1,524 |
| | 3,147 |
|
| Regulatory liabilities, deferred income, and other | | 3,950 |
| | 2,978 |
| | 3,603 |
| | 3,950 |
|
| Contingent liabilities and commitments (Note 17) | |
| |
| |
| Contingent liabilities and commitments (Note 18) | | |
| |
|
| | | | | | | | | |
| Equity: | | | | | | | | |
| Stockholders’ equity: | | | | | | | | |
| Common stock (960 million shares authorized at $1 par value; 861 million shares issued at December 31, 2017 and 785 million shares issued at December 31, 2016) | | 861 |
| | 785 |
| |
| Preferred stock (Note 15) | | | 35 |
| | — |
|
| Common stock ($1 par value; 1,470 million shares authorized at December 31, 2018 and 960 million shares authorized at December 31, 2017; 1,245 million shares issued at December 31, 2018 and 861 million shares issued at December 31, 2017) | | | 1,245 |
| | 861 |
|
| Capital in excess of par value | | 18,508 |
| | 14,887 |
| | 24,693 |
| | 18,508 |
|
| Retained deficit | | (8,434 | ) | | (9,649 | ) | | (10,002 | ) | | (8,434 | ) |
| Accumulated other comprehensive income (loss) | | (238 | ) | | (339 | ) | | (270 | ) | | (238 | ) |
| Treasury stock, at cost (35 million shares of common stock) | | (1,041 | ) | | (1,041 | ) | | (1,041 | ) | | (1,041 | ) |
| Total stockholders’ equity | | 9,656 |
| | 4,643 |
| | 14,660 |
| | 9,656 |
|
| Noncontrolling interests in consolidated subsidiaries | | 6,519 |
| | 9,403 |
| | 1,337 |
| | 6,519 |
|
| Total equity | | 16,175 |
| | 14,046 |
| | 15,997 |
| | 16,175 |
|
| Total liabilities and equity | | $ | 46,352 |
| | $ | 46,835 |
| | $ | 45,302 |
| | $ | 46,352 |
|
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, 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 14) | — |
| | — |
| | (1,836 | ) | | — |
| | — |
| | (1,836 | ) | | — |
| | (1,836 | ) | |
| Dividends and distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (942 | ) | | (942 | ) | |
| Stock-based compensation and related common stock issuances, net of tax | 2 |
| | 28 |
| | — |
| | — |
| | — |
| | 30 |
| | — |
| | 30 |
| |
| Sales of limited partner units of Williams Partners L.P. | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 59 |
| | 59 |
| |
| Changes in ownership of consolidated subsidiaries, net | — |
| | (160 | ) | | — |
| | — |
| | — |
| | (160 | ) | | 254 |
| | 94 |
| |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 111 |
| | 111 |
| |
| Other | — |
| | 14 |
| | (5 | ) | | — |
| | — |
| | 9 |
| | 13 |
| | 22 |
| |
| Net increase (decrease) in equity | 2 |
| | (118 | ) | | (2,412 | ) | | (101 | ) | | — |
| | (2,629 | ) | | (1,318 | ) | | (3,947 | ) | |
| Balance – December 31, 2015 | 784 |
| | 14,807 |
| | (7,960 | ) | | (442 | ) | | (1,041 | ) | | 6,148 |
| | 10,077 |
| | 16,225 |
| $ | — |
| | $ | 784 |
| | $ | 14,807 |
| | $ | (7,960 | ) | | $ | (442 | ) | | $ | (1,041 | ) | | $ | 6,148 |
| | $ | 10,077 |
| | $ | 16,225 |
|
| Net income (loss) | — |
| | — |
| | (424 | ) | | — |
| | — |
| | (424 | ) | | 74 |
| | (350 | ) | — |
| | — |
| | — |
| | (424 | ) | | — |
| | — |
| | (424 | ) | | 74 |
| | (350 | ) |
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | 103 |
| | — |
| | 103 |
| | 69 |
| | 172 |
| — |
| | — |
| | — |
| | — |
| | 103 |
| | — |
| | 103 |
| | 69 |
| | 172 |
|
| Cash dividends – common stock (Note 14) | — |
| | — |
| | (1,261 | ) | | — |
| | — |
| | (1,261 | ) | | — |
| | (1,261 | ) | |
| Cash dividends – common stock ($1.68 per share) | | — |
| | — |
| | — |
| | (1,261 | ) | | — |
| | — |
| | (1,261 | ) | | — |
| | (1,261 | ) |
| Dividends and distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (940 | ) | | (940 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (940 | ) | | (940 | ) |
| Stock-based compensation and related common stock issuances, net of tax | 1 |
| | 56 |
| | — |
| | — |
| | — |
| | 57 |
| | — |
| | 57 |
| — |
| | 1 |
| | 56 |
| | — |
| | — |
| | — |
| | 57 |
| | — |
| | 57 |
|
| Sales of limited partner units of Williams Partners L.P. | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 114 |
| | 114 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 114 |
| | 114 |
|
| Changes in ownership of consolidated subsidiaries, net | — |
| | 12 |
| | — |
| | — |
| | — |
| | 12 |
| | (18 | ) | | (6 | ) | — |
| | — |
| | 12 |
| | — |
| | — |
| | — |
| | 12 |
| | (18 | ) | | (6 | ) |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 29 |
| | 29 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 29 |
| | 29 |
|
| Other | — |
| | 12 |
| | (4 | ) | | — |
| | — |
| | 8 |
| | (2 | ) | | 6 |
| — |
| | — |
| | 12 |
| | (4 | ) | | — |
| | — |
| | 8 |
| | (2 | ) | | 6 |
|
| Net increase (decrease) in equity | 1 |
| | 80 |
| | (1,689 | ) | | 103 |
| | — |
| | (1,505 | ) | | (674 | ) | | (2,179 | ) | — |
| | 1 |
| | 80 |
| | (1,689 | ) | | 103 |
| | — |
| | (1,505 | ) | | (674 | ) | | (2,179 | ) |
| Balance – December 31, 2016 | 785 |
| | 14,887 |
| | (9,649 | ) | | (339 | ) | | (1,041 | ) | | 4,643 |
| | 9,403 |
| | 14,046 |
| — |
| | 785 |
| | 14,887 |
| | (9,649 | ) | | (339 | ) | | (1,041 | ) | | 4,643 |
| | 9,403 |
| | 14,046 |
|
| Net income (loss) | — |
| | — |
| | 2,174 |
| | — |
| | — |
| | 2,174 |
| | 335 |
| | 2,509 |
| — |
| | — |
| | — |
| | 2,174 |
| | — |
| | — |
| | 2,174 |
| | 335 |
| | 2,509 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | 101 |
| | — |
| | 101 |
| | (1 | ) | | 100 |
| — |
| | — |
| | — |
| | — |
| | 101 |
| | — |
| | 101 |
| | (1 | ) | | 100 |
|
| Issuance of common stock (Note 14) | 75 |
| | 2,043 |
| | — |
| | — |
| | — |
| | 2,118 |
| | — |
| | 2,118 |
| |
| Cash dividends – common stock (Note 14) | — |
| | — |
| | (992 | ) | | — |
| | — |
| | (992 | ) | | — |
| | (992 | ) | |
| Issuance of common stock (Note 15) | | — |
| | 75 |
| | 2,043 |
| | — |
| | — |
| | — |
| | 2,118 |
| | — |
| | 2,118 |
|
| Cash dividends – common stock ($1.20 per share) | | — |
| | — |
| | — |
| | (992 | ) | | — |
| | — |
| | (992 | ) | | — |
| | (992 | ) |
| Dividends and distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (883 | ) | | (883 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (883 | ) | | (883 | ) |
| Stock-based compensation and related common stock issuances, net of tax | 1 |
| | 73 |
| | — |
| | — |
| | — |
| | 74 |
| | — |
| | 74 |
| — |
| | 1 |
| | 73 |
| | — |
| | — |
| | — |
| | 74 |
| | — |
| | 74 |
|
| Adoption of ASU 2016-09 (Note 1) | — |
| | 1 |
| | 36 |
| | — |
| | — |
| | 37 |
| | — |
| | 37 |
| |
| Adoption of new accounting standard | | — |
| | — |
| | 1 |
| | 36 |
| | — |
| | — |
| | 37 |
| | — |
| | 37 |
|
| Sales of limited partner units of Williams Partners L.P. | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 61 |
| | 61 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 61 |
| | 61 |
|
| Changes in ownership of consolidated subsidiaries, net | — |
| | 1,497 |
| | — |
| | — |
| | — |
| | 1,497 |
| | (2,407 | ) | | (910 | ) | — |
| | — |
| | 1,497 |
| | — |
| | — |
| | — |
| | 1,497 |
| | (2,407 | ) | | (910 | ) |
| Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 17 |
| | 17 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 17 |
| | 17 |
|
| Other | — |
| | 7 |
| | (3 | ) | | — |
| | — |
| | 4 |
| | (6 | ) | | (2 | ) | — |
| | — |
| | 7 |
| | (3 | ) | | — |
| | — |
| | 4 |
| | (6 | ) | | (2 | ) |
| Net increase (decrease) in equity | 76 |
| | 3,621 |
| | 1,215 |
| | 101 |
| | — |
| | 5,013 |
| | (2,884 | ) | | 2,129 |
| — |
| | 76 |
| | 3,621 |
| | 1,215 |
| | 101 |
| | — |
| | 5,013 |
| | (2,884 | ) | | 2,129 |
|
| Balance – December 31, 2017 | $ | 861 |
| | $ | 18,508 |
| | $ | (8,434 | ) | | $ | (238 | ) | | $ | (1,041 | ) | | $ | 9,656 |
| | $ | 6,519 |
| | $ | 16,175 |
| — |
| | 861 |
| | 18,508 |
| | (8,434 | ) | | (238 | ) | | (1,041 | ) | | 9,656 |
| | 6,519 |
| | 16,175 |
|
| Adoption of new accounting standards (Note 1) | | — |
| | — |
| | ��� |
| | (23 | ) | | (61 | ) | | — |
| | (84 | ) | | (37 | ) | | (121 | ) |
| Net income (loss) | | — |
| | — |
| | — |
| | (155 | ) | | — |
| | — |
| | (155 | ) | | 348 |
| | 193 |
|
| Other comprehensive income (loss) | | — |
| | — |
| | — |
| | — |
| | 32 |
| | — |
| | 32 |
| | (2 | ) | | 30 |
|
| WPZ Merger (Note 1) | | — |
| | 382 |
| | 6,112 |
| | — |
| | (3 | ) | | — |
| | 6,491 |
| | (4,629 | ) | | 1,862 |
|
| Issuance of preferred stock (Note 15) | | 35 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 35 |
| | — |
| | 35 |
|
| Cash dividends – common stock ($1.36 per share) | | — |
| | — |
| | — |
| | (1,386 | ) | | — |
| | — |
| | (1,386 | ) | | — |
| | (1,386 | ) |
| Dividends and distributions to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (637 | ) | | (637 | ) |
| Stock-based compensation and related common stock issuances, net of tax | | — |
| | 1 |
| | 60 |
| | — |
| | — |
| | — |
| | 61 |
| | — |
| | 61 |
|
| Sales of limited partner units of Williams Partners L.P. | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 46 |
| | 46 |
|
| Changes in ownership of consolidated subsidiaries, net | | — |
| | — |
| | 14 |
| | — |
| | — |
| | — |
| | 14 |
| | (18 | ) | | (4 | ) |
| Contributions from noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 15 |
| | 15 |
|
| Deconsolidation of subsidiary (Note 4) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (267 | ) | | (267 | ) |
| Other | | — |
| | 1 |
| | (1 | ) | | (4 | ) | | — |
| | — |
| | (4 | ) | | (1 | ) | | (5 | ) |
| Net increase (decrease) in equity | | 35 |
| | 384 |
| | 6,185 |
| | (1,568 | ) | | (32 | ) | | — |
| | 5,004 |
| | (5,182 | ) | | (178 | ) |
| Balance – December 31, 2018 | | $ | 35 |
| | $ | 1,245 |
| | $ | 24,693 |
| | $ | (10,002 | ) | | $ | (270 | ) | | $ | (1,041 | ) | | $ | 14,660 |
| | $ | 1,337 |
| | $ | 15,997 |
|
| |
| * | Accumulated Other Comprehensive Income (Loss) |
See accompanying notes.notes.
The Williams Companies, Inc.
Consolidated Statement of Cash Flows
| | | | | Years Ended December 31, | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| | | (Millions) | | (Millions) |
| OPERATING ACTIVITIES: | | | | | | | | | | | | |
| Net income (loss) | | $ | 2,509 |
| | $ | (350 | ) | | $ | (1,314 | ) | | $ | 193 |
| | $ | 2,509 |
| | $ | (350 | ) |
| Adjustments to reconcile to net cash provided (used) by operating activities: | | | | | | | | | | | | |
| Depreciation and amortization | | 1,736 |
| | 1,763 |
| | 1,738 |
| | 1,725 |
| | 1,736 |
| | 1,763 |
|
| Provision (benefit) for deferred income taxes | | (2,012 | ) | | (26 | ) | | (337 | ) | | 220 |
| | (2,012 | ) | | (26 | ) |
| Equity (earnings) losses | | | (396 | ) | | (434 | ) | | (397 | ) |
| Distributions from unconsolidated affiliates | | | 693 |
| | 784 |
| | 742 |
|
| Net (gain) loss on disposition of equity-method investments | | (269 | ) | | (27 | ) | | — |
| | — |
| | (269 | ) | | (27 | ) |
| 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 | | 1,249 |
| | 918 |
| | 215 |
| |
| Gain on sale of Geismar Interest (Note 2) | | (1,095 | ) | | — |
| | — |
| |
| Impairment of equity-method investments (Note 17) | | | 32 |
| | — |
| | 430 |
|
| Gain on sale of certain assets (Note 3) | | | (692 | ) | | (1,095 | ) | | — |
|
| Impairment of and net (gain) loss on sale of other assets and businesses (Note 17) | | | 1,915 |
| | 1,249 |
| | 918 |
|
| Gain on deconsolidation of businesses (Note 6) | | | (203 | ) | | — |
| | — |
|
| Amortization of stock-based awards | | 78 |
| | 73 |
| | 82 |
| | 55 |
| | 78 |
| | 73 |
|
| Regulatory charges resulting from Tax Reform (Note 1) | | 776 |
| | — |
| | — |
| | (15 | ) | | 776 |
| | — |
|
| Cash provided (used) by changes in current assets and liabilities: | | | | | | | | | | | | |
| Accounts and notes receivable | | (88 | ) | | 82 |
| | 39 |
| | (36 | ) | | (88 | ) | | 82 |
|
| Inventories | | 8 |
| | (25 | ) | | 105 |
| | (16 | ) | | 8 |
| | (25 | ) |
| Other current assets and deferred charges | | (21 | ) | | (4 | ) | | 4 |
| | 17 |
| | (21 | ) | | (4 | ) |
| Accounts payable | | 118 |
| | 35 |
| | (88 | ) | | (93 | ) | | 118 |
| | 35 |
|
| Accrued liabilities | | (92 | ) | | 512 |
| | 54 |
| | 23 |
| | (92 | ) | | 512 |
|
| Other, including changes in noncurrent assets and liabilities | | (341 | ) | | 299 |
| | (247 | ) | | (129 | ) | | (158 | ) | | 429 |
|
| Net cash provided (used) by operating activities | | 2,556 |
| | 3,680 |
| | 2,708 |
| | 3,293 |
| | 3,089 |
| | 4,155 |
|
| FINANCING ACTIVITIES: | | | | | | | | | | | | |
| Proceeds from (payments of) commercial paper – net | | (93 | ) | | (409 | ) | | (306 | ) | | (2 | ) | | (93 | ) | | (409 | ) |
| Proceeds from long-term debt | | 3,333 |
| | 6,528 |
| | 9,772 |
| | 3,926 |
| | 3,333 |
| | 6,528 |
|
| Payments of long-term debt | | (5,925 | ) | | (7,091 | ) | | (6,516 | ) | | (3,204 | ) | | (5,925 | ) | | (7,091 | ) |
| Proceeds from issuance of common stock | | 2,131 |
| | 9 |
| | 27 |
| | 15 |
| | 2,131 |
| | 9 |
|
| Proceeds from sale of limited partner units of consolidated partnership | | — |
| | 114 |
| | 59 |
| | — |
| | — |
| | 114 |
|
| Dividends paid | | (992 | ) | | (1,261 | ) | | (1,836 | ) | |
| Common dividends paid | | | (1,386 | ) | | (992 | ) | | (1,261 | ) |
| Dividends and distributions paid to noncontrolling interests | | (822 | ) | | (940 | ) | | (942 | ) | | (591 | ) | | (822 | ) | | (940 | ) |
| Contributions from noncontrolling interests | | 17 |
| | 29 |
| | 111 |
| | 15 |
| | 17 |
| | 29 |
|
| Payments for debt issuance costs | | (17 | ) | | (9 | ) | | (35 | ) | | (26 | ) | | (17 | ) | | (9 | ) |
| Special distribution from Gulfstream | | — |
| | — |
| | 396 |
| |
| Contribution to Gulfstream for repayment of debt | | — |
| | (148 | ) | | (248 | ) | | — |
| | — |
| | (148 | ) |
| Other – net | | (92 | ) | | (16 | ) | | (31 | ) | | (46 | ) | | (92 | ) | | (16 | ) |
| Net cash provided (used) by financing activities | | (2,460 | ) | | (3,194 | ) | | 451 |
| | (1,299 | ) | | (2,460 | ) | | (3,194 | ) |
| INVESTING ACTIVITIES: | | | | | | | | | | | | |
| Property, plant, and equipment: | | | | | | | | | | | | |
| Capital expenditures (1) | | (2,399 | ) | | (2,051 | ) | | (3,167 | ) | | (3,256 | ) | | (2,399 | ) | | (2,051 | ) |
| Dispositions – net | | (41 | ) | | 30 |
| | 3 |
| | (7 | ) | | (41 | ) | | 30 |
|
| Contributions in aid of construction | | 426 |
| | 218 |
| | 87 |
| | 411 |
| | 426 |
| | 218 |
|
| Proceeds from sale of businesses, net of cash divested | | 2,067 |
| | 1,020 |
| | — |
| | 1,296 |
| | 2,067 |
| | 1,020 |
|
| Proceeds from dispositions of equity-method investments | | 200 |
| | 34 |
| | — |
| | — |
| | 200 |
| | 34 |
|
| Purchases of businesses, net of cash acquired | | — |
| | — |
| | (112 | ) | |
| Purchases of and contributions to equity-method investments | | (132 | ) | | (177 | ) | | (595 | ) | | (1,132 | ) | | (132 | ) | | (177 | ) |
| Distributions from unconsolidated affiliates in excess of cumulative earnings | | 529 |
| | 472 |
| | 404 |
| |
| Other – net | | (17 | ) | | 38 |
| | 81 |
| | (37 | ) | | (21 | ) | | 35 |
|
| Net cash provided (used) by investing activities | | 633 |
| | (416 | ) | | (3,299 | ) | | (2,725 | ) | | 100 |
| | (891 | ) |
| Increase (decrease) in cash and cash equivalents | | 729 |
| | 70 |
| | (140 | ) | | (731 | ) | | 729 |
| | 70 |
|
| Cash and cash equivalents at beginning of year | | 170 |
| | 100 |
| | 240 |
| | 899 |
| | 170 |
| | 100 |
|
| Cash and cash equivalents at end of year | | $ | 899 |
| | $ | 170 |
| | $ | 100 |
| | $ | 168 |
| | $ | 899 |
| | $ | 170 |
|
| _________ | | | | | | | | | | | | |
| (1) Increases to property, plant, and equipment | | $ | (2,662 | ) | | $ | (1,912 | ) | | $ | (3,024 | ) | | $ | (3,021 | ) | | $ | (2,662 | ) | | $ | (1,912 | ) |
| Changes in related accounts payable and accrued liabilities | | 263 |
| | (139 | ) | | (143 | ) | | (235 | ) | | 263 |
| | (139 | ) |
| Capital expenditures | | $ | (2,399 | ) | | $ | (2,051 | ) | | $ | (3,167 | ) | | $ | (3,256 | ) | | $ | (2,399 | ) | | $ | (2,051 | ) |
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.
WPZ Merger
On August 10, 2018, we completed our merger with Williams Partners L.P. (WPZ), our previously consolidated master limited partnership, pursuant to which we acquired all of the approximately 256 million publicly held outstanding common units of WPZ in exchange for 382 million shares of our common stock (WPZ Merger). Williams continued as the surviving entity. The WPZ Merger was accounted for as a noncash equity transaction resulting in increases to Common stock of $382 million, Capital in excess of par value of $6.112 billion, and Regulatory assets, deferred charges, and other of $33 million and decreases to Accumulated other comprehensive income (loss) (AOCI) of $3 million, Noncontrolling interests in consolidated subsidiaries of $4.629 billion, and Deferred income tax liabilities of $1.829 billion in the Consolidated Balance Sheet. Prior to the completion of the WPZ Merger and pursuant to its distribution reinvestment program, WPZ had issued common units to the public in 2018, 2017, and 2016 associated with reinvested distributions of $46 million, $61 million, and $10 million, respectively.
Financial Repositioning
In January 2017, we entered into agreements with Williams Partners L.P. (WPZ),WPZ, wherein we permanently waived the general partner’s incentive distribution rights (IDRs) and converted our 2 percent general partner interest in WPZ to a noneconomic interest in exchange for 289 million newly issued WPZ common units. Pursuant to this agreement, we also purchased approximately 277 thousand WPZ common units for $10 million. Additionally, we purchased approximately 59 million common units of WPZ at a price of $36.08586 per unit in a private placement transaction, funded with proceeds from our equity offering (see Note 1415 – Stockholders' Equity). According to the terms of this agreement, concurrent with WPZ’s quarterly distributions in February 2017 and May 2017, we paid additional consideration totaling $56 million to WPZ for these units. Subsequent to these transactions and as of December 31, 2017, we own a 74 percent limited partner interest in WPZ.
Termination of WPZ Merger Agreement
On May 12, 2015, we entered into an agreement for a unit-for-stock transaction whereby we would have acquired all of the publicly held outstanding common units of WPZ in exchange for shares of our common stock (WPZ Merger Agreement).
On September 28, 2015, we entered into a Termination Agreement and Release (Termination Agreement), terminating the WPZ Merger Agreement. Under the terms of the Termination Agreement, we were required to pay a $428 million termination fee to WPZ, at which time we owned approximately 60 percent, including the interests of the general partner and IDRs. Such termination fee settled through a reduction of quarterly incentive distributions we were entitled to receive from WPZ (such reduction not to exceed $209 million per quarter). The distributions from WPZ in November 2015, February 2016, and May 2016 were reduced by $209 million, $209 million, and $10 million, respectively, related to this termination fee.
ACMP Merger
On February 2, 2015, Williams Partners L.P. merged with and into Access Midstream Partners, L.P. (ACMP Merger). For the purpose of these financial statements and notes, WPZ refers to the renamed merged partnership, while Pre-merger Access Midstream Partners, L.P. (ACMP) and Pre-merger Williams Partners L.P. (Pre-merger WPZ) refer to the separate partnerships prior to the consummation of the ACMP Merger and subsequent name change. The net assets of Pre-merger WPZ and ACMP were combined at our historical basis. Our basis in ACMP reflected our business combination accounting resulting from acquiring control of ACMP on July 1, 2014.
Description of Business
We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located principally in the United States. We havePrior to the WPZ Merger, we had one reportable segment, Williams Partners. All remaining business activitiesBeginning in the third-quarter 2018, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are includednow presented within the following reportable segments: Northeast G&P, Atlantic-Gulf, and West. Prior period segment disclosures have been recast for the new segment presentation.
Northeast G&P is comprised of our midstream gathering and processing businesses in Other.the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and the Utica Shale region of eastern Ohio, as well as a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated entity), a 62 percent equity-method investment in Utica East Ohio Midstream, LLC (UEOM), a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 58 percent equity-method investment in Caiman Energy II, LLC (Caiman II), and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).
Atlantic-Gulf is comprised of our interstate natural gas pipeline, Transcontinental Gas Pipe Line Company, LLC (Transco), and significant natural gas gathering and processing and crude oil production handling and transportation
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| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Williams Partners
Williams Partners consists of ourassets in the Gulf Coast region, including a 51 percent interest in Gulfstar One LLC (Gulfstar One) (a consolidated master limited partnership, WPZ,entity), which is a proprietary floating production system, and primarily includes gas pipelinevarious petrochemical and midstream businesses.
WPZ’s gas pipeline businesses primarily consist of two interstate natural gasfeedstock 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, includingthe Gulf Coast region, as well as a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), a 60 percent equity-method investment in Discovery Producer Services LLC (Discovery), and a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), which is developing a pipeline project (see Note 34 – Variable Interest Entities)Entities).
WPZ’s midstream businesses primarily consistWest is comprised of (1)our interstate natural gas pipeline, Northwest Pipeline LLC (Northwest Pipeline), and our gathering, processing, and treating compression,operations in Colorado, Wyoming, and processing; (2)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) fractionation, storage, and transportation; (3) crude oil production handling and transportation; and (4) olefins production (see Note 2 – Acquisitions and Divestitures). The primary service areas are concentrated in major producing basins in Colorado, Texas, Oklahoma, Kansas, New Mexico, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio, which include the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, and Utica shale plays as well as the Mid-Continent region.
The midstream businesses include equity-method investments in natural gas gatheringmarketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and processing assets and NGL fractionation and transportation assets, including a 62 percent equity-method investment in Utica East Ohio Midstream, LLC (UEOM), a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 58 percent equity-method investment in Caiman Energy II, LLC (Caiman II), a 60 percent equity-method investment in Discovery Producer Services, LLC (Discovery), a 50 percent equity-method investment in Overland Pass Pipeline, LLC (OPPL), and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66a 50 percent interest in multiple gathering systemsJackalope Gas Gathering Services, L.L.C. (Jackalope) (an equity-method investment following deconsolidation as of June 30, 2018), a 50 percent equity-method investment in the Marcellus Shale (AppalachiaRocky Mountain Midstream Investments)Holdings LLC (RMM), as well asa 15 percent equity-method investment in Brazos Permian II, LLC (Brazos Permian II), and our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see Note 56 – Investing Activities).
The midstream businesses West also included our former natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado (see Note 3 – Divestitures).
Other includes our previously owned operations, including our former Williams Olefins, L.L.C., a wholly owned subsidiary which owned our 88.5 percent undivided interest in the Geismar, Louisiana, olefins plant (Geismar Interest), which was sold in July 2017 (see Note 3 – Divestitures), and a refinery grade propylene splitter in the Gulf region, which was sold in June 2017. This segment also included our previously owned Canadian midstream operations,assets, which were comprised ofincluded an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, we completed the sale of ourthese Canadian operations. (See Note 2 – Acquisitions and Divestitures.)
Other
operations were sold. Other is comprised ofalso includes minor business activities that are not operating segments, as well as corporate operations. Other also includes certain domestic olefins pipeline assets as well as certain Canadian assets, which included a liquids extraction plant located near Fort McMurray, Alberta, that began operations in March 2016, and a propane dehydrogenation facility which was under development. In September 2016, the Canadian assets were sold. (See Note 2 – Acquisitions and Divestitures.)
Basis of Presentation
Consolidated master limited partnershipSignificant risks and uncertainties
AsWe believe that the carrying value of December 31, 2017, we owned approximately 74 percentcertain of the interests in WPZ, a variable interest entity (VIE) (see Note 3 – Variable Interest Entities).
Pursuant to WPZ’s distribution reinvestment program, 1,606,448 common units were issued to the public during 2017 associated with reinvested distributions of $61 million. These common unit issuances, the Financial Repositioning, WPZ’s quarterly distribution of additional paid-in-kind Class B units to us,our property, plant, and equipment and other equity issuances by WPZ had the combined net impact of decreasing Noncontrolling interests in consolidated subsidiaries by $2.407 billion,identifiable intangible assets, notably certain acquired assets accounted for as business combinations between 2012 and increasing Capital2014, may be in excess of parcurrent fair value. However, the carrying value by $1.497 billion 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 Deferredultimately result in impairments of these assets. Such transactions or developments may also indicate that certain of our equity-method investments have experienced other-than-temporary declines in value, which could also result in impairment.
On March 15, 2018, the Federal Energy Regulatory Commission (FERC) issued a revised policy statement (the revised policy statement) regarding the recovery of income tax liabilities by $910 millioncosts in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the Consolidated Balance Sheet.discounted cash flow methodology. As a result, the FERC will no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. The FERC further stated it will address the application of this policy to non-MLP partnership forms as those issues arise in subsequent proceedings. One of the benefits of the recent WPZ Merger is to allow our FERC-regulated pipelines to continue to recover an income tax allowance in their cost of service rates.
On July 18, 2018, the FERC issued an order dismissing the requests for rehearing and clarification of the revised policy statement. In addition, the FERC provided guidance that an MLP pipeline (or other pass-through entity) no longer recovering an income tax allowance pursuant to the revised policy may eliminate previously accumulated deferred
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| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
WPZ is self-funding and maintains separate linesincome taxes (ADIT) from its cost of bank credit and cash management accounts and also has a commercial paper program. (See Note 13 – Debt, Banking Arrangements, and Leases.) Cash distributions from WPZservice instead of flowing these ADIT balances to all partners, including us, are governed by WPZ’s partnership agreement.
Discontinued operations
Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our continuing operations.
Significant risks and uncertainties
We may monetize assets that are not core to our strategy which could result in impairments of certain equity-method investments, property, plant, and equipment, and intangible assets. Such impairments could potentially be caused by indications of fair value implied through the monetization process or, in the case of asset dispositions that are part of a broader asset group,ratepayers. This guidance, if implemented, would significantly mitigate the impact of the lossrevised policy statement. However, the FERC stated that the revised policy statement and such guidance do not establish a binding rule but are instead expressions of general policy intent designed to provide guidance by notifying entities of the course of action the FERC intends to follow in future estimated cash flows.adjudications. To the extent the FERC addresses these issues in future proceedings, it will consider any arguments regarding not only the application of the revised policy to the facts of the case, but also any arguments regarding the underlying validity of the policy itself. The FERC’s guidance on ADIT likely will be challenged by customers and state commissions, which would result in a long period of revenue uncertainty for pipelines eliminating ADIT from their cost of service. The WPZ Merger has the additional benefit of eliminating this uncertainty.
On March 15, 2018, the FERC also issued a Notice of Proposed Rulemaking proposing a filing process that will allow it to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent reduction in the corporate income tax rate in the Tax Cuts and Jobs Act (Tax Reform) and the revised policy statement. On July 18, 2018, the FERC issued a Final Rule, retaining the filing requirement and reaffirming the options that pipelines have to either reflect the reduced tax rate or explain why no rate change is necessary. The FERC also clarified that a natural gas company organized as a pass-through entity and all of whose income or losses are consolidated on the federal income tax return of its corporate parent is considered to be subject to the federal corporate income tax and is thus eligible for a tax allowance. We believe this Final Rule and the previously discussed WPZ Merger allow for the continued recovery of income tax allowances in Transco’s and Northwest Pipeline’s rates. Transco’s August 31, 2018 general rate case filing reflects a tax allowance based on this clarification, and the FERC’s September 28, 2018 order in that rate case proceeding finds that Transco is exempt from the Final Rule’s Form 501-G filing requirement. In addition, on October 19, 2018, Northwest Pipeline filed a petition requesting that the FERC waive its Form 501-G filing requirement under this Final Rule because (i) the reduction in the corporate income tax is already addressed in Northwest Pipeline’s 2017 rate settlement, and (ii) as discussed above, the WPZ Merger allows for the continued recovery of income tax allowances in Northwest Pipeline’s rates. The FERC agreed and granted Northwest Pipeline’s petition for waiver on November 19, 2018. On October 11, 2018 and December 6, 2018, Discovery Gas Transmission, LLC and Pine Needle LNG Company, LLC, respectively, filed their Form 501-Gs, including explanations as to why no adjustments to rates are needed.
On March 15, 2018, the FERC also issued a Notice of Inquiry seeking comments on the additional impacts of Tax Reform on jurisdictional rates, particularly whether, and if so how, the FERC should address changes relating to ADIT amounts after the corporate income tax rate reduction and bonus depreciation rules, as well as whether other features of Tax Reform require FERC action. We are evaluating the impact of these developments on our interstate natural gas pipelines and currently expect any associated impacts would be prospective and determined through subsequent rate proceedings. We also continue to monitor developments that may impact our regulatory liabilities resulting from Tax Reform. It is reasonably possible that future tariff-based rates collected by our interstate natural gas pipelines may be adversely impacted.
Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of certain ventures in which we own an undivided interest. Our judgment is required to evaluate whether we control an entity. Key areas of that evaluation include:
Determining whether an entity is a VIE;variable interest entity (VIE);
Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that we and our related parties have over those activities through our variable interests;
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
Identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether we are a VIE’s primary beneficiary;
Evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant decisions that would be expected to be made in the ordinary course of business such that we do not have the power to control such entities.
We apply the equity method of accounting to investments over which we exercise significant influence but do not control.
Equity-method investment basis differences
Differences between the cost of our equity-method investments and our underlying equity in the net assets of investees are accounted for as if the investees were consolidated subsidiaries. Equity earnings (losses) in the Consolidated Statement of Operations includes our allocable share of net income (loss) of investees adjusted for any depreciation and amortization, as applicable, associated with basis differences.
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
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The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
Significant estimates and assumptions include:
Impairment assessments of investments, property, plant, and equipment, goodwill, and other identifiable intangible assets;
Litigation-related contingencies;
Environmental remediation obligations;
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;
Measurement of regulatory liabilities;
Measurement of deferred income tax assets and liabilities.liabilities, including assumptions related to the realization of deferred income tax assets.
These estimates are discussed further throughout these notes.
Regulatory accounting
Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC).FERC. Their rates, which are established by the FERC, are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, we have determined that it is appropriate under Accounting Standards Codification (ASC) Topic 980, “Regulated Operations,” (ASC 980) to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are
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| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
established. Accounting for these operations that are regulated can differ from the accounting requirements for nonregulated operations. For example, for regulated operations, allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in the process of construction and is capitalized as a cost of property, plant, and equipment because it constitutes an actual cost of construction under established regulatory practices; nonregulated operations are only allowed to capitalize the cost of debt funds related to construction activities, while a component for equity is prohibited. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, pension and other postretirement benefits, and rate allowances for deferred income taxes at a historically higher federal income tax rate.
In December 2017, the Tax Cuts and Jobs ActReform was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent (Tax Reform) (see Note 78 – Provision (Benefit) for Income Taxes). In accordance with ASC 980-740-25-2, Transco and Northwest Pipeline have recognized regulatory liabilities to reflect the probable return to customers through future rates of the future decrease in income taxes payable associated with Tax Reform. These liabilities represent an obligation to return amounts directly to our customers. While a majority of our customers have entered into tariff rates based on our cost-of-service proceedings and related rate base therein, certain other contracts with customers reflect contractually-based rates that are designed to recover the cost of providing those services, including an allowance for income taxes, with no expected future rate adjustment for the term of those contracts. This relative mix of contracts for services was considered in determining the probable amount to be returned to customers through future rates. The regulatory liabilities were recorded in December 2017 through regulatory charges to operating income totaling $674 million. As of December 31, 2018, the balance of these regulatory liabilities totaled $657 million. The timing and actual amount of such return will be subject to future negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing service.
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The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
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Certain of our equity-method investees recorded similar regulatory liabilities, for which our Equity earnings (losses) in the Consolidated Statement of Operations have beenfor 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 67 – 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.Flows.
Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 20172018 and 20162017 are as follows:
| | | | December 31, | December 31, |
| | 2017 | | 2016 | 2018 | | 2017 |
| | (Millions) | (Millions) |
Current assets reported within Other current assets and deferred charges | $ | 102 |
| | $ | 91 |
| $ | 103 |
| | $ | 102 |
|
Noncurrent assets reported within Regulatory assets, deferred charges, and other | 376 |
| | 387 |
| 495 |
| | 376 |
|
| Total regulated assets | $ | 478 |
| | $ | 478 |
| $ | 598 |
| | $ | 478 |
|
| | | | | | | |
Current liabilities reported within Accrued liabilities | $ | 18 |
| | $ | 11 |
| $ | 5 |
| | $ | 18 |
|
Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other | 1,250 |
| | 498 |
| 1,321 |
| | 1,250 |
|
| Total regulated liabilities | $ | 1,268 |
| | $ | 509 |
| $ | 1,326 |
| | $ | 1,268 |
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
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Cash and cash equivalents
Cash and cash equivalents in the Consolidated Balance Sheet includes amounts primarily invested in fundsconsist 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 net realizable value. The cost of inventories is primarily determined using the average-cost method.
Property, plant, and equipment
Property, plant, and equipment is initially recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values.
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The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
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As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply an accelerated depreciation method.
Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation. Other gains or losses are recorded in Other (income) expense – net included in Operating income (loss) in the Consolidated Statement of Operations.
Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment.
We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO)ARO at the time the liability is initially incurred, typically when the asset is acquired or constructed. As regulated entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that is attributable to capitalized ARO cost to a regulatory asset as we expect to recover these amounts in future rates. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in Operating and maintenance expenses in the Consolidated Statement of Operations, except for regulated entities, for which the liability is offset by a regulatory asset. The regulatory asset is amortized commensurate with our collection of those costs in rates.
Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium.
Goodwill
Goodwill included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet represents the excess of the consideration, plus the fair value of any noncontrolling interest or any previously held equity interest, over the fair value of the net assets acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount. Generally, the evaluation of goodwill for impairment involves a two-step quantitative test, although under certain circumstances an initial qualitative evaluation may be sufficient to conclude goodwill is not impaired. If a quantitative assessment is performed, we compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess. Judgments and assumptions are inherent in our estimate of fair value. Effective October 1, 2017, we early adopted Accounting Standards Update (ASU) 2017-04 “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment” (ASU 2017-04), which removed the computation of the implied fair value of goodwill from the measurement process.
Other intangible assets
Our identifiable intangible assets included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet are primarily related to gas gathering, processing, and fractionation contractual customer
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
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relationships. Our intangible assets are amortized on a straight-line basis over the period in which these assets contribute to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining useful life.
Impairment of property, plant, and equipment, other identifiable intangible assets, and investments
We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events or changes in circumstances indicate, in our judgment, that the carrying value of such assets may not be recoverable.
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The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
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When an indicator of impairment has occurred, we compare our estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.
For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.
We evaluate our investments for impairment when events or changes in circumstances indicate, in our judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge.
Judgments and assumptions are inherent in our estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal.
Deferred income
We record a liability for deferred income related to cash received from customers in advance of providing our services. Such amounts are generally recognized in revenue upon satisfying our performance obligations, primarily providing services based on units of production or over remaining contractual service periods ranging from 1 to 25 years. Deferred incomeis reflected within Accrued liabilities and Regulatory liabilities, deferred income, and other on the Consolidated Balance Sheet. (See Note 12 – Accrued Liabilities.)
WPZ received an aggregate amount of $240 million in three equal installments as certain milestones of Transco’s Hillabee Expansion Project were met related to an agreement to resolve several matters in relation to the project. (See Note 12 – Accrued Liabilities.) During the third quarter of 2017, WPZ received the final installment and placed the project into service. As a result of placing the project into service, WPZ reclassified the refundable deposits to deferred income and expects to recognize income associated with these receipts over the term of an underlying contract.
During 2016, we received cash proceeds totaling $820 million associated with restructuring certain gas gathering contracts in the Barnett Shale and Mid-Continent regions. The proceeds were recorded as deferred incomeand are being amortized into income.
In October 2016, we received $104 million of newly constructed assets as part of a noncash investing transaction with a customer for which we provide production handling and other services. The transaction was recorded in Property, plant, and equipment – net and deferred income in the Consolidated Balance Sheet and is being amortized based on units of production through 2024. Due to the noncash nature of this transaction, it is not presented within the Consolidated Statement of Cash Flows.
Contingent liabilities
We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable, and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration
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The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
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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 1314 – Debt, Banking Arrangements, and Leases.)
Treasury stock
Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as Treasury stock in the Consolidated Balance Sheet. Gains and losses on the subsequent reissuance of shares
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
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are credited or charged to Capital in excess of par value in the Consolidated Balance Sheet using the average-cost method.
Derivative instruments and hedging activities
We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of energy commodities. We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Other current assets and deferred charges; Regulatory assets, deferred charges, and other; Accrued liabilities; or Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis. (See Note 1617 – 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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| | |
| Derivative Treatment | | Accounting Method |
| Normal purchases and normal sales exception | | Accrual accounting |
| Designated in a qualifying hedging relationship | | Hedge accounting |
| All other derivatives | | Mark-to-market accounting |
We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.
We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in Product sales or Product costs in the Consolidated Statement of Operations.
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The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
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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 us.
For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in Product sales or Product costs in the Consolidated Statement of Operations.
Certain gains and losses on derivative instruments included in the Consolidated Statement of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
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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)
Customers in our gas pipeline businesses are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical generators. Customers in our midstream businesses are comprised of oil and natural gas producer counterparties. Customers for our product sales are comprised of public utilities, gas marketers, and direct industrial users.
A performance obligation is a promise in a contract to transfer a distinct good or service (or integrated package of goods or services) to the customer. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue, when, or as, the performance obligation is satisfied. A performance obligation is distinct if the service is separately identifiable from other items in the integrated package of services and if a customer can benefit from it on its own or with other resources that are readily available to the customer. An integrated package of services typically represents a single performance obligation if the services are contained within the same contract or within multiple contracts entered into in contemplation with one another that are highly interdependent or highly interrelated, meaning each of the services is significantly affected by one or more of the other services in the contract. Service revenue contracts from our gas pipeline and midstream businesses contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our product sales contracts have a single performance obligation with revenue recognized at a point in time when the products have been sold and delivered to the customer.
Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. For our rate-regulated gas pipeline businesses that apply ASC 980, we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, the construction activities do not represent an ongoing major and central operation of our gas pipeline businesses and are not within the scope of ASC Topic 606, “Revenue from Contracts with Customers” (ASC 606). Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset. For our midstream businesses, reimbursement and service contracts with customers are viewed together as providing the same commercial objective, as we have the ability to negotiate the mix of consideration between reimbursements and amounts billed over time. Accordingly, we generally recognize reimbursements of construction costs from customers on a gross basis as a contract liability separate from the associated costs included within property, plant, and equipment. The contract liability is recognized into service revenues as the underlying performance obligations are satisfied.
Service Revenues
Gas pipeline businesses: Revenues from our regulated interstate natural gas pipeline businesses, which are subject to regulation by certain state and federal authorities, including the FERC, include both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a fixed reservation charge based on the pipeline or storage capacity reserved, and a commodity charge based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or based on negotiated contractual rates, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
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one-month periods or less. Our performance obligations related to our interstate natural gas pipeline businesses include the following:
Firm transportation or storage under firm transportation and storage contracts—an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities;
Interruptible transportation and storage under interruptible transportation and storage contracts—an integrated package of services typically constituting a single performance obligation once scheduled, which includes receiving, transporting or storing (as applicable), and redelivering commodities.
In situations where, in our judgment, we consider the integrated package of services as a single performance obligation, which represents a majority of our interstate natural gas pipeline contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized over time upon satisfaction of our daily stand ready performance obligation.
We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges in our interstate natural gas pipeline businesses are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refund upon the issuance of final orders by the FERC in pending rate proceedings. We use judgment to record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks.
Midstream businesses: Revenues from our non-regulated gathering, processing, transportation, and storage midstream businesses include contracts for natural gas gathering, processing, treating, compression, transportation, and other related services with contract terms that are generally long-term in nature and may extend up to the production life of the associated reservoir. Additionally, our midstream businesses generate revenues from fees charged for storing customers’ natural gas and NGLs, generally under prepaid contracted storage capacity contracts. In situations where, in our judgment, we provide an integrated package of services combined into a single performance obligation, which represents a majority of this class of contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to provide gathering, processing, transportation, storage, and related services resulting in the delivery, or redelivery in the context of storage services, of pipeline-quality natural gas and NGLs to the customer. As such, revenue is recognized at the daily completion of the integrated package of services as the integrated package represents a single performance obligation. Additionally, certain contracts in our midstream businesses contain fixed or upfront payment terms that result in the deferral of revenues until such services have been performed or such capacity has been made available.
We also earn revenues from offshore crude oil and natural gas gathering and transportation and offshore production handling. These services represent an integrated package of services and are considered a single distinct performance obligation for which we recognize revenues as the services are provided to the customer.
We generally earn a contractually stated fee per unit for the volume of product transported, gathered, processed, or stored. The rate is generally fixed; however, certain contracts contain variable rates that are subject to change based on commodity prices, levels of throughput, or an annual adjustment based on a formulaic cost of service calculation. In addition, we have contracts with contractually stated fees that decline over the contract term, such as declines based on the passage of time periods or achievement of cumulative throughput amounts. For all of our
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
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contracts, we allocate the transaction price to each performance obligation based on the judgmentally determined relative standalone selling price. The excess of consideration received over revenue recognized results in the deferral of those amounts until future periods based on a units of production or straight-line methodology as these methods appropriately match the consumption of services provided to the customer. The units of production methodology requires the use of production estimates that are uncertain and the use of judgment when developing estimates of future production volumes, thus impacting the rate of revenue recognition. Production estimates are monitored as circumstances and events warrant. Certain of our gas gathering and processing agreements have minimum volume commitments (MVC). If a customer under such an agreement fails to meet its MVC for a specified period (thus not exercising all the contractual rights to gathering and processing services within the specified period, herein referred to as “breakage”), it is obligated to pay a contractually determined fee based upon the shortfall between the actual gathered or processed volumes and the MVC for the period contained in the contract. When we conclude, based on management’s judgment, it is probable that the customer will not exercise all or a portion of its remaining rights, we recognize revenue associated with such breakage amount in proportion to the pattern of exercised rights within the respective MVC period.
Under keep-whole and percent-of-liquids processing contracts, we receive commodity consideration in the form of NGLs and take title to the NGLs at the tailgate of the plant. We recognize such commodity consideration as service revenue based on the market value of the NGLs retained at the time the processing is provided. The current market value, as opposed to the market value at the contract inception date, is used due to a combination of factors, including the fact that the volume, mix, and market price of NGL consideration to be received is unknown at the time of contract execution and is not specified in our contracts with customers. Additionally, product sales revenue (discussed below) is recognized upon the sale of the NGLs to a third party based on the sales price at the time of sale. As a result, revenue is recognized both at the time the processing service is provided in Service revenues – commodity consideration and at the time the NGLs retained as part of the processing service are sold in Product sales. The recognition of revenue related to commodity consideration has the impact of increasing the book value of NGL inventory, resulting in higher cost of goods sold at the time of sale. Given that most inventory is sold in the same period that it is generated, the impact of these transactions is expected to have little impact to operating income.
Product Sales
In the course of providing transportation services to customers of our gas pipeline businesses and gathering and processing services to customers of our midstream businesses, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs or gathering and processing agreements, respectively. Revenue is recognized from the sale of natural gas upon settlement of imbalances.
In certain instances, we purchase NGLs, crude oil, and natural gas from our oil and natural gas producer customers. In addition, we retain NGLs as consideration in certain processing arrangements, as discussed above in the Service Revenues - Midstream businesses section. We recognize revenue from the sale of these commodities when the products have been sold and delivered. Our product sales contracts are primarily short-term contracts based on prevailing market rates at the time of the transaction.
Contract Assets
Our contract assets primarily consist of revenue recognized under contracts containing MVC features whereby management has concluded it is probable there will be a short-fall payment at the end of the current MVC period, which typically follows the calendar year, and that a significant reversal of revenue recognized currently for the future MVC payment will not occur. As a result, our contract assets related to our future MVC payments are generally expected to be collected within the next 12 months and are included within Other current assets and deferred charges in our Consolidated Balance Sheet until such time as the MVC short-fall payments are invoiced to the customer.
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
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Contract Liabilities
Our contract liabilities consist of advance payments primarily from midstream business customers which include construction reimbursements, prepayments, and other billings for which future services are to be provided under the contract. These amounts are deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily based on a units of production methodology over the remaining contractual service periods, and are classified as current or noncurrent according to when such amounts are expected to be recognized. Current and noncurrent contract liabilities are included within Accrued liabilities and Regulatory liabilities, deferred income, and other, respectively, in our Consolidated Balance Sheet.
Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide us with a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer the promised good or service to the customer, when the customer pays for those goods or services, and the prevailing interest rates. We have assessed our contracts for significant financing components and determined, in our judgment, that one group of contracts entered into in contemplation of one another for certain capital reimbursements contains a significant financing component. As a result, we recognize noncash interest expense based on the effective interest method and revenue (noncash) is recognized when the underlying asset is placed into service utilizing a units of production or straight-line methodology over the life of the corresponding customer contract.
Revenue recognition (prior to the adoption of ASC 606)
Revenues
As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks.
Service revenues
Revenues from our interstate natural gas pipeline businesses include services pursuant to long-term firm transportation and storage agreements. These agreements provide for a reservation charge based on the volume of contracted capacity and a commodity charge based on the volume of gas delivered, both at rates specified in our FERC tariffs. We recognize revenues for reservation charges ratably over the contract period regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges, from both firm and interruptible transportation services and storage injection and withdrawal services, are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility.
Certain revenues from our midstream operations include those derived from natural gas gathering, processing, treating, and compression services and are performed under volumetric-based fee contracts. These revenues are recorded when services have been performed.
Certain of our gas gathering and processing agreements have minimum volume commitments. If a customer under such an agreement fails to meet its minimum volume commitment for a specified period, generally measured on an annual basis, it is obligated to pay a contractually determined fee based upon the shortfall between actual production volumes and the minimum volume commitment for that period. The revenue associated with minimum volume commitments is recognized in the period that the actual shortfall is determined and is no longer subject to future reduction or offset, which is generally at the end of the annual period or fourth quarter.
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The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
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Crude oil gathering and transportation revenues and offshore production handling fees are recognized when the services have been performed. Certain offshore production handling contracts contain fixed payment terms that result in the deferral of revenues until such services have been performed or such capacity has been made available.
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
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Storage revenues from our midstream operations associated with prepaid contracted storage capacity contracts are recognized on a straight-line basis over the life of the contract as services are provided.
Product sales
In the course of providing transportation services to customers of our interstate natural gas pipeline businesses, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided for in our FERC tariffs. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances.
We market NGLs, crude oil, and natural gas that we purchase from our producer customers as part of the overall service provided to producers. Revenues from marketing activities are recognized when the products have been sold and delivered.
Under our keep-whole and percent-of-liquids processing contracts, we retain the rights to all or a portion of the NGLs extracted from the producers’ natural gas stream and recognize revenues when the extracted NGLs are sold and delivered.
Our former domestic olefins business produced olefins from purchased or produced feedstock and we recognized revenues when the olefins were sold and delivered.
Our Canadian businesses that were sold in September 2016 had processing and fractionation operations where we retained certain NGLs and olefins from an upgrader’s offgas stream and we recognized revenues when the fractionated products were sold and delivered.
Interest capitalized
We capitalize interest during construction on major projects with construction periods of at least 3 months and a total project cost in excess of $1 million. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds (equity AFUDC). The latter is included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations. The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by nonregulated companies are based on our average interest rate on debt.
Employee stock-based awards
We recognize compensation expense on employee stock-based awards on a straight-line basis; forfeitures are recognized when they occur. (See Note 1516 – 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 910 – Employee Benefit Plans.)
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The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
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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.
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| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
Unrecognized actuarial gains and losses and unrecognized prior service costs and credits are deferred and recorded in AOCI or, for Transco and Northwest Pipeline, as a regulatory asset or liability, until amortized as a component of net periodic benefit cost (credit). Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation or the market-related value of plan assets are amortized over the participants’ average remaining future years of service, which is approximately 13 years for our pension plans and approximately 7 years for our other postretirement benefit plans.
The expected return on plan assets component of net periodic benefit cost (credit) is calculated using the market-related value of plan assets. For our pension plans, the market-related value of plan assets is equal to the fair value of plan assets adjusted to reflect the amortization of gains or losses associated with the difference between the expected and actual return on plan assets over a 5-year period. Additionally, the market-related value of assets may be no more than 110 percent or less than 90 percent of the fair value of plan assets at the beginning of the year. The market-related value of plan assets for our other postretirement benefit plans is equal to the unadjusted fair value of plan assets at the beginning of the year.
Income taxes
We include the operations of our domestic corporate subsidiaries and income from our subsidiary partnerships in our consolidated federal income tax return and also file tax returns in various foreign and state jurisdictions as required. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of our assets and liabilities. Our judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets.
Earnings (loss) per common share
Basic earnings (loss) per common share in the Consolidated Statement of Operations is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share in the Consolidated Statement of Operations includes any dilutive effect of stock options, nonvested restricted stock units, and convertible debt, unless otherwise noted. Diluted earnings (loss) per common share are calculated using the treasury-stock method.
Foreign currency translationAccounting standards issued and adopted
During the first quarter of 2018, we early adopted Accounting Standards Update (ASU) 2018-02 “Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income” (ASU 2018-02). As a result of Tax Reform lowering the federal income tax rate and prior to adopting this standard, the tax effects of items within accumulated other comprehensive income may not have reflected the appropriate tax rate. ASU 2018-02 allows for the reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from Tax Reform. The adoption of ASU 2018-02 resulted in the reclassification of $61 million from Accumulated other comprehensive income (loss) to Retained deficit on our foreign subsidiariesConsolidated Balance Sheet.
Effective January 1, 2018, we adopted ASU 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities” (ASU 2017-12). ASU 2017-12 applies to entities that usedelect hedge accounting in accordance with ASC 815. The ASU affects both the Canadian dollar as their functional currency were sold in 2016. The assetsdesignation and liabilitiesmeasurement guidance for hedging relationships and the presentation of such foreign subsidiaries were translatedhedging results. ASU 2017-12 was applied using a modified retrospective approach for cash flow and net investment hedges existing at the spot ratedate of adoption and prospectively for the presentation and disclosure guidance. The adoption of ASU 2017-12 did not have a significant impact on our consolidated financial statements.
In May 2014, the Financial Accounting Standards Board (FASB) issued ASU 2014-09 establishing ASC 606. ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in effect atan amount that reflects the applicable reporting date, andconsideration 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 changesentity expects to be entitled to receive in exchange rates whenfor those goods or services and requires significantly enhanced revenue disclosures. In August 2015, 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.FASB issued ASU
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| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Accounting standards issued2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard became effective for interim and adoptedannual reporting periods beginning after December 15, 2017.
EffectiveWe adopted the provisions of ASC 606 effective January 1, 2017, we adopted ASU 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements2018, utilizing the modified retrospective transition method for all contracts with customers, which included applying the provisions of ASC 606 beginning January 1, 2018, to Employee Share-Based Payment Accounting” (ASU 2016-09). ASU 2016-09 changedall contracts not completed as of that date with the accountingcumulative effect of applying the standard for income taxes such that all excess tax benefits and all tax deficiencies are now recognizedperiods prior to January 1, 2018, as a discrete item in the provision for income taxes in the financial reporting period they occur and the recognitionan adjustment to Total equity, net of tax, benefits is no longer delayed untilupon adoption. As a result of our adoption, the cumulative impact to our Total equity, net of tax, benefit is realized through a reduction in income taxes payable. These changes were applied prospectively beginning in 2017. We recorded a cumulative-effect adjustment as ofat January 1, 2017, decreasing Retained deficit by $372018, was a decrease of $121 million in the Consolidated Balance Sheet.
For each revenue contract type, we conducted a formal contract review process to recognize tax benefits that were not previously recognized. ASU 2016-09 requires entitiesevaluate the impact of ASC 606. The adjustment to classify excess tax benefits as an operating activity on the statementTotal equity upon adoption of cash flows. We applied this partASC 606 is primarily comprised of the guidance prospectively beginningimpact to the timing of recognition of deferred revenue (contract liabilities) associated with certain contracts which underwent modifications in 2017; therefore,periods prior to January 1, 2018. Under the cash flowsprovisions of ASC 606, when a contract modification does not increase both the scope and price of the contract, and the remaining goods and services are distinct from the goods and services transferred prior to the modification, the modification is treated as a termination of the existing contract and the creation of a new contract. ASC 606 requires that the transaction price, including any remaining contract liabilities from the old contract, be allocated to the performance obligations over the term of the new contract. The contract modification adjustments are partially offset by the impact of changes to the timing of recognizing revenue which is subject to the constraint on estimates of variable consideration of certain contracts. The constraint of variable consideration will result in the acceleration of revenue recognition and corresponding de-recognition of contract liabilities for prior periods were not adjusted. In recognizing compensation cost from share-based payments, ASU 2016-09 allows entitiescertain contracts (as compared to make an accounting policy election to either recognize forfeitures when they occur or estimate the number of forfeitures expected to occur. We are recognizing forfeitures when they occur andprevious revenue recognition model) as a result of our assessment that it is probable such recognition would not result in a significant revenue reversal in the changefuture. Additionally, under ASC 606, our revenues will increase in situations where we receive noncash consideration, which exists primarily in certain of our accounting policy,gas processing contracts where we increased our Retained deficitreceive commodities as full or partial consideration for an insignificant cumulative-effect adjustment as ofservices provided. This increase in revenues will be offset by a similar increase in costs and expenses when the commodities received are subsequently sold. Financial systems and internal controls necessary for adoption were implemented effective January 1, 2017. ASU 2016-09 requires entities to classify as a financing activity, on the statement of cash flows, cash paid by an employer to a taxing authority when directly withholding shares from an employee’s award to satisfy the employer’s statutory tax withholding obligation. This guidance was applied retrospectively.
Effective October 1, 2017, we early adopted ASU 2017-04 “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” ASU 2017-04 modified the concept of goodwill impairment to represent the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. Under ASU 2017-04, entities are no longer required to determine the implied fair value of goodwill by assigning the fair value of a reporting unit to its individual assets and liabilities as if that reporting unit had been acquired in a business combination. Our Williams Partners reportable segment has $47 million of goodwill included in Intangible assets2018. (See Note 2 – net of accumulated amortization in the Consolidated Balance Sheet (see Note 11 – Goodwill and Other Intangible Assets).Revenue Recognition.)
Accounting standards issued but not yet adopted
In February 2018, the Financial Accounting Standards Board (FASB) issued ASU 2018-02 “Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income” (ASU 2018-02). As a result of Tax Reform lowering the federal income tax rate, the tax effects of items within accumulated other comprehensive income may not reflect the appropriate tax rate. ASU 2018-02 allows for the reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from Tax Reform. ASU 2018-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. ASU 2018-02 should be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the federal corporate income tax rate as a result of Tax Reform is recognized. We plan to early adopt ASU 2018-02 during the first quarter of 2018 and do not believe the adoption will have a significant impact on our consolidated financial statements.
In August 2017, the FASB issued ASU 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities” (ASU 2017-12). ASU 2017-12 applies to entities that elect hedge accounting in accordance with Accounting Standards Codification (ASC) 815. The ASU affects both the designation and measurement guidance for hedging relationships and the presentation of hedging results. ASU 2017-12 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. ASU 2017-12 will be applied using a modified retrospective approach for cash flow and net investment hedges existing at the date of adoption and prospectively for the presentation and disclosure guidance. During the first quarter of 2018, we early adopted ASU 2017-12. The adoption did not have a significant impact on our consolidated financial statements.
In March 2017, the FASB issued ASU 2017-07 “Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost” (ASU 2017-07). ASU 2017-07 requires employers to report the service cost component of net benefit cost in the same line item or items as other
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The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
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compensation costs arising from employee services. The other components of net benefit cost must be presented in the income statement separately from the service cost component and outside a subtotal of income from operations, if one is presented. Only the service cost component is now eligible for capitalization when applicable. ASU 2017-07 is effective beginning January 1, 2018. The presentation aspect of ASU 2017-07 must be applied retrospectively and the capitalization requirement prospectively. Upon adoption, we will present the elements of net periodic benefit costs in the Consolidated Statement of Operations in accordance with ASU 2017-07. We do not expect the change in the costs eligible to be capitalized to have a material effect on our consolidated financial statements.
In August 2016, the FASB issued ASU 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). ASU 2016-15 provides specific guidance on eight cash flow classification issues, including debt prepayment or debt extinguishment costs and distributions received from equity method investees, to reduce diversity in practice. ASU 2016-15 is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted. ASU 2016-15 requires a retrospective transition. We do not expect ASU 2016-15 to have a material impact on our consolidated financial statements.
In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. The standard requires varying transition methods for the different categories of amendments. Although we do not expect ASU 2016-13 to have a significant impact, it willcould impact our trade receivables as the related allowance for credit losses will be recognized earlier under the expected loss model.
In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach to lease classification similar to current lease accounting, and causes lessees to recognize operating leases on the balance sheet as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset, with an exception for leases with a term of one year or less. Additional disclosures will also be required regarding the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01 “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842” (ASU 2018-01). Per ASU 2018-01, land easements and rights-of-way are required to be assessed under ASU 2016-02 to determine whether the arrangements are or contain a lease. ASU 2018-01 permits an entity to elect a transition practical expedient to not apply ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not previously assessed under the previous lease guidance in ASC Topic 840 “Leases.”
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| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
In July 2018, the FASB issued ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted.2018-11 “Leases (Topic 842): Targeted Improvements” (ASU 2018-11). Prior to ASU 2016-02 currently requires2018-11, 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.
In January 2018, the FASB proposed an accounting standard update titled “Leases (Topic 842): Targeted Improvements,” which is an update to ASU 2016-02 allowing2018-11 allows entities an additional transition method to the existing requirements whereby an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. ASU 2018-11 also allows a practical expedient that permits lessors to not separate non-lease components from the associated lease component if certain conditions are present. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. We expect to adoptare adopting ASU 2016-02 effective January 1, 2019.
We are in the processsubstantially complete with our review of reviewing contracts to identify leases based on the modified definition of a lease and implementing a financial lease accounting system, and evaluatingchanges to our internal control changescontrols to support management in the accounting for and disclosure of leasing activities. While we are stillactivities upon adoption of ASU 2016-02. We implemented a financial lease accounting system to assist management in the process of completing ouraccounting for leases upon adoption. We are substantially complete with the implementation evaluation of ASU 2016-02 we currentlyand believe the most significant changes to our financial statements relate to the recognition of a lease liability and offsetting right-of-use asset in our consolidated balance sheet Consolidated Balance Sheetfor operating leases.leases, which we estimate to be less than 1 percent of total liabilities and total assets, respectively. We arehave also evaluatingevaluated ASU 2016-02’s currently available and proposed practical expedients on adoption. We generally elected to adopt the practical expedients, which includes the practical expedient to not separate lease and non-lease components by both lessees and lessors by class of underlying assets and the land easements practical expedient.
Note 2 – Revenue Recognition
Revenue by Category
The following table presents our revenue disaggregated by major service line:
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Northeast Midstream | | Atlantic- Gulf Midstream | | West Midstream | | Transco | | Northwest Pipeline | | Other | | Intercompany Eliminations | | Total |
| | (Millions) |
| Year Ended December 31, 2018 | | |
| Revenues from contracts with customers: | | | | | | | | | | | | | | | |
| Service revenues: | | | | | | | | | | | | | | | |
| Non-regulated gathering, processing, transportation, and storage: | | | | | | | | | | | | | | | |
| Monetary consideration | $ | 861 |
| | $ | 541 |
| | $ | 1,590 |
| | $ | — |
| | $ | — |
| | $ | 2 |
| | $ | (73 | ) | | $ | 2,921 |
|
| Commodity consideration | 20 |
| | 59 |
| | 321 |
| | — |
| | — |
| | — |
| | — |
| | 400 |
|
| Regulated interstate natural gas transportation and storage | — |
| | — |
| | — |
| | 1,921 |
| | 443 |
| | — |
| | (2 | ) | | 2,362 |
|
| Other | 94 |
| | 17 |
| | 46 |
| | 2 |
| | — |
| | — |
| | (15 | ) | | 144 |
|
| Total service revenues | 975 |
| | 617 |
| | 1,957 |
| | 1,923 |
| | 443 |
| | 2 |
| | (90 | ) | | 5,827 |
|
| Product Sales: | | | | | | | | | | | | | | | |
| NGL and natural gas | 287 |
| | 307 |
| | 2,421 |
| | 127 |
| | — |
| | — |
| | (382 | ) | | 2,760 |
|
| Other | — |
| | — |
| | 21 |
| | — |
| | — |
| | — |
| | (4 | ) | | 17 |
|
| Total product sales | 287 |
| | 307 |
| | 2,442 |
| | 127 |
| | — |
| | — |
| | (386 | ) | | 2,777 |
|
| Total revenues from contracts with customers | 1,262 |
| | 924 |
| | 4,399 |
| | 2,050 |
| | 443 |
| | 2 |
| | (476 | ) | | 8,604 |
|
| Other revenues (1) | 21 |
| | 18 |
| | 12 |
| | 11 |
| | — |
| | 32 |
| | (12 | ) | | 82 |
|
| Total revenues | $ | 1,283 |
| | $ | 942 |
| | $ | 4,411 |
| | $ | 2,061 |
| | $ | 443 |
| | $ | 34 |
| | $ | (488 | ) | | $ | 8,686 |
|
| |
| (1) | Service revenues in our Consolidated Statement of Operations include leasing revenues associated with our headquarters building and management fees that we receive for certain services we provide to operated joint ventures and other investments. The leasing revenues and the management fees do not constitute revenue from contracts with customers. Product sales in our Consolidated Statement of Operations include amounts associated with our derivative contracts that are not within the scope of ASC 606. |
Contract Assets
The following table presents a reconciliation of our contract assets:
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| | | |
| | Year Ended December 31, 2018 |
| | (Millions) |
| Balance at beginning of period | $ | 4 |
|
| Revenue recognized in excess of amounts invoiced | 66 |
|
| Minimum volume commitments invoiced | (66 | ) |
| Balance at end of period | $ | 4 |
|
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| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
Contract Liabilities
The following table presents a reconciliation of our contract liabilities:
|
| | | |
| | Year Ended December 31, 2018 |
| | (Millions) |
| Balance at beginning of period | $ | 1,596 |
|
| Payments received and deferred | 314 |
|
| Noncash interest expense for significant financing component | 16 |
|
| Deconsolidation of Jackalope interest (Note 4) | (52 | ) |
| Deconsolidation of certain Permian assets (Note 6) | (26 | ) |
| Recognized in revenue | (451 | ) |
| Balance at end of period | $ | 1,397 |
|
The following table presents the amount of the contract liabilities balance as of December 31, 2018, expected to be recognized as revenue in each of the next five years as performance obligations are expected to be satisfied:
|
| | | |
| | (Millions) |
| 2019 | $ | 271 |
|
| 2020 | 142 |
|
| 2021 | 121 |
|
| 2022 | 102 |
|
| 2023 | 95 |
|
| Thereafter | 666 |
|
| Total | $ | 1,397 |
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Remaining Performance Obligations
The following table presents the transaction price allocated to the remaining performance obligations under certain contracts as of December 31, 2018. These primarily include long-term contracts containing MVCs associated with our midstream businesses, fixed payments associated with offshore production handling, and reservation charges on contracted capacity on our gas pipeline firm transportation contracts with customers, as well as storage capacity contracts. Amounts included in the table below for our interstate natural gas pipeline businesses reflect the rates for such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes is not currently known. As a practical expedient permitted by ASC 606, this table excludes variable consideration as well as consideration in contracts that is recognized in revenue as billed. It also excludes consideration received prior to December 31, 2018, that will be recognized in future periods (see above for Contract Liabilities and the expected recognition of those amounts within revenue). Certain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term of the contract. The remaining performance obligation amounts as of December 31, 2018, do not consider potential future performance obligations for which the renewal has not been exercised.
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
In May 2014,The table below also does not include contracts with customers for which the FASB issued ASU 2014-09 establishing ASC Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expectsunderlying facilities have not received FERC authorization to be entitled to receive in exchange for those goods or servicesplaced into service.
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| | | |
| | (Millions) |
| 2019 | $ | 2,909 |
|
| 2020 | 2,728 |
|
| 2021 | 2,622 |
|
| 2022 | 2,262 |
|
| 2023 | 2,089 |
|
| Thereafter | 16,916 |
|
| Total | $ | 29,526 |
|
Accounts Receivable
The following is a summary of our Trade accounts and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606)other receivables: Deferral
|
| | | | | | | |
| | December 31, 2018 | | January 1, 2018 |
| | (Millions) |
| Accounts receivable related to revenues from contracts with customers | $ | 858 |
| | $ | 958 |
|
| Other accounts receivable | 134 |
| | 18 |
|
Total reflected in Trade accounts and other receivables | $ | 992 |
| | $ | 976 |
|
Impact 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.Adoption of ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016. We are adopting ASC 606 utilizing the modified retrospective transition approach, effective January 1, 2018, by recognizing the cumulative effect of initially applying ASC 606 for periods prior to January 1, 2018, which we expect to result in a decrease of approximately $255 million, net of tax, to the opening balance of Total equity in the Consolidated Balance Sheet.
We are in the final stages of evaluating the impact ASC 606 will have on our financial statements. For each revenue contract type, we have conducted a formal contract review process to evaluateThe following table depicts the impact of ASC 606. We have substantially completed our evaluation. During the fourth quarter, we concluded on certain technical matters, including the evaluation of significant financing components, tiered pricing structures, and minimum volume commitments, and certain contracts for which we received prepayments for services. The adjustment to Total equity upon adoption of ASC 606 is primarily comprised of the impacton our 2018 financial statements. The adjustment to the timing of recognition of deferred revenue (contract liabilities) associated with certain contracts which underwent modifications in periods prior to January 1, 2018. Under the provisions of ASC 606, when a contract modification does not increase both the scope and price of the contract, and the remaining goods and services are distinct from the goods and services transferred prior to the modification, the modification is treated as a termination of the existing contract and the creation of a new contract. The new contract requires that the transaction price, including any remaining deferred revenue from the old contract, be allocated to the performance obligations over the term of the new contract. The contract modifications adjustments are partially offset by the impact of changes to the timing of recognizing revenue which is subject to the constraint on estimates of variable consideration of certain contracts. The constraint of variable consideration will result in the acceleration of revenue recognition and corresponding de-recognition of deferred revenue for certain contracts (as compared to the previous revenue recognition model) as a result of our assessment that it is probable such recognition would not result in a significant revenue reversal in the future. Additionally, under ASC 606, our revenues will increase in situations where we receive noncash consideration, which exists primarily in certain of our gas processing contracts where we receive commodities as full or partial consideration for services provided. This increase in revenues will be offset by a similar increase in costs and expenses when the commodities received are subsequently sold. Based on commodities received during 2017 as consideration for services and market prices during 2017, the increase in revenues and costs would have been approximately $350 million. Financial systems and internal controls necessary for adoption were implemented effective January 1, 2018.
Note 2 – Acquisitions and Divestitures
Eagle Ford Gathering System
In May 2015, WPZ acquired a gathering system comprised of approximately 140 miles of pipeline and a sour gas compression facility in the Eagle Ford Shale for $112 million. The acquisition was accounted for as a business combination, and the allocation of the acquisition-date fair value of the major classes of assets acquired includes $80 million of Property, plant, and equipment – net and $32 million of Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet. Changestable below relates to the preliminaryrecognition under ASC 606 of contract assets for MVC-related contracts associated with a 2014 acquisition. The recognition of these contract assets resulted in a lower purchase price allocation disclosedto intangible assets. The adoption of ASC 606 did not result in the second quarter of 2015 reflect an increase of $20 million in Property, plant, and equipment – net, and a decrease of $20 million in Intangible assets – net of accumulated amortization.adjustments to total operating, investing, or financing cash flows.
In July 2017, WPZ completed the sale of Williams Olefins, L.L.C., a wholly owned subsidiary which owned our 88.5 percent undivided interest in the Geismar, Louisiana, olefins plant (Geismar Interest) for total consideration of $2.084 billion in cash. We received a final working capital adjustment of $12 million in October 2017. Upon closing |
| | | | | | | | | | | |
| | As Reported | | Adjustments resulting from adoption of ASC 606 | | Balance without adoption of ASC 606 |
| | (Millions, except per-share amounts) |
| Consolidated Statement of Operations |
| Year Ended December 31, 2018 |
| Service revenues | $ | 5,502 |
| | $ | 89 |
| | $ | 5,591 |
|
| Service revenues – commodity consideration | 400 |
| | (400 | ) | | — |
|
| Product sales | 2,784 |
| | 135 |
| | 2,919 |
|
| Total revenues | 8,686 |
| | (176 | ) | | 8,510 |
|
| Product costs | 2,707 |
| | (124 | ) | | 2,583 |
|
| Processing commodity expenses | 137 |
| | (137 | ) | | — |
|
| Operating and maintenance expenses | 1,507 |
| | 1 |
| | 1,508 |
|
| Depreciation and amortization expenses | 1,725 |
| | 2 |
| | 1,727 |
|
| Impairment of certain assets | 1,915 |
| | 202 |
| | 2,117 |
|
| Total costs and expenses | 7,918 |
| | (56 | ) | | 7,862 |
|
| Operating income (loss) | 768 |
| | (120 | ) | | 648 |
|
| Equity earnings (losses) | 396 |
| | 1 |
| | 397 |
|
| Other investing income (loss) – net | 219 |
| | 84 |
| | 303 |
|
| Interest incurred | (1,160 | ) | | 16 |
| | (1,144 | ) |
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
|
| | | | | | | | | | | |
| | As Reported | | Adjustments resulting from adoption of ASC 606 | | Balance without adoption of ASC 606 |
| | (Millions, except per-share amounts) |
| Interest capitalized | 48 |
| | (10 | ) | | 38 |
|
| Income (loss) before income taxes | 331 |
| | (29 | ) | | 302 |
|
| Provision (benefit) for income taxes | 138 |
| | (9 | ) | | 129 |
|
| Net income (loss) | 193 |
| | (20 | ) | | 173 |
|
| Less: Net income (loss) attributable to noncontrolling interests | 348 |
| | (1 | ) | | 347 |
|
| Net income (loss) attributable to The Williams Companies, Inc. | (155 | ) | | (19 | ) | | (174 | ) |
| Basic earnings (loss) per common share | $ | (0.16 | ) | | $ | (0.02 | ) | | $ | (0.18 | ) |
| Diluted earnings (loss) per common share | (0.16 | ) | | (0.02 | ) | | (0.18 | ) |
| | | | | | |
| Consolidated Statement of Comprehensive Income (Loss) |
| Year Ended December 31, 2018 |
| Net income (loss) | $ | 193 |
| | $ | (20 | ) | | $ | 173 |
|
| Comprehensive income (loss) | 223 |
| | (20 | ) | | 203 |
|
| Less: Comprehensive income (loss) attributable to noncontrolling interests | 346 |
| | (1 | ) | | 345 |
|
| Comprehensive income (loss) attributable to The Williams Companies, Inc. | (123 | ) | | (19 | ) | | (142 | ) |
| | | | | | |
| Consolidated Balance Sheet |
| December 31, 2018 |
| Inventories | $ | 130 |
| | $ | (13 | ) | | $ | 117 |
|
| Total current assets | 1,464 |
| | (13 | ) | | 1,451 |
|
| Investments | 7,821 |
| | 1 |
| | 7,822 |
|
| Property, plant, and equipment – net | 27,504 |
| | (212 | ) | | 27,292 |
|
| Intangible assets – net of accumulated amortization | 7,767 |
| | 61 |
| | 7,828 |
|
| Regulatory assets, deferred charges, and other | 746 |
| | (4 | ) | | 742 |
|
| Total assets | 45,302 |
| | (167 | ) | | 45,135 |
|
| Accrued liabilities | 1,102 |
| | 67 |
| | 1,169 |
|
| Total current liabilities | 1,811 |
| | 67 |
| | 1,878 |
|
| Deferred income tax liabilities | 1,524 |
| | 20 |
| | 1,544 |
|
| Regulatory liabilities, deferred income, and other | 3,603 |
| | (346 | ) | | 3,257 |
|
| Retained deficit | (10,002 | ) | | 64 |
| | (9,938 | ) |
| Total stockholders’ equity | 14,660 |
| | 64 |
| | 14,724 |
|
| Noncontrolling interests in consolidated subsidiaries | 1,337 |
| | 28 |
| | 1,365 |
|
| Total equity | 15,997 |
| | 92 |
| | 16,089 |
|
| Total liabilities and equity | 45,302 |
| | (167 | ) | | 45,135 |
|
| | | | | | |
| Consolidated Statement of Changes in Equity |
| December 31, 2018 |
| Adoption of ASC 606 | $ | (121 | ) | | $ | 121 |
| | $ | — |
|
| Net income (loss) | 193 |
| | (20 | ) | | 173 |
|
| Deconsolidation of subsidiary | (267 | ) | | (9 | ) | | (276 | ) |
| Net increase (decrease) in equity | (178 | ) | | 92 |
| | (86 | ) |
| Balance at December 31, 2018 | 15,997 |
| | 92 |
| | 16,089 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
Note 3 – Divestitures
Sale of Gulf Coast Pipeline Systems
In November 2018, we completed the sale of certain assets and operations located in the Gulf Coast area for $177 million in cash. These assets were designated as held for sale during the third quarter of 2018. As a result of this sale, we recorded a gain of approximately $101 million in the fourth quarter of 2018, consisting of $81 million in our Atlantic-Gulf segment and $20 million in Other.
Previous impairments made to a portion of these assets and operations include $66 million related to certain idle pipelines in the second quarter of 2018, as well as $68 million and $23 million related to an NGL pipeline near the Houston Ship Channel region and project development costs associated with an olefins pipeline project, respectively, in 2017. These impairments are reflected in Impairment of certain assets in the Consolidated Statement of Operations. (See Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) The results of operations for this disposal group, excluding the impairments and gains noted, were not significant for the reporting periods.
Sale of Four Corners Assets
In October 2018, we completed the sale of our natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado for total consideration of $1.125 billion, subject to customary working capital adjustments. These assets were designated as held for sale during the third quarter of 2018. As a result of this sale, we recorded a gain of approximately $591 million within the West segment in the fourth quarter of 2018.
The following table presents the results of operations for the Four Corners area, excluding the gain noted above:
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | (Millions) |
| Income (loss) before income taxes of Four Corners area | $ | 52 |
| | $ | 47 |
| | $ | 37 |
|
| Income (loss) before income taxes of Four Corners area attributable to The Williams Companies, Inc. | 43 |
| | 35 |
| | 23 |
|
Sale of Geismar Interest
In July 2017, we completed the sale of Williams Olefins, L.L.C., a wholly owned subsidiary which owned our Geismar Interest for total consideration of $2.084 billion in cash. We received a final working capital adjustment of $12 million in October 2017. Upon closing of the sale, WPZwe entered into a long-term supply and transportation agreement with the purchaser to provide feedstock to the plant via its Bayou Ethane pipeline system. The assets and liabilities of the Geismar olefins plant were designated as held for sale within the Williams Partners segment during the first quarter of 2017. As a result of this sale, we recorded a gain of $1.095 billion in the third quarter of 2017.2017 in our Other segment. Following this sale, the cash proceeds were used to repay WPZ’sour $850 million term loan. Proceeds have also been funding a portion of the capital and investment expenditures that are a part of WPZ’s growth portfolio.
The following table presents the results of operations for the Geismar Interest, excluding the gain noted above:
| | | | Years Ended December 31, | Years Ended December 31, |
| | 2017 | | 2016 | 2018 | | 2017 | | 2016 |
| | (Millions) | (Millions) |
| Income (loss) before income taxes of the Geismar Interest | $ | 26 |
| | $ | 141 |
| $ | — |
| | $ | 26 |
| | $ | 141 |
|
| Income (loss) before income taxes of the Geismar Interest attributable to The Williams Companies, Inc. | 19 |
| | 85 |
| — |
| | 19 |
| | 85 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
Sale of Canadian Operations
In September 2016, we completed the sale of subsidiaries conducting Canadian operations including subsidiaries of WPZ, (such subsidiaries, the Canadian disposal group). Consideration received totaled $1.020 billion, net of $31 million of cash divested and subject to customary working capital adjustments. In connection with the sale, we waived $150 million of incentive distributions otherwise payable by WPZ to us in the fourth quarter of 2016 in recognition of certain affiliate contracts wherein WPZ’s Canadian operations provided services to certain of our other businesses. The proceeds were primarily used to reduce borrowings on credit facilities.
During the second quarter of 2016, we designated these operations as held for sale. As a result, we measured the fair value of the disposal group, as of June 30, 2016, resulting in an impairment charge of $747 million, reflected in Impairment of certain assets in the Consolidated Statement of Operations. (See Note 1617 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) DuringUpon completion of the second half of 2016sale, we also recorded an additionala loss of $66 million upon completion of the sale,in Other, primarily reflecting revisions to the sales price and estimated contingent consideration and includingconsideration. This included a $15 million benefit related to transactions to hedge our foreign currency exchange risk on the Canadian proceeds, reflected in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Operations. The total loss consists of a loss of $34 million at Williams Partners and $32 million at Other.
The following table presentsFor the year ended December 31, 2016, the results of operations for the Canadian disposal group, excluding the impairment and loss noted, above:
|
| | | | | | | |
| | Years Ended December 31, |
| | 2017 | | 2016 |
| | (Millions) |
| Income (loss) before income taxes of Canadian disposal group | $ | — |
| | $ | (98 | ) |
| Income (loss) before income taxes of Canadian disposal group attributable to The Williams Companies, Inc. | — |
| | (95 | ) |
Note 34 – Variable Interest Entities
WPZConsolidated VIEs
As of December 31, 2018, we consolidate the following VIEs:
Gulfstar One
We own a 7451 percent interest in WPZ, a master limited partnership that is a VIE due to the limited partners’ lack of substantive voting rights, such as either participating rights or kick-out rights that can be exercised with a simple majority of the vote of the limited partners. We are the primary beneficiary of WPZ because we have the power, through our general partner interest, to direct the activities that most significantly impact WPZ’s economic performance.
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of WPZ and/or its subsidiaries, and which comprise a significant portion of our consolidated assets and liabilities:
|
| | | | | | | | | |
| | December 31, | | |
| | 2017 | | 2016 | | Classification |
| | (Millions) | | |
| Assets (liabilities): | | | | | |
| Cash and cash equivalents | $ | 881 |
| | $ | 145 |
| | Cash and cash equivalents |
Trade accounts and other receivables – net | 972 |
| | 925 |
| | Trade accounts and other receivables |
| Inventories | 113 |
| | 138 |
| | Inventories |
| Other current assets | 176 |
| | 205 |
| | Other current assets and deferred charges |
| Investments | 6,552 |
| | 6,701 |
| | Investments |
Property, plant, and equipment – net | 27,912 |
| | 28,021 |
| | Property, plant, and equipment – net |
Intangible assets – net | 8,790 |
| | 9,662 |
| | Intangible assets – net of accumulated amortization |
| Regulatory assets, deferred charges, and other noncurrent assets | 507 |
| | 467 |
| | Regulatory assets, deferred charges, and other |
| Accounts payable | (957 | ) | | (589 | ) | | Accounts payable |
| Accrued liabilities including current asset retirement obligations | (857 | ) | | (1,122 | ) | | Accrued liabilities |
| Commercial paper | — |
| | (93 | ) | | Commercial paper |
| Long-term debt due within one year | (501 | ) | | (785 | ) | | Long-term debt due within one year |
| Long-term debt | (15,996 | ) | | (17,685 | ) | | Long-term debt |
| Deferred income tax liabilities | (16 | ) | | (20 | ) | | Deferred income tax liabilities |
| Noncurrent asset retirement obligations | (944 | ) | | (798 | ) | | Regulatory liabilities, deferred income, and other |
| Long-term deferred income | (1,119 | ) | | (1,048 | ) | | Regulatory liabilities, deferred income, and other |
| Regulatory liabilities and other | (1,690 | ) | | (812 | ) | | Regulatory liabilities, deferred income, and other |
The assets and liabilities presented in the table above also include the consolidated interests of the following individual VIEs within WPZ:
Gulfstar One,
WPZ owns a 51 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 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.
Constitution
WPZ ownsWe own a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its long-term firm transportation contracts, is a VIE. WPZ isWe are the primary beneficiary because it haswe have the power to direct the activities that most significantly impact Constitution’s economic performance. WPZ,We, as operator of
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
Constitution, isare responsible for constructing the proposed pipeline connecting its gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. The total remaining cost of the project is estimated to be approximately $740 million, which would be funded with capital contributions from WPZus and the other equity partners on a proportional basis.
In December 2014, Constitution received approval from the Federal Energy Regulatory Commission (FERC)FERC to construct and operate its proposed pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied the necessary water quality certification under Section 401 of the Clean Water Act for the New York portion of the pipeline. In May 2016, Constitution appealed the NYSDEC’s denial of the Section 401 certification to the United States Court of Appeals for the Second Circuit and in August 2017, the court issued a decision denying in part and dismissing in part Constitution’s appeal. The court expressly declined to rule on Constitution’s argument that the delay in the NYSDEC’s decision on Constitution’s Section 401 application constitutes a waiver of the certification requirement. The court determined that it lacked jurisdiction to address that contention and found that jurisdiction over the waiver issue lies exclusively with the United States Court of Appeals for the District of Columbia Circuit.Circuit (D.C. Circuit). As to the denial itself, the court determined that NYSDEC’s action was not arbitrary or capricious. Constitution filed a petition for rehearing with the Second Circuit Court of Appeals, but in October 2017 the court denied our petition.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
In October 2017, WPZwe filed a petition for declaratory order requesting the FERC to find that, by operation of law, the Section 401 certification requirement for the New York State portion of Constitution’s pipeline project was waived due to the failure by the NYSDEC to act on Constitution’s Section 401 application within a reasonable period of time as required by the express terms of such statute. In January 2018, the FERC denied WPZ’sour petition, finding that Section 401 provides that a state waives certification only when it does not act on an application within one year from the date of the application. We filed a request for rehearing of the FERC’s decision, but in July 2018 the FERC denied our request.
The project’s sponsors remain committed to the project,project. On November 5, 2018, the FERC granted our request for an extension of time to December 2, 2020, to construct and place into service the Constitution pipeline. And, in that regard, we are pursuing two separate and independent paths in order to overturn the NYSDEC’s denial of the Section 401 certification. In JanuarySeptember 2018, we filed a petition with the United States Supreme Court toD.C. Circuit for review the decision of the Second Circuit Court of Appeals that upheld the merits of the NYSDEC’sFERC’s denial of the Section 401 certification. And, in February 2018, we filed a request with the FERC for rehearing of its finding that the NYSDEC did not waive the Section 401 certification requirement. If the FERC denies such request, we will file aour petition for review with the D.C. Circuit Court of Appeals.
We estimate that the target in-service date for the project would be approximately 10 to 12 months following any court or FERC decision that the NYSDEC denial order was improper or that the NYSDEC waived the Section 401 certification requirement.declaratory order. An unfavorable resolution of that appeal could result in the impairment of a significant portion of the capitalized project costs, which total $381$377 million on a consolidated basis at December 31, 2017,2018, and are included within Property, plant, and equipment – netin the Consolidated Balance Sheet.Sheet. Beginning in April 2016, we discontinued capitalization of development costs related to this project. It is also possible that we could incur certain supplier-related costs in the event of a continued prolonged delay or termination of the project.
Cardinal
WPZ ownsWe own a66 percent interest in Cardinal, Gas Services, L.L.C. (Cardinal), a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. WPZ isWe are the primary beneficiary because it haswe have the power to direct the activities that most significantly impact Cardinal’s economic performance. Future expansion activity is expected to be funded with capital contributions from WPZus 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.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation of our consolidated VIEs:
|
| | | | | | | | | |
| | December 31, | | |
| | 2018 | | 2017 (1) | | Classification |
| | (Millions) | | |
| Assets (liabilities): | | | | | |
| Cash and cash equivalents | $ | 33 |
| | $ | 881 |
| | Cash and cash equivalents |
Trade accounts and other receivables – net | 62 |
| | 972 |
| | Trade accounts and other receivables |
| Inventories | — |
| | 113 |
| | Inventories |
| Other current assets | 2 |
| | 176 |
| | Other current assets and deferred charges |
| Investments | — |
| | 6,552 |
| | Investments |
Property, plant, and equipment – net | 2,363 |
| | 27,912 |
| | Property, plant, and equipment – net |
Intangible assets – net | 1,177 |
| | 8,790 |
| | Intangible assets – net of accumulated amortization |
| Regulatory assets, deferred charges, and other noncurrent assets | — |
| | 507 |
| | Regulatory assets, deferred charges, and other |
| Accounts payable | (15 | ) | | (957 | ) | | Accounts payable |
| Accrued liabilities including current asset retirement obligations | (115 | ) | | (857 | ) | | Accrued liabilities |
| Long-term debt due within one year | — |
| | (501 | ) | | Long-term debt due within one year |
| Long-term debt | — |
| | (15,996 | ) | | Long-term debt |
| Deferred income tax liabilities | — |
| | (16 | ) | | Deferred income tax liabilities |
| Noncurrent asset retirement obligations | (105 | ) | | (944 | ) | | Regulatory liabilities, deferred income, and other |
| Long-term deferred income | (159 | ) | | (1,119 | ) | | Regulatory liabilities, deferred income, and other |
| Regulatory liabilities and other | — |
| | (1,690 | ) | | Regulatory liabilities, deferred income, and other |
_________________
| |
| (1) | Includes WPZ, which was a consolidated VIE at December 31, 2017 (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies). |
Nonconsolidated VIEs
Jackalope
We own a50 percent interest in Jackalope, which provides gathering and processing services for the Powder River basin and is a VIE due to certain risks shared with customers. Prior to the second quarter of 2018 we were the primary beneficiary of Jackalope. During the second quarter of 2018, the scope of Jackalope’s planned future activities changed, resulting in a VIE reconsideration event. Upon evaluation, we determined that we are no longer the primary beneficiary, most notably due to changes in the activities that most significantly impact Jackalope’s economic performance and our determination that we do not control the power to direct such activities. These activities are primarily related to the capital decision making process. As a result, we deconsolidated Jackalope on June 30, 2018 and now account for our interest using the equity method of accounting as we exert significant influence over the financial and operational policies of Jackalope (see Note 6 – Investing Activities). At December 31, 2018, the carrying value of our investment in Jackalope was $343 million. Our maximum exposure to loss is limited to the carrying value of our investment. Jackalope is currently undertaking an expansion project with a remaining cost up to approximately $350 million as of December 31, 2018, which will be funded on a proportional basis.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
Brazos Permian II
We own a 15 percent interest in Brazos Permian II (see Note 6 – Investing Activities), which provides gathering and processing services in the Delaware basin and is a VIE due primarily to our limited participating rights as the minority equity holder. At December 31, 2018, the carrying value of our investment in Brazos Permian II was $191 million. Our maximum exposure to loss is limited to the carrying value of our investment.
Note 45 – 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 $236 million, $226 million, $180and $180 million, and $187 million for the years ended 2018, 2017, 2016, and 2015,2016, respectively. We have $20$18 million and $19$20 million included in Accounts payablein the Consolidated Balance Sheetwith our equity-method investees at December 31, 20172018 and 2016,2017, 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 $75 million, $67 million, $66 million, and $64$66 million for the years ended 2018, 2017, 2016, and 2015,2016, respectively.
Board of Directors
A former member of our Board of Directors, who was elected in 2013 and resigned during 2016, is also the current chairman, president, and chief executive officer of an energy services company that is a customer of ours. We recorded $144 million and $111 million in Service revenues in the Consolidated Statement of Operations from this company for transportation and storage of natural gas for the yearsyear ended December 31, 2016 and 2015, respectively.2016.
Note 56 – Investing Activities
ImpairmentBrazos Permian II Equity-Method Investment
During the fourth quarter of 2018, we contributed the majority of our existing Delaware basin assets and $27 million in cash in exchange for a 15 percent interest in the Brazos Permian II, which consists of gas and crude oil gathering pipelines, natural gas processing, and oil storage facilities. We recorded a deconsolidation gain of $141 million reflected in Other investing income (loss) – net in the Consolidated Statement of Operations reflecting the excess of the fair value of our acquired interest over the carrying value of the assets contributed. We estimated the fair value of our interest to be $192 million primarily using a market approach (a Level 3 measurement within the fair value hierarchy). This approach involved the observation of recent transaction multiples in the Permian basin, including recent acquisitions consummated during 2018. Our interest in Brazos Permian II is considered an equity-method investmentsinvestment due to the fact that we are able to exert significant influence over its operating and financial policies.
The following table presents other-than-temporary impairment charges relatedRMM Equity-Method Investment
During the third quarter of 2018, our joint venture, RMM, purchased a natural gas and oil gathering and natural gas processing business in Colorado’s Denver-Julesburg basin. Our initial economic ownership was 40 percent, which has since increased to certain equity-method investments50 percent at December 31, 2018, based on additional capital contributions made since the initial purchase.
Jackalope Deconsolidation
During the second quarter of 2018, we deconsolidated our interest in Jackalope (see Note 164 – Fair Value Measurements, Guarantees, and ConcentrationVariable Interest Entities). We recorded our interest in Jackalope as an equity-method investment at its estimated fair value, resulting in a deconsolidation gain of Credit Risk):$62 million reflected in Other investing income (loss) – net in the Consolidated Statement of Operations. We estimated the fair value of our interest to be $310 million using an income approach based on expected
|
| | | | | | | | |
| | | 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 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
future cash flows and an appropriate discount rate (a Level 3 measurement within the fair value hierarchy). The determination of expected future cash flows involved significant assumptions regarding gathering and processing volumes and related capital spending. A 10.9 percent discount rate was utilized and reflected our estimate of the cost of capital as impacted by market conditions and risks associated with the underlying business. The deconsolidated carrying value of the net assets of Jackalope included $47 million of goodwill.
Acquisition of Additional Interests in Appalachia Midstream Investments
During the first quarter of 2017, WPZwe exchanged all of itsour 50 percent interest in DBJV for an increased interest in two natural gas gathering systems that are part of the Appalachia Midstream Investments and $155 million in cash. This transaction was recorded based on our estimate of the fair value of the interests received as we have more insight to this value as we operate the underlying assets. Following this exchange, WPZ haswe have an approximate average 66 percent interest in the Appalachia Midstream Investments. We continue to account for this investment under the equity-methodequity method of accounting due to the significant participatory rights of our partners such that we do not exercise control. WPZWe also sold all of itsour interest in Ranch Westex JV LLC (Ranch Westex) for $45 million. These transactions resulted in a total gain of $269 million reflected in Other investing income (loss) – net in the Consolidated Statement of Operations.Operations
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
.
The fair value of the increased interests in the Appalachia Midstream Investments received as consideration was estimated to be $1.1 billion using an income approach based on expected cash flows and an appropriate discount rate (a Level 3 measurement within the fair value hierarchy). The determination of estimated future cash flows involved significant assumptions regarding gathering volumes, rates, and related capital spending. A 9.5 percent discount rate was utilized and reflected our estimate of the cost of capital as impacted by market conditions and risks associated with the underlying business.
AcquisitionImpairment of Additional Interest in UEOMequity-method investments
In June 2015, WPZ acquired an approximate 13 percent additional interest in itsThe following table presents other-than-temporary impairment charges related to certain equity-method investment, UEOM, for $357 million. Following the acquisition WPZ owns approximately 62 percentinvestments (see Note 17 – Fair Value Measurements, Guarantees, and Concentration 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.Credit Risk):
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. |
| | | | | | | | | | | | |
| | | Years Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | (Millions) |
| Northeast G&P | | | | | | |
| UEOM | | $ | 32 |
| | $ | — |
| | $ | — |
|
| Appalachia Midstream Investments | | — |
| | — |
| | 294 |
|
| Laurel Mountain | | — |
| | — |
| | 50 |
|
| West | | | | | | |
| DBJV | | — |
| | — |
| | 59 |
|
| Ranch Westex | | — |
| | — |
| | 24 |
|
| Other | | — |
| | — |
| | 3 |
|
| | | $ | 32 |
| | $ | — |
| | $ | 430 |
|
Other investing income (loss) – net
In 2016, we recognized a $27 million gain from the sale of an equity-method investment interest in a gathering system that was part of the Appalachia Midstream Investments.
Other investing income (loss) – net also includes $36 million and $27 million of interest income for 2016 and 2015, respectively, associated with a receivable related to the sale of certain former Venezuela assets. Due to changes in circumstances that led to late payments and increased uncertainty regarding the recovery of the receivable, we began accounting for the receivable under a cost recovery model in first quarter 2015. Subsequently, we received payments greater than the remaining carrying amount of the receivable, which resulted in the recognition of interest income.
|
| | | | | | | | | |
| | Ownership Interest at December 31, 2017 | | December 31, |
| | | 2017 | | 2016 |
| | | | (Millions) |
| Equity-method investments: | | | | | |
| Appalachia Midstream Investments | (1) | | $ | 3,104 |
| | $ | 2,062 |
|
| UEOM | 62% | | 1,383 |
| | 1,448 |
|
| Discovery | 60% | | 534 |
| | 572 |
|
| Caiman II | 58% | | 429 |
| | 426 |
|
| OPPL | 50% | | 422 |
| | 430 |
|
| Laurel Mountain | 69% | | 309 |
| | 324 |
|
| Gulfstream | 50% | | 244 |
| | 261 |
|
| DBJV | — | | — |
| | 988 |
|
| Other | Various | | 127 |
| | 190 |
|
| | | | $ | 6,552 |
| | $ | 6,701 |
|
___________
| |
(1) | Includes equity-method investments in multiple gathering systems in the Marcellus Shale with an approximate average 66 percent interest. |
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
|
| | | | | | | | | |
| | Ownership Interest at December 31, 2018 | | December 31, |
| | | 2018 | | 2017 |
| | | | (Millions) |
| Equity-method investments: | | | | | |
| Appalachia Midstream Investments | (1) | | $ | 3,218 |
| | $ | 3,104 |
|
| UEOM | 62% | | 1,293 |
| | 1,383 |
|
| RMM | 50% | | 776 |
| | — |
|
| Discovery | 60% | | 507 |
| | 534 |
|
| OPPL | 50% | | 415 |
| | 422 |
|
| Caiman II | 58% | | 412 |
| | 429 |
|
| Jackalope | 50% | | 343 |
| | — |
|
| Laurel Mountain | 69% | | 314 |
| | 309 |
|
| Gulfstream | 50% | | 225 |
| | 244 |
|
| Brazos Permian II | 15% | | 191 |
| | — |
|
| Other | Various | | 127 |
| | 127 |
|
| | | | $ | 7,821 |
| | $ | 6,552 |
|
___________
| |
| (1) | Includes equity-method investments in multiple gathering systems in the Marcellus Shale with an approximate average 66 percent interest. |
We have differences between the carrying value of our equity-method investments and the underlying equity in the net assets of the investees of $1.8 billion at December 31, 20172018 and $1.9 billion at December 31, 2016. For 2017 these2017. These differences primarily relate to our investments in Appalachia Midstream Investments and UEOM resulting from property, plant, and equipment, as well as customer-based intangible assets and goodwill. For 2016, the difference also includes DBJV.
Purchases of and contributions to equity-method investments
We generally fund our portion of significant expansion or development projects of these investees through additional capital contributions. These transactions increased the carrying value of our investments and included:
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (Millions) |
| Appalachia Midstream Investments | $ | 70 |
| | $ | 28 |
| | $ | 93 |
|
| DBJV | 32 |
| | 105 |
| | 57 |
|
| Caiman II | 24 |
| | 22 |
| | — |
|
| Discovery | 1 |
| | — |
| | 35 |
|
| UEOM | — |
| | — |
| | 357 |
|
| Other | 5 |
| | 22 |
| | 53 |
|
| | $ | 132 |
| | $ | 177 |
| | $ | 595 |
|
Dividends and distributions
The organizational documents of entities in which we have an equity-method interest generally require distribution of available cash to members on at least a quarterly basis. These transactions reduced the carrying value of our investments and included:
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (Millions) |
| Appalachia Midstream Investments | $ | 270 |
| | $ | 211 |
| | $ | 219 |
|
| Discovery | 127 |
| | 141 |
| | 116 |
|
| Gulfstream | 92 |
| | 100 |
| | 88 |
|
| UEOM | 80 |
| | 92 |
| | 42 |
|
| OPPL | 68 |
| | 69 |
| | 45 |
|
| Caiman II | 49 |
| | 40 |
| | 33 |
|
| DBJV | 39 |
| | 39 |
| | 33 |
|
| Laurel Mountain | 32 |
| | 28 |
| | 31 |
|
| Other | 27 |
| | 22 |
| | 26 |
|
| | $ | 784 |
| | $ | 742 |
| | $ | 633 |
|
In addition, on September 24, 2015, WPZ received a special distribution of $396 million from Gulfstream reflecting its proportional share of the proceeds from new debt issued by Gulfstream. The new debt was issued to refinance Gulfstream’s debt maturities. Subsequently, WPZ contributed $248 million and $148 million to Gulfstream for its proportional share of amounts necessary to fund debt maturities of $500 million due on November 1, 2015, and $300 million due on June 1, 2016, respectively. |
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | (Millions) |
| RMM | $ | 795 |
| | $ | — |
| | $ | — |
|
| Appalachia Midstream Investments | 246 |
| | 70 |
| | 28 |
|
| Jackalope | 42 |
| | — |
| | — |
|
| Brazos Permian II | 27 |
| | — |
| | — |
|
| Laurel Mountain | 16 |
| | — |
| | — |
|
| Discovery | 5 |
| | 1 |
| | — |
|
| DBJV | — |
| | 32 |
| | 105 |
|
| Caiman II | — |
| | 24 |
| | 22 |
|
| Other | 1 |
| | 5 |
| | 22 |
|
| | $ | 1,132 |
| | $ | 132 |
| | $ | 177 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Dividends and distributions
The organizational documents of entities in which we have an equity-method investment generally require distribution of available cash to members on at least a quarterly basis. These transactions reduced the carrying value of our investments and included:
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | (Millions) |
| Appalachia Midstream Investments | $ | 297 |
| | $ | 270 |
| | $ | 211 |
|
| Gulfstream | 93 |
| | 92 |
| | 100 |
|
| OPPL | 73 |
| | 68 |
| | 69 |
|
| UEOM | 70 |
| | 80 |
| | 92 |
|
| Caiman II | 46 |
| | 49 |
| | 40 |
|
| Discovery | 45 |
| | 127 |
| | 141 |
|
| DBJV | — |
| | 39 |
| | 39 |
|
| Laurel Mountain | 23 |
| | 32 |
| | 28 |
|
| Other | 46 |
| | 27 |
| | 22 |
|
| | $ | 693 |
| | $ | 784 |
| | $ | 742 |
|
In addition, on September 24, 2015, we received a special distribution of $396 million from Gulfstream reflecting our proportional share of the proceeds from new debt issued by Gulfstream. The new debt was issued to refinance Gulfstream’s debt maturities. Subsequently, we contributed $248 million and $148 million to Gulfstream for our proportional share of amounts necessary to fund debt maturities of $500 million due on November 1, 2015, and $300 million due on June 1, 2016, respectively.
Summarized Financial Position and Results of Operations of All Equity-Method Investments
| | | | December 31, | December 31, |
| | 2017 | | 2016 | 2018 | | 2017 |
| | (Millions) | (Millions) |
| Assets (liabilities): | | | | | | |
| Current assets | $ | 447 |
| | $ | 508 |
| $ | 834 |
| | $ | 447 |
|
| Noncurrent assets | 9,181 |
| | 9,695 |
| 13,199 |
| | 9,181 |
|
| Current liabilities | (295 | ) | | (412 | ) | (605 | ) | | (295 | ) |
| Noncurrent liabilities | (1,538 | ) | | (1,484 | ) | (2,491 | ) | | (1,538 | ) |
| | | | Years Ended December 31, | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (Millions) | (Millions) |
| Gross revenue | $ | 1,961 |
| | $ | 1,883 |
| | $ | 1,707 |
| $ | 2,411 |
| | $ | 1,961 |
| | $ | 1,883 |
|
| Operating income | 871 |
| | 799 |
| | 690 |
| 804 |
| | 871 |
| | 799 |
|
| Net income | 806 |
| | 726 |
| | 611 |
| 795 |
| | 806 |
| | 726 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
Note 67 – Other Income and Expenses
The following table presents certain gains or losses reflected in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Operations:
| | | | Years Ended December 31, | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (Millions) | (Millions) |
| Williams Partners | | | | | | |
| Loss on sale of Canadian operations (Note 2) | $ | 4 |
| | $ | 34 |
| | $ | — |
| |
| Atlantic-Gulf | | | | | | |
| Amortization of regulatory assets associated with asset retirement obligations | 33 |
| | 33 |
| | 33 |
| $ | 33 |
| | $ | 33 |
| | $ | 33 |
|
| Accrual of regulatory liability related to overcollection of certain employee expenses | 22 |
| | 25 |
| | 20 |
| 22 |
| | 22 |
| | 25 |
|
| Project development costs related to Constitution (Note 3) | 16 |
| | 28 |
| | — |
| |
| Project development costs related to Constitution (Note 4) | | 4 |
| | 16 |
| | 28 |
|
| Gains on asset retirements | | (12 | ) | | — |
| | (11 | ) |
| West | | | | | | |
| Gains on contract settlements and terminations | (15 | ) | | — |
| | — |
| — |
| | (15 | ) | | — |
|
| Regulatory charge per approved rates related to Tax Reform | | 24 |
| | — |
| | — |
|
| Charge for regulatory liability associated with the decrease in Northwest Pipeline’s estimated deferred state income tax rates following WPZ Merger | | 12 |
| | — |
| | — |
|
| Other | | | | | | |
| Gain on sale of Refinery Grade Propylene Splitter | (12 | ) | | — |
| | — |
| — |
| | (12 | ) | | — |
|
| Loss on sale of Canadian operations (Note 3) | | — |
| | 5 |
| | 66 |
|
| Net foreign currency exchange (gains) losses (1) | — |
| | 10 |
| | (10 | ) | — |
| | — |
| | 10 |
|
| Gain on asset retirement | — |
| | (11 | ) | | — |
| |
| Other | | | | | | |
| Loss on sale of Canadian operations (Note 2) | 1 |
| | 32 |
| | — |
| |
| Gain on sale of unused pipe | — |
| | (10 | ) | | — |
| — |
| | — |
| | (10 | ) |
| Benefit of regulatory asset associated with increase in Transco’s estimated deferred state income tax rate following WPZ Merger | | (37 | ) | | — |
| | — |
|
________________
| |
| (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 23 – Acquisitions and Divestitures). |
Additional Items
Certain additional items included in the Consolidated Statement of Operations are as follows:
Service revenues for the year ended December 31, 2016, includes $173 million associated with the amortization of deferred income related to the restructuring of certain gas gathering contracts in the Barnett Shale and Mid-Continent regions within the West segment.
Service revenues for the year ended December 31, 2016 were reduced by $15 million related to potential refunds associated with a ruling received in certain rate case litigation within the Atlantic-Gulf segment.
Selling, general, and administrative expenses for the year ended December 31, 2018, includes a $35 million charge associated with a charitable contribution of preferred stock to The Williams Companies Foundation, Inc. (a not-for-profit corporation) within the Other segment (see Note 15 – Stockholders' Equity). Selling, general, and administrative expenses for the year ended December 31, 2018, also includes $20 million for WPZ Merger related costs within the Other segment.
Selling, general, and administrative expenses and Operating and maintenance expenses for the year ended December 31, 2017, included $22 million in severance and other related costs within the Other segment. The year ended December 31, 2016, included $42 million in severance and other related costs associated with an
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
ACMP Acquisition, Merger, and Transition
Certain ACMP acquisition, merger, and transition costs includedapproximate 10 percent reduction in workforce in the Consolidated Statement of Operations are as follows:
Selling, general, and administrative expenses includes $26 million in 2015 primarily related to professional advisory fees within the Williams Partners segment.
Selling, general, and administrative expenses includes $32 million in 2015 of general corporate expenses associated with integration and realignment of resources within the Other segment.
Operating and maintenance expenses includes $12 million in 2015 primarily related to employee transition costs within the Williams Partners segment.
Additional Items
Certain additional items included in the Consolidated Statement of Operations are as follows:
Service revenues includes $66 million, $58 million, and $239 million recognized in the fourthfirst quarter of 2017, 2016, and 2015, respectively, from minimum volume commitment feesin the Barnett Shale and Mid-Continent regions within the Williams Partners segment.
Service revenues for the year ended December 31, 2016, includes $173comprised of $3 million associated with the amortization of deferred income related to the restructuring of certain gas gathering contracts in the Barnett Shale and Mid-Continent regions within the Williams Partners segment.
Service revenues were reduced by $15Northeast G&P segment, $8 million for the year ended December 31, 2016, related to potential refunds associated with a ruling received in certain rate case litigation within the Williams PartnersAtlantic-Gulf segment, $13 million associated with the West segment, and $18 million associated with the Other segment.
Selling, general, and administrative expenses includes $9 million and $47 million for the years ended December 31, 2017 and 2016 included $9 million and $47 million, respectively, of costs associated with our evaluation of strategic alternatives within the Other segment. Selling, general, and administrative expenses also includes $61 million for the year ended December 31, 2016, also included $61 million of project development costs related to a proposed propane dehydrogenation facility in Alberta, Canada within the Other segment. Beginning in the first quarter of 2016, these costs did not qualify for capitalization.
Selling, general, and administrative expenses and Operating and maintenance expenses includes $22 million in severance and other related costs for the year ended December 31, 2017, for the Williams Partners segment. The year ended December 31, 2016, included $42 million in severance and other related costs associated with an approximate 10 percent reduction in workforce in the first quarter of 2016, primarily within the Williams Partners segment.
Selling, general, and administrative expenses and Operating and maintenance expenses includes $35 million of settlement charge expense in 2017 related to the program to pay out certain deferred vested pension benefits within the Williams Partners segment (see Note 9 – Employee Benefit Plans).
Other income (expense) – net below Operating income (loss) includes $89 million, $71 million, $66 million, and $77$66 million for equity AFUDC primarily within the Atlantic-Gulf segment for the years ended December 31, 2018, 2017, 2016, and 2015,2016, respectively. Other income (expense) – net below Operating income (loss) also includes $35 million, $52 million, $23 million and $18$23 million for the years ended December 31, 2018, 2017, 2016 and 2015,2016, respectively, of income associated with regulatory assets related to the effects of deferred taxes on equity funds used during construction.
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
Other income (expense) – net below Operating income (loss) includes a $102 million charge for the year ended December 31, 2017, for regulatory assets associated with the effects of deferred taxes on equity funds used during construction as a result of Tax Reform comprised of $39 million within the Williams Partners segment and $63 millionprimarily within the Other segment (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies).
Other income (expense) – net below Operating income (loss) includes $35 million of settlement charge expense in 2017 related to the program to pay out certain deferred vested pension benefits (see Note 9 – Employee Benefit Plans).segment.
Other income (expense) – net below Operating income (loss) for the year ended December 31, 2018, includes a $7 million net loss associated with the March 28, 2018, early retirement of $750 million of 4.875 percent senior unsecured notes that were due in 2024. The net loss within the Other segment reflects $34 million in premiums paid, partially offset by $27 million of unamortized premium. The year ended December 31, 2017, includesincluded a net gain of $30 million associated with the February 23, 2017, early retirement of $750 million of 6.125 percent senior unsecured notes that were due in 2022 and a net loss of $3 million associated with the July 3, 2017, early retirement of of $1.4 billion of 4.875 percent senior unsecured notes that were due in 2023. The net gain for the February 23, 2017, early retirement within the Other segment reflects $53 million of unamortized premium, partially offset by $23 million in premiums paid. The net loss for the July 3, 2017, early retirement within the Other segment reflects $51 million of unamortized premium, offset by $54 million in premiums paid (see Note 1314 – Debt, Banking Arrangements, and Leases).
Note 7Other income (expense) – Provision (Benefit) for Income Taxes
The Provision (benefit) for income taxesnet includes:below Operating income (loss) includes settlement charge expense related to the program to pay out certain deferred vested pension benefits as follows (see Note 10 – Employee Benefit Plans):
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (Millions) |
| Current: | | | | | |
| Federal | $ | 15 |
| | $ | — |
| | $ | — |
|
| State | 23 |
| | 2 |
| | (7 | ) |
| Foreign | — |
| | (1 | ) | | (55 | ) |
| | 38 |
| | 1 |
| | (62 | ) |
| Deferred: | | | | | |
| Federal | (2,004 | ) | | (6 | ) | | (317 | ) |
| State | (8 | ) | | 61 |
| | (25 | ) |
| Foreign | — |
| | (81 | ) | | 5 |
|
| | (2,012 | ) | | (26 | ) | | (337 | ) |
| Provision (benefit) for income taxes | $ | (1,974 | ) | | $ | (25 | ) | | $ | (399 | ) |
|
| | | | | | | |
| | Years Ended December 31, |
| | 2018 | | 2017 |
| | (Millions) |
| Atlantic-Gulf | $ | 7 |
| | $ | 15 |
|
| Northeast | 4 |
| | 7 |
|
| West | 6 |
| | 13 |
|
| Other | 5 |
| | 35 |
|
Other income (expense) – net below Operating income (loss) for the year ended December 31, 2017, included a $102 million charge for regulatory assets associated with the effects of deferred taxes on equity funds used during construction as a result of Tax Reform, comprised of $33 million within the Atlantic-Gulf segment, $6 million within the West segment, and $63 million within the Other segment (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies).
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Note 8 – Provision (Benefit) for Income Taxes
The Provision (benefit) for income taxes includes:
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | (Millions) |
| Current: | | | | | |
| Federal | $ | (83 | ) | | $ | 15 |
| | $ | — |
|
| State | 1 |
| | 23 |
| | 2 |
|
| Foreign | — |
| | — |
| | (1 | ) |
| | (82 | ) | | 38 |
| | 1 |
|
| Deferred: | | | | | |
| Federal | 183 |
| | (2,004 | ) | | (6 | ) |
| State | 37 |
| | (8 | ) | | 61 |
|
| Foreign | — |
| | — |
| | (81 | ) |
| | 220 |
| | (2,012 | ) | | (26 | ) |
| Provision (benefit) for income taxes | $ | 138 |
| | $ | (1,974 | ) | | $ | (25 | ) |
Reconciliations from the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes are as follows:
| | | | Years Ended December 31, | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (Millions) | (Millions) |
| Provision (benefit) at statutory rate | $ | 187 |
| | $ | (131 | ) | | $ | (600 | ) | $ | 69 |
| | $ | 187 |
| | $ | (131 | ) |
| Increases (decreases) in taxes resulting from: | | | | | | | | | | |
| Impact of nontaxable noncontrolling interests | (117 | ) | | (22 | ) | | 263 |
| (73 | ) | | (117 | ) | | (22 | ) |
| Federal Tax Reform rate change | (1,932 | ) | | — |
| | — |
| — |
| | (1,932 | ) | | — |
|
| State income taxes (net of federal benefit) | (17 | ) | | 3 |
| | (21 | ) | (10 | ) | | (17 | ) | | 3 |
|
| State deferred income tax rate change | 26 |
| | 43 |
| | — |
| 38 |
| | 26 |
| | 43 |
|
| Foreign operations – net (including tax effect of Canadian Sale) | (127 | ) | | 78 |
| | 8 |
| — |
| | (127 | ) | | 78 |
|
| Valuation allowance | | 105 |
| | — |
| | — |
|
| Translation adjustment of certain unrecognized tax benefits | — |
| | (1 | ) | | (71 | ) | — |
| | — |
| | (1 | ) |
| Other – net | 6 |
| | 5 |
| | 22 |
| 9 |
| | 6 |
| | 5 |
|
| Provision (benefit) for income taxes | $ | (1,974 | ) | | $ | (25 | ) | | $ | (399 | ) | $ | 138 |
| | $ | (1,974 | ) | | $ | (25 | ) |
Income (loss) before income taxes includes $3 million, $7 million, and $885 million of foreign loss in 2018, 2017, and 2016, respectively, and $20 million of foreign income in 2015.respectively.
Foreign operations – net (including tax effect of Canadian Sale) increased in 2016 due toreflects a valuation allowance associated with impairments and losses on the sale of our Canadian operations (see Note 23 – Acquisitions and Divestitures) and the reversal of anticipatory foreign tax credits, partially offset by the tax effect of the impairments associated with our Canadian disposition. 2017 reflects the release of this valuation allowance.
On December 22, 2017, Tax Reform was enacted. Most of the provisions of Tax Reform are notwere effective until after January 1, 2018. However, the deferred tax impact of reducing the U.S. corporate tax rate from 35 percent to 21 percent iswas recognized in the period of enactment. This remeasurement resulted in a reduction of our deferred tax liabilities of approximately $1.9 billion, with a corresponding net adjustment to Provision (benefit) for income taxes. Under the guidance provided by Securities and Exchange Commission Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act, we are recording provisional adjustments related to the impact of Tax Reform, including items such as direct expensing of assets placed into service after September 27, 2017. We anticipate that additional guidance from the Internal Revenue Service (IRS) will be released to guide us in determining what assets are eligible for direct expensing in 2017. We are also recording provisional adjustments for valuation allowances associated with State losses and credits (see following table), since, at this time, we cannot assess the impact that the interest expense disallowance will have on our estimated future taxable income. We are not reducing our Minimum tax credit (see following table) for sequestration until we receive further guidance on that matter.
The Translation adjustment of certain unrecognized tax benefits in 2016 and 2015 reflects the impact of changes in foreign currency exchange rates on the remeasurement of a foreign currency denominated unrecognized tax benefit, including associated penalties and interest.
The 2015 federal and state income tax provisions include the tax effect of a $2.7 billion impairment loss associated with certain goodwill, equity-method investments, and other assets. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.)
During the course of audits of our business by domestic and foreign tax authorities, we frequently face challenges regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions and the allocation of income among various tax jurisdictions. In evaluating the liability associated with our various
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
filing positions, we apply the two-step process of recognition and measurement. In association with this liability, we record an estimate of related interest and tax exposure as a component of our tax provision. The impact of this accrual is included within Other – net in our reconciliation of the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes.
Significant components of Deferred income tax liabilities and Deferred income tax assets are as follows. Following the WPZ Merger, the attributes below are presented based on the underlying assets.
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| | (Millions) |
| Deferred income tax liabilities: | | | |
| Property, plant and equipment | $ | 2,317 |
| | $ | — |
|
| Investments | 295 |
| | 3,565 |
|
| Other | 30 |
| | 19 |
|
| Total deferred income tax liabilities | 2,642 |
| | 3,584 |
|
| Deferred income tax assets: | | | |
| Accrued liabilities | 667 |
| | 53 |
|
| Minimum tax credit | 71 |
| | 155 |
|
| Foreign tax credit | 140 |
| | 140 |
|
| Federal loss carryovers | 147 |
| | — |
|
| State losses and credits | 319 |
| | 283 |
|
| Other | 94 |
| | 30 |
|
| Total deferred income tax assets | 1,438 |
| | 661 |
|
| Less valuation allowance | 320 |
| | 224 |
|
| Net deferred income tax assets | 1,118 |
| | 437 |
|
| Overall net deferred income tax liabilities | $ | 1,524 |
| | $ | 3,147 |
|
The valuation allowance at December 31, 2018 and 2017 serves to reduce the available deferred income tax assets to an amount that will, more likely than not, be realized. We consider all available positive and negative evidence, including projected future taxable income, which incorporates available tax planning strategies, and management’s estimate of future reversals of existing taxable temporary differences, and have determined that a portion of our deferred income tax assets related to the Foreign tax credit and State losses and credits may not be realized. The Valuation allowance change from 2017 is primarily due to a $105 million valuation allowance associated with foreign tax credits, that expire between 2024 and 2028. The completion of the WPZ Merger (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies) was a taxable exchange to the WPZ unit holders, which resulted in an adjustment to the tax basis in the underlying assets deemed acquired. A reduction to the deferred tax liability of $1.829 billion related to the book-tax basis difference in this investment has been recorded. Increased tax depreciation from the additional tax basis will reduce future taxable income, which serves to impact our expected realization of the Foreign tax credit. The amounts presented in the table above are, with respect to state items, before any federal benefit. The change from prior year for the State losses and credits reflects increases in losses and credits generated in the current and prior years less losses and/or credits utilized in the current year. We have loss and credit carryovers in multiple state taxing jurisdictions. Additionally, valuation allowances on state net operating losses decreased by $31 million after the completion of the WPZ Merger. These attributes generally expire between 2019 and 2038 with some carryovers having indefinite carryforward periods. The remaining federal Minimum tax credit of $71 million will be refunded/utilized no later than 2021.
Federal loss carryovers includes deferred tax assets of $5 million at the end of 2018 that are expected to be utilized by us prior to expiration between 2019 and 2023. Deferred tax assets on net operating loss carryovers of $142 million have no expiration date.
|
| | | | |
| 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, |
| | 2017 | | 2016 |
| | (Millions) |
| Deferred income tax liabilities: | | | |
| Investments | $ | 3,565 |
| | $ | 5,300 |
|
| Other | 19 |
| | 29 |
|
| Total deferred income tax liabilities | 3,584 |
| | 5,329 |
|
| Deferred income tax assets: | | | |
| Accrued liabilities | 53 |
| | 145 |
|
| Minimum tax credit | 155 |
| | 139 |
|
| Foreign tax credit | 140 |
| | 140 |
|
| Federal loss carryovers | — |
| | 651 |
|
| State losses and credits | 283 |
| | 313 |
|
| Other | 30 |
| | 37 |
|
| Total deferred income tax assets | 661 |
| | 1,425 |
|
| Less valuation allowance | 224 |
| | 334 |
|
| Net deferred income tax assets | 437 |
| | 1,091 |
|
| Overall net deferred income tax liabilities | $ | 3,147 |
| | $ | 4,238 |
|
As of December 31, 2017, Overall net deferred income tax liabilities reflects the 21 percent federal rate change as established by Tax Reform. We consider all amounts recorded related to Tax Reform to be reasonable estimates. The amounts recorded are provisional as our interpretation, assessment, and presentation of the impact of the tax law change may be further clarified with additional guidance from regulatory, tax, and accounting authorities. Should additional guidance be provided by these authorities or other sources, we will review the provisional amounts and adjust as appropriate.
The valuation allowance at December 31, 2017 and 2016 serves to reduce the available deferred income tax assets to an amount that will, more likely than not, be realized. We consider all available positive and negative evidence, including projected future taxable income and management’s estimate of future reversals of existing taxable temporary differences, and have determined that a portion of our deferred income tax assets related to State losses and credits may not be realized. The change in Valuation allowance is partially due to this evaluation. The amounts presented in the table above are, with respect to state items, before any federal benefit. The change from prior year for the State losses and credits is primarily due to increases in losses and credits generated in the current and prior years less losses and/or credits utilized in the current year. We have loss and credit carryovers in multiple state taxing jurisdictions. These attributes generally expire between 2018 and 2037 with some carryovers having indefinite carryforward periods. The Valuation allowance change from prior year is primarily due to releasing a $127 million valuation allowance on a deferred tax asset associated with a capital loss carryover. Under Tax Reform, the federal Minimum tax credit of $155 million will be refunded/utilized no later than 2021. Foreign tax credit carryforwards of $140 million are expected to be utilized prior to their expiration between 2024 and 2027.
Federal deferred income tax assets related to our net operating loss carryovers and charitable contribution carryovers at the end of 2017 are fully offset by our unrecognized tax positions in the table below.
Cash payments for income taxes (net of refunds) were $11 million, $28 million, and $5 million in 2018, 2017, and 2016, respectively. Cash refunds for income taxes (net of payments and discontinued operations) were $136 million in 2015.
As of December 31, 2017,2018, we had approximately $50$51 million of unrecognized tax benefits. If recognized, income tax expense would be reduced by $51 million and $50 million for 2018 and $49 million for 2017, and 2016, respectively, including the effect of these changes on other tax attributes, with state income tax amounts included net of federal tax effect. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
| | | | 2017 | | 2016 | 2018 | | 2017 |
| | (Millions) | (Millions) |
| Balance at beginning of period | $ | 50 |
| | $ | 55 |
| $ | 50 |
| | $ | 50 |
|
| Reductions for tax positions of prior years | — |
| | (4 | ) | |
| Changes due to currency translation | — |
| | (1 | ) | |
| Additions for tax positions of prior years | | 1 |
| | — |
|
| Balance at end of period | $ | 50 |
| | $ | 50 |
| $ | 51 |
| | $ | 50 |
|
We recognize related interest and penalties as a component of Provision (benefit) for income taxes. Total interest and penalties recognized as part of income tax provision were benefitsexpenses of $800 thousand and $300 thousand for 2018 and 2016, respectively, and a benefit of $400 thousand and $22 million for 2017 and 2015, respectively, and expenses of $300 thousand for 2016.2017. Approximately $2$3 million and $3$2 million of interest and penalties primarily relating to uncertain tax positions have been accrued as of December 31, 20172018 and 2016,2017, respectively.
During the next 12 months, we do not expect ultimate resolution of any unrecognized tax benefit associated with domestic or international matters to have a material impact on our unrecognized tax benefit position.
Consolidated U.S. Federal income tax returns are open to IRSInternal Revenue Service (IRS) examination for years after 2010. As of December 31, 2017,2018, examinations of tax returns for 2011 through 2013 are currently in process. We do not expect material changes in our financial position resulting from these examinations. The statute of limitations for most states expires one year after expiration of the IRS statute. Generally, tax returns for our previously owned Canadian entities are open to audit for tax years after 2012.2013. Tax years 2013 and 2014through 2016 are currently under examination. We have indemnified the purchaser for any adjustments to Canadian tax returns for periods prior to the sale of our Canadian operations in September 2016.
On September 13, 2013, the IRS issued final regulations providing guidance on the treatment of amounts paid to acquire, produce, or improve tangible property. On August 18, 2014, the IRS issued final regulations providing guidance on the dispositions of such property. The implementation date for these regulations was January 1, 2014. The IRS is expected to issue additional procedural guidance regarding how the requirements may be implemented for the gas transmission and distribution industry. Pending the issuance of this additional procedural guidance from the IRS, we cannot at this time estimate the impact of implementing the regulations for our gas transmission business, although we anticipate that it will result in an immaterial balance-sheet-only impact.
Note 89 – Earnings (Loss) Per Common Share | | | | Years Ended December 31, | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| | (Dollars in millions, except per-share amounts; shares in thousands) | (Dollars in millions, except per-share amounts; shares in thousands) |
| Net income (loss) attributable to The Williams Companies, Inc. available to common stockholders for basic and diluted earnings (loss) per common share | $ | 2,174 |
| | $ | (424 | ) | | $ | (571 | ) | |
| Net income (loss) available to common stockholders | | $ | (156 | ) | | $ | 2,174 |
| | $ | (424 | ) |
| Basic weighted-average shares | 826,177 |
| | 750,673 |
| | 749,271 |
| 973,626 |
| | 826,177 |
| | 750,673 |
|
| Effect of dilutive securities: | | | | | | | | | | |
| Nonvested restricted stock units | 1,704 |
| | — |
| | — |
| — |
| | 1,704 |
| | — |
|
| Stock options | 637 |
| | — |
| | — |
| — |
| | 637 |
| | — |
|
| Diluted weighted-average shares (1) | 828,518 |
| | 750,673 |
| | 749,271 |
| 973,626 |
| | 828,518 |
| | 750,673 |
|
| Earnings (loss) per common share: | | | | | | | | | | |
| Basic | $ | 2.63 |
| | $ | (.57 | ) | | $ | (.76 | ) | $ | (.16 | ) | | $ | 2.63 |
| | $ | (.57 | ) |
| Diluted | $ | 2.62 |
| | $ | (.57 | ) | | $ | (.76 | ) | $ | (.16 | ) | | $ | 2.62 |
| | $ | (.57 | ) |
________________
| |
| (1) | For the years ended December 31, 20162018 and December 31, 2015, 0.62016, 2.0 million and 1.70.6 million weighted-average nonvested restricted stock units, respectively, and 0.5 million and 1.50.5 million weighted-average stock options, respectively, have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to The Williams Companies, Inc. |
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Note 910 – Employee Benefit Plans
We have noncontributory defined benefit pension plans in which all eligible employees participate. Currently, eligible employees earn benefits primarily based on a cash balance formula. Various other formulas, as defined in the plan documents, are utilized to calculate the retirement benefits for plan participants not covered by the cash balance formula. At the time of retirement, participants may elect, to the extent they are eligible for the various options, to receive annuity payments, a lump-sum payment, or a combination of annuity and lump-sum payments. In addition to our pension plans, we currently provide subsidized retiree medical and life insurance benefits (other postretirement benefits) to certain eligible participants. Generally, employees hired after December 31, 1991, are not eligible for the subsidized retiree medical benefits, except for participants that were employees or retirees of Transco Energy Company on December 31, 1995, and other miscellaneous defined participant groups.1995. Subsidized retiree medical benefits for eligible participants age 65 and older are paid through contributions to health reimbursement accounts. Subsidized retiree medical benefits for eligible participants under age 65 are provided through a self-insured medical plan sponsored by us. The self-insured retiree medical plan provides for retiree contributions and contains other cost-sharing features such as deductibles, co-payments, and co-insurance. The accounting for 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 November 2018, we announced changes to our defined benefit pension plans and our defined contribution plan. Eligible employees hired or rehired on or after January 1, 2019, will not be eligible to participate in the pension plan, but will be eligible for an additional fixed annual contribution made by us to the defined contribution plan. Additionally, as of January 1, 2020, certain active eligible employees will no longer receive future compensation credits under the defined benefit pension plan, but will be eligible for an additional fixed annual contribution made by us to the defined contribution plan. Also as of January 1, 2020, certain active eligible employees will continue to receive compensation credits under the defined benefit pension plans and these employees will not be eligible to receive the fixed annual contribution under the defined contribution plan. As a result of this amendment, a curtailment gain and a prior service credit were recorded to Accumulated other comprehensive income (loss). The amounts of the curtailment gain and prior service credit were not significant and are reported in Net actuarial gain (loss) within the subsequent tables of changes in benefit obligations, amounts included in Accumulated other comprehensive income (loss), and other changes in plan assets and benefit obligations recognized in other comprehensive income (loss) before taxes.
In September 2017, we initiated a program to pay out certain deferred vested pension benefits to reduce investment risk, cash funding volatility, and administrative costs. In December 2017 theand August 2018, lump-sum payments were made, and the annuity payments were commenced in relation to this program. As a result of these lump-sum payments, as well as lump-sum benefit payments made throughout 2017 and 2018, settlement accounting was required. We settled $261$103 million in liabilities of our pension plans in 2018 and $261 million in 2017 and recognized a pre-tax, non-cashnoncash settlement chargecharges of $23 million in 2018 and $71 million ofin 2017, which $35 million isare substantially reported in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations (see Note 67 – Other Income and Expenses). These amounts are included within the subsequent tables of changes in benefit obligations and plan assets, net periodic benefit cost (credit), and other changes in plan assets and benefit obligations recognized in other comprehensive income (loss) before taxes.
|
| | | | |
| 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 | Pension Benefits | | Other Postretirement Benefits |
| | 2017 | | 2016 | | 2017 | | 2016 | 2018 | | 2017 | | 2018 | | 2017 |
| | (Millions) | (Millions) |
| Change in benefit obligation: | | | | | | | | | | | | | | |
| Benefit obligation at beginning of year | $ | 1,466 |
| | $ | 1,464 |
| | $ | 197 |
| | $ | 202 |
| $ | 1,319 |
| | $ | 1,466 |
| | $ | 206 |
| | $ | 197 |
|
| Service cost | 50 |
| | 54 |
| | 1 |
| | 1 |
| 50 |
| | 50 |
| | 1 |
| | 1 |
|
| Interest cost | 59 |
| | 62 |
| | 8 |
| | 8 |
| 46 |
| | 59 |
| | 7 |
| | 8 |
|
| Plan participants’ contributions | — |
| | — |
| | 3 |
| | 2 |
| — |
| | — |
| | 2 |
| | 3 |
|
| Benefits paid | (35 | ) | | (130 | ) | | (14 | ) | | (15 | ) | (35 | ) | | (35 | ) | | (13 | ) | | (14 | ) |
| Actuarial loss (gain) | 40 |
| | 20 |
| | 11 |
| | (1 | ) | |
| Net actuarial loss (gain) | | (90 | ) | | 40 |
| | (17 | ) | | 11 |
|
| Settlements | (261 | ) | | (4 | ) | | — |
| | — |
| (103 | ) | | (261 | ) | | — |
| | — |
|
| Net increase (decrease) in benefit obligation | (147 | ) | | 2 |
| | 9 |
| | (5 | ) | (132 | ) | | (147 | ) | | (20 | ) | | 9 |
|
| Benefit obligation at end of year | 1,319 |
| | 1,466 |
| | 206 |
| | 197 |
| 1,187 |
| | 1,319 |
| | 186 |
| | 206 |
|
| Change in plan assets: | | | | | | | | | | | | | | |
| Fair value of plan assets at beginning of year | 1,254 |
| | 1,241 |
| | 208 |
| | 201 |
| 1,227 |
| | 1,254 |
| | 227 |
| | 208 |
|
| Actual return on plan assets | 184 |
| | 82 |
| | 25 |
| | 13 |
| (45 | ) | | 184 |
| | (7 | ) | | 25 |
|
| Employer contributions | 85 |
| | 65 |
| | 5 |
| | 7 |
| 88 |
| | 85 |
| | 5 |
| | 5 |
|
| Plan participants’ contributions | — |
| | — |
| | 3 |
| | 2 |
| — |
| | — |
| | 2 |
| | 3 |
|
| Benefits paid | (35 | ) | | (130 | ) | | (14 | ) | | (15 | ) | (35 | ) | | (35 | ) | | (13 | ) | | (14 | ) |
| Settlements | (261 | ) | | (4 | ) | | — |
| | — |
| (103 | ) | | (261 | ) | | — |
| | — |
|
| Net increase (decrease) in fair value of plan assets | (27 | ) | | 13 |
| | 19 |
| | 7 |
| (95 | ) | | (27 | ) | | (13 | ) | | 19 |
|
| Fair value of plan assets at end of year | 1,227 |
| | 1,254 |
| | 227 |
| | 208 |
| 1,132 |
| | 1,227 |
| | 214 |
| | 227 |
|
| Funded status — overfunded (underfunded) | $ | (92 | ) | | $ | (212 | ) | | $ | 21 |
| | $ | 11 |
| $ | (55 | ) | | $ | (92 | ) | | $ | 28 |
| | $ | 21 |
|
| Accumulated benefit obligation | $ | 1,294 |
| | $ | 1,440 |
| | | | | $ | 1,171 |
| | $ | 1,294 |
| | | | |
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, | December 31, |
| | 2017 | | 2016 | 2018 | | 2017 |
| | (Millions) | (Millions) |
| Underfunded pension plans: | | | | | | |
| Current liabilities | $ | (2 | ) | | $ | (2 | ) | $ | (2 | ) | | $ | (2 | ) |
| Noncurrent liabilities | (90 | ) | | (210 | ) | (53 | ) | | (90 | ) |
| Overfunded (underfunded) other postretirement benefit plans: | | | | |
| Overfunded (underfunded) other postretirement benefit plan: | | | | |
| Current liabilities | (6 | ) | | (7 | ) | (6 | ) | | (6 | ) |
| Noncurrent assets (liabilities) | 27 |
| | 18 |
| |
| Noncurrent assets | | 34 |
| | 27 |
|
The plan assets within our other postretirement benefit plans areplan is 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 $40$(90) million in 2018 is primarily due to the impact of an increase in the discount rates utilized to calculate the benefit obligation. The pension plans’ benefit obligation Net actuarial loss (gain) of$40 million in 2017 is primarily due to the impact of a decrease in the discount rates utilized to calculate the benefit obligation.
The pension plans’2018 benefit obligation ActuarialNet actuarial loss (gain)of$20 $(17) million in 2016for our other postretirement benefit plan is primarily due to the impact of a decreasean increase in the discount rates utilizedrate used to calculate the benefit obligation.
The 2017 benefit obligation ActuarialNet actuarial loss (gain) of $11 million for our other postretirement benefit plansplan is primarily due to a decrease in the discount rate used to calculate the benefit obligation.
At December 31, 2018, one of our pension plans had plan assets in excess of its accumulated benefit obligation. For our other pension plans, the accumulated benefit obligation of $367 million exceeded plan assets of $326 million. All of our pension plans had a projected benefit obligation in excess of plan assets at December 31, 2018. At December 31, 2017, and 2016, all of our pension plans had a projected benefit obligation and accumulated benefit obligation in excess of plan assets.
Pre-tax amounts not yet recognized in Net periodic benefit cost (credit) at December 31 are as follows:
| | | | Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits |
| | 2017 | | 2016 | | 2017 | | 2016 | 2018 | | 2017 | | 2018 | | 2017 |
| | (Millions) | (Millions) |
Amounts included in Accumulated other comprehensive income (loss): | | | | | | | | | | | | | | |
| Prior service credit | $ | — |
| | $ | — |
| | $ | — |
| | $ | 5 |
| |
| Net actuarial loss | (375 | ) | | (535 | ) | | (21 | ) | | (18 | ) | $ | (347 | ) | | $ | (375 | ) | | $ | (12 | ) | | $ | (21 | ) |
| Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline: | | | | | | | | | | | | | | |
| Prior service credit | N/A |
| | N/A |
| | $ | 2 |
| | $ | 10 |
| N/A |
| | N/A |
| | $ | — |
| | $ | 2 |
|
| Net actuarial gain | N/A |
| | N/A |
| | 14 |
| | 8 |
| N/A |
| | N/A |
| | 4 |
| | 14 |
|
In addition to the regulatory liabilities included in the previous table, differences in the amount of actuarially determined Net periodic benefit cost (credit) for our other postretirement benefit 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 $116 million at December 31, 2018 and $108 million at December 31, 2017, and $94 million at December 31, 2016, related to these deferrals. Additionally, Transco recognizes a regulatory liability for rate collections in excess of its amount funded to the tax-qualified pension plans. At December 31, 20172018 and 2016,2017, these regulatory liabilities were $33$49 million and $21$33 million, respectively. These pension and other postretirement plans amounts will be reflected in future rates based on the rate structures of these gas pipelines.
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 |
| | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
| | (Millions) |
| Components of net periodic benefit cost (credit): | | | | | | | | | | | |
| Service cost | $ | 50 |
| | $ | 54 |
| | $ | 59 |
| | $ | 1 |
| | $ | 1 |
| | $ | 2 |
|
| Interest cost | 59 |
| | 62 |
| | 58 |
| | 8 |
| | 8 |
| | 9 |
|
| Expected return on plan assets | (82 | ) | | (85 | ) | | (75 | ) | | (11 | ) | | (12 | ) | | (12 | ) |
| Amortization of prior service credit | — |
| | — |
| | — |
| | (13 | ) | | (15 | ) | | (17 | ) |
| Amortization of net actuarial loss | 27 |
| | 30 |
| | 42 |
| | — |
| | — |
| | 2 |
|
| Net actuarial loss from settlements | 71 |
| | 2 |
| | 2 |
| | — |
| | — |
| | — |
|
| Reclassification to regulatory liability | — |
| | — |
| | — |
| | 3 |
| | 4 |
| | 3 |
|
| Net periodic benefit cost (credit) | $ | 125 |
| | $ | 63 |
| | $ | 86 |
| | $ | (12 | ) | | $ | (14 | ) | | $ | (13 | ) |
|
| | | | |
| 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 |
| | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| | (Millions) |
| Components of net periodic benefit cost (credit): | | | | | | | | | | | |
| Service cost | $ | 50 |
| | $ | 50 |
| | $ | 54 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
|
| Interest cost | 46 |
| | 59 |
| | 62 |
| | 7 |
| | 8 |
| | 8 |
|
| Expected return on plan assets | (63 | ) | | (82 | ) | | (85 | ) | | (11 | ) | | (11 | ) | | (12 | ) |
| Amortization of prior service credit | — |
| | — |
| | — |
| | (2 | ) | | (13 | ) | | (15 | ) |
| Amortization of net actuarial loss | 23 |
| | 27 |
| | 30 |
| | — |
| | — |
| | — |
|
| Net actuarial loss from settlements | 23 |
| | 71 |
| | 2 |
| | — |
| | — |
| | — |
|
| Reclassification to regulatory liability | — |
| | — |
| | — |
| | 2 |
| | 3 |
| | 4 |
|
| Net periodic benefit cost (credit) | $ | 79 |
| | $ | 125 |
| | $ | 63 |
| | $ | (3 | ) | | $ | (12 | ) | | $ | (14 | ) |
The components of Net periodic benefit cost (credit) other than the service cost component are included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations.
Items Recognized in Other Comprehensive Income (Loss) and Regulatory Assets and Liabilities
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) before taxes for the years ended December 31 consist of the following:
| | | | Pension Benefits |
| Other Postretirement Benefits | Pension Benefits |
| Other Postretirement Benefits |
| | 2017 |
| 2016 |
| 2015 |
| 2017 |
| 2016 |
| 2015 | 2018 |
| 2017 |
| 2016 |
| 2018 |
| 2017 |
| 2016 |
| | (Millions) | (Millions) |
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net actuarial gain (loss) | $ | 62 |
|
| $ | (23 | ) |
| $ | 5 |
|
| $ | (3 | ) |
| $ | — |
|
| $ | 8 |
| $ | (18 | ) |
| $ | 62 |
|
| $ | (23 | ) |
| $ | 9 |
|
| $ | (3 | ) |
| $ | — |
|
| Amortization of prior service credit | — |
|
| — |
|
| — |
|
| (5 | ) |
| (6 | ) |
| (6 | ) | — |
|
| — |
|
| — |
|
| — |
|
| (5 | ) |
| (6 | ) |
| Amortization of net actuarial loss | 27 |
|
| 30 |
|
| 42 |
|
| — |
|
| — |
|
| 2 |
| 23 |
|
| 27 |
|
| 30 |
|
| — |
|
| — |
|
| — |
|
| Net actuarial loss from settlements | 71 |
| | 2 |
| | 2 |
| | — |
| | — |
| | — |
| 23 |
| | 71 |
| | 2 |
| | — |
| | — |
| | — |
|
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) | $ | 160 |
|
| $ | 9 |
|
| $ | 49 |
|
| $ | (8 | ) |
| $ | (6 | ) |
| $ | 4 |
| $ | 28 |
|
| $ | 160 |
|
| $ | 9 |
|
| $ | 9 |
|
| $ | (8 | ) |
| $ | (6 | ) |
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 and liabilities. Amounts recognized in regulatory assets and liabilities for the years ended December 31 consist of the following:
|
| | | | | | | | | | | | |
| | | 2017 | | 2016 | | 2015 |
| | | (Millions) |
Other changes in plan assets and benefit obligations recognized in regulatory (assets) and liabilities: | | | | | | |
| Net actuarial gain (loss) | | $ | 6 |
| | $ | 2 |
| | $ | 10 |
|
| Amortization of prior service credit | | (8 | ) | | (9 | ) | | (11 | ) |
Pre-tax amounts expected to be amortized in Net periodic benefit cost (credit) in 2018 are as follows:
|
| | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | (Millions) |
Amounts included in Accumulated other comprehensive income (loss): | | | |
| Prior service credit | $ | — |
| | $ | (1 | ) |
| Net actuarial loss | 23 |
| | — |
|
| Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline: | | | |
| Prior service credit | N/A |
| | $ | (2 | ) |
| 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 |
| | 2017 | | 2016 | | 2017 | | 2016 |
| Discount rate | 3.66 | % | | 4.17 | % | | 3.71 | % | | 4.27 | % |
| Rate of compensation increase | 4.93 |
| | 4.87 |
| | N/A |
| | N/A |
|
|
| | | | | | | | | | | | |
| | | 2018 | | 2017 | | 2016 |
| | | (Millions) |
Other changes in plan assets and benefit obligations recognized in regulatory (assets) and liabilities: | | | | | | |
| Net actuarial gain (loss) | | $ | (10 | ) | | $ | 6 |
| | $ | 2 |
|
| Amortization of prior service credit | | (2 | ) | | (8 | ) | | (9 | ) |
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Key Assumptions
The weighted-average assumptions utilized to determine benefit obligations as of December 31 are as follows:
|
| | | | | | | | | | | |
| | Pension Benefits | | Other Postretirement Benefits |
| | 2018 | | 2017 | | 2018 | | 2017 |
| Discount rate | 4.34 | % | | 3.66 | % | | 4.39 | % | | 3.71 | % |
| Rate of compensation increase | 4.83 |
| | 4.93 |
| | N/A |
| | N/A |
|
| Cash balance interest crediting rate | 4.25 |
| | 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 | Pension Benefits | | Other Postretirement Benefits |
| | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| Discount rate | 4.17 | % | | 4.37 | % | | 3.96 | % | | 4.27 | % | | 4.50 | % | | 4.12 | % | 3.67 | % | | 4.17 | % | | 4.37 | % | | 3.71 | % | | 4.27 | % | | 4.50 | % |
| Expected long-term rate of return on plan assets | 6.45 |
| | 6.85 |
| | 6.38 |
| | 5.53 |
| | 6.11 |
| | 5.70 |
| 5.34 |
| | 6.45 |
| | 6.85 |
| | 4.95 |
| | 5.53 |
| | 6.11 |
|
| Rate of compensation increase | 4.87 |
| | 4.88 |
| | 4.62 |
| | N/A |
| | N/A |
| | N/A |
| 4.93 |
| | 4.87 |
| | 4.88 |
| | N/A |
| | N/A |
| | N/A |
|
| Cash balance interest crediting rate | | 4.25 |
| | 4.25 |
| | 4.25 |
| | 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 20182019 is 8.07.5 percent. This rate decreases to 4.5 percent by 2026. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
|
| | | | | | | |
| | Point increase | | Point decrease |
| | (Millions) |
| Effect on total of service and interest cost components | $ | — |
| | $ | — |
|
| Effect on other postretirement benefit obligation | 5 |
| | (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 approximately 3738 percent of the other postretirement benefit plan assets are subject to income tax; therefore, certain investments are managed in a tax efficient manner.
The investment policy for the pension plans includes a general target asset allocation at December 31, 2017,2018, of 4625 percent equity securities and 5475 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 Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
the fixed income securities of any one issuer with the exception of bond index funds and U.S. government guaranteed and agency securities.
The following securities and transactions are not authorized: unregistered securities, commodities or commodity contracts, short sales or margin transactions, or other leveraging strategies. Investment strategies using direct investments in derivative securities require approval and, historically, have not been used; however, these instruments may be used in mutual funds and commingled investment funds held by the plans’ trusts. Additionally, real estate equity,
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
natural resource property, venture capital, leveraged buyouts, and other high-return, high-risk investments are generally restricted.
There are no significant concentrations of risk within the plans’ investment securities because of the diversity of the types of investments, diversity of the various industries, and the diversity of the fund managers and investment strategies. Generally, the investments held in the plans are publicly traded, therefore, minimizing liquidity risk in the portfolio.
The fair values of our pension plan assets at December 31, 20172018 and 20162017 by asset class are as follows:
| | | | 2017 | 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 | $ | 17 |
| | $ | — |
| | $ | — |
| | $ | 17 |
| $ | 10 |
| | $ | — |
| | $ | — |
| | $ | 10 |
|
| Equity securities: | | | | | | | | | | | | | | |
| U.S. large cap | 62 |
| | — |
| | — |
| | 62 |
| 30 |
| | — |
| | — |
| | 30 |
|
| U.S. small cap | 54 |
| | — |
| | — |
| | 54 |
| 22 |
| | — |
| | — |
| | 22 |
|
| Fixed income securities (1): | | | | | | | | | | | | | | |
| U.S. Treasury securities | 103 |
| | — |
| | — |
| | 103 |
| 157 |
| | — |
| | — |
| | 157 |
|
| Government and municipal bonds | — |
| | 15 |
| | — |
| | 15 |
| — |
| | 21 |
| | — |
| | 21 |
|
| Mortgage and asset-backed securities | — |
| | 47 |
| | — |
| | 47 |
| — |
| | 48 |
| | — |
| | 48 |
|
| Corporate bonds | — |
| | 158 |
| | — |
| | 158 |
| — |
| | 210 |
| | — |
| | 210 |
|
| Insurance company investment contracts and other | — |
| | 5 |
| | — |
| | 5 |
| — |
| | 6 |
| | — |
| | 6 |
|
| | $ | 236 |
| | $ | 225 |
| | $ | — |
| | 461 |
| $ | 219 |
| | $ | 285 |
| | $ | — |
| | 504 |
|
| Commingled investment funds measured at net asset value practical expedient (2): | | | | | | | | | | | | | | |
| Equities — U.S. large cap | | | | | | | 265 |
| | | | | | | 123 |
|
| Equities — International small cap | | | | | | | 26 |
| | | | | | | 8 |
|
| Equities — International emerging markets | | | | | | | 41 |
| | | | | | | 19 |
|
| Equities — International developed markets | | | | | | | 110 |
| | | | | | | 51 |
|
| Fixed income — U.S. long duration | | | | | | | 205 |
| | | | | | | 335 |
|
| Fixed income — Corporate bonds | | | | | | | 119 |
| | | | | | | 92 |
|
| Total assets at fair value at December 31, 2017 | | | | | | | $ | 1,227 |
| |
| Total assets at fair value at December 31, 2018 | | | | | | | | $ | 1,132 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
| | | | 2016 | 2017 |
| | 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 |
| $ | 17 |
| | $ | — |
| | $ | — |
| | $ | 17 |
|
| Equity securities: | | | | | | | | | | | | | | |
| U.S. large cap | 87 |
| | — |
| | — |
| | 87 |
| 62 |
| | — |
| | — |
| | 62 |
|
| U.S. small cap | 77 |
| | — |
| | — |
| | 77 |
| 54 |
| | — |
| | — |
| | 54 |
|
| Fixed income securities (1): | | | | | | | | | | | | | | |
| U.S. Treasury securities | 68 |
| | — |
| | — |
| | 68 |
| 103 |
| | — |
| | — |
| | 103 |
|
| Government and municipal bonds | — |
| | 10 |
| | — |
| | 10 |
| — |
| | 15 |
| | — |
| | 15 |
|
| Mortgage and asset-backed securities | — |
| | 80 |
| | — |
| | 80 |
| — |
| | 47 |
| | — |
| | 47 |
|
| Corporate bonds | — |
| | 148 |
| | — |
| | 148 |
| — |
| | 158 |
| | — |
| | 158 |
|
| Insurance company investment contracts and other | — |
| | 5 |
| | — |
| | 5 |
| — |
| | 5 |
| | — |
| | 5 |
|
| | $ | 246 |
| | $ | 243 |
| | $ | — |
| | 489 |
| $ | 236 |
| | $ | 225 |
| | $ | — |
| | 461 |
|
| Commingled investment funds measured at net asset value practical expedient (2): | | | | | | | | | | | | | | |
| Equities — U.S. large cap | | | | | | | 369 |
| | | | | | | 265 |
|
| Equities — International small cap | | | | | | | 27 |
| | | | | | | 26 |
|
| Equities — International emerging markets | | | | | | | 50 |
| | | | | | | 41 |
|
| Equities — International developed markets | | | | | | | 149 |
| | | | | | | 110 |
|
| Fixed income — U.S. long duration | | | | | | | 88 |
| | | | | | | 205 |
|
| Fixed income — Corporate bonds | | | | | | | 82 |
| | | | | | | 119 |
|
| Total assets at fair value at December 31, 2016 | | | | | | | $ | 1,254 |
| |
| Total assets at fair value at December 31, 2017 | | | | | | | | $ | 1,227 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
The fair values of our other postretirement benefits plan assets at December 31, 20172018 and 20162017 by asset class are as follows:
| | | | 2017 | 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 | 25 |
| | — |
| | — |
| | 25 |
| 20 |
| | — |
| | — |
| | 20 |
|
| U.S. small cap | 14 |
| | — |
| | — |
| | 14 |
| 9 |
| | — |
| | — |
| | 9 |
|
| International developed markets large cap growth | — |
| | 6 |
| | — |
| | 6 |
| — |
| | 5 |
| | — |
| | 5 |
|
| Fixed income securities (1): | | | | | | | | | | | | | | |
| U.S. Treasury securities | 12 |
| | — |
| | — |
| | 12 |
| 19 |
| | — |
| | — |
| | 19 |
|
| Government and municipal bonds | — |
| | 2 |
| | — |
| | 2 |
| — |
| | 2 |
| | — |
| | 2 |
|
| Mortgage and asset-backed securities | — |
| | 5 |
| | — |
| | 5 |
| — |
| | 6 |
| | — |
| | 6 |
|
| Corporate bonds | — |
| | 19 |
| | — |
| | 19 |
| — |
| | 25 |
| | — |
| | 25 |
|
| Mutual fund — Municipal bonds | 43 |
| | — |
| | — |
| | 43 |
| 43 |
| | — |
| | — |
| | 43 |
|
| | $ | 105 |
| | $ | 32 |
| | $ | — |
| | 137 |
| $ | 102 |
| | $ | 38 |
| | $ | — |
| | 140 |
|
| Commingled investment funds measured at net asset value practical expedient (2): | | | | | | | | | | | | | | |
| Equities — U.S. large cap | | | | | | | 31 |
| | | | | | | 14 |
|
| Equities — International small cap | | | | | | | 3 |
| | | | | | | 1 |
|
| Equities — International emerging markets | | | | | | | 5 |
| | | | | | | 2 |
|
| Equities — International developed markets | | | | | | | 13 |
| | | | | | | 6 |
|
| Fixed income — U.S. long duration | | | | | | | 24 |
| | | | | | | 40 |
|
| Fixed income — Corporate bonds | | | | | | | 14 |
| | | | | | | 11 |
|
| Total assets at fair value at December 31, 2017 | | | | | | | $ | 227 |
| |
| Total assets at fair value at December 31, 2018 | | | | | | | | $ | 214 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
| | | | 2016 | 2017 |
| | 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 | 24 |
| | — |
| | — |
| | 24 |
| 25 |
| | — |
| | — |
| | 25 |
|
| U.S. small cap | 15 |
| | — |
| | — |
| | 15 |
| 14 |
| | — |
| | — |
| | 14 |
|
| International developed markets large cap growth | — |
| | 5 |
| | — |
| | 5 |
| — |
| | 6 |
| | — |
| | 6 |
|
| Fixed income securities (1): | | | | | | | | | | | | | | |
| U.S. Treasury securities | 7 |
| | — |
| | — |
| | 7 |
| 12 |
| | — |
| | — |
| | 12 |
|
| Government and municipal bonds | — |
| | 1 |
| | — |
| | 1 |
| — |
| | 2 |
| | — |
| | 2 |
|
| Mortgage and asset-backed securities | — |
| | 8 |
| | — |
| | 8 |
| — |
| | 5 |
| | — |
| | 5 |
|
| Corporate bonds | — |
| | 15 |
| | — |
| | 15 |
| — |
| | 19 |
| | — |
| | 19 |
|
| Mutual fund — Municipal bonds | 42 |
| | — |
| | — |
| | 42 |
| 43 |
| | — |
| | — |
| | 43 |
|
| | $ | 99 |
| | $ | 29 |
| | $ | — |
| | 128 |
| $ | 105 |
| | $ | 32 |
| | $ | — |
| | 137 |
|
| Commingled investment funds measured at net asset value practical expedient (2): | | | | | | | | | | | | | | |
| Equities — U.S. large cap | | | | | | | 38 |
| | | | | | | 31 |
|
| Equities — International small cap | | | | | | | 3 |
| | | | | | | 3 |
|
| Equities — International emerging markets | | | | | | | 5 |
| | | | | | | 5 |
|
| Equities — International developed markets | | | | | | | 16 |
| | | | | | | 13 |
|
| Fixed income — U.S. long duration | | | | | | | 9 |
| | | | | | | 24 |
|
| Fixed income — Corporate bonds | | | | | | | 9 |
| | | | | | | 14 |
|
| Total assets at fair value at December 31, 2016 | | | | | | | $ | 208 |
| |
| Total assets at fair value at December 31, 2017 | | | | | | | | $ | 227 |
|
| | | | | | | | | | | | | | | |
____________
| |
| (1) | The weighted-average credit quality rating of the fixed income security portfolio is investment grade with a weighted-average duration of approximately 13 years for 2018 and 12 years for 2017 and 8 years for 2016.2017. |
| |
| (2) | The stated intents of the funds vary based on each commingled fund’s investment objective. These objectives generally include strategies to replicate or outperform various market indices. Certain standard withdrawal restrictions generally apply, which may include redemption notification period restrictions ranging from 10 days to 30 days. Additionally, the fund managers retain the right to restrict withdrawals from and/or purchases into the funds so as not to disadvantage other investors in the funds. Generally, the funds also reserve the right to make all or a portion of the redemption in-kind rather than in cash or a combination of cash and in-kind. |
The fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement of an asset.
Shares of the cash management funds and mutual funds are valued at fair value based on published market prices as of the close of business on the last business day of the year, which represents the net asset values of the shares held.
The fair values of equity securities traded on U.S. exchanges are derived from quoted market prices as of the close of business on the last business day of the year. The fair values of equity securities traded on foreign exchanges are also derived from quoted market prices as of the close of business on an active foreign exchange on the last business day of the year. However, the valuation requires translation of the foreign currency to U.S. dollars and this translation is considered an observable input to the valuation.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
day of the year. However, the valuation requires translation of the foreign currency to U.S. dollars and this translation is considered an observable input to the valuation.
The fair values of all commingled investment funds are determined based on the net asset values per unit of each of the funds. The net asset values per unit represent the aggregate values of the funds’ assets at fair value less liabilities, divided by the number of units outstanding.
The fair values of fixed income securities, except U.S. Treasury securities, are determined using pricing models. These pricing models incorporate observable inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads for similar securities to determine fair value. The U.S. Treasury securities are valued at fair value based on closing prices on the last business day of the year reported in the active market in which the security is traded.
There have been no significant changes in the preceding valuation methodologies used at December 31, 20172018 and 2016.2017. Additionally, there were no transfers or reclassifications of investments between Level 1 and Level 2 from December 20162017 to December 2017.2018. If transfers between levels had occurred, the transfers would have been recognized as of the end of the period.
Plan Benefit Payments and Employer Contributions
Following are the expected benefits to be paid by the plans. These estimates are based on the same assumptions previously discussed and reflect future service as appropriate. The actuarial assumptions are based on long-term expectations and include, but are not limited to, assumptions as to average expected retirement age and form of benefit payment. Actual benefit payments could differ significantly from expected benefit payments if near-term participant behaviors differ significantly from the actuarial assumptions.
| | | | Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits |
| | (Millions) | (Millions) |
| 2018 | $ | 91 |
| | $ | 13 |
| |
| 2019 | 90 |
| | 13 |
| $ | 85 |
| | $ | 14 |
|
| 2020 | 92 |
| | 14 |
| 87 |
| | 14 |
|
| 2021 | 96 |
| | 13 |
| 90 |
| | 13 |
|
| 2022 | 96 |
| | 13 |
| 90 |
| | 14 |
|
| 2023-2027 | 486 |
| | 60 |
| |
| 2023 | | 89 |
| | 14 |
|
| 2024-2028 | | 467 |
| | 59 |
|
In 2018,2019, we expect to contribute approximately $80$60 million to our tax-qualified pension plans and approximately $5$3 million to our nonqualified pension plans, for a total of approximately $85$63 million, and approximately $6 million to our other postretirement benefit plans.
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 $35 million in 2018, $34 million in 2017, and $36 million in 2016, and $39 million in 2015.2016.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Note 1011 – 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, |
| 2017 |
| 2016 | 2018 |
| 2017 |
| | | | | | (Millions) | | | | | (Millions) |
| Nonregulated: | | | | | | | | |
Natural gas gathering and processing facilities (2) | 5 - 40 | | $ | 18,440 |
| | $ | 19,523 |
| 5 - 40 | | $ | 15,324 |
| | $ | 18,440 |
|
| Construction in progress | Not applicable | | 566 |
| | 412 |
| Not applicable | | 778 |
| | 566 |
|
| Other (2) | 2 - 45 | | 2,776 |
| | 3,092 |
| |
| Other | | 2 - 45 | | 2,356 |
| | 2,776 |
|
| Regulated: | | | | | | | | |
| Natural gas transmission facilities | | 1.20 - 6.97 | | 14,460 |
| | 12,692 |
| | 1.20 - 6.97 | | 17,312 |
| | 14,460 |
|
| Construction in progress | Not applicable | | Not applicable | | 1,637 |
| | 1,603 |
| Not applicable | | Not applicable | | 965 |
| | 1,637 |
|
| Other | 5 - 45 | | 1.35 - 33.33 | | 1,634 |
| | 1,590 |
| 5 - 45 | | 1.35 - 33.33 | | 1,926 |
| | 1,634 |
|
| Total property, plant, and equipment, at cost | | 39,513 |
| | 38,912 |
| | 38,661 |
| | 39,513 |
|
| Accumulated depreciation and amortization | | (11,302 | ) | | (10,484 | ) | | (11,157 | ) | | (11,302 | ) |
| Property, plant, and equipment — net | | $ | 28,211 |
| | $ | 28,428 |
| | $ | 27,504 |
| | $ | 28,211 |
|
__________
| |
| (1) | Estimated useful life and depreciation rates are presented as of December 31, 2017.2018. Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC. |
| |
(2) | The 2016 presentation has been changed to reflect $890 million of right-of-way assets previously presented in Natural gas gathering and processing facilities, now in Other.
|
Depreciation and amortization expense for Property, plant, and equipment – net was $1.392 billion, $1.389 billion, and $1.407 billion in 2018, 2017, and $1.382 billion in 2017, 2016, and 2015, respectively.
Regulated Property, plant, and equipment – net includes approximately $626$586 million and $665$626 million at December 31, 20172018 and 2016,2017, respectively, related to amounts in excess of the original cost of the regulated facilities within our gas pipeline businesses as a result of our prior acquisitions. This amount is being amortized over 40 years using the straight-line amortization method. Current FERC policy does not permit recovery through rates for amounts in excess of original cost of construction.
Asset Retirement Obligations
Our accrued obligations relate to underground storage caverns, offshore platforms and pipelines, fractionation and compression facilities, gas gathering well connections and pipelines, and gas transmission pipelines and facilities. At the end of the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any related surface equipment, to restore land and remove surface equipment at gas processing, fractionation, and compression facilities, to dismantle offshore platforms and appropriately abandon offshore pipelines, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
The following table presents the significant changes to our ARO, of which $946$968 million and $801$946 million are included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued liabilities at December 31, 20172018 and 2016,2017, respectively.
| | | | December 31, | December 31, |
| | 2017 | | 2016 | 2018 | | 2017 |
| | (Millions) | (Millions) |
| Beginning balance | $ | 862 |
| | $ | 915 |
| $ | 998 |
| | $ | 862 |
|
| Liabilities incurred | 33 |
| | 24 |
| 21 |
| | 33 |
|
| Liabilities settled | (16 | ) | | (8 | ) | (19 | ) | | (16 | ) |
| Accretion expense (1) | 141 |
| | 69 |
| 71 |
| | 141 |
|
| Revisions (2) | (22 | ) | | (138 | ) | (39 | ) | | (22 | ) |
| Ending balance | $ | 998 |
| | $ | 862 |
| $ | 1,032 |
| | $ | 998 |
|
___________
| |
| (1) | The increasedecrease in accretion expense forin 2018 primarily reflects the absence of a 2017 includes an adjustment associated with obligations identified from certain Transco land agreements. |
| |
| (2) | Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2018 revisions reflect changes in removal cost estimates, decreases in the estimated remaining useful life of certain assets and increases in the discount rates used in the annual review process. The 2017 revisions reflect changes in removal cost estimates and decreases in the estimated remaining useful life of certain assets and discount rates used in the annual review process. The 2016 revisions reflect changes in removal cost estimates, increases in the estimated remaining useful life of certain assets, and decreases in the inflation rate and discount rates used in the annual review process. |
The funds Transco collects through a portion of its rates to fund its ARO are deposited into an external trust account dedicated to funding its ARO (ARO Trust). (See Note 1617 – 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 1112 – Goodwill and Other Intangible Assets
Goodwill
At December 31, 2017, 2016, and 2015, our Consolidated Balance Sheet includes $47 million of goodwill in Intangible assets – net of accumulated amortization, reported in the Williams Partners segment. Our goodwill is not subject to amortization, but is evaluated at least annually for impairment or more frequently if impairment indicators are present. We did not identify or recognize any impairments to goodwill in connection with our annual evaluation of goodwill for impairment (performed as of October 1) during the years ended December 31, 2017 and 2016. During 2015, we performed an interim assessment and an annual assessment as of September 30, 2015 and October 1, 2015, respectively, of certain goodwill within the Williams Partners segment. The estimated fair value of the reporting units evaluated exceeded their carrying amounts, and thus no impairment was identified. We performed an additional goodwill impairment evaluation as of December 31, 2015, of the goodwill recorded within the Williams Partners segment. As a result of this evaluation, we recorded goodwill impairment charges totaling $1.098 billion. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.)
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
Other Intangible Assets
The gross carrying amount and accumulated amortization of other intangible assets, included in Intangible assets – net of accumulated amortization, at December 31 are as follows:
|
| | | | | | | | | | | | | | | |
| | 2017 | | 2016 |
| | Gross Carrying Amount | | Accumulated Amortization | | Gross Carrying Amount | | Accumulated Amortization |
| | (Millions) |
| Contractual customer relationships | $ | 10,027 |
| | $ | (1,283 | ) | | $ | 10,635 |
| | $ | (1,019 | ) |
|
| | | | | | | | | | | | | | | |
| | 2018 | | 2017 |
| | Gross Carrying Amount | | Accumulated Amortization | | Gross Carrying Amount | | Accumulated Amortization |
| | (Millions) |
| Contractual customer relationships | $ | 9,232 |
| | $ | (1,465 | ) | | $ | 10,027 |
| | $ | (1,283 | ) |
Other intangible assets primarily relate to gas gathering, processing, and fractionation contractual customer relationships recognized in acquisitions including ACMP and Eagle Ford (see Note 2 – Acquisitions and Divestitures).acquisitions. The decrease in the gross carrying amount of other intangible assets during 20172018 is primarily related to the impairment of certain gathering operationsassets located in the Mid-ContinentBarnett Shale and Marcellus South regionsthe deconsolidation of our interest in Jackalope (see Note 1617 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk)Risk and Note 6 – Investing Activities, respectively). The write-off of accumulated amortization related to the impaired assets isThese decreases are the primary reasonreasons for the difference between the change in accumulated amortization during 20172018 indicated above and the amortization expense for 20172018 noted below. Other intangible assets are being amortized on a straight-line basis over an initial period of 30 years which represents a portion of the term over which the contractual customer relationships are expected to contribute to our cash flows.
We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts with customers. Basedcustomers based on the estimated future revenues during the contract periods (as estimated at the time of the acquisition), the(the weighted-average periodperiods prior to the next renewal or extension of the associated contractual customer relationships associated withas estimated at the Eagle Ford acquisition was approximately 10 years.time of the
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
acquisition). Although a significant portion of the expected future cash flows associated with these contractual customer relationships are dependent on our ability to renew or extend the arrangements beyond the initial contract periods, these expected future cash flows are significantly influenced by the scope and pace of our producer customers’ drilling programs. Once producer customers’ wells are connected to our gathering infrastructure, their likelihood of switching to another provider before the wells are abandoned is reduced due to the significant capital investment required.
The amortization expense related to other intangible assets was $333 million, $347 million, and $356 million in 2018, 2017, and $353 million in 2017, 2016, and 2015, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $337$312 million.
Note 1213 – Accrued Liabilities
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | (Millions) |
| Deferred income | $ | 361 |
| | $ | 338 |
|
| Interest on debt | 267 |
| | 310 |
|
| Employee costs | 202 |
| | 223 |
|
| Refundable deposits | — |
| | 160 |
|
| Property taxes | 63 |
| | 55 |
|
| Asset retirement obligations | 53 |
| | 61 |
|
| Other, including other loss contingencies | 221 |
| | 301 |
|
| | $ | 1,167 |
| | $ | 1,448 |
|
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| | (Millions) |
| Interest on debt | $ | 282 |
| | $ | 267 |
|
| Revenue contract liabilities (Note 2) | 244 |
| | 361 |
|
| Employee costs | 205 |
| | 202 |
|
| Other, including other loss contingencies | 371 |
| | 337 |
|
| | $ | 1,102 |
| | $ | 1,167 |
|
Deferred income includes cash proceeds associated with restructuring certain gas gathering contracts in the Barnett Shale and Mid-Continent regions. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
Refundable deposits in 2016 includes receipts related to an agreement to resolve several matters in relation to Transco’s Hillabee Expansion Project. In accordance with the agreement, the member–sponsors of Sabal Trail paid WPZ an aggregate amount of $240 million in three equal installments as certain milestones of the project were met. During the third quarter of 2017 WPZ received the final installment and placed the project into service. As a result of placing the project into service, WPZ reclassified the Refundable deposits to Accrued liabilities and Regulatory liabilities, deferred income, and other and expects to recognize income associated with these receipts over the term of an underlying contract.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Note 1314 – Debt, Banking Arrangements, and Leases
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | (Millions) |
| Transco: | | | |
| 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 |
| | 1,000 |
|
| 5.4% Notes due 2041 | 375 |
| | 375 |
|
| 4.45% Notes due 2042 | 400 |
| | 400 |
|
| Other financing obligation | 231 |
| | — |
|
| Northwest Pipeline: |
| | |
| 5.95% Notes due 2017 | — |
| | 185 |
|
| 6.05% Notes due 2018 | 250 |
| | 250 |
|
| 7.125% Debentures due 2025 | 85 |
| | 85 |
|
| 4% Notes due 2027 | 250 |
| | — |
|
| WPZ: | | | |
| 7.25% Notes due 2017 | — |
| | 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 |
|
| 4.5% Notes due 2023 | 600 |
| | 600 |
|
| 4.875% Notes due 2023 | — |
| | 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 |
|
| 3.75% Notes due 2027 | 1,450 |
| | — |
|
| 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 |
|
| 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 |
|
| 7.75% Notes due 2031 | 252 |
| | 252 |
|
| 8.75% Notes due 2032 | 445 |
| | 445 |
|
| 5.75% Notes due 2044 | 650 |
| | 650 |
|
| Various — 7.625% to 10.25% Notes and Debentures due 2019 to 2027 | 55 |
| | 55 |
|
| Credit facility loans | 270 |
| | 775 |
|
| Debt issuance costs | (122 | ) | | (119 | ) |
| Net unamortized debt premium (discount) | (24 | ) | | 88 |
|
| Total long-term debt, including current portion | 20,935 |
| | 23,409 |
|
| Long-term debt due within one year | (501 | ) | | (785 | ) |
| Long-term debt | $ | 20,434 |
| | $ | 22,624 |
|
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| | (Millions) |
| Transco: | | | |
| 6.05% Notes due 2018 | $ | — |
| | $ | 250 |
|
| 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 |
| | — |
|
| 5.4% Notes due 2041 | 375 |
| | 375 |
|
| 4.45% Notes due 2042 | 400 |
| | 400 |
|
| 4.6% Notes due 2048 | 600 |
| | — |
|
| Other financing obligations | 1,067 |
| | 231 |
|
| Northwest Pipeline: |
| | |
| 6.05% Notes due 2018 | — |
| | 250 |
|
| 7.125% Debentures due 2025 | 85 |
| | 85 |
|
| 4% Notes due 2027 | 500 |
| | 250 |
|
| 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 |
|
| 4.875% Notes due 2024 | — |
| | 750 |
|
| 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 |
| | — |
|
| Various — 7.625% to 10.25% Notes and Debentures due 2019 to 2027 | 55 |
| | 55 |
|
| Credit facility loans | 160 |
| | 270 |
|
| Debt issuance costs | (131 | ) | | (122 | ) |
| Net unamortized debt premium (discount) | (62 | ) | | (24 | ) |
| Total long-term debt, including current portion | 22,414 |
| | 20,935 |
|
| Long-term debt due within one year | (47 | ) | | (501 | ) |
| Long-term debt | $ | 22,367 |
| | $ | 20,434 |
|
Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, sell assets, and incur additional debt. Default of these agreements could also restrict our ability to make certain distributions or repurchase equity.
|
| | | | |
| 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, 2017 | December 31, 2018 |
| | (Millions) | (Millions) |
| 2018 | $ | 502 |
| |
| 2019 | 33 |
| $ | 47 |
|
| 2020 | 2,123 |
| 2,138 |
|
| 2021 | 1,143 |
| 890 |
|
| 2022 | 2,003 |
| 2,021 |
|
| 2023 | | 1,633 |
|
Issuances and retirements
On August 24, 2018, Northwest Pipeline issued $250 million of 4 percent senior unsecured notes to investors in a private debt placement. The notes are an additional issuance of Northwest Pipeline’s existing 4 percent senior unsecured notes due 2027. In the fourth quarter of 2018, Northwest Pipeline filed a registration statement and completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.
Northwest Pipeline retired $250 million of 6.05 percent senior unsecured notes that matured on June 15, 2018.
On March 5, 2018, WPZ completed a public offering of $800 million of 4.85 percent senior unsecured notes due 2048. WPZ used the net proceeds for general partnership purposes, primarily the March 28, 2018 repayment of $750 million of 4.875 percent senior unsecured notes that were due in 2024.
On March 15, 2018, Transco issued $400 million of 4 percent senior unsecured notes due 2028 and $600 million of 4.6 percent senior unsecured notes due 2048 to investors in a private debt placement. Transco used the net proceeds to retire $250 million of 6.05 percent senior unsecured notes that matured on June 15, 2018, and for general corporate purposes, including the funding of capital expenditures. In the third quarter of 2018, Transco filed a registration statement and completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.
On July 6, 2017, WPZ repaid its $850 million variable interest rate term loan that was due December 2018 using proceeds from the sale of its Geismar Interest.
On June 5, 2017, WPZ issued $1.45 billion of 3.75 percent senior unsecured notes due 2027. WPZ used the proceeds for general partnership purposes, primarily the July 3, 2017 repayment of $1.4 billion of 4.875 percent senior unsecured notes that were due in 2023.
On April 3, 2017, Northwest Pipeline issued $250 million of 4.04 percent senior unsecured notes due 2027 to investors in a private debt placement. Northwest Pipeline used the net proceeds to retire $185 million of 5.95 percent senior unsecured notes that matured on April 15, 2017, and for general corporate purposes. As partIn the first quarter of the issuance,2018, Northwest Pipeline entered into a registration rights agreement with the initial purchaserscompleted an exchange of the unsecured notes. Under the terms of the agreement, Northwest Pipeline was obligated to file and consummate a registration statement for an offer to exchange thethese notes for a new issue of substantially identical new notes that are registered under the Securities Act of 1933, as amended, within 365 days from closing and to use commercially reasonable efforts to complete the exchange offer. Northwest Pipeline has filed the registration statement, which became effective in January 2018. The exchange offer is expected to be completed in the first quarter of 2018.amended.
On February 23, 2017, using proceeds received from the Financial Repositioning (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies), WPZ early retired $750 million of 6.125 percent senior unsecured notes that were due in 2022.
WPZ retired $600 million of 7.25 percent senior unsecured notes that matured on February 1, 2017.
Northwest Pipeline retired $175 million of 7 percent senior unsecured notes that matured on June 15, 2016.
Transco retired $200 million of 6.4 percent senior unsecured notes that matured on April 15, 2016.
On January 22, 2016, Transco issued $1 billion of 7.85 percent senior unsecured notes due 2026 to investors in a private debt placement. In January 2017, Transco completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended. Transco used the net proceeds to repay debt and to fund capital expenditures.
Other financing obligation
During the construction of Transco’s Dalton expansion project, WPZ received funding from a partner for its proportionate share of construction costs related to its undivided ownership interest in the project. Amounts received were recorded within noncurrent liabilities and 100 percent of the costs associated with construction were capitalized
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
on our Consolidated Balance Sheet. Upon placing the project in service during the third quarter of 2017, WPZ began leasing this partner’s undivided interest in the lateral, including the associated pipeline capacity, and reclassified approximately $237 million of funding previously received from its partner from noncurrent liabilities to debt to reflect the financing obligation payable to its partner over an expected term of 35 years.
|
| | | | | | | |
| | December 31, 2017 |
| | Available | | Outstanding |
| | (Millions) |
| WMB | | | |
| Long-term credit facility | $ | 1,500 |
| | $ | 270 |
|
| 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 |
|
________________
| |
(1) | In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. |
WMB long-term credit facility
On February 2, 2015, we entered into the Second Amended and Restated Credit Agreement. The aggregate commitments available remained at $1.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. In November 2017, the maturity date of the credit facility was extended to February 2, 2021. However, we may request an additional extension of the maturity date for a one year period to allow a maturity date as late as February 2, 2022, under certain circumstances. The agreement also allows for swing line loans up to an aggregate amount of $50 million, subject to available capacity under the credit facility, and the letters of credit up to $675 million.
The agreements governing the credit facilities contain the following terms and conditions:
Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, make investments, and allow any material change in the nature of its business.
If an event of default with respect to a borrower occurs under its respective credit facility, the lenders will be able to terminate the commitments for the respective borrowers and accelerate the maturity of any loans of the defaulting borrower under the respective credit facility agreement and exercise other rights and remedies.
Each time funds are borrowed under our credit facility, the borrower may choose from two methods of calculating interest: a fluctuating base rate equal to the bank’s alternate base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus an applicable margin. The borrower is required to pay a commitment fee based on the unused portion of its respective credit facility. The applicable margin and the commitment fee are determined for us by reference to a pricing schedule based on our senior unsecured long-term debt ratings.
Significant financial covenants under the agreement require the ratio of debt to EBITDA (each as defined in the credit agreement) be no greater than 5 to 1, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the ratio of debt to EBITDA is to be no greater than 5.5 to 1.
We are in compliance with these financial covenants as measured at December 31, 2017.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
AsOther financing obligations
During the construction of Februarythe Dalton expansion project, Transco received funding from a partner for its proportionate share of construction costs related to its undivided ownership interest in the project. Amounts received were recorded within noncurrent liabilities and 100 percent of the costs associated with construction were capitalized in our Consolidated Balance Sheet. Upon placing the project in service during the third quarter of 2017, Transco began utilizing this partner’s undivided interest in the lateral, including the associated pipeline capacity, and reclassified the funding previously received from its partner from noncurrent liabilities to debt to reflect the financing obligation payable to its partner over an expected term of 35 years. Amounts related to this financing obligation included in debt within our Consolidated Balance Sheet were $260 million and $231 million at December 31, 2018 and 2017, respectively.
During the construction of the Atlantic Sunrise project, Transco received funding from a partner for its proportionate share of construction costs related to an undivided ownership interest in certain parts of the project. Amounts received were recorded within noncurrent liabilities and 100 percent of the costs associated with construction were capitalized in our Consolidated Balance Sheet. Upon placing the project in service during the fourth quarter of 2018, Transco began utilizing this partner’s undivided interest in the lateral, including the associated pipeline capacity, and reclassified the funding previously received from its partner from noncurrent liabilities to debt to reflect the financing obligation payable to its partner over an expected term of 20 years. At December 31, 2018, there are no amounts outstanding under$807 million related to this financing obligation was included in debt within our long-termConsolidated Balance Sheet.
|
| | | | | | | |
| | December 31, 2018 |
| | Stated Capacity | | Outstanding |
| | (Millions) |
| Long-term credit facility (1) | $ | 4,500 |
| | $ | 160 |
|
| 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. |
Revolving credit facility.
WPZ long-term credit facilitiesfacility
On February 2, 2015, WPZJuly 13, 2018, we along with Transco and Northwest Pipeline, the lenders named therein, and an administrative agent entered into the Second Amended & Restated Credit Agreementa new credit agreement (Credit Agreement) with aggregate commitments available of $3.5$4.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. In November 2017,On August 10, 2018, following the completion of the WPZ Merger, the Credit Agreement became effective and we terminated both our and WPZ’s existing credit facilities. The maturity date of the new credit facility was extended to February 2, 2021.is August 10, 2023. However, the co-borrowers may request an additional extensionup to two extensions of the maturity date each for a one yearan additional one-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 new 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.
The agreement governing this credit facilityCredit Agreement contains the following terms and conditions:
Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, 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.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
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 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 periodLondon Interbank Offered Rate 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 5.00than:
5.75 to 1 for each fiscal quarter end through June 30, 2019;
5.5 to 1 for the fiscal quarters ending September 30, 2019, and December 31, 2019;
5.0 to 1 for the fiscal quarter ending March 31, 2020, and each subsequent fiscal quarter end, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions with a total aggregate purchase price of $25 million or more has been executed, in which case the ratio of debt to EBITDA is to be no greater than 5.5 to 1.
The ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for each of Transco and Northwest Pipeline. WPZ is
At December 31, 2018, we are in compliance with these financial covenants as measured at December 31, 2017.
As of February 20, 2018, there are no amounts outstanding under the WPZ long-term credit facility.covenants.
Commercial Paper Program
On February 2, 2015,August 10, 2018, following the consummation of the WPZ amended and restated theMerger, WPZ’s $3 billion commercial paper program for the ACMP Mergerwas discontinued and to allowwe entered into a maximum outstanding amount of unsecurednew $4 billion 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.for other general corporate purposes. At December 31, 2018 and 2017, no Commercial paper was outstanding. At February 19, 2019, no commercial paper was outstanding.
Cash Payments for Interest (Net of Amounts Capitalized)
Cash payments for interest (net of amounts capitalized)were $1.064 billion in 2018, $1.110 billion in 2017, and $1.152 billion in 2016.
Leases-Lessee
The future minimum annual rentals under noncancelable operating leases, are payable as follows:
|
| | | |
| | December 31, 2018 |
| | (Millions) |
| 2019 | $ | 32 |
|
| 2020 | 31 |
|
| 2021 | 28 |
|
| 2022 | 24 |
|
| 2023 | 15 |
|
| Thereafter | 86 |
|
| Total | $ | 216 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
December 31, 2017, WPZ had no Commercial paper outstanding. At December 31, 2016, WPZ had $93 million of Commercial paper outstanding at a weighted-average interest rate of 1.06 percent, which was classified in Current liabilities in the Consolidated Balance Sheet, as the outstanding notes had maturity dates less than three months from the date of issuance.
Cash Payments for Interest (Net of Amounts Capitalized)
Cash payments for interest (net of amounts capitalized)were $1.110 billion in 2017, $1.152 billion in 2016, and $1.023 billion in 2015.
Restricted Net Assets of Subsidiaries
We have considered the guidance in the Securities and Exchange Commission’s Regulation S-X related to restricted net assets of subsidiaries. In accordance with Rule 4-08(e) of Regulation S-X, we have determined that certain net assets of our subsidiaries are considered restricted under this guidance and exceed 25 percent of our consolidated net assets. As of December 31, 2017, substantially all of these restricted net assets relate to the net assets of WPZ, which are technically considered restricted under this accounting rule due to terms within WPZ’s partnership agreement that govern the partnerships’ assets. Our interest in WPZ’s net assets that are considered to be restricted at December 31, 2017, was $16 billion.
Leases-Lessee
The future minimum annual rentals under noncancelable operating leases, are payable as follows:
|
| | | |
| | December 31, 2017 |
| | (Millions) |
| 2018 | $ | 43 |
|
| 2019 | 41 |
|
| 2020 | 33 |
|
| 2021 | 33 |
|
| 2022 | 29 |
|
| Thereafter | 137 |
|
| Total | $ | 316 |
|
Total rent expense was $73 million in 2018, $62 million in 2017, and $64 million in 2016 and $69 million in 2015 and primarily included in Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement of Operations.
Note 1415 – Stockholders' Equity
Cash dividends declared per common share were $1.20, $1.68, and $2.45 for 2017, 2016, and 2015, respectively. On February 21, 2018,20, 2019, our board of directors approved a regular quarterly dividend of $0.34$0.38 per share payable on March 26,25, 2019.
In July 2018, through a wholly owned subsidiary, we contributed 35,000 shares of newly issued Series B Non-Voting Perpetual Preferred Stock (Preferred Stock) to The Williams Companies Foundation, Inc. (a not-for-profit corporation) for use in future charitable and nonprofit causes. The charitable contribution of Preferred Stock was recorded as an expense in the third quarter of 2018. The Preferred Stock was issued for an aggregate value of $35 million and pays non-cumulative quarterly cash dividends when, as and if declared, at a rate of 7.25 percent per year. We paid dividends totaling $1.1 million on the shares of Preferred Stock in 2018. Our certificate of incorporation authorizes 30 million shares of Preferred Stock, $1 par value per share.
In January 2017, we issued 65 million shares of common stock in a public offering at a price of $29.00 per share. In February 2017, we issued 9.75 million shares of common stock pursuant to the full exercise of the underwriter’s option to purchase additional shares. The net proceeds of approximately $2.1 billion were used to purchase newly issued common units in WPZ as part of our Financial Repositioning. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)
AOCI
The following table presents the changes in AOCI by component, net of income taxes:
|
| | | | | | | | | | | | | | | |
| | Cash Flow Hedges | | Foreign Currency Translation | | Pension and Other Post Retirement Benefits | | Total |
| | (Millions) |
| Balance at December 31, 2017 | $ | (2 | ) | | $ | (1 | ) | | $ | (235 | ) | | $ | (238 | ) |
| Adoption of new accounting standard (Note 1) | — |
| | — |
| | (61 | ) | | (61 | ) |
| WPZ Merger (Note 1) | (3 | ) | | — |
| | — |
| | (3 | ) |
| Other comprehensive income (loss): | | | | | | | |
Other comprehensive income (loss) before reclassifications | (2 | ) | | — |
| | (6 | ) | | (8 | ) |
Amounts reclassified from accumulated other comprehensive income (loss) | 5 |
| | — |
| | 35 |
| | 40 |
|
| Other comprehensive income (loss) | 3 |
| | — |
| | 29 |
| | 32 |
|
| Balance at December 31, 2018 | $ | (2 | ) | | $ | (1 | ) | | $ | (267 | ) | | $ | (270 | ) |
|
| | | | |
| 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, 2016 | $ | — |
| | $ | (2 | ) | | $ | (337 | ) | | $ | (339 | ) |
Other comprehensive income (loss) before reclassifications | (6 | ) | | 1 |
| | 44 |
| | 39 |
|
Amounts reclassified from accumulated other comprehensive income (loss) | 4 |
| | — |
| | 58 |
| | 62 |
|
| Other comprehensive income (loss) | (2 | ) | | 1 |
| | 102 |
| | 101 |
|
| Balance at December 31, 2017 | $ | (2 | ) | | $ | (1 | ) | | $ | (235 | ) | | $ | (238 | ) |
Reclassifications out of AOCI are presented in the following table by component for the year ended December 31, 2017:2018:
| | | Component | | Reclassifications | | Classification | | Reclassifications | | Classification |
| | | (Millions) | | | (Millions) | |
| Cash flow hedges: | | | | | | |
| Energy commodity contracts | | $ | 7 |
| | Product sales and Product costs | | $ | 9 |
| | Product sales |
| Pension and other postretirement benefits: | | | | | | |
| Amortization of prior service cost (credit) included in net periodic benefit cost (credit) | | (5 | ) | | Note 9 – Employee Benefit Plans | |
| Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit) | | 98 |
| | Note 9 – Employee Benefit Plans | | 46 |
| | Note 10 – Employee Benefit Plans |
| Total before tax | | 100 |
| | | 55 |
| |
| Income tax benefit | | (36 | ) | | Provision (benefit) for income taxes | | (12 | ) | | Provision (benefit) for income taxes |
| Net of income tax | | 64 |
| | | 43 |
| |
| Noncontrolling interest | | (2 | ) | | Net income (loss) attributable to noncontrolling interests | | (3 | ) | | Net income (loss) attributable to noncontrolling interests |
| Reclassifications during the period | | $ | 62 |
| | | $ | 40 |
| |
Note 1516 – Equity-Based Compensation
Williams’ Plan Information
On May 17, 2007, our stockholders approved The Williams Companies, Inc. 2007 Incentive Plan (the Plan) that provides common-stock-based awards to both employees and nonmanagement directors and reserved 19 million new shares for issuance. On May 20, 2010 and May 22, 2014, our stockholders approved amendments and restatements of the Plan to increase by 11 million and 10 million, respectively, the number of new shares authorized for making awards under the Plan, among other changes. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. At December 31, 2017, 262018, 24 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 1512 million shares were available for future grants.
Additionally, on May 17, 2007, our stockholders approved an Employee Stock Purchase Plan (ESPP) which authorized up to 2 million new shares of our common stock to be available for sale under the ESPP. On May 22, 2014, our stockholders approved an amendment and restatement of the ESPP to increase by 1.6 million the number of new shares authorized for sale under the ESPP. Employees purchased 272338 thousand shares at an average price of $25.83
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
$20.70 per share during 2017.2018. Approximately 1.1 million746 thousand shares were available for purchase under the ESPP at December 31, 2017.2018.
Operating and maintenance expenses and Selling, general, and administrative expenses include equity-based compensation expense for the years ended December 31, 2018, 2017, and 2016 and 2015 of $70$54 million, $5370 million, and $56$53 million, respectively. Income tax benefit recognized related to the stock-based compensation expense for the years ended December 31, 2018, 2017, and 2016 and 2015 was $14 million, $17 million, $20 million, and $21$20 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2017,2018, was $61$56 million, comprised of $4 million related to stock options and $57$52 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.8 years.
Stock Options
The following summary reflects stock option activity and related information for the year ended December 31, 2017:
|
| | | | | | | | | | |
| Stock Options | Options | | Weighted- Average Exercise Price | | Aggregate Intrinsic Value |
| | (Millions) | | | | (Millions) |
| Outstanding at December 31, 2016 | 6.2 |
| | $ | 31.32 |
| | |
| Granted | 1.0 |
| | $ | 28.85 |
| | |
| Exercised | (0.5 | ) | | $ | 21.33 |
| | |
| Cancelled | (0.1 | ) | | $ | 36.75 |
| | |
| Outstanding at December 31, 2017 | 6.6 |
| | $ | 31.53 |
| | $ | 23 |
|
| Exercisable at December 31, 2017 | 5.1 |
| | $ | 31.85 |
| | $ | 19 |
|
The following table summarizes additional information related to stock option activity during each of the last three years:
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (Millions) |
| Total intrinsic value of options exercised | $ | 4 |
| | $ | 2 |
| | $ | 37 |
|
| Tax benefits realized on options exercised | $ | 1 |
| | $ | 1 |
| | $ | 13 |
|
| Cash received from the exercise of options | $ | 7 |
| | $ | 4 |
| | $ | 20 |
|
The weighted-average remaining contractual life for stock options outstanding and exercisable at December 31, 2017, was 5.0 years and 4.0 years, respectively.
The estimated fair value at date of grant of options for our common stock granted in each respective year, using the Black-Scholes option pricing model, is as follows:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Weighted-average grant date fair value of options for our common stock granted during the year, per share | $ | 6.61 |
| | $ | 7.90 |
| | $ | 7.61 |
|
| Weighted-average assumptions: | | | | | |
| Dividend yield | 4.2 | % | | 3.2 | % | | 4.8 | % |
| Volatility | 35.1 | % | | 44.7 | % | | 27.8 | % |
| Risk-free interest rate | 2.1 | % | | 1.2 | % | | 1.8 | % |
| Expected life (years) | 6.0 |
| | 6.0 |
| | 6.0 |
|
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
Stock Options
The 2017following summary reflects stock option activity and related information for the year ended December 31, 2018:
|
| | | | | | | | | | |
| Stock Options | Options | | Weighted- Average Exercise Price | | Aggregate Intrinsic Value |
| | (Millions) | | | | (Millions) |
| Outstanding at December 31, 2017 | 6.6 |
| | $ | 31.53 |
| | |
| Granted | 1.3 |
| | $ | 29.09 |
| | |
| Exercised | (0.4 | ) | | $ | 23.06 |
| | |
| Cancelled | (0.2 | ) | | $ | 31.45 |
| | |
| Outstanding at December 31, 2018 | 7.3 |
| | $ | 31.55 |
| | $ | 6 |
|
| Exercisable at December 31, 2018 | 5.3 |
| | $ | 32.63 |
| | $ | 6 |
|
The following table summarizes additional information related to stock option activity during each of the last three years:
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | (Millions) |
| Total intrinsic value of options exercised | $ | 3 |
| | $ | 4 |
| | $ | 2 |
|
| Tax benefits realized on options exercised | $ | — |
| | $ | 1 |
| | $ | 1 |
|
| Cash received from the exercise of options | $ | 9 |
| | $ | 7 |
| | $ | 4 |
|
The weighted-average remaining contractual life for stock options outstanding and exercisable at December 31, 2018, was 5.1 years and 3.7 years, respectively.
The estimated fair value at date of grant of options for our common stock granted in each respective year, using the Black-Scholes option pricing model, is as follows:
|
| | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| Weighted-average grant date fair value of options for our common stock granted during the year, per share | $ | 5.49 |
| | $ | 6.61 |
| | $ | 7.90 |
|
| Weighted-average assumptions: | | | | | |
| Dividend yield | 4.7 | % | | 4.2 | % | | 3.2 | % |
| Volatility | 30.1 | % | | 35.1 | % | | 44.7 | % |
| Risk-free interest rate | 2.7 | % | | 2.1 | % | | 1.2 | % |
| Expected life (years) | 6.0 |
| | 6.0 |
| | 6.0 |
|
The 2018 expected dividend yield is based on the 20172018 dividend forecast and the grant-date market price of our stock. Our expected future volatility is determined using the historical volatility of our stock and implied volatility on our traded options. Historical volatility is based on the blended 10-year historical volatility of our stock and certain peer companies. The risk-free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life of the option is based on historical exercise behavior and expected future experience.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
Nonvested Restricted Stock Units
The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2017:2018:
| | | Restricted Stock Units Outstanding | Shares | | Weighted- Average Fair Value (1) | Shares | | Weighted- Average Fair Value (1) |
| | (Millions) | | | (Millions) | | |
| Nonvested at December 31, 2016 | 3.9 |
| | $ | 35.19 |
| |
| Nonvested at December 31, 2017 | | 4.2 |
| | $ | 31.02 |
|
| Granted | 2.0 |
| | $ | 29.47 |
| 1.7 |
| | $ | 30.48 |
|
| Forfeited | (0.8 | ) | | $ | 39.21 |
| (0.5 | ) | | $ | 32.97 |
|
| Vested | (0.9 | ) | | $ | 38.30 |
| (0.9 | ) | | $ | 39.30 |
|
| Nonvested at December 31, 2017 | 4.2 |
| | $ | 31.02 |
| |
| Nonvested at December 31, 2018 | | 4.5 |
| | $ | 28.96 |
|
______________
| |
| (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.and return on capital employed. All other restricted stock units are valued at the grant-date market price. Restricted stock units generally vest after three years. |
| | | Value of Restricted Stock Units | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| Weighted-average grant date fair value of restricted stock units granted during the year, per share | $ | 29.47 |
| | $ | 26.51 |
| | $ | 40.15 |
| $ | 30.48 |
| | $ | 29.47 |
| | $ | 26.51 |
|
| Total fair value of restricted stock units vested during the year ($’s in millions) | $ | 33 |
| | $ | 32 |
| | $ | 42 |
| |
| Total fair value of restricted stock units vested during the year ($s in millions) | | $ | 35 |
| | $ | 33 |
| | $ | 32 |
|
Performance-based restricted stock units granted under the Plan represent 3134 percent of nonvested restricted stock units outstanding at December 31, 2017.2018. These grants may be earned at the end of the vesting period based on actual performance against a performance target. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original grant amount.
WPZ’s Plan Information
During 2014, certain employees of ACMP’sthe general partner of Access Midstream Partners, L.P. (ACMP) received equity-based compensation through ACMP’s equity-based compensation program. These awards were converted to WPZ equity-based awards in accordance with the terms of the ACMP Merger. NoFebruary 2, 2015 merger of Williams Partners L.P. with and into Access Midstream Partners, L.P (which was subsequently renamed Williams Partners L.P.). During 2018, no additional grants of restricted common units were awarded through WPZ’s equity-based compensation programs, and no additional grants are expected in the future.all outstanding shares were vested and exercised. Equity-based compensation expense of less than $1 million, $8 million, $20 million, and $29$20 million related to WPZ’s equity-based compensation program is included in Operating and maintenance expenses and Selling, general, and administrative expenses for the years ended December 31, 2018, 2017, 2016, and 2015,2016, respectively. The total fair value of the restricted common units vested during 2018, 2017, and 2016 and 2015 was $5 million, $24 million, and $34 million, and $5 million, respectively. As of December 31, 2017, there were 76 thousand nonvested units outstanding and $1 million of unrecognized compensation expense attributable to the outstanding awards which will be recognized in 2018.This plan is no longer active.
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
Note 1617 – 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, 2017: | | | | | | | | | |
| Measured on a recurring basis: | | | | | | | | | |
| ARO Trust investments | $ | 135 |
| | $ | 135 |
| | $ | 135 |
| | $ | — |
| | $ | — |
|
| Energy derivatives liabilities designated as hedging instruments | (3 | ) | | (3 | ) | | (2 | ) | | (1 | ) | | — |
|
| Energy derivatives liabilities not designated as hedging instruments | (3 | ) | | (3 | ) | | — |
| | — |
| | (3 | ) |
| Additional disclosures: | | | | | | | | | |
| Other receivables | 7 |
| | 7 |
| | 7 |
| | — |
| | — |
|
| Long-term debt, including current portion | (20,935 | ) | | (23,005 | ) | | — |
| | (23,005 | ) | | — |
|
| Guarantees | (43 | ) | | (30 | ) | | — |
| | (14 | ) | | (16 | ) |
| | | | | | | | | | |
| 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 | ) |
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
|
| | | | | | | | | | | | | | | | | | | |
| | | | | | 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, 2018: | | | | | | | | | |
| Measured on a recurring basis: | | | | | | | | | |
| ARO Trust investments | $ | 150 |
| | $ | 150 |
| | $ | 150 |
| | $ | — |
| | $ | — |
|
| Energy derivatives assets not designated as hedging instruments | 3 |
| | 3 |
| | 3 |
| | — |
| | — |
|
| Energy derivatives 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 | ) |
| | | | | | | | | | |
| Assets (liabilities) at December 31, 2017: | | | | | | | | | |
| Measured on a recurring basis: | | | | | | | | | |
| ARO Trust investments | $ | 135 |
| | $ | 135 |
| | $ | 135 |
| | $ | — |
| | $ | — |
|
| Energy derivatives liabilities designated as hedging instruments | (3 | ) | | (3 | ) | | (2 | ) | | (1 | ) | | — |
|
| Energy derivatives liabilities not designated as hedging instruments | (3 | ) | | (3 | ) | | — |
| | — |
| | (3 | ) |
| Additional disclosures: | | | | | | | | | |
| Long-term debt, including current portion | (20,935 | ) | | (23,005 | ) | | — |
| | (23,005 | ) | | — |
|
| Guarantees | (43 | ) | | (30 | ) | | — |
| | (14 | ) | | (16 | ) |
Fair Value Methods
We use the following methods and assumptions in estimating the fair value of our financial instruments:
Assets and liabilities measured at fair value on a recurring basis
ARO Trust investments: Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust that is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market is classified as available-for-sale, and is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet.Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.
Energy derivatives: Energy derivatives include commodity-based exchange-traded contracts and over-the-counter contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives assets are reported in Other current assets and deferred charges and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet.Sheet. Energy derivatives liabilities are reported in Accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.Sheet.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the years ended December 31, 20172018 or 20162017.
Additional fair value disclosures
Other receivables: Other receivables consist of margin deposits, which are reported in Other current assets and deferred charges in the Consolidated Balance Sheet. The disclosed fair value of our margin deposits is considered to approximate the carrying value generally due to the short-term nature of these items.
Long-term debt, including current portion: The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair valuevalues of the financing obligationobligations associated with our Dalton lateral and Atlantic Sunrise projects, which isare included within long-term debt, waswere determined using an income approach (see Note 1314 – Debt, Banking Arrangements, and Leases).
Guarantees: Guarantees primarily consist of a guarantee we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on a lease performance obligation that extends through 2042. Guarantees also include an indemnification related to a disposed operation.
To estimate the fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying value of the WilTel guarantee is reported in Accrued liabilities in the Consolidated Balance Sheet.Sheet. The maximum potential undiscounted exposure is approximately $30$29 million at December 31, 2017.2018. Our exposure declines systematically through the remaining term of WilTel’s obligation.
The fair value of the guarantee associated with the indemnification related to a disposed operation was estimated using an income approach that considered probability-weighted scenarios of potential levels of future performance. The terms of the indemnification do not limit the maximum potential future payments associated with the guarantee.
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
The carrying value of this guarantee is reported in Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.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 former Central and Northeast G&P reporting units as of September 30, 2015, and the annual assessment of goodwill associated with our Northeast G&P and West reporting units as of October 1, 2015. No impairment charges were required following these evaluations.
During the fourth quarter of 2015, we observed a significant decline in the market values of WPZ and comparable midstream companies within the industry. This served to reduce our estimate of enterprise value and increased our estimates of discount rates. As a result, we performed an impairment assessment as of December 31, 2015, of the goodwill associated with these reporting units, all within the Williams Partners segment.
We estimated the fair value of each reporting unit based on an income approach utilizing discount rates specific to the underlying businesses of each reporting unit. These discount rates considered variables unique to each business area, including equity yields of comparable midstream businesses, expectations for future growth, and customer performance considerations. Weighted-average discount rates utilized ranged from approximately 10 percent to 13 percent across the three reporting units.
As a result of the increases in discount rates during the fourth quarter of 2015, coupled with certain reductions in estimated future cash flows determined during the same period, the fair values of the former Central and Northeast G&P reporting units were determined to be below their respective carrying values. For these measurements, the book basis of each reporting unit was reduced by the associated deferred tax liabilities. We then calculated the implied fair value of goodwill by performing a hypothetical application of the acquisition method wherein the estimated fair value was allocated to the underlying assets and liabilities of each reporting unit. As a result of these Level 3 measurements, we determined that the previously recorded goodwill associated with each reporting unit was fully impaired, resulting in a fourth-quarter 2015 noncash charge of $1,098 million, reflected in Impairment of goodwill in the Consolidated Statement of Operations. For the West reporting unit, the estimated fair value exceeded the carrying value and no impairment was recorded.
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
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Nonrecurring fair value measurements
The following table presents impairments of assets and investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy.hierarchy, except as specifically noted.
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| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Impairments |
| | | | | | | | | | Years Ended December 31, |
| | Classification | | Segment | | Date of Measurement | | Fair Value | | 2017 | | 2016 | | 2015 |
| | | | | | | | (Millions) |
| Certain gathering operations (1) | Property, plant, and equipment – net and Intangible assets - net of accumulated amortization | | Williams Partners | | September 30, 2017 | | $ | 439 |
| | $ | 1,019 |
| | | | |
| Certain gathering operations (2) | Property, plant, and equipment – net and Intangible assets - net of accumulated amortization | | Williams Partners | | September 30, 2017 | | 21 |
| | 115 |
| | | | |
| Certain NGL pipeline (3) | Property, plant, and equipment – net | | Other | | September 30, 2017 | | 32 |
| | 68 |
| | | | |
| Certain olefins pipeline project (4) | Property, plant, and equipment – net | | Other | | June 30, 2017 | | 18 |
| | 23 |
| | | | |
| Canadian operations (5) | Assets held for sale | | Other | | June 30, 2016 | | 206 |
| | | | $ | 406 |
| | |
| Canadian operations (5) | Assets held for sale | | Williams Partners | | June 30, 2016 | | 924 |
| | | | 341 |
| | |
| Certain gathering operations (6) | Property, plant, and equipment – net | | Williams Partners | | June 30, 2016 | | 18 |
| | | | 48 |
| | |
| Certain idle assets | Property, plant, and equipment – net | | Other | | December 31, 2016 | | 73 |
| | | | 8 |
| | |
| Previously capitalized project development costs (7) | Property, plant, and equipment – net | | Williams Partners | | December 31, 2015 | | 13 |
| | | | | | $ | 94 |
|
| Previously capitalized project development costs (8) | Property, plant, and equipment – net | | Other | | December 31, 2015 | | 40 |
| | | | | | 64 |
|
| Surplus equipment (9) | Property, plant, and equipment – net | | Williams Partners | | June 30, 2015 | | 17 |
| | | | | | 20 |
|
| Level 3 fair value measurements of certain assets | | | | | | | | | 1,225 |
| | 803 |
| | 178 |
|
| Other impairments and write-downs (10) | | | | | | | | | 23 |
| | 70 |
| | 31 |
|
| Impairment of certain assets | | | | | | | | | $ | 1,248 |
| | $ | 873 |
| | $ | 209 |
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| | | | | | | | | | Impairments |
| | | | | | | | | | Years Ended December 31, |
| | Classification | | Segment | | Date of Measurement | | Fair Value | | 2018 | | 2017 | | 2016 |
| | | | | | | | (Millions) |
| Certain gathering operations (1) | Property, plant, and equipment – net and Intangible assets - net of accumulated amortization | | West | | December 31, 2018 | | $ | 470 |
| | $ | 1,849 |
| | | | |
| Certain idle pipeline assets (2) | Property, plant, and equipment – net | | Other | | June 30, 2018 | | 25 |
| | 66 |
| | | | |
| Certain gathering operations (3) | Property, plant, and equipment – net and Intangible assets - net of accumulated amortization | | West | | September 30, 2017 | | 439 |
| |
| | $ | 1,019 |
| | |
| Certain gathering operations (4) | Property, plant, and equipment – net and Intangible assets - net of accumulated amortization | | Northeast G&P | | September 30, 2017 | | 21 |
| |
| | 115 |
| | |
| Certain NGL pipeline (5) | Property, plant, and equipment – net | | Other | | September 30, 2017 | | 32 |
| |
| | 68 |
| | |
| Certain olefins pipeline project (6) | Property, plant, and equipment – net | | Other | | June 30, 2017 | | 18 |
| |
| | 23 |
| | |
| Canadian operations (7) | Assets held for sale | | Other | | June 30, 2016 | | 1,130 |
| | | |
| | $ | 747 |
|
| Certain gathering operations (8) | Property, plant, and equipment – net | | West | | June 30, 2016 | | 18 |
| | | |
| | 48 |
|
| Certain idle pipeline assets | Property, plant, and equipment – net | | Other | | December 31, 2016 | | 73 |
| | | |
| | 8 |
|
| Fair value measurements of certain assets | | | | | | | | | 1,915 |
| | 1,225 |
| | 803 |
|
| Other impairments and write-downs (9) | | | | | | | | | — |
| | 23 |
| | 70 |
|
| Impairment of certain assets | | | | | | | | | $ | 1,915 |
| | $ | 1,248 |
| | $ | 873 |
|
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| Equity-method investments (10) | Investments | | Northeast G&P | | December 31, 2018 | | $ | 1,293 |
| | $ | 32 |
| | | | |
| Equity-method investments (11) | Investments | | West and Northeast G&P | | December 31, 2016 | | 1,295 |
| | | |
| | $ | 318 |
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
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| | | | | | | Impairments | | | | Impairments |
| | | | | Years Ended December 31, | | | | Years Ended December 31, |
| | Classification | | Segment | | Date of Measurement | | Fair Value | | 2017 | | 2016 | | 2015 | Classification | | Segment | | Date of Measurement | | Fair Value | | 2018 | | 2017 | | 2016 |
| | | (Millions) | | (Millions) |
| Equity-method investments (11) | Investments | | Williams Partners | | December 31, 2016 | | $ | 1,295 |
| | | | $ | 318 |
| | | |
| Equity-method investments (12) | Investments | | Williams Partners | | March 31, 2016 | | 1,294 |
| | | | 109 |
| | | Investments | | West and Northeast G&P | | March 31, 2016 | | 1,294 |
| | | |
| | 109 |
|
| Other equity-method investment | Investments | | Williams Partners | | March 31, 2016 | | — |
| | | | 3 |
| | | Investments | | West | | March 31, 2016 | | — |
| | | |
| | 3 |
|
| Equity-method investments (13) | Investments | | Williams Partners | | December 31, 2015 | | 4,017 |
| | | | | | $ | 890 |
| |
| Equity-method investments (14) | Investments | | Williams Partners | | September 30, 2015 | | 1,203 |
| | | | | | 461 |
| |
| Other equity-method investment | Investments | | Williams Partners | | December 31, 2015 | | 58 |
| | | | | | 8 |
| |
| Impairment of equity-method investments | | | | | | $ | 430 |
| | $ | 1,359 |
| | | | $ | 32 |
| |
| | $ | 430 |
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______________
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| (1) | Relates to our gathering operations in the Barnett Shale. Certain of our contractual gathering rates, primarily those in the Barnett Shale, are based on a percentage of the New York Mercantile Exchange (NYMEX) natural gas prices. During the fourth quarter of 2018, we determined there was a sustained decline in the forward price curves for natural gas. During this same period, a large producer customer in the Barnett Shale removed their remaining drilling rig. These factors gave rise to an impairment evaluation of these assets, which incorporated management’s projections of future drilling activity and gathering rates, taking into consideration the information previously noted as well as recently available information regarding producer drilling cost assumptions in the basin. The resulting estimate of future undiscounted cash flows was less than our carrying value, necessitating the estimation of the fair value of these assets. To arrive at the fair value, we utilized an income approach with a discount rate of 8.5 percent, reflecting an estimated cost of capital and risks associated with the underlying assets. |
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| (2) | Relates to certain idle pipelines. The estimated fair value was determined by a market approach incorporating information derived from bids received for these assets, which we marketed for sale together with certain other assets. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. We sold these assets in the fourth quarter of 2018. (See Note 3 – Divestitures.) |
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| (3) | Relates to certain gathering operations in the Mid-Continent region. During the third quarter of 2017, we received solicitations and engaged in negotiations for the sale of certain of these assets which led to our impairment evaluation. The estimated fair value was determined using an income approach and incorporated market inputs based on ongoing negotiations for a potential sale of a portion of the underlying assets. For the income approach, we utilized a discount rate of 10.2 percent, reflecting an estimated cost of capital and risks associated with the underlying assets. |
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(2)(4) | Relates to certain gathering operations in the Marcellus South region resulting from an anticipated decline in future volumes following a third-quarter 2017 shut-in by the primary producer. The estimated fair value was determined by the income approach utilizing a discount rate of 11.1 percent, reflecting an estimated cost of capital and risks associated with the underlying assets. |
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(3)(5) | Relates to an NGL pipeline near the Houston Ship Channel region which we anticipate willanticipated would be underutilized for the foreseeable future. The estimated fair value was primarily determined by using a market approach based on our analysis of observable inputs in the principal market. We sold these assets in the fourth quarter of 2018. (See Note 3 – Divestitures.) |
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(4)(6) | Relates primarily to project development costs associated with an olefins pipeline project in the Gulf Coast region, the likelihood of completion of which is nowwe considered remote. The estimated fair value of the remaining pipe and equipment considered a market approach based on our analysis of observable inputs in the principal market, as well as an estimate of replacement cost. We sold these assets in the fourth quarter of 2018. (See Note 3 – Divestitures.) |
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
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(5)(7) | Relates to our Canadian operations. We designated these operations as held for sale as of June 30, 2016. As a result, we measured the fair value of the disposal group, resulting in an impairment charge. The estimated fair value was determined by a market approach based primarily on inputs received in the marketing process and reflected our estimate of the potential assumed proceeds. We disposed of our Canadian operations through a sale during the third quarter of 2016. (See Note 23 – Acquisitions and Divestitures).Divestitures.) |
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(6)(8) | Relates to certain gathering assets within the Mid-Continent region. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market. |
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The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
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(7) | Relates to a gas processing plant, the completion of which is considered remote due to unfavorable impact of low natural gas prices on customer drilling activities. The assessed fair value primarily represents the estimated salvage value of certain equipment measured using a market approach based on our analysis of observable inputs in the principal market. |
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(8) | Relates to an olefins pipeline project, the completion of which is considered remote due to lack of customer interest. The assessed fair value primarily represents the estimated fair value of unused pipeline measured using a market approach based on our analysis of observable inputs in the principal market. |
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| (9) | Relates to certain surplus equipment. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market. |
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(10) | Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be lower than the carrying value. |
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| (10) | Relates to Northeast G&P’s equity-method investment in UEOM. The estimated fair value was determined by a market approach based on our analysis of inputs in the principal market. |
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| (11) | Relates to Williams Partners’West’s previously held interest in Ranch Westex and multiple, currently held Appalachia Midstream Investments currently held.at Northeast G&P. The historical carrying value of these equity-method investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We estimated the fair value of these Appalachia Midstream Investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes, rates, and related capital spending. The discount rate utilized for the Appalachia Midstream Investments evaluation was 10.2 percent and reflected an estimated cost of capital as impacted by market conditions and risks associated with the underlying businesses. In addition to utilizing an income approach, we also considered a market approach for certain Appalachia Midstream Investments and Ranch Westex based on an agreement reached in February 2017 to exchange our interests in DBJV and Ranch Westex for additional interests in certain Appalachia Midstream Investments and cash. (See Note 56 – Investing Activities).Activities.) |
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| (12) | Relates to Williams Partners’West’s previously held interest in DBJV and Northeast G&P’s currently held equity-method investment in Laurel Mountain. Our carrying values in these equity-method investments had been written down to fair value at December 31, 2015. Our first-quarter 2016 analysis reflected higher discount rates for both of these equity-method investments, along with lower natural gas prices for Laurel Mountain. We estimated the fair value of these equity-method investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from 13.0 percent to 13.3 percent and reflected increases in the estimated cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses. |
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(13) | Relates to Williams Partners’ previously held interest in DBJV, as well as equity-method investments in certain of the Appalachia Midstream Investments, UEOM, and Laurel Mountain, all of which are currently held. We estimated the fair value of these equity-method investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from 10.8 percent to 14.4 percent and reflected further fourth-quarter 2015 increases in the estimated cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses. |
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(14) | Relates to Williams Partners’ previously held interest in DBJV and certain of the Appalachia Midstream Investments currently held. The historical carrying value of these equity-method investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We estimated the fair value of these equity-method investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized were 11.8 percent and 8.8 percent for DBJV and certain of the Appalachia Midstream Investments, respectively, and reflected an estimated cost of capital as impacted by market conditions, and risks associated with the underlying businesses. |
Concentration of Credit Risk
Trade accounts and other receivables
The following table summarizes concentration of receivables, net of allowances:
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| | (Millions) |
| NGLs, natural gas, and related products and services | $ | 626 |
| | $ | 760 |
|
| Transportation of natural gas and related products | 232 |
| | 212 |
|
| Other | 134 |
| | 4 |
|
| Total | $ | 992 |
| | $ | 976 |
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
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Concentration of Credit Risk
Cash equivalents
Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.
Trade accounts and other receivables
The following table summarizes concentration of receivables, net of allowances:
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | (Millions) |
| NGLs, natural gas, and related products and services | $ | 760 |
| | $ | 736 |
|
| Transportation of natural gas and related products | 212 |
| | 187 |
|
| Other | 4 |
| | 15 |
|
| Total | $ | 976 |
| | $ | 938 |
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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, 20172018 and 2016,2017, Chesapeake Energy Corporation, and its affiliates (Chesapeake), a customer primarily within our Williams Partners segment,Northeast G&P and West segments, accounted for $176$65 million and $133$176 million, respectively, of the consolidated Trade accounts and other receivables balances. The increase in Other is primarily due to an increase in our federal income tax receivable.
Revenues
In 2018, 2017, 2016, and 2015,2016, Chesapeake accounted for 8 percent, 10 percent, 14 percent, and 1814 percent, respectively, of our consolidated revenues.
Note 1718 – 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 has appealed.been remanded to the Nevada federal district court.
In the putative class actions, on March 30, 2017, the court issued an order denying the plaintiffs’ motions for class certification. On June 13, 2017, the United States Court of Appeals for the Ninth Circuit granted the plaintiffs’ petition for permission to appeal the order. On August 6, 2018, the Ninth Circuit reversed the order denying class certification and remanded the appeal is now pending.case to the Nevada federal district court.
Because of the uncertainty around the remaining pending unresolved issues, we cannot reasonably estimate a range of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of these actions and our related indemnification obligation could result in a potential loss that may be material to our results of operations. In connection with this indemnification, we have an accrued liability balance associated with this matter, and as a result, have exposure to future developments in this matter.
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The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
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developments.
Alaska Refinery Contamination Litigation
We are involved in litigation arising from our ownership and operation of the North Pole Refinery in North Pole, Alaska, from 1980 until 2004, through our wholly-ownedwholly owned subsidiaries, Williams Alaska Petroleum Inc. (WAPI) and MAPCO Inc. We sold the refinery to Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., in 2004. The litigation involves three cases, with filing dates ranging from 2010 to 2014. The actions arise from sulfolane contamination allegedly emanating from the refinery. A putative class action lawsuit was filed by James West in 2010 naming us, WAPI, and FHRA as defendants. We and FHRA filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination. In 2011, we and FHRA settled the claim with James West. Certain claims by FHRA against us were resolved by the Alaska Supreme Court in our favor. FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-site sulfolane remain pending. The State of Alaska filed its action in March 2014, seeking damages. The City of North Pole (North Pole) filed its lawsuit in November 2014, seeking past and future damages, as well as punitive damages.
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
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Both we and WAPI asserted counterclaims against the State of Alaska and North Pole, and cross-claims against FHRA. FHRA has also filed cross-claims against us.
The underlying factual basis and claims in the cases are similar and may duplicate exposure. As such, in February 2017, the three cases were consolidated into one action in state court containing the remaining claims from the James West case and those of the State of Alaska and North Pole. ASeveral trial dates encompassing all three cases was originallyhave been scheduled to commence in May 2017, but has been continued. Aand stricken; we are awaiting a new trial date has not been scheduled.date. Due to the ongoing assessment of the level and extent of sulfolane contamination, the lack of an articulated cleanup level for sulfolane, and the lack of a concrete remedial proposal and cost estimate, we are unable to estimate a range of exposure to the State of Alaska or North Pole at this time. We currently estimate that our reasonably possible loss exposure to FHRA could range from an insignificant amount up to $32 million, although uncertainties inherent in the litigation process, expert evaluations, and jury dynamics might cause our exposure to exceed that amount.
Independent of the litigation matter described in the preceding paragraphs, in 2013, the Alaska Department of Environmental Conservation indicated that it views FHRA and us as responsible parties, and that it intendedintends to enter a compliance order to address the environmental remediation of sulfolane and other possible contaminants including cleanup work outside the refinery’s boundaries. To date, no compliance order has been issued. Due to the ongoing assessment of the level and extent of sulfolane contamination, the ultimate cost of remediation and division of costs among the potentially responsible parties, and the previously described separate litigation, we are unable to estimate a range of exposure at this time.
Royalty Matters
Certain of our customers, including one major customer, have been named in various lawsuits alleging underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases filed in Pennsylvania based on allegations that we improperly participated with that major customer in causing the alleged royalty underpayments. We believe that the claims asserted are subject to indemnity obligations owed to us by that major customer. DueThat customer has reached a tentative settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement would apply to both the preliminary status of the cases, we are unable to estimate a range of potential loss at this time.
Shareholder Litigation
A purported shareholder filed a class action lawsuit in the Delaware Court of Chancery on January 15, 2016.customer and us. The putative class action complaint alleged that the individual members of our Board of Directors breached their fiduciary duties by, among other things, agreeing to the WPZ Merger Agreement, which purportedly reduced the merger consideration to have been received in the subsequently proposed but now terminated merger with Energy Transfer Equity, L.P. (Energy Transfer). The plaintiff filed a motion to voluntarily dismiss, which the court granted on January 13, 2017. On September 2, 2016, the same purported shareholder filed a derivative action claiming that the members of our Board of Directors breached their fiduciary duties by executing the WPZ Merger Agreementsettlement as a defensive measure against Energy Transfer. On September 28, 2016, we requested the court dismiss this action, and on May 15, 2017, the
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The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
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court dismissed the action. On June 6, 2017, the plaintiff filed a notice of appeal, and on December 18, 2017, the Delaware Supreme Court affirmed the lower court’s decision.
On March 7, 2016, a purported unitholder of WPZ filed a putative class action on behalf of certain purchasers of WPZ units in U.S. District Court in Oklahoma. The action names as defendants us, WPZ, Williams Partners GP LLC, Alan S. Armstrong, and former Chief Financial Officer Donald R. Chappel and alleges violations of certain federal securities laws for failure to disclose Energy Transfer’s intention to pursue a purchase of us conditioned on usreported would not closing the WPZ Merger Agreement when announcing the WPZ Merger Agreement. The complaint seeks, among other things, damages and an award of costs and attorneys’ fees. The plaintiff filed an amended complaint on August 31, 2016. On October 17, 2016, we requested the court dismiss the action, and on March 8, 2017, the court dismissed the complaint with prejudice. On April 7, 2017, the plaintiff filed a notice of appeal.
We cannot reasonably estimate a range of potential loss related to these matters at this time.require any contribution from us.
Litigation Against Energy Transfer and Related Parties
On April 6, 2016, we filed suit in Delaware Chancery Court against Energy Transfer Equity, L.P. (Energy Transfer) and LE GP, LLC (the general partner for Energy Transfer) alleging willful and material breaches of the Agreement and Plan of Merger (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.
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| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
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The Court of Chancery coordinated the Special Offering and Tax Opinion suits. On May 20, 2016, the Energy Transfer defendants filed amended affirmative defenses and verified counterclaims in the Special Offering and Tax Opinion suits, alleging certain breaches of the ETE Merger Agreement by us and seeking, among other things, a declaration that we were not entitled to specific performance, that Energy Transfer could terminate the ETC Merger, and that Energy Transfer is entitled to a $1.48 billion termination fee. On June 24, 2016, following a two-day trial, the court issued a Memorandum Opinion and Order denying our requested relief in the Tax Opinion suit. The court did not rule on the substance of our claims related to the Special Offering or on the substance of Energy Transfer’s counterclaims. On June 27, 2016, we filed an appeal of the court’s decision with the Supreme Court of Delaware, seeking reversal and remand to pursue damages. On March 23, 2017, the Supreme Court of Delaware affirmed the Court of Chancery’s ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied on April 5, 2017.
On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the ETE Merger Agreement by defendants. On September 23, 2016, Energy Transfer filed a second amended and supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things, payment of the $1.48 billion termination fee due to our alleged breaches of the ETE Merger Agreement. On December 1, 2017, the court granted our motion to dismiss certain of Energy Transfer’s counterclaims, including its claim seeking payment of the $1.48 billion termination fee. On December 8, 2017, Energy Transfer filed a motion for reargument, withwhich the Court of Chancery.
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The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
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Chancery denied on April 16, 2018. Although the Court of Chancery scheduled trial for May 20 through May 24, 2019, the parties anticipate trial will be re-scheduled for a later date.
Environmental Matters
We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of December 31, 2017,2018, we have accrued liabilities totaling $38$35 million for these matters, as discussed below. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At December 31, 2017,2018, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.
The EPA and various state regulatory agencies routinely promulgate and propose new rules and issue updated guidance to existing rules. More recent rules andThese rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, 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 rule regarding National Ambient Air Quality Standards for ground-level ozone, setting a stricter standard of 70 parts per billion.ozone. We are monitoring the rule’s implementation as the reductionit will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.
Continuing operations
Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At December 31, 20172018, we have accrued liabilities of $7$6 million for these costs. We expect that these costs will be recoverable through rates.
We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December 31, 20172018, we have accrued liabilities totaling $8$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;
Former petroleum products and natural gas pipelines;
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
Former petroleum refining facilities;
Former exploration and production and mining operations;
Former electricity and natural gas marketing and trading operations.
At December 31, 20172018, we have accrued environmental liabilities of $23$22 million related to these matters.
Other Divestiture Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way, and other representations that we have provided.
At December 31, 20172018, other than as previously disclosed, we are not aware of any material claims against us involving the indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made.
In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations, none of which are expected to be material to our expected future annual results of operations, liquidity, and financial position.
Summary
We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity, and financial position. These calculations have been made without consideration of any potential recovery from third parties.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
|
Commitments
Commitments for construction and acquisition of property, plant, and equipment are approximately $348$480 million at December 31, 2017.2018.
Note 1819 – Segment Disclosures
We have oneOur reportable segment, Williams Partners.segments are Northeast G&P, Atlantic-Gulf, and West. All remaining business activities are included in Other. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)
Our segment presentation of Williams Partners, which includes our consolidated master limited partnership, is reflective of the parent-level focus by our chief operating decision-maker, considering the resource allocation and governance provisions associated with the master limited partnership structure. This partnership maintains capital and cash management structures that are separate from ours. It is self-funding and maintains its own lines of bank credit and cash management accounts. These factors serve to differentiate the management of this entity as a whole.
Performance Measurement
We evaluate segment operating performance based upon Modified EBITDA (earnings before interest, taxes, depreciation, and amortization). This measure represents the basis of our internal financial reporting and is the primary
|
| | | | |
The Williams Companies, Inc. |
Notes to Consolidated Financial Statements – (Continued) |
|
performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments. Intersegment revenues primarily represent the sale of NGLs from our natural gas processing plants to our marketing business.
We define Modified EBITDA as follows:
•Net income (loss) before:
◦Provision (benefit) for income taxes;
◦Interest incurred, net of interest capitalized;
◦Equity earnings (losses);
◦Gain on remeasurement of equity-method investment;
◦Impairment of equity-method investments;
◦Other investing income (loss) – net;
◦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:origin:
|
| | | | | | | | | | | | | |
| | | | United States | | Canada | | Total |
| | | | (Millions) |
| Revenues from external customers: | | | | | | |
| | 2017 | | $ | 8,030 |
| | $ | 1 |
| | $ | 8,031 |
|
| | 2016 | | 7,425 |
| | 74 |
| | 7,499 |
|
| | 2015 | | 7,247 |
| | 113 |
| | 7,360 |
|
| | | | | | | | |
| Long-lived assets: | | | | | | |
| | 2017 | | $ | 37,002 |
| | $ | — |
| | $ | 37,002 |
|
| | 2016 | | 38,091 |
| | — |
| | 38,091 |
|
| | 2015 | | 38,016 |
| | 1,580 |
| | 39,596 |
|
|
| | | | | | | | | | | | | |
| | | | United States | | Canada | | Total |
| | | | (Millions) |
| Revenues from external customers: | | | | | | |
| | 2018 | | $ | 8,686 |
| | $ | — |
| | $ | 8,686 |
|
| | 2017 | | 8,030 |
| | 1 |
| | 8,031 |
|
| | 2016 | | 7,425 |
| | 74 |
| | 7,499 |
|
Long-lived assets are comprised of property, plant, and equipment, goodwill, and other intangible assets.
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Operations and Other financial information:
| | | | Williams Partners | | Other | | Eliminations | | Total | Northeast G&P | | Atlantic-Gulf | | West | | Other | | Eliminations | | Total |
| | | (Millions) |
| 2018 | | 2018 |
| Segment revenues: | | | | | | | | | | | | |
| Service revenues | | | | | | | | | | | | |
| External | | $ | 935 |
| | $ | 2,460 |
| | $ | 2,085 |
| | $ | 22 |
| | $ | — |
| | $ | 5,502 |
|
| Internal | | 41 |
| | 49 |
| | — |
| | 12 |
| | (102 | ) | | — |
|
| Total service revenues | | 976 |
| | 2,509 |
| | 2,085 |
| | 34 |
| | (102 | ) | | 5,502 |
|
| Total service revenues – commodity consideration (external only) | | 20 |
| | 59 |
| | 321 |
| | — |
| | — |
| | 400 |
|
| Product sales | | | | | | | | | | | | |
| External | | 245 |
| | 174 |
| | 2,365 |
| | — |
| | — |
| | 2,784 |
|
| Internal | | 42 |
| | 261 |
| | 83 |
| | — |
| | (386 | ) | | — |
|
| Total product sales | | 287 |
| | 435 |
| | 2,448 |
| | — |
| | (386 | ) | | 2,784 |
|
| Total revenues | | $ | 1,283 |
| | $ | 3,003 |
| | $ | 4,854 |
| | $ | 34 |
| | $ | (488 | ) | | $ | 8,686 |
|
| | | | | | | | | | | | | |
| Other financial information: | | | | | | | | | | | | |
| Additions to long-lived assets | | $ | 477 |
| | $ | 2,297 |
| | $ | 361 |
| | $ | 36 |
| | $ | — |
| | $ | 3,171 |
|
| Proportional Modified EBITDA of equity-method investments | | 493 |
| | 183 |
| | 94 |
| | — |
| | — |
| | 770 |
|
| | (Millions) | | | | | | | | | | | |
2017 | | Segment revenues: | | | | | | | | | | | | | | | | | | |
| Service revenues | | | | | | | | | | | | | | | | | | |
| External | $ | 5,291 |
| | $ | 21 |
| | $ | — |
| | $ | 5,312 |
| $ | 837 |
| | $ | 2,202 |
| | $ | 2,246 |
| | $ | 27 |
| | $ | — |
| | $ | 5,312 |
|
| Internal | 1 |
| | 11 |
| | (12 | ) | | — |
| 35 |
| | 37 |
| | — |
| | 11 |
| | (83 | ) | | — |
|
| Total service revenues | 5,292 |
| | 32 |
| | (12 | ) | | 5,312 |
| 872 |
| | 2,239 |
| | 2,246 |
| | 38 |
| | (83 | ) | | 5,312 |
|
| Product sales | | | | | | | | | | | | | | | | | | |
| External | 2,718 |
| | 1 |
| | — |
| | 2,719 |
| 264 |
| | 257 |
| | 1,840 |
| | 358 |
| | — |
| | 2,719 |
|
| Internal | — |
| | — |
| | — |
| | — |
| 27 |
| | 227 |
| | 173 |
| | 8 |
| | (435 | ) | | — |
|
| Total product sales | 2,718 |
| | 1 |
| | — |
| | 2,719 |
| 291 |
| | 484 |
| | 2,013 |
| | 366 |
| | (435 | ) | | 2,719 |
|
| Total revenues | $ | 8,010 |
| | $ | 33 |
| | $ | (12 | ) | | $ | 8,031 |
| $ | 1,163 |
| | $ | 2,723 |
| | $ | 4,259 |
| | $ | 404 |
| | $ | (518 | ) | | $ | 8,031 |
|
| | | | | | | | | | | | | | | | | | | |
| Other financial information: | | | | | | | | | | | | | | | | | | |
| Additions to long-lived assets | $ | 2,792 |
| | $ | 22 |
| | $ | — |
| | $ | 2,814 |
| $ | 460 |
| | $ | 2,001 |
| | $ | 321 |
| | $ | 32 |
| | $ | — |
| | $ | 2,814 |
|
| Proportional Modified EBITDA of equity-method investments | 795 |
| | — |
| | — |
| | 795 |
| 452 |
| | 264 |
| | 79 |
| | — |
| | — |
| | 795 |
|
| | | | | | | | | | | | | | | | | | | |
| 2016 | 2016 | | | | | | | | | | | |
| Segment revenues: | | | | | | | | | | | | | | | | | | |
| Service revenues | | | | | | | | | | | | | | | | | | |
| External | $ | 5,140 |
| | $ | 31 |
| | $ | — |
| | $ | 5,171 |
| $ | 836 |
| | $ | 1,959 |
| | $ | 2,328 |
| | $ | 48 |
| | $ | — |
| | $ | 5,171 |
|
| Internal | 33 |
| | 19 |
| | (52 | ) | | — |
| 34 |
| | 39 |
| | — |
| | 11 |
| | (84 | ) | | — |
|
| Total service revenues | 5,173 |
| | 50 |
| | (52 | ) | | 5,171 |
| 870 |
| | 1,998 |
| | 2,328 |
| | 59 |
| | (84 | ) | | 5,171 |
|
| Product sales | | | | | | | | | | | | | | | | | | |
| External | 2,318 |
| | 10 |
| | — |
| | 2,328 |
| 134 |
| | 245 |
| | 1,183 |
| | 766 |
| | — |
| | 2,328 |
|
| Internal | — |
| | 16 |
| | (16 | ) | | — |
| 28 |
| | 205 |
| | 197 |
| | 22 |
| | (452 | ) | | — |
|
| Total product sales | 2,318 |
| | 26 |
| | (16 | ) | | 2,328 |
| 162 |
| | 450 |
| | 1,380 |
| | 788 |
| | (452 | ) | | 2,328 |
|
| Total revenues | $ | 7,491 |
| | $ | 76 |
| | $ | (68 | ) | | $ | 7,499 |
| $ | 1,032 |
| | $ | 2,448 |
| | $ | 3,708 |
| | $ | 847 |
| | $ | (536 | ) | | $ | 7,499 |
|
| | | | | | | | | | | | | | | | | | | |
| Other financial information: | | | | | | | | | | | | | | | | | | |
| Additions to long-lived assets | $ | 2,102 |
| | $ | 44 |
| | $ | (1 | ) | | $ | 2,145 |
| $ | 223 |
| | $ | 1,608 |
| | $ | 223 |
| | $ | 92 |
| | $ | (1 | ) | | $ | 2,145 |
|
| Proportional Modified EBITDA of equity-method investments | 754 |
| | — |
| | — |
| | 754 |
| 357 |
| | 287 |
| | 110 |
| | — |
| | — |
| | 754 |
|
| | | | | | | | | |
| 2015 | | | | | | | | |
| Segment revenues: | | | | | | | | |
| Service revenues | | | | | | | | |
| External | $ | 5,134 |
| | $ | 30 |
| | $ | — |
| | $ | 5,164 |
| |
| Internal | 1 |
| | 91 |
| | (92 | ) | | — |
| |
| Total service revenues | 5,135 |
| | 121 |
| | (92 | ) | | 5,164 |
| |
| Product sales | | | | | | | | |
| External | 2,196 |
| | — |
| | — |
| | 2,196 |
| |
| Internal | — |
| | — |
| | — |
| | — |
| |
| Total product sales | 2,196 |
| | — |
| | — |
| | 2,196 |
| |
| Total revenues | $ | 7,331 |
| | $ | 121 |
| | $ | (92 | ) | | $ | 7,360 |
| |
| | | | | | | | | |
| Other financial information: | | | | | | | | |
| Additions to long-lived assets | $ | 2,960 |
| | $ | 388 |
| | $ | (12 | ) | | $ | 3,336 |
| |
| Proportional Modified EBITDA of equity-method investments | 699 |
| | — |
| | — |
| | 699 |
| |
|
| | | | |
| The Williams Companies, Inc. |
| Notes to Consolidated Financial Statements – (Continued) |
| |
The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in the Consolidated Statement of Operations:
| | | | | Years Ended December 31, | | Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
| | | | (Millions) | | | (Millions) |
| Modified EBITDA by segment: | Modified EBITDA by segment: | | | | | | Modified EBITDA by segment: | | | | | |
| Williams Partners | $ | 3,616 |
| | $ | 3,864 |
| | $ | 4,003 |
| |
| Northeast G&P | | Northeast G&P | $ | 1,086 |
| | $ | 819 |
| | $ | 853 |
|
| Atlantic-Gulf | | Atlantic-Gulf | 2,023 |
| | 1,238 |
| | 1,621 |
|
| West | | West | 308 |
| | 412 |
| | 1,544 |
|
| Other | Other | (150 | ) | | (542 | ) | | (112 | ) | Other | (29 | ) | | 997 |
| | (696 | ) |
| | | 3,466 |
| | 3,322 |
| | 3,891 |
| | 3,388 |
| | 3,466 |
| | 3,322 |
|
| Accretion expense associated with asset retirement obligations for nonregulated operations | Accretion expense associated with asset retirement obligations for nonregulated operations | (33 | ) | | (31 | ) | | (28 | ) | Accretion expense associated with asset retirement obligations for nonregulated operations | (33 | ) | | (33 | ) | | (31 | ) |
| Depreciation and amortization expenses | Depreciation and amortization expenses | (1,736 | ) | | (1,763 | ) | | (1,738 | ) | Depreciation and amortization expenses | (1,725 | ) | | (1,736 | ) | | (1,763 | ) |
| Impairment of goodwill | — |
| | — |
| | (1,098 | ) | |
| Equity earnings (losses) | Equity earnings (losses) | 434 |
| | 397 |
| | 335 |
| Equity earnings (losses) | 396 |
| | 434 |
| | 397 |
|
| Impairment of equity-method investments | Impairment of equity-method investments | — |
| | (430 | ) | | (1,359 | ) | Impairment of equity-method investments | (32 | ) | | — |
| | (430 | ) |
| Other investing income (loss) – net | Other investing income (loss) – net | 282 |
| | 63 |
| | 27 |
| Other investing income (loss) – net | 219 |
| | 282 |
| | 63 |
|
| Proportional Modified EBITDA of equity-method investments | Proportional Modified EBITDA of equity-method investments | (795 | ) | | (754 | ) | | (699 | ) | Proportional Modified EBITDA of equity-method investments | (770 | ) | | (795 | ) | | (754 | ) |
| Interest expense | Interest expense | (1,083 | ) | | (1,179 | ) | | (1,044 | ) | Interest expense | (1,112 | ) | | (1,083 | ) | | (1,179 | ) |
| (Provision) benefit for income taxes | (Provision) benefit for income taxes | 1,974 |
| | 25 |
| | 399 |
| (Provision) benefit for income taxes | (138 | ) | | 1,974 |
| | 25 |
|
| Net income (loss) | Net income (loss) | $ | 2,509 |
| | $ | (350 | ) | | $ | (1,314 | ) | Net income (loss) | $ | 193 |
| | $ | 2,509 |
| | $ | (350 | ) |
The following table reflects Total assets and Equity-method investments by reportable segments:
|
| | | | | | | | | | | | | | | | |
| | | Total Assets | | Equity-Method Investments |
| | | December 31, 2017 | | December 31, 2016 | | December 31, 2017 | | December 31, 2016 |
| | | (Millions) |
| Williams Partners | | $ | 45,903 |
| | $ | 46,265 |
| | $ | 6,552 |
|
| $ | 6,701 |
|
| Other | | 589 |
| | 685 |
| | — |
| | — |
|
| Eliminations | | (140 | ) | | (115 | ) | | — |
| | — |
|
| Total | | $ | 46,352 |
| | $ | 46,835 |
| | $ | 6,552 |
| | $ | 6,701 |
|
|
| | | | | | | | | | | | | | | | |
| | | Total Assets | | Equity-Method Investments |
| | | December 31, 2018 | | December 31, 2017 | | December 31, 2018 | | December 31, 2017 |
| | | (Millions) |
| Northeast G&P | | $ | 14,526 |
| | $ | 14,397 |
| | $ | 5,319 |
|
| $ | 5,307 |
|
| Atlantic-Gulf | | 16,346 |
| | 14,989 |
| | 776 |
| | 823 |
|
| West | | 13,948 |
| | 16,143 |
| | 1,726 |
| | 422 |
|
| Other (1) | | 849 |
| | 1,449 |
| | — |
| | — |
|
| Eliminations (2) | | (367 | ) | | (626 | ) | | — |
| | — |
|
| Total | | $ | 45,302 |
| | $ | 46,352 |
| | $ | 7,821 |
| | $ | 6,552 |
|
______________
| |
| (1) | Decrease in Other is due primarily to a decreased cash balance. |
| |
| (2) | Eliminations primarily relate to the intercompany notes and accounts receivable generated by our cash management program. |
|
| | |
| The Williams Companies Inc. |
| Quarterly Financial Data – (Continued) |
(Unaudited)
|
Summarized quarterly financial data are as follows:
| | | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
| | (Millions, except per-share amounts) | (Millions, except per-share amounts) |
| 2018 | | |
| Revenues | | $ | 2,088 |
| | $ | 2,091 |
| | $ | 2,303 |
| | $ | 2,204 |
|
| Product costs and processing commodity expenses | | 648 |
| | 662 |
| | 820 |
| | 714 |
|
| Net income (loss) | | 270 |
| | 269 |
| | 200 |
| | (546 | ) |
| Amounts attributable to The Williams Companies, Inc.: | | | | | | | | |
| Net income (loss) | | 152 |
| | 135 |
| | 129 |
| | (571 | ) |
| Basic earnings (loss) per common share | | .18 |
| | .16 |
| | .13 |
| | (.47 | ) |
| Diluted earnings (loss) per common share | | .18 |
| | .16 |
| | .13 |
| | (.47 | ) |
| 2017 | | | | | | | | |
| Revenues | $ | 1,988 |
| | $ | 1,924 |
| | $ | 1,891 |
| | $ | 2,228 |
| $ | 1,988 |
| | $ | 1,924 |
| | $ | 1,891 |
| | $ | 2,228 |
|
| Product costs | 579 |
| | 537 |
| | 504 |
| | 680 |
| 579 |
| | 537 |
| | 504 |
| | 680 |
|
| Net income (loss) | 569 |
| | 193 |
| | 125 |
| | 1,622 |
| 569 |
| | 193 |
| | 125 |
| | 1,622 |
|
| Amounts attributable to The Williams Companies, Inc.: | | | | | | | | | | | | | | |
| Net income (loss) | 373 |
| | 81 |
| | 33 |
| | 1,687 |
| 373 |
| | 81 |
| | 33 |
| | 1,687 |
|
| Basic earnings (loss) per common share | .45 |
| | .10 |
| | .04 |
| | 2.04 |
| .45 |
| | .10 |
| | .04 |
| | 2.04 |
|
| Diluted earnings (loss) per common share | .45 |
| | .10 |
| | .04 |
| | 2.03 |
| |
| | | | | | | | | |
| 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 | ) | |
| Diluted earnings (loss) per common share: | | .45 |
| | .10 |
| | .04 |
| | 2.03 |
|
The sum of earnings (loss) per share for the four quarters may not equal the total earnings (loss) per share for the year due to changes in the average number of common shares outstanding and rounding.
2018
Net income (loss) for fourth-quarter 2018 includes:
$1.849 billion impairment of certain assets in the Barnett Shale region (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements);
$591 million gain on the sale of our natural gas gathering and processing assets in the Four Corners area of New Mexico and Colorado (see Note 3 – Divestitures);
$141 million deconsolidation gain associated with our investment in the Brazos Permian II joint venture (see Note 6 – Investing Activities);
$101 million gain on the sale of certain assets and operations located in the Gulf Coast area (see Note 3 – Divestitures).
2017
Net income (loss) for fourth-quarter 2017 includes:
$1.923 billion benefit for income taxes resulting from Tax Reform rate change (see Note 78 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements)Taxes);
$674 million of regulatory charges resulting from Tax Reform and $102 million of charges associated with regulatory asset-related deferred taxes on equity funds used during construction due to Tax Reform (see Note 67 – Other Income and Expenses).
Net income (loss) for third-quarter 2017 includes includes:
$1.095 billion gain on the sale of Williams Olefins, L.L.C., a wholly owned subsidiary which owned our interest in the Geismar, Louisiana, olefins plant (Geismar Interest) (see Note 2 – Acquisitions and Divestitures);
$1.210 billion impairment on certain assets (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk).
Net income (loss) for first-quarter 2017 includes a gain of $269 million associated with the disposition of certain equity-method investments (see Note 5 – Investing Activities).
|
| | |
| The Williams Companies Inc. |
| Quarterly Financial Data – (Continued) |
| (Unaudited) |
2016
Net income (loss) for fourth-quarter 2016third-quarter 2017 includes:
$173 million1.095 billion gain on the sale of income associated with the amortization of deferred income related to the restructuring of certain gas gathering contractsWilliams Olefins, L.L.C., a wholly owned subsidiary which owned our interest in the Barnett Shale and Mid-Continent regions and $58 million of related minimum volume commitment feesGeismar, Louisiana, olefins plant (Geismar Interest) (see Note 63 – Other Income and Expenses)Divestitures);
$318 million1.210 billion impairment loss on certain equity-method investmentsassets (see Note 1617 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk).
Net income (loss) for second-quarter 2016first-quarter 2017 includes a $747gain of $269 million impairment loss on Canadian assets (see Note 16 – Fair Value Measurements, Guarantees, and Concentrationassociated with the disposition of Credit Risk).
Net income (loss) for first-quarter 2016 includes a $112 million impairment loss on certain equity-method investments (see Note 166 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk)Investing Activities).
The Williams Companies, Inc.
Schedule I — Condensed Financial Information of Registrant
Statement of Comprehensive Income (Loss) (Parent)
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (Millions, except per-share amounts) |
| Equity in earnings of consolidated subsidiaries | $ | 898 |
| | $ | 522 |
| | $ | 232 |
|
| Interest incurred — external | (261 | ) | | (268 | ) | | (255 | ) |
| Interest incurred — affiliate | (413 | ) | | (568 | ) | | (828 | ) |
| Interest income — affiliate | — |
| | — |
| | 6 |
|
| Other income (expense) — net | (23 | ) | | (53 | ) | | (75 | ) |
| Income (loss) before income taxes | 201 |
| | (367 | ) | | (920 | ) |
| Provision (benefit) for income taxes | (1,973 | ) | | 57 |
| | (349 | ) |
| Net income (loss) | $ | 2,174 |
| | $ | (424 | ) | | $ | (571 | ) |
| Basic earnings (loss) per common share: | | | | | |
| Net income (loss) | $ | 2.63 |
| | $ | (.57 | ) | | $ | (.76 | ) |
| Weighted-average shares (thousands) | 826,177 |
| | 750,673 |
| | 749,271 |
|
| Diluted earnings (loss) per common share: | | | | | |
| Net income (loss) | $ | 2.62 |
| | $ | (.57 | ) | | $ | (.76 | ) |
| Weighted-average shares (thousands) | 828,518 |
| | 750,673 |
| | 749,271 |
|
| Other comprehensive income (loss): | | | | | |
| Equity in other comprehensive income (loss) of consolidated subsidiaries | $ | (2 | ) | | $ | 171 |
| | $ | (204 | ) |
| Other comprehensive income (loss) attributable to The Williams Companies, Inc. | 102 |
| | 1 |
| | 33 |
|
| Other comprehensive income (loss) | 100 |
| | 172 |
| | (171 | ) |
| Less: Other comprehensive income (loss) attributable to noncontrolling interests | (1 | ) | | 69 |
| | (70 | ) |
| Comprehensive income (loss) attributable to The Williams Companies, Inc. | $ | 2,275 |
| | $ | (321 | ) | | $ | (672 | ) |
See accompanying notes.
The Williams Companies, Inc.
Schedule I — Condensed Financial Information of Registrant – (Continued)
Balance Sheet (Parent)
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | (Millions) |
| ASSETS | | | |
| Current assets: | | | |
| Cash and cash equivalents | $ | 14 |
| | $ | 14 |
|
| Other current assets and deferred charges | 10 |
| | 16 |
|
| Total current assets | 24 |
| | 30 |
|
| Investments in and advances to consolidated subsidiaries | 25,268 |
| | 22,359 |
|
| Property, plant, and equipment — net | 77 |
| | 77 |
|
| Other noncurrent assets | 6 |
| | 8 |
|
| Total assets | $ | 25,375 |
| | $ | 22,474 |
|
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | |
| Current liabilities: | | | |
| Accounts payable | $ | 20 |
| | $ | 27 |
|
| Other current liabilities | 187 |
| | 169 |
|
| Total current liabilities | 207 |
| | 196 |
|
| Long-term debt | 4,438 |
| | 4,939 |
|
| Notes payable — affiliates | 7,763 |
| | 8,171 |
|
| Pension, other postretirement, and other noncurrent liabilities | 164 |
| | 287 |
|
| Deferred income tax liabilities | 3,147 |
| | 4,238 |
|
| Contingent liabilities and commitments |
| |
|
| Equity: | | | |
| Common stock | 861 |
| | 785 |
|
| Other stockholders’ equity | 8,795 |
| | 3,858 |
|
| Total stockholders’ equity | 9,656 |
| | 4,643 |
|
| Total liabilities and stockholders’ equity | $ | 25,375 |
| | $ | 22,474 |
|
See accompanying notes.
The Williams Companies, Inc.
Schedule I — Condensed Financial Information of Registrant – (Continued)
Statement of Cash Flows (Parent)
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (Millions) |
| NET CASH FLOWS PROVIDED (USED) BY OPERATING ACTIVITIES | $ | (648 | ) | | $ | (827 | ) | | $ | (1,181 | ) |
| | | | | | |
| FINANCING ACTIVITIES: | | | | | |
| Proceeds from long-term debt | 1,635 |
| | 2,280 |
| | 2,097 |
|
| Payments of long-term debt | (2,140 | ) | | (2,155 | ) | | (1,817 | ) |
| Changes in notes payable to affiliates | (408 | ) | | 9 |
| | 2,211 |
|
| Proceeds from issuance of common stock | 2,131 |
| | 9 |
| | 27 |
|
| Dividends paid | (992 | ) | | (1,261 | ) | | (1,836 | ) |
| Other — net | (9 | ) | | (6 | ) | | (30 | ) |
| Net cash provided (used) by financing activities | 217 |
| | (1,124 | ) | | 652 |
|
| | | | | | |
| INVESTING ACTIVITIES: | | | | | |
| Capital expenditures | (22 | ) | | (13 | ) | | (29 | ) |
| Changes in investments in and advances to consolidated subsidiaries | 453 |
| | 1,966 |
| | 521 |
|
| Net cash provided (used) by investing activities | 431 |
| | 1,953 |
| | 492 |
|
| Increase (decrease) in cash and cash equivalents | — |
| | 2 |
| | (37 | ) |
| Cash and cash equivalents at beginning of year | 14 |
| | 12 |
| | 49 |
|
| Cash and cash equivalents at end of year | $ | 14 |
| | $ | 14 |
| | $ | 12 |
|
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, 2017, is approximately $305 million.
Note 2. Cash Dividends Received
We receive dividends and distributions either directly from our subsidiaries or indirectly through dividends received by subsidiaries and subsequent transfers of cash to us through our corporate cash management system. The total of such receipts ultimately related to dividends and distributions for the years ended December 31, 2017, 2016, and 2015 was approximately $1.9 billion, $1.7 billion, and $1.8 billion, respectively.
The Williams Companies, Inc.
Schedule II — Valuation and Qualifying Accounts
| | | | | | Additions | | | | | | | Additions | | | | |
| | Beginning Balance | | Charged (Credited) To Costs and Expenses | | Other | | Deductions | | Ending Balance | Beginning Balance | | Charged (Credited) To Costs and Expenses | | Other | | Deductions | | Ending Balance |
| | (Millions) | (Millions) |
| 2018 | | | | | | | | | | |
| Deferred tax asset valuation allowance (1) | | $ | 224 |
| | $ | 96 |
| | $ | — |
| | $ | — |
| | $ | 320 |
|
| 2017 | | | | | | | | | | | | | | | | | | |
| Deferred tax asset valuation allowance (1) | $ | 334 |
| | $ | (110 | ) | | $ | — |
| | $ | — |
| | $ | 224 |
| 334 |
| | (110 | ) | | — |
| | — |
| | 224 |
|
| 2016 | | | | | | | | | | | | | | | | | | |
| Deferred tax asset valuation allowance (1) | 190 |
| | 144 |
| | — |
| | — |
| | 334 |
| 190 |
| | 144 |
| | — |
| | — |
| | 334 |
|
| 2015 | | | | | | | | | | |
| Deferred tax asset valuation allowance (1) | 206 |
| | (16 | ) | | — |
| | — |
| | 190 |
| |
__________
(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 20172018 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, 2017,2018, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we concluded that, as of December 31, 2017,2018, our internal control over financial reporting was effective.
Ernst & Young LLP, our independent registered public accounting firm, has audited our internal control over financial reporting, as stated in their report which is included in this Annual Report on Form 10-K.
Report of Independent Registered Public Accounting Firm
on Internal Control Over Financial Reporting
The Stockholders and the Board of Directors of
The Williams Companies, Inc.
Opinion on Internal Control Over Financial Reporting
We have audited The Williams Companies, Inc.’s internal control over financial reporting as of December 31, 2017,2018, 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”)COSO criteria). In our opinion, The Williams Companies, Inc. (the “Company”)Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2018, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”)(PCAOB), the consolidated balance sheet of the Company as of December 31, 20172018 and 2016,2017, and the related consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2017,2018, and the related notes and the financial statement schedulesschedule listed in the index at Item 15(a) and our report dated February 22, 201821, 2019 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 22, 201821, 2019
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The information regarding our directors and nominees for director required by Item 401 of Regulation S-K will be presented under the heading “Election of Directors” in our definitive proxy statement prepared for the solicitation of proxies in connection with our Annual Meeting of Stockholders to be held May 10, 2018,9, 2019, which shall be filed no later than April 30, 2018March 28, 2019 (Proxy Statement), which information is incorporated by reference herein.
Information regarding our executive officers required by Item 401(b) of Regulation S-K is presented at the end of Part I herein and captioned “Executive Officers of the Registrant” as permitted by General Instruction G(3) to and Instruction 3 to Item 401(b) of Regulation S-K.
Information required by Item 405 of Regulation S-K will be included under the heading “Section 16(a) Beneficial Ownership Reporting Compliance” in our Proxy Statement, which information is incorporated by reference herein.
Information required by paragraphs (c)(3), (d)(4) and (d)(5) of Item 407 of Regulation S-K will be included under the heading “Questions and Answers About the Annual Meeting and Voting” and “Corporate Governance and Board Matters” in our Proxy Statement, which information is incorporated by reference herein.
We have adopted a Code of Ethics for Senior Officers that applies to our Chief Executive Officer, Chief Financial Officer, and Controller, or persons performing similar functions. The Code of Ethics for Senior Officers, together with our Corporate Governance Guidelines, the charters for each of our board committees, and our Code of Business Conduct applicable to all employees are available on our Internet website at www.williams.com. We will provide, free of charge, a copy of our Code of Ethics or any of our other corporate documents listed above upon written request to our Corporate Secretary at Williams, One Williams Center, Suite 4700, Tulsa, Oklahoma 74172. We intend to disclose any amendments to or waivers of the Code of Ethics on behalf of our Chief Executive Officer, Chief Financial Officer, Controller, and persons performing similar functions on the corporate governance section of our Internet website at www.williams.com, promptly following the date of any such amendment or waiver.
Item 11. Executive Compensation
The information required by Item 402 and paragraphs (e)(4) and (e)(5) of Item 407 of Regulation S-K regarding executive compensation will be presented under the headings “Compensation Discussion and Analysis,” “Executive Compensation and Other Information,” “Compensation of Directors,” “Compensation and Management Development Committee Report on Executive Compensation,” and “Compensation and Management Development Committee Interlocks and Insider Participation” in our Proxy Statement, which information is incorporated by reference herein. Notwithstanding the foregoing, the information provided under the heading “Compensation and Management Development Committee Report on Executive Compensation” in our Proxy Statement is furnished and shall not be deemed to be filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, is not subject to the liabilities of that section and is not deemed incorporated by reference in any filing under the Securities Act of 1933, as amended.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information regarding securities authorized for issuance under equity compensation plans required by Item 201(d) of Regulation S-K and the security ownership of certain beneficial owners and management required by Item 403 of Regulation S-K will be presented under the headings “Equity Compensation Stock Plans” and “Security
Ownership of Certain Beneficial Owners and Management” in our Proxy Statement, which information is incorporated by reference herein.
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.
|
| |
| | Page |
| Covered by report of independent auditors: | |
| |
| |
| |
| |
| |
| |
Schedule for each year in the three-year period ended December 31, 2017:2018: | |
| |
| |
| Not covered by report of independent auditors: | |
| |
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+ | __ | 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). |
| | | |
|
| | |
Exhibit
No. | | Description |
| | | |
| 2.4 | — | |
| | |
2.5 | — | |
| | |
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). |
| | | |
2.72.5 | __ | 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 | — | |
| | |
| 3.4 | — | |
| | | |
| 4.1 | — | |
| | | |
| 4.2 | — | |
| | | |
| 4.3 | — | |
| | | |
| 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 on March 30, 1999, as Exhibit 4(J) to Williams Holdings of Delaware, Inc.’s annual report on Form 10-K for the fiscal year ended December 31, 1998 (File No. 000-20555) and incorporated herein by reference). |
| | | |
| 4.5 | — | Fourth Supplemental Indenture, dated as of July 31, 1999, among Williams Holdings of Delaware, Inc., The Williams Companies, Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed on March 28, 2000, as Exhibit 4(q) to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference). |
| | | |
| | |
|
| | |
Exhibit
No. | | Description |
| | |
| 4.6 | —
| |
| | |
|
| | |
Exhibit
No. | | Description |
| | | |
| 4.7 | — | |
| | | |
| 4.8 | — | |
| | | |
| 4.9 | —
| |
| | | |
| 4.10 | — | |
| | |
4.11 | — | |
| | | |
4.124.11 | — | |
| | | |
4.134.12 | — | |
| | | |
4.144.13 | — | |
| | | |
4.154.14 | — | |
| | | |
4.164.15 | — | |
| | | |
4.174.16 | — | |
| | | |
|
| 4.17 | — | |
Exhibit
| | Description 001-04174) and incorporated herein by reference). |
| | | |
| 4.18 | — | |
|
| | |
Exhibit
No. | | Description |
| | |
| | | |
| 4.19 | — | |
| | | |
| 4.20 | — | |
| | | |
| 4.21 | — | |
| | | |
| 4.22 | — | |
| | | |
| 4.23 | — | |
| | | |
| 4.24 | — | |
| | | |
| 4.25 | — | |
| | | |
| 4.26 | — | |
| | | |
| 4.27 | __ | |
| | | |
| 4.28 | —__ | Tenth Supplemental Indenture, dated as of December 19, 2012, by and among Access MidstreamMarch 5, 2018, between Williams Partners L.P., ACMP Finance Corp., the guarantors listed therein and The Bankbank of New York Mellon Trust Company, N.A., as trustee (filed on December 19, 2012March 5, 2018, as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference). |
| | | |
| 4.29 | __ | |
| | |
|
| | |
Exhibit
No. | | Description |
| | |
4.29 | — | |
| | | |
| 4.30 | — | |
| | | |
| 4.31 | — | |
| | |
4.32 | __ | |
| | | |
4.334.32 | — | |
| | | |
4.34 | — | |
| | |
4.354.33 | — | |
| | | |
4.364.34 | — | |
| | | |
4.374.35 | — | |
| | | |
10.1*§4.36 | — | |
| | |
| 10.1§ | — | |
| | | |
| 10.2§ | — | |
| | | |
| 10.3§ | — | |
| | | |
| 10.4§ | — | |
| | | |
|
| | |
Exhibit
No. | | Description |
| | |
| 10.5§ | — | |
| | |
10.6§ | — | |
| | |
10.7§ | — | |
| | | |
10.8§10.6§ | — | |
| | | |
10.9§ |
| — | |
Exhibit 10.13 to The Williams Companies, Inc. annual report on Form 10-K (File
No. 001-04174) and incorporated herein by reference). | | Description |
| | | |
10.10§ | — | |
| | |
10.11§10.7§ | — | |
| | | |
10.12§10.8§ | — | |
| | | |
10.13§10.9§ | — | |
| | | |
10.14§10.10§
| — | |
| | | |
10.15§10.11§ | — |
|
| | | |
10.16§10.12§
| — |
|
| | | |
10.17§10.13§ | — |
|
| | | |
10.18§10.14§
| — |
|
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|
| | |
Exhibit
No. | | Description |
| | | |
10.19§10.15§ | — |
|
| | | |
10.20§10.16§ | — |
|
| | | |
10.21§10.17§
| — |
|
| | | |
10.22§10.18§ | — |
|
| | | |
10.23§10.19§ | __ | |
| | |
| 10.20§ | __ | |
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|
| | |
Exhibit
No. | | Description |
| | |
| 10.21§ | __ | |
| | |
| 10.22§ | __ | |
| | |
| 10.23§ | __ | |
| | | |
| 10.24§ | — | |
| | | �� |
| 10.25§ | — | |
| | | |
| 10.26§ | — | |
| | | |
| 10.27§ | — | |
| | | |
| 10.28§* | — | |
| | | |
| 10.29§* | — | |
| | | |
| 10.30§ | — | |
| | | |
| 10.31§ | — | |
| | |
|
| | |
Exhibit
No. | | Description |
| | | |
| 10.32 | — | |
| | | |
| 10.33 | — | |
| | | |
| 10.34§ | — | |
| | | |
|
| | |
Exhibit
No. | | Description |
| | |
| 10.35§ | — | |
| | | |
| 10.36 | — | TerminationCredit Agreement and Release, dated as of September 29, 2015, by and amongJuly 13, 2018, between The Williams Companies, Inc., SCMSNorthwest Pipeline LLC, Williams Partners L.P. and WPZ GPTranscontinental Gas Pipe Line Company, LLC (filed on September 28, 2015 as Exhibit 10.1 to Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
| | |
10.37 | — | |
| | |
10.38 | __ | |
| | | |
10.3910.37 | — | Second Amended and Restated CreditForm of Commercial Paper Dealer Agreement, dated as of February 2, 2015,August 10, 2018, between The Williams Partners L.P.Companies, Inc., Northwest Pipeline LLC, Transcontinental Gas Pipeline Company, LLC, as co-borrowers,Issuer, and the lenders named therein, and Citibank, N.A. as Administrative Agent (filedDealer party thereto(filed on February 3, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference). |
| | |
10.40 | — | Amendment No. 1 to Second Amended and Restated Credit Agreement dated as of December 18, 2015, between Williams Partners L.P., Northwest Pipeline LLC, Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on December 23, 2015August 10, 2018, as Exhibit 10.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
| | | |
10.41 | __ | |
| | |
10.42 | — | |
| | |
|
| | |
Exhibit
No. | | Description |
| | |
10.4310.38 | — | |
| | | |
10.4410.39 | — | |
| | |
| 10.40 | — | |
| | |
10.45 | __ | |
| | |
12* | — | |
| | | |
| 14 | — | |
| | | |
| 21* | — | |
| | | |
| 23.1* | — | |
| | | |
| 23.2* | | |
| | | |
| 23.3* | — | |
| | | |
| 31.1* | — | |
| | | |
| 31.2* | — | |
| | | |
| 32** | — | |
| | | |
| 101.INS* | — | XBRL Instance Document. |
| | | |
| 101.SCH* | — | XBRL Taxonomy Extension Schema. |
| | | |
| 101.CAL* | — | XBRL Taxonomy Extension Calculation Linkbase. |
| | | |
|
| | |
Exhibit
No. | | Description |
| | |
| 101.DEF* | — | XBRL Taxonomy Extension Definition Linkbase. |
| | | |
| 101.LAB* | — | XBRL Taxonomy Extension Label Linkbase. |
| | | |
| 101.PRE* | — | XBRL Taxonomy Extension Presentation Linkbase. |
|
| |
| ______________ |
| * | Filed herewith |
| ** | Furnished herewith |
| § | Management contract or compensatory plan or arrangement |
| + | Pursuant to item 601(6)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request. |
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.
|
| | |
THE WILLIAMS COMPANIES, INC. (Registrant) |
| | | |
| By: | | /s/ TED T. TIMMERMANS |
| | | Ted T. Timmermans Vice President, Controller and Chief Accounting Officer |
Date: February 22, 201821, 2019
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
|
| | | | |
| Signature | | Title | | Date |
| | | | | |
| /s/ ALAN S. ARMSTRONG | | President, Chief Executive Officer and Director | | February 22, 201821, 2019 |
| Alan S. Armstrong | | (Principal Executive Officer) | | |
| | | | | |
| /s/ JOHN D. CHANDLER | | Senior Vice President and Chief Financial Officer | | February 22, 201821, 2019 |
| John D. Chandler | | (Principal Financial Officer) | | |
| | | | | |
| /s/ TED T. TIMMERMANS | | Vice President, Controller and Chief Accounting Officer | | February 22, 201821, 2019 |
| Ted T. Timmermans | | (Principal Accounting Officer) | | |
| | | | | |
| /s/ STEPHEN W. BERGSTROM | | Chairman of the Board | | February 22, 201821, 2019 |
| Stephen W. Bergstrom | | | | |
| | | | |
| /s/ NANCY K. BUESE | | Director | | February 21, 2019 |
| Nancy K. Buese | | | | |
| | | | | |
| /s/ STEPHEN I. CHAZEN | | Director | | February 22, 201821, 2019 |
| Stephen I. Chazen | | | | |
| | | | | |
| /s/ CHARLES I. COGUT | | Director | | February 22, 201821, 2019 |
| Charles I. Cogut | | | | |
| | | | | |
| /s/ KATHLEEN B. COOPER | | Director | | February 22, 201821, 2019 |
| Kathleen B. Cooper | | | | |
| | | | | |
| /s/ MICHAEL A. CREEL | | Director | | February 22, 201821, 2019 |
| Michael A. Creel | | | | |
| | | | |
| /s/ VICKI L. FULLER | | Director | | February 21, 2019 |
| Vicki L. Fuller | | | | |
| | | | | |
| /s/ PETER A. RAGAUSS | | Director | | February 22, 201821, 2019 |
| Peter A. Ragauss | | | | |
| | | | |
/s/ SCOTT D. SHEFFIELD | | Director | | February 22, 2018 |
Scott D. Sheffield | | | | |
| | | | |
/s/ MURRAY D. SMITH | | Director | | February 22, 2018 |
Murray D. Smith | | | | |
| | | | | |
|
| | | | |
| Signature | | Title | | Date |
| | | | | |
/s/ WILLIAM H. SPENCESCOTT D. SHEFFIELD | | Director | | February 22, 201821, 2019 |
William H. SpenceScott D. Sheffield | | | | |
| | | | | |
/s/ JANICEMURRAY D. STONEYSMITH | | Director | | February 22, 201821, 2019 |
JaniceMurray D. StoneySmith | | | | |
| | | | |
| /s/ WILLIAM H. SPENCE | | Director | | February 21, 2019 |
| William H. Spence | | | | |
