Exhibit 99.1
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.
Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of December 31, 2017, we account for as an equity-method investment, including principally the following:
Aux Sable: Aux Sable Liquid Products LP
Caiman II: Caiman Energy II, LLC
Discovery: Discovery Producer Services LLC
Gulfstream: Gulfstream Natural Gas System, L.L.C.
Laurel Mountain: Laurel Mountain Midstream, LLC
OPPL: Overland Pass Pipeline Company LLC
UEOM: Utica East Ohio Midstream LLC
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Government and Regulatory:
EPA: Environmental Protection Agency
Exchange Act, the: Securities and Exchange Act of 1934, as amended
FERC: Federal Energy Regulatory Commission
GAAP: Generally accepted accounting principles
IRS: Internal Revenue Service
SEC: Securities and Exchange Commission
Other:
ACMP: Access Midstream Partners, L.P. prior to its merger with Pre-Merger WPZ
Energy Transfer: Energy Transfer Equity, L.P.
ETC: Energy Transfer Corp LP
ETC Merger: Merger wherein Williams would have been merged into ETC
Fractionation: The process by which a mixed stream of natural gas liquids is separated into its constituent products,
such as ethane, propane, and butane
IDR: Incentive distribution right
LNG: Liquefied natural gas; natural gas which has been liquefied at cryogenic temperatures
Merger Agreement: Merger Agreement and Plan of Merger of Williams with Energy Transfer and certain of its
affiliates
MVC: Minimum volume commitment
NGLs: Natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are
used as petrochemical feedstocks, heating fuels, and gasoline additives, among other applications
NGL margins: NGL revenues less Btu replacement cost, plant fuel, transportation, and fractionation
Pre-merger WPZ: Williams Partners L.P. prior to its merger with ACMP
PDH facility: Propane dehydrogenation facility
RGP Splitter: Refinery grade propylene splitter
Throughput: The volume of product transported or passing through a pipeline, plant, terminal, or other facility
The statements in this Annual Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements. Forward-looking statements may be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “guidance,” “outlook,” “in-service date,” or other similar expressions and other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that such expectations or assumptions will be achieved. Additional information regarding forward-looking statements and important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Part I, Item 1A in this Annual Report.
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PART II
Item 6. Selected Financial Data
The following financial data at December 31, 2017 and 2016, and for each of the three years in the period ended December 31, 2017, should be read in conjunction with the other financial information included in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, Financial Statements and Supplementary Data of this Form 10-K. All other financial data has been prepared from our accounting records.
2017 | 2016 | 2015 | 2014 | 2013 | |||||||||||||||
(Millions, except per-share amounts) | |||||||||||||||||||
Revenues (1) | $ | 8,031 | $ | 7,499 | $ | 7,360 | $ | 7,637 | $ | 6,860 | |||||||||
Income (loss) from continuing operations (2) | 2,509 | (350 | ) | (1,314 | ) | 2,335 | 679 | ||||||||||||
Amounts attributable to The Williams Companies, Inc.: | |||||||||||||||||||
Income (loss) from continuing operations (2) | 2,174 | (424 | ) | (571 | ) | 2,110 | 441 | ||||||||||||
Diluted earnings (loss) per common share: | |||||||||||||||||||
Income (loss) from continuing operations (2) | 2.62 | (.57 | ) | (.76 | ) | 2.91 | .64 | ||||||||||||
Total assets at December 31 (3) | 46,352 | 46,835 | 49,020 | 50,455 | 27,065 | ||||||||||||||
Commercial paper and long-term debt due within one year at December 31 (4) | 501 | 878 | 675 | 802 | 226 | ||||||||||||||
Long-term debt at December 31 (3) | 20,434 | 22,624 | 23,812 | 20,780 | 11,276 | ||||||||||||||
Stockholders’ equity at December 31 (3) (5) | 9,656 | 4,643 | 6,148 | 8,777 | 4,864 | ||||||||||||||
Cash dividends declared per common share | 1.200 | 1.680 | 2.450 | 1.958 | 1.438 | ||||||||||||||
(1) | Revenues for 2014 increased reflecting the consolidation of ACMP beginning in third quarter and new Canadian construction management services. |
(2) | Income (loss) from continuing operations: |
• | For 2017 includes a $1.923 billion benefit for income taxes resulting from Tax Reform rate change, a $1.095 billion pre-tax gain on the sale of our Geismar Interest, partially offset by $1.248 billion of pre-tax impairments of certain assets, and $776 million of pre-tax regulatory charges resulting from Tax Reform; |
• | For 2016 includes an $873 million impairment of certain assets and a $430 million impairment of certain equity-method investments; |
• | For 2015 includes a $1.4 billion impairment of certain equity-method investments and a $1.1 billion impairment of goodwill; |
• | For 2014 includes $2.5 billion pre-tax gain recognized as a result of remeasuring to fair value the equity-method investment we held before we acquired a controlling interest in ACMP, $246 million of insurance recoveries related to the 2013 Geismar Incident, and $154 million of cash received related to a contingency settlement. 2014 also includes $78 million of pre-tax equity losses from Bluegrass Pipeline and Moss Lake related primarily to the underlying write-off of previously capitalized project development costs and $76 million of pre-tax acquisition, merger, and transition expenses related to our acquisition of ACMP; |
• | For 2013 includes $99 million of deferred income tax expense incurred on undistributed earnings of our foreign operations that are no longer considered permanently reinvested. |
(3) | The increases in 2014 reflect assets acquired and debt assumed primarily related to our acquisition of ACMP in third quarter as well as $1.9 billion of related debt issuances and $2.8 billion of debt issuances at WPZ. Additionally, we issued $3.4 billion of equity. |
(4) | The increase in 2014 reflects borrowings under WPZ’s commercial paper program, which was initiated in 2013. |
(5) | The increase in 2017 includes our issuance of common stock as part of our Financial Repositioning. |
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas and NGLs. Our operations are located principally in the United States. We have one reportable segment, Williams Partners. All remaining business activities are included in Other.
Williams Partners
Williams Partners consists of our consolidated master limited partnership, WPZ, which includes gas pipeline and midstream businesses. The gas pipeline businesses include interstate natural gas pipelines and pipeline joint project investments; and the midstream businesses provide natural gas gathering, treating, and processing services; NGL production, fractionation, storage, marketing, and transportation; deepwater production handling and crude oil transportation services; and are comprised of several wholly owned and partially owned subsidiaries and joint project investments. As of December 31, 2017, we own 74 percent of the interests in WPZ.
Williams Partners’ gas pipeline businesses consist primarily of Transco and Northwest Pipeline. The gas pipeline business also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent equity-method investment in Gulfstream and a 41 percent interest in Constitution (a consolidated entity), which is developing a pipeline project. (See Note 3 – Variable Interest Entities of Notes to Consolidated Financial Statements.) As of December 31, 2017, Transco and Northwest Pipeline owned and operated a combined total of approximately 13,600 miles of pipelines with a total annual throughput of approximately 4,533 Tbtu of natural gas and peak-day delivery capacity of approximately 18.8 MMdth of natural gas.
Williams Partners’ midstream businesses primarily consist of (1) natural gas gathering, treating, compression, and processing; (2) NGL fractionation, storage, and transportation; (3) crude oil production handling and transportation; and (4) olefins production. (See Note 2 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements.) The primary service areas are concentrated in major producing basins in Colorado, Texas, Oklahoma, Kansas, New Mexico, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio, which include the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, and Utica shale plays as well as the Mid-Continent region.
The midstream businesses include equity-method investments in natural gas gathering and processing assets and NGL fractionation and transportation assets, including a 62 percent equity-method investment in UEOM, a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, a 60 percent equity-method investment in Discovery, a 50 percent equity-method investment in OPPL, and Appalachia Midstream Services, LLC, which owns an approximate average 66 percent equity-method investment interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments), as well as our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see Note 5 – Investing Activities of Notes to Consolidated Financial Statements).
The midstream businesses previously included Canadian midstream operations, which were comprised of an oil sands offgas processing plant near Fort McMurray, Alberta and an NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, these Canadian operations were sold.
Williams Partners’ ongoing strategy is to safely and reliably operate large-scale, interstate natural gas transmission and midstream infrastructures where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers and investing in growing markets and areas of increasing natural gas demand.
Williams Partners’ interstate transmission and related storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have
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limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.
Other
Other is comprised of business activities that are not operating segments, as well as corporate operations. Other also includes certain domestic olefins pipeline assets as well as certain Canadian assets, which included a liquids extraction plant located near Fort McMurray, Alberta, that began operations in March 2016, and a propane dehydrogenation facility which was under development. In September 2016, the Canadian assets were sold.
Financial Repositioning
In January 2017, we entered into agreements with WPZ, wherein we permanently waived the general partner’s IDRs and converted our 2 percent general partner interest in WPZ to a noneconomic interest in exchange for 289 million newly issued WPZ common units. Pursuant to this agreement, we also purchased approximately 277 thousand WPZ common units for $10 million. Additionally, we purchased approximately 59 million common units of WPZ at a price of $36.08586 per unit in a private placement transaction, funded with proceeds from our equity offering (see Note 14 – Stockholders’ Equity of Notes to Consolidated Financial Statements). According to the terms of this agreement, concurrent with WPZ’s quarterly distributions in February 2017 and May 2017, we paid additional consideration totaling $56 million to WPZ for these units. Subsequent to these transactions and as of December 31, 2017, we own a 74 percent limited partner interest in WPZ.
Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto included in Part II, Item 8 of this report.
Dividends
In December 2017, we paid a regular quarterly dividend of $0.30 per share. On February 21, 2018, our board of directors approved a regular quarterly dividend of $0.34 per share payable on March 26, 2018.
Overview
Net income (loss) attributable to The Williams Companies, Inc., for the year ended December 31, 2017, changed favorably by $2.598 billion compared to the year ended December 31, 2016, reflecting a $1.949 billion improvement in the provision (benefit) for income taxes primarily due to Tax Reform, the absence of $430 million of impairments of equity-method investments incurred in 2016, a $219 million increase in Other investing income (loss) – net primarily associated with the disposition of certain equity-method investments in 2017, a $238 million increase in operating income and reduced interest expense, partially offset by a $261 million increase in net income attributable to noncontrolling interests primarily due to increased income at WPZ and an unfavorable change in Other income (expense) – net below Operating income (loss). The increase in operating income reflects a gain of $1.095 billion from the sale of our Geismar Interest, increased service revenue from expansion projects, and lower costs and expenses, partially offset by a $674 million regulatory charge resulting from Tax Reform, a $375 million increase in impairments of certain assets, and a $184 million decrease in product margins primarily due to the loss of olefins volumes as a result of the sale of our Gulf Olefins and Canadian operations.
Tax Reform
In December 2017, the Tax Cuts and Jobs Act was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent (Tax Reform). As a result, we have remeasured our existing deferred income tax assets and liabilities, to reflect the expected future realization of existing temporary differences at the lower income tax rate. This resulted in the recognition of a net income tax provision benefit of $1.923 billion for the year ended December 31, 2017. Certain adjustments within the provision benefit are considered provisional and are potentially subject to change in the future. (See Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements.)
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Transco and Northwest Pipeline have recognized regulatory liabilities to reflect the probable return to customers through future rates of the future decrease in income taxes payable associated with Tax Reform. These liabilities represent an obligation to return amounts directly to our customers. The regulatory liabilities were recorded in December 2017 through regulatory charges to operating income totaling $674 million. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements.) The timing and actual amount of such return will be subject to future negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing service.
Revenue Recognition
As a result of the adoption of Accounting Standards Update 2014-09, Revenues from Contracts with Customers (ASC 606), we expect that our 2018 revenues will increase in situations where we receive noncash consideration, which exists primarily in certain of our gas processing contracts where we receive commodities as full or partial consideration for services provided. This increase in revenues will be offset by a similar increase in costs and expenses when the commodities received are subsequently sold. Based on commodities received during 2017 as consideration for services and market prices during 2017, we estimate the impact to revenues and costs would have been approximately $350 million.
Additionally, we expect future revenues will be impacted by application of the new accounting standard to certain contracts for which we received prepayments for services and have recorded deferred revenue (contract liabilities). For these contracts, which underwent modifications in periods prior to January 1, 2018, the modification is treated as a termination of the existing contract and the creation of a new contract. The new accounting guidance requires that the transaction price, including any remaining deferred revenue from the old contract, be allocated to the performance obligations over the term of the new contract. As a result, we will recognize the deferred revenue over longer periods than application of revenue recognition under accounting guidance prior to January 1, 2018. The application of ASC 606 to prior periods related to these contracts would have resulted in lower revenues in 2016 and 2017. Revenues will also be lower in 2018 and 2019 than what would have been recorded under the previous guidance, offset by increased revenues in later reporting periods given the longer period of recognition.
We are adopting ASC 606 utilizing the modified retrospective transition approach, effective January 1, 2018, by recognizing the cumulative effect of initially applying ASC 606 for periods prior to January 1, 2018, which we expect to result in a decrease of approximately $255 million, net of tax, to the opening balance of Total equity in the Consolidated Balance Sheet. This adjustment is primarily associated with the impact to the timing of deferred revenue (contract liabilities) for certain contracts as noted above.
Pension Deferred Vested Benefit Early Payout Program
In September 2017, we initiated a program to pay out certain deferred vested pension benefits to reduce investment risk, cash funding volatility, and administrative costs. In December 2017, the lump-sum payments were made and the annuity payments were commenced in relation to this program. As a result of these lump-sum payments, as well as lump-sum benefit payments made throughout 2017, settlement accounting was required. We settled $261 million in liabilities and recognized a pre-tax, non-cash settlement charge of $71 million. (See Note 9 – Employee Benefit Plans of Notes to Consolidated Financial Statements.)
Expansion Project Completions
Virginia Southside II
In December 2017, the Virginia Southside II expansion project to the Transco system was placed into service. The project expanded Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from our Station 210 in New Jersey and our Station 165 in Virginia to a new lateral extending from our Brunswick Lateral in Virginia. The project increased capacity by 250 Mdth/d.
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New York Bay Expansion
In October 2017, the New York Bay expansion to the Transco system was placed into service. The project expanded Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point and the Narrows meter station in New York. The project increased capacity by 115 Mdth/d.
Dalton
In August 2017, the Dalton expansion to the Transco system was placed into service. This project expanded Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from our Station 210 in New Jersey to markets in northwest Georgia. On April 1, 2017, we began providing firm transportation service through the mainline portion of the project on an interim basis and we placed the full project into service in August 2017. The project increased capacity by 448 Mdth/d.
Hillabee
In July 2017, Phase I of the Hillabee Expansion Project was placed into service. The project involves an expansion of Transco’s existing natural gas transmission system from our Station 85 in west central Alabama to a new interconnection with the Sabal Trail pipeline in Alabama. The project will be constructed in phases, and all of the project expansion capacity is dedicated to Sabal Trail pursuant to a capacity lease agreement. We placed a portion of Phase I into service in June of 2017 and the remainder of Phase I into service in July of 2017. Phase I increased capacity by 818 Mdth/d. The in-service date of Phase II is planned for the second quarter of 2020 and together they are expected to increase capacity by 1,025 Mdth/d.
In March 2016, WPZ entered into an agreement with the member-sponsors of Sabal Trail to resolve several matters. In accordance with the agreement, the member-sponsors paid us an aggregate amount of $240 million in three equal installments as certain milestones of the project were met. The first $80 million payment was received in March 2016, the second installment was received in September 2016 and the third installment was received in July 2017. WPZ expects to recognize income associated with these receipts over the term of the capacity lease agreement.
In August 2017, the Court of Appeals for the District of Columbia Circuit granted an appeal of the FERC certificate order for the Southeast Market Pipelines projects (a group of related projects, including the Hillabee Expansion Project) filed by certain non-governmental organizations. In doing so, the court (i) remanded the matter to the FERC for preparation of an Environmental Impact Statement (EIS) that conforms with the court’s opinion regarding quantifying certain greenhouse gas emissions, and (ii) vacated the FERC’s certificate order for the projects, which would be effective following the court’s mandate (by court order, the mandate will not issue until after disposition of all petitions for rehearing). We, along with other intervenors, and the FERC filed petitions for rehearing with the court to overturn the remedy that would involve vacating the FERC certificate order, but on January 31, 2018 the court denied the petitions. In compliance with the court’s directive, on February 5, 2018, the FERC issued a Final Supplemental EIS for the projects, reaffirming that while the projects would result in temporary and permanent impacts on the environment, those impacts would not be significant. On February 6, 2018, we, along with other intervenors, and the FERC filed motions with the court to stay the issuance of the mandate in order to give the FERC time to re-issue the authorizations for the projects. The filing of the motions automatically stays the effectiveness of the court’s mandate. If the court’s mandate is issued prior to the FERC re-issuing the authorizations for the projects, we believe that the FERC will take the necessary steps (which may include issuing temporary certificate authority) to avoid any lapse in federal authorization for the projects.
Geismar olefins facility monetization
In July 2017, WPZ completed the sale of its Geismar Interest for $2.084 billion in cash. WPZ received a final working capital adjustment of $12 million in October 2017. Additionally, WPZ entered into a long-term supply and transportation agreement with the purchaser to provide feedstock to the plant via its Bayou Ethane pipeline system, which is expected to provide a long-term, fee-based revenue stream. (See Note 2 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements.)
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Following this sale, the cash proceeds were used to repay WPZ’s $850 million term loan. WPZ has also been using these proceeds to fund a portion of the capital and investment expenditures that are a part of its growth portfolio.
Acquisition of additional interests in Appalachia Midstream Investments
During the first quarter of 2017, WPZ exchanged all of its 50 percent interest in DBJV for an increased interest in two natural gas gathering systems that are part of the Appalachia Midstream Investments and $155 million in cash. Following this exchange, WPZ has an approximate average 66 percent interest in the Appalachia Midstream Investments. WPZ also sold all of its interest in Ranch Westex JV LLC for $45 million. These transactions resulted in a total gain of $269 million reflected in Other investing income (loss) – net in the Consolidated Statement of Operations within the Williams Partners segment. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.)
Commodity Prices
NGL per-unit margins were approximately 62 percent higher in 2017 compared to 2016 due to a 42 percent increase in per-unit non-ethane prices. The per-unit margin increase also reflects the absence of our former Canadian operations which had lower per-unit non-ethane margins in the prior year compared to our domestic operations. These favorable impacts were partially offset by an approximate 26 percent increase in per-unit natural gas feedstock prices.
NGL margins are defined as NGL revenues less any applicable Btu replacement cost, plant fuel, and third-party transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. Our equity volumes include NGLs where we own the rights to the value from NGLs recovered at our plants under both “keep-whole” processing agreements, where we have the obligation to replace the lost heating value with natural gas, and “percent-of-liquids” agreements whereby we receive a portion of the extracted liquids with no obligation to replace the lost heating value.
The following graph illustrates the NGL production and sales volumes, as well as the margin differential between ethane and non-ethane products and the relative mix of those products.
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 |
The potential impact of commodity prices on our business is further discussed in the following Company Outlook.
Company Outlook
Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States. We accomplish this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins. We continue to maintain a strong commitment to safety, environmental stewardship, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe and reliable service to our customers and an attractive return to our shareholders.
Our business plan for 2018 includes a continued focus on growing our fee-based businesses, executing growth projects and accomplishing cost discipline initiatives to ensure operations support our strategy. We anticipate operating results will increase through organic business growth driven primarily by Transco expansion projects and continued growth in the Northeast region. WPZ intends to fund planned growth capital with retained cash flow and debt, and based on currently forecasted projects, does not expect to access public equity markets for the next several years.
Our growth capital and investment expenditures in 2018 are expected to be approximately $2.7 billion. Approximately $1.7 billion of our growth capital funding needs include Transco expansions and other interstate pipeline growth projects, most of which are fully contracted with firm transportation agreements. The remaining growth capital spending in 2018 primarily reflects investment in gathering and processing systems in the Northeast region limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.
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As a result of our significant continued capital and investment expenditures on Transco expansions and fee-based gathering and processing projects, fee-based businesses are a significant component of our portfolio and serve to reduce the influence of commodity price fluctuations on our operating results and cash flows. We expect to benefit as continued growth in demand for low-cost natural gas is driven by increases in LNG exports, industrial demand and power generation. For 2018, current forward market prices indicate oil prices are expected to be higher compared to 2017, while natural gas and NGL prices are expected to be lower or comparable with 2017. We continue to address certain pricing risks through the utilization of commodity hedging strategies. However, some of our customers may continue to curtail or delay drilling plans until there is a more sustained recovery in prices, which may negatively impact our gathering and processing volumes. The credit profiles of certain of our producer customers have been, and may continue to be, challenged as a result of lower energy commodity prices. Unfavorable changes in energy commodity prices or the credit profile of our producer customers may also result in noncash impairments of our assets.
In 2018, our operating results are expected to include increases from our regulated Transco fee-based business, primarily related to projects recently placed in-service or expected to be placed in-service in 2018 including the Atlantic Sunrise project. For our non-regulated businesses, we anticipate increases in fee-based revenue in the Northeast region, partially offset by lower fee-based revenue in the West region. As previously discussed, under the new accounting guidance for revenue recognition, deferred revenue under certain contracts will be recognized over longer periods than under the prior guidance, resulting in a decrease in revenue for the West region. We expect overall gathering and processing volumes to grow in 2018 and increase thereafter to meet the growing demand for natural gas and natural gas products. We also anticipate lower general and administrative expenses due to the full year impact of prior year cost reduction initiatives.
Potential risks and obstacles that could impact the execution of our plan include:
• | Certain aspects of Tax Reform, including regulatory liabilities relating to reduced corporate federal income tax rates, could adversely impact the rates we can charge on our regulated pipelines; |
• | Opposition to infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects; |
• | Unexpected significant increases in capital expenditures or delays in capital project execution; |
• | Counterparty credit and performance risk, including that of Chesapeake Energy Corporation and its affiliates; |
• | Lower than anticipated demand for natural gas and natural gas products which could result in lower than expected volumes, energy commodity prices and margins; |
• | General economic, financial markets, or further industry downturn, including increased interest rates; |
• | Physical damages to facilities, including damage to offshore facilities by named windstorms; |
• | Lower than expected distributions from WPZ; |
• | Production issues impacting offshore gathering volumes; |
• | Other risks set forth under Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2017, as filed with the SEC on February 22, 2018. |
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.
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Expansion Projects
Williams Partners’ ongoing major expansion projects include the following:
Atlantic Sunrise
In February 2017, we received approval from the FERC to expand Transco’s existing natural gas transmission system along with greenfield facilities to provide incremental firm transportation capacity from the northeastern Marcellus producing area to markets along Transco’s mainline as far south as Station 85 in west central Alabama. We placed a portion of the mainline project facilities into service in September 2017 and it increased capacity by 400 Mdth/d. We plan to place the full project into service during mid-2018, assuming timely receipt of all remaining regulatory approvals. The full project is expected to increase capacity by 1,700 Mdth/d.
Constitution Pipeline
We currently own 41 percent of Constitution with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We are the operator of Constitution. The 126-mile Constitution pipeline is proposed to connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York, as well as to a local distribution company serving New York and Pennsylvania.
In December 2014, Constitution received approval from the FERC to construct and operate its proposed pipeline, which will have an expected capacity of 650 Mdth/d. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied the necessary water quality certification under Section 401 of the Clean Water Act for the New York portion of the pipeline. In May 2016, Constitution appealed the NYSDEC’s denial of the Section 401 certification to the United States Court of Appeals for the Second Circuit and in August 2017, the court issued a decision denying in part and dismissing in part Constitution’s appeal. The court expressly declined to rule on Constitution’s argument that the delay in the NYSDEC’s decision on Constitution’s Section 401 application constitutes a waiver of the certification requirement. The court determined that it lacked jurisdiction to address that contention, and found that jurisdiction over the waiver issue lies exclusively with the United States Court of Appeals for the District of Columbia Circuit. As to the denial itself, the court determined that NYSDEC’s action was not arbitrary or capricious. Constitution filed a petition for rehearing with the Second Circuit Court of Appeals, but in October the court denied our petition.
In October 2017, we filed a petition for declaratory order requesting the FERC to find that, by operation of law, the Section 401 certification requirement for the New York State portion of Constitution’s pipeline project was waived due to the failure by the NYSDEC to act on Constitution’s Section 401 application within a reasonable period of time as required by the express terms of such statute. In January 2018, the FERC denied our petition, finding that Section 401 provides that a state waives certification only when it does not act on an application within one year from the date of the application.
The project’s sponsors remain committed to the project, and, in that regard, we are pursuing two separate and independent paths in order to overturn the NYSDEC’s denial of the Section 401 certification. In January 2018, we filed a petition with the United States Supreme Court to review the decision of the Second Circuit Court of Appeals that upheld the merits of the NYSDEC’s denial of the Section 401 certification. And, in February 2018, we filed a request with the FERC for rehearing of its finding that the NYSDEC did not waive the Section 401 certification requirement. If the FERC denies such request, we will file a petition for review with the D.C. Circuit Court of Appeals.
We estimate that the target in-service date for the project would be approximately 10 to 12 months following any court or FERC decision that the NYSDEC denial order was improper or that the NYSDEC waived the Section 401 certification requirement. (See Note 3 – Variable Interest Entities of Notes to Consolidated Financial Statements.)
Garden State
In April 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 210 in New Jersey to a new interconnection
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on our Trenton Woodbury Lateral in New Jersey. The project will be constructed in phases and is expected to increase capacity by 180 Mdth/d. We placed the initial phase of the project into service in September 2017 and plan to place the remaining portion of the project into service during the first quarter of 2018.
Gateway
In November 2017, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from PennEast Pipeline Company's proposed interconnection with Transco’s mainline south of Station 205 in New Jersey to other existing Transco meter stations within New Jersey. We plan to place the project into service in the first quarter of 2021, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 65 Mdth/d.
Gulf Connector
In November 2017, we received approval from the FERC allowing Transco to expand its existing natural gas transmission system to provide incremental firm transportation capacity from Station 65 in Louisiana to delivery points in Wharton and San Patricio Counties, Texas. The project will be constructed in two phases and we plan to place both phases into service during the first half of 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 475 Mdth/d.
Hillabee
In February 2016, the FERC issued a certificate order for the initial phases of Transco’s Hillabee Expansion Project. The project involves an expansion of Transco’s existing natural gas transmission system from Station 85 in west central Alabama to a new interconnection with the Sabal Trail pipeline in Alabama. The project will be constructed in phases, and all of the project expansion capacity will be leased to Sabal Trail. We placed a portion of Phase I into service in June of 2017 and the remainder of Phase I into service in July of 2017. Phase I increased capacity by 818 Mdth/d. The in-service date of Phase II is planned for the second quarter of 2020 and together they are expected to increase capacity by 1,025 Mdth/d. See Expansion Project Completions within Overview.
Norphlet Project
In March 2016, we announced that we have reached an agreement to provide deepwater gas gathering services to the Appomattox development in the Gulf of Mexico. The project will provide offshore gas gathering services to our existing Transco lateral, which will provide transmission services onshore to our Mobile Bay processing facility. We also plan to make modifications to our Main Pass 261 Platform to install an alternate delivery route from the platform, as well as modifications to our Mobile Bay processing facility. The project is scheduled to go into service during the second half of 2019.
North Seattle Lateral Upgrade
In May 2017, we filed an application with the FERC to expand delivery capabilities on Northwest Pipeline’s North Seattle Lateral. The project consists of the removal and replacement of approximately 5.9 miles of 8-inch diameter pipeline with new 20-inch diameter pipeline. We plan to place the project into service as early as the fourth quarter of 2019. The project is expected to increase capacity by up to 159 Mdth/d.
Northeast Supply Enhancement
In March 2017, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point in New York. We plan to place the project into service in late 2019 or during the first half of 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 400 Mdth/d.
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Ohio River Supply Hub Expansion
We agreed to expand our services to a customer to provide 660 MMcf/d of processing wet gas capacity in the Marcellus and Upper Devonian Shale in West Virginia. Associated with this agreement, we expect to further expand the processing capacity of our Oak Grove facility, which has the ability to increase capacity by an additional 1.8 Bcf/d. Additionally, with the same customer, we secured a gathering dedication agreement to gather dry gas in this same region. These expansions will be supported by long-term, fee-based agreements and volumetric commitments.
Rivervale South to Market
In August 2017, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the existing Rivervale interconnection with Tennessee Gas Pipeline on Transco’s North New Jersey Extension to other existing Transco locations within New Jersey. We plan to place the project into service as early as the fourth quarter of 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 190 Mdth/d.
Susquehanna Supply Hub Expansion
The Susquehanna Supply Hub Expansion, which involves two new compression facilities with an additional 49,000 horsepower and 59 miles of 12 inch to 24 inch pipeline, is expected to increase gathering capacity, allowing a certain producer to fulfill its commitment to deliver 850 Mdth/d to our Atlantic Sunrise development. We placed a portion of this project into service in January 2018 and anticipate this expansion will be fully commissioned in the first quarter of 2018.
Critical Accounting Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.
Pension and Postretirement Obligations
We have employee benefit plans that include pension and other postretirement benefits. Net periodic benefit cost and obligations for these plans are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, expected rate of compensation increase, health care cost trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed. The assumptions utilized to compute cost and the benefit obligations are shown in Note 9 – Employee Benefit Plans of Notes to Consolidated Financial Statements.
The following table presents the estimated increase (decrease) in net periodic benefit cost and obligations resulting from a one-percentage-point change in the specific assumption.
Benefit Cost | Benefit Obligation | ||||||||||||||
One- Percentage- Point Increase | One- Percentage- Point Decrease | One- Percentage- Point Increase | One- Percentage- Point Decrease | ||||||||||||
(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 | ) | ||||||||||
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Our expected long-term rates of return on plan assets, as determined at the beginning of each fiscal year, are based on the average rate of return expected on the funds invested in the plans. We determine our long-term expected rates of return on plan assets using our expectations of capital market results, which include an analysis of historical results as well as forward-looking projections. These capital market expectations are based on a period of at least 10 years and take into account our investment strategy and mix of assets. We develop our expectations using input from our third-party independent investment consultant. The forward-looking capital market projections start with current conditions of interest rates, equity pricing, economic growth, and inflation and those are overlaid with forward looking projections of normal inflation, growth, and interest rates to determine expected returns. The capital market return projections for specific asset classes in the investment portfolio are then applied to the relative weightings of the asset classes in the investment portfolio. The resulting rates are an estimate of future results and, thus, likely to be different than actual results.
In 2017, the benefit plans’ assets outperformed their respective benchmarks for fixed income strategies, but generally underperformed the respective benchmarks for equity strategies. While the 2017 investment performance was greater than our expected rates of return, the expected rates of return on plan assets are long-term in nature and are not significantly impacted by short-term market performance. Changes to our asset allocation would also impact these expected rates of return. Our expected long-term rate of return on plan assets used for our pension plans was 6.45 percent in 2017. The 2017 actual return on plan assets for our pension plans was approximately 15.5 percent. The 10-year average rate of return on pension plan assets through December 2017 was approximately 4.3 percent.
The discount rates are used to measure the benefit obligations of our pension and other postretirement benefit plans. The objective of the discount rates is to determine the amount, if invested at the December 31 measurement date in a portfolio of high-quality debt securities, that will provide the necessary cash flows when benefit payments are due. Increases in the discount rates decrease the obligation and, generally, decrease the related cost. The discount rates for our pension and other postretirement benefit plans are determined separately based on an approach specific to our plans and their respective expected benefit cash flows as described in Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies and Note 9 – Employee Benefit Plans of Notes to Consolidated Financial Statements. Our discount rate assumptions are impacted by changes in general economic and market conditions that affect interest rates on long-term, high-quality debt securities as well as by the duration of our plans’ liabilities.
The expected rate of compensation increase represents average long-term salary increases. An increase in this rate causes the pension obligation and cost to increase.
The assumed health care cost trend rates are based on national trend rates adjusted for our actual historical cost rates and plan design. An increase in this rate causes the other postretirement benefit obligation and cost to increase.
Property, Plant, and Equipment and Other Identifiable Intangible Assets
We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events or changes in circumstances indicate, in our judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.
During the third quarter of 2017, we received solicitations and engaged in negotiations for the sale of certain gas gathering assets within the Mid-Continent region. As a result of these events, we evaluated the Mid-Continent asset group, which includes property, plant, and equipment and intangible assets, for impairment. Our evaluation considered the likelihood of divesting certain assets within the Mid-Continent region as well as information developed from the negotiation process that impacted our estimate of future cash flows associated with these assets. The estimated undiscounted future cash flows were determined to be below the carrying amount for these assets. We computed the
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estimated fair value using an income approach and incorporated market inputs based on ongoing negotiations for the potential sale of a portion of the underlying assets. For the income approach, we utilized a discount rate of 10.2 percent, reflecting an estimated cost of capital and risks associated with the underlying assets. As a result of this evaluation, we recorded an impairment charge of $1.019 billion for the difference between the estimated fair value and carrying amount of these assets.
Judgments and assumptions are inherent in estimating undiscounted future cash flows, fair values, and the probability-weighting of possible outcomes. The use of alternate judgments and assumptions could result in a different determination affecting the consolidated financial statements.
Equity-Method Investments
At December 31, 2017, our Consolidated Balance Sheet includes approximately $6.6 billion of investments that are accounted for under the equity-method of accounting. We evaluate these investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. We continue to monitor our equity-method investments for any indications that the carrying value may have experienced an other-than-temporary decline in value. When evidence of a loss in value has occurred, we compare our estimate of the fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We generally estimate the fair value of our investments using an income approach where significant judgments and assumptions include expected future cash flows and the appropriate discount rate. In some cases, we may utilize a form of market approach to estimate the fair value of our investments.
If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge. Events or changes in circumstances that may be indicative of an other-than-temporary decline in value will vary by investment, but may include:
• | A significant or sustained decline in the market value of an investee; |
• | Lower than expected cash distributions from investees; |
• | Significant asset impairments or operating losses recognized by investees; |
• | Significant delays in or lack of producer development or significant declines in producer volumes in markets served by investees; |
• | Significant delays in or failure to complete significant growth projects of investees. |
As of December 31, 2017, the carrying value of our equity-method investment in Discovery is $534 million. During the fourth quarter of 2017, certain customers of Discovery terminated a significant offshore gas gathering agreement following the shut-in of production after the associated wells ceased flowing. As a result, we evaluated this investment for impairment and determined that no impairment was necessary.
We estimated the fair value of our investment in Discovery using an income approach that primarily considered probability-weighted assumptions of additional commercial development, the continued operation of the business under existing contracts, and a discount rate of 11.3 percent. Higher probabilities were generally assigned to those commercial development opportunities that were more advanced in the discussion and contracting process, utilizing existing infrastructure due to producer capital constraints, and/or we believe Discovery has a competitive advantage due to geographical proximity to the prospect. The estimated fair value of our investment in Discovery exceeded its carrying value by approximately 6 percent and thus no impairment was necessary.
Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and additional development probabilities. It is reasonably possible that an impairment could be required in the future if commercial development activities are not as successful or as timely as assumed. The use of alternate judgments and assumptions
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could result in a different calculation of fair value, which could ultimately result in the recognition of an impairment charge in the consolidated financial statements.
Constitution Pipeline Capitalized Project Costs
As of December 31, 2017, Property, plant, and equipment – net in our Consolidated Balance Sheet includes approximately $381 million of capitalized project costs for Constitution, for which we are the construction manager and own a 41 percent consolidated interest. As a result of the events discussed in Company Outlook, we evaluated the capitalized project costs for impairment as recently as December 31, 2017, and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including scenarios assuming construction of the pipeline, as well as a scenario where the project does not proceed. These scenarios included our most recent estimate of total construction costs. The probability-weighted scenarios also considered our assessment of the likelihood of success of the two separate and independent paths to obtain necessary certification, as described in Company Outlook. It is reasonably possible that future unfavorable developments, such as a reduced likelihood of success, increased estimates of construction costs, or further significant delays, could result in a future impairment.
Regulatory Liabilities resulting from Tax Reform
In December 2017, Tax Reform was enacted, which, among other things, reduced the corporate income tax rate from 35 percent to 21 percent. Rates charged to customers of our regulated natural gas pipelines are subject to the rate-making policies of the FERC, which permit the recovery of an income tax allowance that includes a deferred income tax component. As a result of the reduced income tax rate from Tax Reform and the collection of historical rates that reflected historical federal income tax rates, we expect that our regulated natural gas pipelines will be required to return amounts to certain customers through future rates and have established regulatory liabilities accordingly. These liabilities were recorded in December 2017 through regulatory charges to operating income totaling $674 million. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements.) The timing and actual amount of such return will be subject to future negotiations regarding this matter and many other elements of cost–of–service rate proceedings, including other costs of providing service.
Our estimation of these regulatory liabilities incorporated the following significant judgments and assumptions involving income taxes collected from our customers.
• | We utilized current FERC guidance for the default income tax rate for non-corporate taxpayers, which is an element of our overall effective tax rate. It is possible that the FERC will provide updated implementation guidance in the future, including an updated default income tax rate for non-corporate taxpayers. We estimate that a decline of one percentage point in our assumed overall effective tax rate would increase our regulatory liabilities by approximately $42 million. |
• | We made assumptions regarding the allocation of WPZ taxable income between corporate and non-corporate taxpayers. This allocation is subject to annual variation that could impact the weighted average federal tax component of the overall income tax allowance rate. |
• | We made assumptions regarding the allocation of WPZ taxable income among the states in which WPZ conducts business. This allocation is subject to annual variation that could impact the weighted average state tax component of the overall income tax allowance rate. It is possible that certain states may change their income tax laws and/or rates in the future in response to Tax Reform. |
• | In determining the estimated liability that we currently believe is probable of return to customers through future rates, we considered the mix of services provided by our regulated natural gas pipelines, taking into consideration that certain of these services are provided under contractually-based rates, in lieu of recourse-based rates. The contractually-based rates are designed to recover the cost of providing those services, with |
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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.
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Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2017. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
Years Ended December 31, | |||||||||||||||||||||||
2017 | $ Change from 2016* | % Change from 2016* | 2016 | $ Change from 2015* | % Change from 2015* | 2015 | |||||||||||||||||
(Millions) | |||||||||||||||||||||||
Revenues: | |||||||||||||||||||||||
Service revenues | $ | 5,312 | +141 | +3 | % | $ | 5,171 | +7 | — | % | $ | 5,164 | |||||||||||
Product sales | 2,719 | +391 | +17 | % | 2,328 | +132 | +6 | % | 2,196 | ||||||||||||||
Total revenues | 8,031 | 7,499 | 7,360 | ||||||||||||||||||||
Costs and expenses: | |||||||||||||||||||||||
Product costs | 2,300 | -575 | -33 | % | 1,725 | +54 | +3 | % | 1,779 | ||||||||||||||
Operating and maintenance expenses | 1,576 | +16 | +1 | % | 1,592 | +67 | +4 | % | 1,659 | ||||||||||||||
Depreciation and amortization expenses | 1,736 | +27 | +2 | % | 1,763 | -25 | -1 | % | 1,738 | ||||||||||||||
Selling, general, and administrative expenses | 594 | +128 | +18 | % | 722 | +14 | +2 | % | 736 | ||||||||||||||
Impairment of goodwill | — | — | — | % | — | +1,098 | +100 | % | 1,098 | ||||||||||||||
Impairment of certain assets | 1,248 | -375 | -43 | % | 873 | -664 | NM | 209 | |||||||||||||||
Gain on sale of Geismar Interest | (1,095 | ) | +1,095 | NM | — | — | — | % | — | ||||||||||||||
Regulatory charges resulting from Tax Reform | 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 | |||||||||||||||
Total costs and expenses | 7,104 | 6,810 | 7,133 | ||||||||||||||||||||
Operating income (loss) | 927 | 689 | 227 | ||||||||||||||||||||
Equity earnings (losses) | 434 | +37 | +9 | % | 397 | +62 | +19 | % | 335 | ||||||||||||||
Impairment of equity-method investments | — | +430 | +100 | % | (430 | ) | +929 | +68 | % | (1,359 | ) | ||||||||||||
Other investing income (loss) – net | 282 | +219 | NM | 63 | +36 | +133 | % | 27 | |||||||||||||||
Interest expense | (1,083 | ) | +96 | +8 | % | (1,179 | ) | -135 | -13 | % | (1,044 | ) | |||||||||||
Other income (expense) – net | (25 | ) | -110 | NM | 85 | -16 | -16 | % | 101 | ||||||||||||||
Income (loss) before income taxes | 535 | (375 | ) | (1,713 | ) | ||||||||||||||||||
Provision (benefit) for income taxes | (1,974 | ) | +1,949 | NM | (25 | ) | -374 | -94 | % | (399 | ) | ||||||||||||
Net income (loss) | 2,509 | (350 | ) | (1,314 | ) | ||||||||||||||||||
Less: Net income (loss) attributable to noncontrolling interests | 335 | -261 | NM | 74 | -817 | NM | (743 | ) | |||||||||||||||
Net income (loss) attributable to The Williams Companies, Inc. | $ | 2,174 | $ | (424 | ) | $ | (571 | ) | |||||||||||||||
_______
* | + = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200. |
2017 vs. 2016
Service revenues increased due to higher transportation fee revenues at Transco and in the eastern Gulf reflecting expansion projects placed in-service in 2016 and 2017; partially offset by a decrease in gathering, processing, and fractionation revenue including lower rates, primarily in the Barnett Shale region associated with the restructuring of
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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 decreased primarily due to the absence of costs associated with our former Canadian and Gulf Olefins operations and lower labor-related costs resulting from our workforce reductions that occurred late in first-quarter 2016, and ongoing cost containment efforts, partially offset by higher pipeline integrity testing and general maintenance at Transco.
Depreciation and amortization expenses decreased primarily due to the absence of our former Canadian and Gulf Olefins operations, partially offset by new assets placed in-service.
Selling, general, and administrative expenses (SG&A) decreased primarily due to the absence of certain project development costs associated with the Canadian PDH facility that were expensed in 2016, lower labor-related costs resulting from our workforce reductions that occurred late in first-quarter 2016, ongoing cost containment efforts, lower strategic development costs, and the absence of costs associated with our former Canadian and Gulf Coast operations. These decreases were partially offset by higher severance and organizational realignment costs in 2017 (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements).
The unfavorable change in Impairment of certain assets reflects 2017 impairments of certain gathering operations in the Mid-Continent and Marcellus South regions, certain NGL pipeline assets, and an olefins pipeline project in the Gulf coast region. These 2017 impairments are partially offset by the absence of 2016 impairments of our former Canadian operations and certain Mid-Continent assets (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
The Gain on sale of Geismar Interest reflects the gain recognized on the sale of our Geismar Interest in July 2017. (See Note 2 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements.)
Regulatory charges resulting from Tax Reform relates to the recognition of regulatory liabilities for the probable return to customers through future rates of the future decrease in income taxes payable associated with Tax Reform. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements).
The favorable change in Other (income) expense – net within Operating income (loss) includes the absence of the 2016 loss on the sale of our Canadian operations, gains from certain contract settlements and terminations in 2017, a gain on the sale of our RGP Splitter in 2017, and the absence of an unfavorable change in foreign currency exchange associated with our former Canadian operations. These favorable changes are partially offset by additional expense associated with an annual revision to the ARO liability, accrual of additional expenses in 2017 related to the Geismar Incident, as well as the absence of a gain in first-quarter 2016 associated with the sale of unused pipe.
Operating income (loss) changed favorably primarily due to the Gain on sale of Geismar Interest, the absence of the 2016 impairments of certain Mid-Continent assets and our former Canadian operations, higher service revenues primarily from expansion projects placed in-service in 2016 and 2017, the absence of expensed Canadian PDH facility project development costs in 2016, as well as ongoing cost containment efforts, including workforce reductions in first-quarter 2016. Operating income (loss) also improved due to the absence of a 2016 loss on the sale of our Canadian operations, the absence of an operating loss associated with our former Canadian operations, gains from certain contract settlements and the sale of our RGP Splitter. These favorable changes were partially offset by 2017 impairments of certain gathering operations in the Mid-Continent and Marcellus South regions, regulatory charges resulting from Tax
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Reform, and certain NGL pipeline assets, as well as the absence of operating income associated with our former Gulf Olefins operations.
The favorable change in Equity earnings (losses) is due to an increase in ownership of our Appalachia Midstream Investments and improved results at Aux Sable due to favorable pricing and higher volumes, partially offset by lower UEOM results driven by lower processing volumes from the Utica gathering system and lower Discovery results due to lower volumes.
The decrease in Impairment of equity-method investments reflects the absence of 2016 impairment charges associated with our Appalachia Midstream Investments, DBJV, Laurel Mountain, and Ranch Westex equity-method investments. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)
Other investing income (loss) – net reflects the gain on disposition of our investments in DBJV and Ranch Westex JV LLC in 2017, partially offset by the absence of interest income received in 2016 associated with a receivable related to the sale of certain former Venezuelan assets and the absence of a 2016 gain on the sale of an equity-method investment interest in a gathering system that was part of our Appalachia Midstream Investments. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements).
Interest expense decreased primarily due to lower Interest incurred primarily attributable to debt retirements in 2017 and lower borrowings on our credit facilities in 2017. (See Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)
Other income (expense) – net below Operating income (loss) changed unfavorably primarily due to charges reducing regulatory assets related to deferred taxes on equity funds used during construction (AFUDC) resulting from Tax Reform and a settlement charge from a pension early payout program (see Note 9 – 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 5 – Other Income and Expenses of Notes to Consolidated Financial Statements.)
Provision (benefit) for income taxes changed favorably primarily due to a reduction in the federal statutory rate from 35 percent to 21 percent with the enactment of Tax Reform. The remeasurement of our existing deferred tax assets and liabilities at the reduced rate resulted in the recognition of a net income tax provision benefit of $1.923 billion. Adjustments within this provision benefit are considered provisional and are potentially subject to change in the future. See Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to the impact of decreased income allocated to us driven by the permanent waiver of IDRs and higher operating results at WPZ, partially offset by a decrease in the ownership of the noncontrolling interests. Both the permanent waiver of IDRs and the change in ownership are associated with the first-quarter 2017 Financial Repositioning (see Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements). In addition, improved results in our Gulfstar operations also contributed to the increase in Net income (loss) attributable to noncontrolling interests, partially offset by lower results for our Cardinal gathering system.
2016 vs. 2015
Service revenues increased slightly primarily due to expansion projects placed in service in 2015 and 2016, partially offset by a decrease in gathering, processing, and fractionation revenue primarily due to lower volumes in the Barnett Shale and Anadarko basin.
Product sales increased primarily due to higher olefin sales reflecting increased volumes at our former Geismar plant as a result of the plant operating at higher production levels in 2016, partially offset by a decrease from our other olefin operations associated with lower volumes and per-unit sales prices. Product sales also reflect higher marketing revenues associated with higher NGL and propylene prices and natural gas and crude oil volumes, partially offset by lower NGL volumes, and crude oil prices.
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The decrease in Product costs includes lower olefin feedstock purchases and lower costs associated with other product sales, partially offset by higher marketing purchases primarily due to the same factors that increased marketing sales. The decline in olefin feedstock purchases is primarily associated with lower per-unit feedstock costs and volumes at our other olefin operations, partially offset by an increase in olefin feedstock purchases at our former Geismar plant reflecting increased volumes resulting from higher production levels in 2016.
Operating and maintenance expenses decreased primarily due to lower labor-related and outside service costs resulting from our first-quarter 2016 workforce reductions and cost containment efforts and lower costs associated with general maintenance activities in the Marcellus Shale, as well as the absence of ACMP transition-related costs recognized in 2015. These decreases are partially offset by $16 million of severance and related costs recognized in 2016 and higher pipeline testing and general maintenance costs at Transco.
Depreciation and amortization expenses increased primarily due to depreciation on new assets placed in service, including Transco pipeline projects, partially offset by lower depreciation related to Canadian operations sold in 2016.
SG&A decreased primarily due to lower merger and transition costs associated with the ACMP merger and lower labor-related costs resulting from our first-quarter 2016 workforce reductions and cost containment efforts. These decreases were partially offset by certain project development costs associated with the Canadian PDH facility that we began expensing in 2016, as well as $26 million of severance and related costs recognized in 2016 and $17 million of higher costs associated with our evaluation of strategic alternatives.
Impairment of goodwill decreased due to the absence of a 2015 impairment charge associated with certain goodwill. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)
Impairment of certain assets reflects 2016 impairments of our Canadian operations and certain Mid-Continent assets, and other assets. Impairments recognized in 2015 relate primarily to previously capitalized development costs and surplus equipment write-downs. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)
Insurance recoveries – Geismar Incident changed unfavorably reflecting the receipt of $126 million of insurance proceeds in the second quarter of 2015, as compared to the receipt of $7 million of proceeds in the fourth quarter of 2016.
The unfavorable change in Other (income) expense – net within Operating income (loss) includes a loss on the sale of our Canadian operations that were sold in September 2016, project development costs at Constitution as we discontinued capitalization of these costs in April 2016, and an unfavorable change in foreign currency exchange that primarily relates to losses incurred on foreign currency transactions and the remeasurement of the U.S. dollar-denominated current assets and liabilities within our former Canadian operations, partially offset by a $10 million gain on the sale of idle pipe in 2016.
Operating income (loss) changed favorably primarily due to the absence of a goodwill impairment in 2015, higher olefin margins related to the Geismar plant operating at higher production levels in 2016, lower costs related to the merger and integration of ACMP, and lower costs and expenses primarily associated with cost containment efforts. These favorable changes are partially offset by impairments and loss on sale of certain assets in 2016, a decrease in insurance proceeds received, expensed Canadian PDH facility project development costs, and higher depreciation expenses related to new projects placed in service.
Equity earnings (losses) changed favorably primarily due to a $30 million increase at Discovery driven by the completion of the Keathley Canyon Connector in the first quarter of 2015. Additionally, OPPL, Laurel Mountain, and DBJV improved $16 million, $11 million, and $10 million, respectively.
Impairment of equity-method investments reflects 2016 impairment charges associated with our Appalachia Midstream Investments, DBJV, Laurel Mountain, and Ranch Westex equity-method investments, while the 2015 impairment charges relate to our equity-method investments in Appalachia Midstream Investments, DBJV, UEOM, and Laurel Mountain. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.)
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Other investing income (loss) – net changed favorably due to a 2016 gain on the sale of an equity-method investment interest in a gathering system that was part of our Appalachia Midstream Investments and higher interest income associated with a receivable related to the sale of certain former Venezuela assets. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.)
Interest expense increased due to higher Interest incurred of $99 million primarily attributable to new debt issuances in 2016 and 2015 and lower Interest capitalized of $36 million primarily related to construction projects that have been placed into service, partially offset by lower interest due to 2015 and 2016 debt retirements. (See Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)
Other income (expense) – net below Operating income (loss) changed unfavorably primarily due to a decrease in AFUDC due to decreased spending on Constitution and the absence of a $14 million gain on early debt retirement in 2015.
Provision (benefit) for income taxes changed unfavorably primarily due to a decrease in pre-tax loss in 2016. See Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both years.
The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to higher operating results at WPZ, the impact of decreased income allocated to the WPZ general partner driven by the impact of reduced incentive distributions from WPZ, and the absence of the accelerated amortization of a beneficial conversion feature from the first quarter of 2015. These changes are partially offset by a favorable change primarily related to our partners’ share of Constitution project development costs in 2016.
Year-Over-Year Operating Results – Segments
We evaluate segment operating performance based upon Modified EBITDA. Note 18 – Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.
Williams Partners
Years Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(Millions) | |||||||||||
Service revenues | $ | 5,292 | $ | 5,173 | $ | 5,135 | |||||
Product sales | 2,718 | 2,318 | 2,196 | ||||||||
Segment revenues | 8,010 | 7,491 | 7,331 | ||||||||
Product costs | (2,300 | ) | (1,728 | ) | (1,779 | ) | |||||
Other segment costs and expenses | (2,124 | ) | (2,203 | ) | (2,229 | ) | |||||
Net insurance recoveries – Geismar Incident | 9 | 7 | 126 | ||||||||
Gain on sale of Geismar Interest | 1,095 | — | — | ||||||||
Impairment of certain assets | (1,156 | ) | (457 | ) | (145 | ) | |||||
Regulatory charges resulting from Tax Reform | (713 | ) | — | — | |||||||
Proportional Modified EBITDA of equity-method investments | 795 | 754 | 699 | ||||||||
Williams Partners Modified EBITDA | $ | 3,616 | $ | 3,864 | $ | 4,003 | |||||
NGL margin | $ | 203 | $ | 169 | $ | 159 | |||||
Olefin margin | 126 | 337 | 226 | ||||||||
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2017 vs. 2016
Modified EBITDA decreased primarily due to $713 million of regulatory charges associated with the impact of Tax Reform for Transco and Northwest Pipeline, impairments of certain gathering operations in 2017 and lower olefin margins due to the sale of our Gulf Olefins operations early in the third quarter of 2017 and $35 million of expense in 2017 related to a settlement charge from a pension early payout program (see Note 9 – Employee Benefit Plans of Notes to Consolidated Financial Statements). These decreases are partially offset by the $1.095 billion gain on the sale of our Geismar Interest in third-quarter 2017, the absence of impairments of our former Canadian operations and certain gathering assets in the Mid-Continent region in 2016, the absence of a loss on the sale of our former Canadian operations in third-quarter 2016, higher service revenues, lower segment costs and expenses, and higher Proportional Modified EBITDA of equity-method investments.
Service revenues increased primarily due to:
• | Transco’s natural gas transportation fee revenues increased $135 million primarily due to a $150 million increase associated with expansion projects placed in-service in 2016 and 2017, partially offset by lower volume-based transportation services revenues; |
• | Higher eastern Gulf Coast region revenue of $103 million associated primarily with higher volumes, including the impact of new volumes at Gulfstar One related to the Gunflint expansion placed in-service in the third quarter of 2016, the absence of the temporary shut-down and subsequent ramp-up of Gulfstar One in the second and third quarters of 2016 to tie-in Gunflint and the absence of producers’ operational issues in the Tubular Bells field during the first quarter of 2016. This increase is partially offset by lower volumes as a result of a temporary increase in 2016 due to disrupted operations of a competitor; |
• | A $39 million increase related to the amortization of deferred revenue associated with the up-front cash payment received in conjunction with the fourth quarter 2016 Barnett Shale contract restructuring; |
• | A $15 million increase in Transco’s storage revenue primarily reflecting the absence of an accrual for potential refunds associated with a ruling received in certain rate case litigation in 2016; |
• | In the Northeast region, a slight increase reflecting a $38 million increase in gathering fee revenue at Susquehanna Supply Hub driven by 11 percent higher gathered volumes reflecting increased customer production and a $23 million increase in fee revenue at Ohio Valley Midstream reflecting the absence of shut-in volumes from the first half of 2016, as well as new production coming online. The increases were substantially offset by a $56 million decrease in the Utica gathering system primarily due to 14 percent lower gathered volumes driven by natural declines in the wet gas areas which are partially offset by higher volumes from new development in the dry gas areas; |
• | A $79 million decrease in the West region related to net lower gathering rates in the Barnett Shale area primarily due to the fourth quarter 2016 contract restructuring, along with lower rates recognized in the Niobrara, Eagle Ford Shale, and Haynesville Shale regions. These rate decreases are offset by higher commodity-based fee revenues in the Piceance area primarily due to higher per-unit NGL margins and higher rates in the Wamsutter area as a result of renegotiated rates in conjunction with infrastructure expansions. Rates recognized in the Niobrara region represent a portion of the total contractual rate that is received, with the difference reflected as deferred revenue; |
• | A $34 million decrease driven by lower volumes in the West region primarily as a result of natural declines and more extreme weather conditions in the Rocky Mountains in the first quarter of 2017, partially offset by higher volumes in the Haynesville Shale region as a result of increased drilling in certain areas; |
• | A $36 million decrease due to the absence of revenue generated by our former Canadian operations that were sold in September 2016; |
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• | A $15 million decrease in western Gulf Coast region fee revenues due to lower volumes primarily associated with producer maintenance. |
Product sales increased primarily due to:
• | A $735 million increase in marketing revenues primarily due to significantly higher prices across all products and higher NGL volumes (substantially offset in marketing purchases); |
• | A $32 million increase in revenues from our equity NGLs including a $102 million increase driven primarily by higher non-ethane prices, partially offset by a $36 million decrease due to the absence of NGL production revenues associated with our former Canadian operations and a $34 million decrease primarily related to lower non-ethane volumes at our domestic plants driven by the absence of temporary volumes in 2016 related to disrupted operations of a competitor, severe winter conditions in the first quarter of 2017, and natural declines; |
• | A $12 million increase in system management gas sales from Transco. System management gas sales are offset in Product costs and, therefore, have no impact on Modified EBITDA; |
• | A $380 million decrease in olefin sales primarily due to a $343 million decrease reflecting the absence of third- and fourth-quarter sales of our Gulf Olefins operations, a $29 million decrease due to the sale of the Canadian operations in 2016, and a $16 million decrease at our Geismar plant in the first half of 2017 primarily due to lower volumes associated with the electrical outage in second-quarter 2017, as well as planned maintenance downtime in first-quarter 2017. These items were partially offset by $8 million higher sales at the RGP Splitter in the first half 2017 primarily due to higher propylene prices. |
Product costs increased primarily due to:
• | A $725 million increase in marketing purchases primarily due to the same factors that increased marketing sales (more than offset in marketing revenues). The increase in marketing costs does not reflect the intercompany costs associated with certain gathering and processing services performed by an affiliate; |
• | A $12 million increase in system management gas costs (offset in Product sales); |
• | A $166 million decrease in olefin feedstock purchases primarily due to the absence of $163 million in feedstock purchases in the second half of 2017 reflecting the sale of the Gulf Olefins operations, as well as the absence of $9 million in costs associated with our former Canadian operations, partially offset by $6 million higher feedstock costs in the first half of 2017. |
• | A $2 million decrease in costs from our equity NGLs including a $35 million increase driven primarily by higher gas prices, partially offset by a $24 million decrease due to the absence of NGL production revenues associated with our former Canadian operations and a $13 million decrease primarily related to lower volumes at our domestic plants driven by severe winter conditions in the first quarter of 2017, and the absence of temporary volumes in 2016 related to disrupted operations of a competitor and natural declines. |
The favorable change in Other segment costs and expenses includes a decrease in labor-related expenses primarily due to our first quarter 2016 workforce reduction and ongoing cost containment efforts; the absence of $117 million of operating and other expenses associated with our Gulf Olefins and Canadian operations; and the absence of a $34 million loss on the sale of our former Canadian operations. Additional favorable changes in Other segment costs and expenses include a $27 million net gain associated with early debt retirement; a $15 million gain related to favorable contract settlements and terminations; a favorable change in equity AFUDC, primarily associated with an increase in Transco’s capital spending, which is partially offset by a decrease in capital spending at Constitution; and a $12 million gain on the sale of the RGP Splitter. These decreases are partially offset by $35 million of expense in 2017 related to a settlement charge from a pension early payout program (see Note 9 – Employee Benefit Plans of Notes to Consolidated Financial Statements), higher various maintenance expenses, an increase in pipeline integrity testing on Transco, and higher Geismar selling expenses and repairs related to a Geismar electrical outage.
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Gain on sale of Geismar Interest reflects the gain recognized on the sale of our Geismar Interest in July 2017. (See Note 2 - Acquisitions and Divestitures of Notes to Consolidated Financial Statements.)
Impairment of certain assets increased primarily due to a $1.032 billion impairment of certain gathering operations primarily in the Mid-Continent region and a $115 million impairment of certain gathering operations in the Marcellus South region, partially offset by the absence of a $341 million impairment of our former Canadian operations and a $100 million impairment of certain Mid-Continent gathering assets and impairments or write-downs of other certain assets that may no longer be in use or are surplus in nature during 2016. (See Note 16 - Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)
Regulatory charges resulting from Tax Reform reflects $713 million of regulatory charges associated with the impact of Tax Reform at Transco and Northwest Pipeline with $674 million presented as Regulatory charges resulting from Tax Reform and $39 million included within Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations.
The increase in Proportional Modified EBITDA of equity-method investments includes a $100 million increase at Appalachia Midstream Investments reflecting our increased ownership acquired late in the first quarter of 2017, higher gathering volumes reflecting the absence of shut-in volumes from 2016 and increased customer production, and a $20 million increase at Aux Sable due to increased customer production. These increases are partially offset by a $34 million decrease at UEOM reflecting lower processing volumes from the wet gas areas of the Utica gathering system, the divestiture of our interests in DBJV and Ranch Westex JV LLC late in the first quarter of 2017, a $12 million decrease from Discovery primarily attributable to lower fee revenue driven by production issues at certain wells and higher turbine maintenance expenses.
2016 vs. 2015
Modified EBITDA decreased primarily due to higher impairments, lower insurance recoveries associated with the Geismar Incident, and loss on sale associated with our Canadian operations. These decreases were partially offset by higher olefin margins related to the Geismar plant operating at higher production levels in 2016, lower segment costs and expenses, and higher earnings related to our equity-method investments, including the completion of the Keathley Canyon Connector at Discovery in the first quarter of 2015. Additionally, higher marketing margins, higher service revenues related to projects placed in service, and higher NGL margins improved Modified EBITDA.
The increase in Service revenues is primarily due to a $79 million increase in Transco’s natural gas transportation fee revenues primarily associated with expansion projects placed in service in 2015 and 2016 and a $31 million transportation and fractionation revenue increase associated with Williams’ Horizon liquids extraction plant in Canada. The Canadian operations were sold in late September 2016. These increases were partially offset by a decrease in gathering, processing, and fractionation revenue primarily due to lower volumes primarily in the Barnett Shale and Anadarko basin and a $15 million decrease in Transco’s storage revenue related to potential refunds associated with a ruling received in certain rate case litigation in 2016.
Product sales increased primarily due to:
• | A $94 million increase in olefin sales comprised of a $170 million increase from the Geismar plant that returned to service in late March 2015, partially offset by a $76 million decrease from our other former olefin operations. The increase at Geismar includes $153 million associated with increased volumes as a result of the plant operating at higher production levels in 2016 than when production resumed in March 2015 following the Geismar Incident and $17 million primarily associated with higher ethylene per-unit sales prices. The decrease in other olefin sales includes a $14 million reduction due to the absence of our former Canadian operations in the fourth quarter of 2016, as well as lower volumes and lower per-unit sales prices within our other olefin operations; |
• | A $70 million increase in marketing revenues primarily due to higher NGL and propylene prices and natural gas and crude oil volumes, partially offset by lower NGL volumes and crude oil prices (partially offset in marketing purchases); |
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• | A $6 million increase in revenues from our equity NGLs due to a $10 million increase associated with higher volumes, partially offset by a $4 million decrease associated with lower NGL prices; |
• | A $39 million decrease in system management gas sales from Transco. System management gas sales are offset in Product costs and, therefore, have no impact on Modified EBITDA. |
The decrease in Product costs includes:
• | A $39 million decrease in system management gas costs (offset in Product sales); |
• | A $17 million decrease in olefin feedstock purchases is primarily comprised of $78 million in lower purchases at our former other olefins operations, partially offset by $61 million of higher purchases due primarily to increased volumes at the Geismar plant resulting from higher productions levels. The lower costs at our former other olefin operations are comprised of $54 million in lower per-unit feedstock costs and $24 million in primarily lower propylene volumes; |
• | A $4 million decrease in natural gas purchases associated with the production of equity NGLs reflecting a decrease of $13 million due to lower natural gas prices, partially offset by a $9 million increase associated with higher volumes; |
• | Lower costs associated with various other products, primarily condensate; |
• | A $22 million increase in marketing purchases primarily due to the same factors that increased marketing sales (more than offset in marketing revenues). The increase in marketing costs does not reflect the intercompany costs associated with certain gathering and processing services performed by an affiliate. |
The decrease in Other segment costs and expenses is primarily due to lower operating costs and general and administrative expenses reflecting decreases in primarily labor-related and outside services costs resulting from our first-quarter 2016 workforce reductions and ongoing cost containment efforts and lower costs associated with general maintenance activities in the Marcellus Shale, as well as $43 million of lower ACMP Merger and transition-related expenses. Other items partially offsetting these decreases are as follows:
• | $37 million increase for severance and related costs associated with workforce reductions incurred in the first quarter of 2016 and the organizational realignment in the fourth quarter of 2016; |
• | $34 million increase related to the 2016 loss on sale of our Canadian operations; |
• | $28 million higher project development costs at Constitution as we discontinued capitalization of development costs related to this project beginning in April 2016; |
• | $22 million higher contract services for pipeline testing and general maintenance at Transco; |
• | $20 million unfavorable change in foreign currency exchange that primarily relates to losses incurred on foreign currency transactions and the remeasurement of the U.S. dollar-denominated current assets and liabilities within our former Canadian operations; |
• | $19 million unfavorable change in AFUDC associated with a decrease in spending on Constitution; |
• | The absence of a $14 million gain recognized in second-quarter 2015 resulting from the early retirement of certain debt. |
Net insurance recoveries – Geismar Incident decreased reflecting $7 million of insurance proceeds received in 2016 compared to $126 million received in 2015.
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Impairment of certain assets increased primarily due to 2016 impairments of $341 million associated with our Canadian operations and $63 million associated with certain Mid-Continent gathering assets as well as impairments or write-downs of other certain assets that may no longer be in use or are surplus in nature, partially offset by the absence of 2015 impairments of $94 million associated with previously capitalized project development costs for a gas processing plant and $20 million associated with certain surplus equipment within our Ohio Valley Midstream business. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)
The increase in Proportional Modified EBITDA of equity-method investments is primarily due to a $30 million increase from Discovery primarily associated with higher fee revenues attributable to the completion of the Keathley Canyon Connector in the first quarter of 2015. Additionally, Caiman II contributed a $20 million increase resulting from higher volumes due to assets placed into service in 2015, OPPL contributed a $16 million increase primarily due to higher transportation volumes and lower expenses, and UEOM contributed an $11 million increase primarily associated with an increase in our ownership percentage. These increases were partially offset by a $29 million decrease from Appalachia Midstream Investments primarily due to lower fee revenues driven by lower rates, partially offset by lower impairments and higher volumes.
Other
Years Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(Millions) | |||||||||||
Other Modified EBITDA | $ | (150 | ) | $ | (542 | ) | $ | (112 | ) | ||
2017 vs. 2016
The favorable change in Modified EBITDA is primarily due to:
• | The absence of the $406 million 2016 impairment of our Canadian operations, partially offset by the $23 million impairment of an olefins pipeline project in the Gulf Coast region in the second quarter of 2017 and the $68 million impairment of a certain NGL pipeline asset in the third quarter of 2017 (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements); |
• | The absence of $61 million of certain project development costs associated with the Canadian PDH facility that we expensed in 2016; |
• | A $31 million favorable change in the loss on the sale of our Canadian operations in September 2016; |
• | The absence of $32 million of transportation and fractionation fees incurred in 2016 related to the Redwater fractionation facility, which was included in the sale of our Canadian operations in September 2016; |
• | A $38 million decrease in costs related to our evaluation of strategic alternatives; |
• | A $29 million increase in income associated with an increase in a regulatory asset primarily driven by our increased ownership in WPZ. |
These favorable changes are partially offset by:
• | A $63 million charge reducing regulatory assets related to deferred taxes on AFUDC resulting from Tax Reform (see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements); |
• | A $35 million settlement charge expense related to the program to pay out certain deferred vested pension benefits of employees associated with former operations. (See Note 9 – Employee Benefit Plans of Notes to Consolidated Financial Statements); |
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• | 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. |
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Management’s Discussion and Analysis of Financial Condition and Liquidity
Overview
In 2017, we exceeded our target for asset sales, significantly improved our balance sheet to provide ample available liquidity, and continued to focus on growth in our businesses by identifying, contracting, permitting, and constructing attractive expansion projects. Examples of this activity included:
• | Sale of our Geismar Interest (see Note 2 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements). |
• | Repayment of WPZ’s $850 million variable interest rate term loan that was due December 2018, and early retirement of WPZ’s $750 million of 6.125 percent senior unsecured notes that were due in 2022; |
• | Repayment of WPZ’s $1.4 billion of 4.875 percent senior unsecured notes that were due in 2023 with proceeds from the issuance of WPZ’s $1.45 billion of 3.75 percent senior unsecured notes due in 2027; |
• | Extension to 2021 for the maturity dates of our long-term credit facility and WPZ’s long-term credit facility; |
• | Expansion of WPZ’s interstate natural gas pipeline system through completion of 2017 strategic projects (Gulf Trace, Hillabee Phase 1, Dalton, New York Bay, and Virginia Southside II) to meet the demand of growth markets. |
Outlook
Fee-based businesses are a significant component of our portfolio and serve to reduce the influence of commodity price fluctuations on our cash flows. We expect to benefit as continued growth in demand for low-cost natural gas is driven by increases in LNG exports, industrial demand, and power generation.
As previously discussed in Company Outlook, our consolidated growth capital and investment expenditures in 2018 are expected to be approximately $2.7 billion. Approximately $1.7 billion of our growth capital funding needs include Transco expansions and other interstate pipeline growth projects, most of which are fully contracted with firm transportation agreements. The remaining growth capital spending in 2018 primarily reflects investment in gathering and processing systems in the Northeast region limited primarily to known new producer volumes, including volumes that support Transco expansion projects including our Atlantic Sunrise project. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments. WPZ intends to fund their planned 2018 growth capital with retained cash flow and debt. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities.
Liquidity
Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2018. WPZ expects to be self-funding and maintain separate bank accounts and credit facilities, including its commercial paper program. Our potential material internal and external sources and uses of consolidated liquidity for 2018 are as follows:
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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 from equity-method investees | ü | ||||
Utilization of credit facilities 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 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, we had a working capital deficit of $467 million. Our available liquidity is as follows:
December 31, 2017 | ||||||||||||
Available Liquidity | WPZ | WMB | Total | |||||||||
(Millions) | ||||||||||||
Cash and cash equivalents | $ | 881 | $ | 18 | $ | 899 | ||||||
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 | ||||||||||
$ | 4,381 | $ | 1,248 | $ | 5,629 | |||||||
__________
(1) | The highest amount outstanding under our credit facility during 2017 was $805 million. At December 31, 2017, we were in compliance with the financial covenants associated with this credit facility. See Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements for additional information on our credit facility. Borrowing capacity available under this facility as of February 20, 2018, was $1.5 billion. |
(2) | In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of WPZ’s credit facility inclusive of any outstanding amounts under its commercial paper program. As of December 31, 2017, no Commercial paper was outstanding under WPZ’s commercial paper program. The highest amount outstanding under WPZ’s commercial paper program and credit facility during 2017 was $178 million. At December 31, 2017, WPZ was in compliance with the financial covenants associated with this credit facility. See Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements for additional information on WPZ’s credit facility and WPZ’s commercial paper program. Borrowing capacity available under WPZ’s $3.5 billion credit facility as of February 20, 2018, was $3.5 billion. |
As described in Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements, we have determined that we have net assets that are technically considered restricted in accordance with Rule 4-08(e) of Regulation S-X of the Securities and Exchange Commission in excess of 25 percent of our consolidated net assets. We do not expect this determination will impact our ability to pay dividends or meet future obligations as the terms of WPZ’s partnership agreement require it to make quarterly distributions of all available cash, as defined, to its unitholders.
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Dividends
As part of the Financial Repositioning, we increased our regular quarterly cash dividend by 50 percent from the previous quarterly dividend of $0.20 per share paid in December 2016, to $0.30 per share for the dividends paid in each quarter of 2017.
Registrations
In September 2016, WPZ filed a registration statement for its distribution reinvestment program.
In May 2015, we filed a shelf registration statement, as a well-known seasoned issuer.
In February 2015, WPZ filed a shelf registration statement, as a well-known seasoned issuer, registering common units representing limited partner interests and debt securities. Also in February 2015, WPZ filed a shelf registration statement for the offer and sale from time to time of common units representing limited partner interests in WPZ having an aggregate offering price of up to $1 billion. These sales are to be made over a period of time and from time to time in transactions at prices which are market prices prevailing at the time of sale, prices related to market price, or at negotiated prices. Such sales are to be made pursuant to an equity distribution agreement between WPZ and certain banks who may act as sales agents or purchase for their own accounts as principals. During 2016 and 2015, WPZ received net proceeds of approximately $115 million and approximately $59 million, respectively, from equity issued under this registration; there was no activity during 2017.
Distributions from Equity-Method Investees
The organizational documents of entities in which we have an equity-method investment generally require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements for our more significant equity-method investees.)
Credit Ratings
Our ability to borrow money is impacted by our credit ratings and the credit ratings of WPZ. The current ratings are as follows:
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 | Stable | BBB | BBB | |||
Moody’s Investors Service | Positive | Baa3 | N/A | ||||
Fitch Ratings | Positive | BBB- | N/A | ||||
During March 2017, S&P Global Ratings upgraded its rating for both WMB and WPZ. These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our or WPZ’s securities, and each rating should be evaluated independently of any other rating. No assurance can be given that the credit rating agencies will continue to assign us or WPZ the ratings shown above even if we or WPZ meet or exceed their current criteria. A downgrade of our credit ratings or the credit ratings of WPZ might increase our future cost of borrowing and would require us to provide additional collateral to third parties, negatively impacting our available liquidity.
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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 | $ | 3,089 | $ | 4,155 | $ | 3,114 | ||||||
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 | |||||||||
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 | (171 | ) | 39 | 13 | ||||||||
Increase (decrease) in cash and cash equivalents | $ | 729 | $ | 70 | $ | (140 | ) | ||||||
Operating activities
The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash items such as Depreciation and amortization, Provision (benefit) for deferred income taxes, Equity (earnings) losses, Net (gain) loss on disposition of equity-method investments, Impairment of goodwill, Impairment of equity-method investments, Impairment of and net (gain) loss on sale of assets and businesses, Gain on sale of Geismar Interest, and Regulatory charges resulting from Tax Reform.
Our Net cash provided (used) by operating activities in 2017 decreased from 2016 primarily due to the absence in 2017 of receipts from 2016 contract restructurings, partially offset by higher operating income 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.
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Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments
We have various other guarantees and commitments which are disclosed in Note 3 – Variable Interest Entities, Note 10 – Property, Plant, and Equipment, Note 13 – Debt, Banking Arrangements, and Leases, Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk, and Note 17 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements. We do not believe these guarantees and commitments or the possible fulfillment of them will prevent us from meeting our liquidity needs.
Contractual Obligations
The table below summarizes the maturity dates of our contractual obligations at December 31, 2017:
2018 | 2019 - 2020 | 2021 - 2022 | Thereafter | Total | |||||||||||||||
(Millions) | |||||||||||||||||||
Long-term debt: (1) | |||||||||||||||||||
Principal | $ | 502 | $ | 2,156 | $ | 3,146 | $ | 15,277 | $ | 21,081 | |||||||||
Interest | 1,049 | 1,995 | 1,743 | 7,795 | 12,582 | ||||||||||||||
Operating leases | 44 | 74 | 62 | 137 | 317 | ||||||||||||||
Purchase obligations (2) | 1,171 | 914 | 632 | 277 | 2,994 | ||||||||||||||
Other obligations (3)(4) | 1 | 2 | 1 | 1 | 5 | ||||||||||||||
Total | $ | 2,767 | $ | 5,141 | $ | 5,584 | $ | 23,487 | $ | 36,979 | |||||||||
______________
(1) | Includes the borrowings outstanding under credit facilities, but does not include any related variable-rate interest payments. |
(2) | Includes approximately $348 million in open property, plant, and equipment purchase orders. Includes an estimated $314 million long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2017 prices. This obligation is part of an overall exchange agreement whereby volumes we transport on OPPL are sold at a third-party fractionator near Conway, Kansas, and we are subsequently obligated to purchase ethane volumes at Mont Belvieu. The purchased ethane volumes may be utilized or sold at comparable prices in the Mont Belvieu market. Includes an estimated $454 million long-term ethane purchase obligation with index-based pricing terms that primarily supplies third parties at their plants and is valued in this table at a price calculated using December 31, 2017 prices. Any excess purchased volumes may be sold at comparable market prices. Includes an estimated $765 million long-term mixed NGLs purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2017 prices. Includes an estimated $278 million long-term ethane purchase obligation with index-based pricing terms that primarily supplies a third party for consumption at their plant and is reflected in this table at a price calculated using December 31, 2017 prices. Any excess purchased volumes may be sold at comparable market prices. In addition, we have not included certain natural gas life-of-lease contracts for which the future volumes are indeterminable. We have not included commitments, beyond purchase orders, for the acquisition or construction of property, plant, and equipment or expected contributions to our jointly owned investments. (See Company Outlook — Expansion Projects.) |
(3) | Does not include estimated contributions to our pension and other postretirement benefit plans. We made contributions to our pension and other postretirement benefit plans of $90 million in 2017 and $72 million in 2016. In 2018, we expect to contribute approximately $91 million to these plans (see Note 9 – Employee Benefit Plans of Notes to Consolidated Financial Statements). Tax-qualified pension plans are required to meet minimum contribution requirements. In the past, we have contributed amounts to our tax-qualified pension plans in excess of the minimum required contribution. These excess amounts can be used to offset future minimum contribution requirements. During 2017, we contributed $80 million to our tax-qualified pension plans. In addition to these contributions, a portion of the excess contributions was used to meet the minimum contribution requirements. During 2018, we expect to contribute approximately $80 million to our tax-qualified pension plans and use excess amounts to satisfy minimum contribution requirements, if needed. Additionally, estimated future minimum funding requirements may vary significantly from historical requirements if actual results differ significantly from estimated results for assumptions such as returns on plan assets, interest rates, retirement rates, mortality, and other significant assumptions or by changes to current legislation and regulations. |
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(4) | We have not included income tax liabilities in the table above. See Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of income taxes, including our contingent tax liability reserves. |
Effects of Inflation
Our operations have historically not been materially affected by inflation. Approximately 43 percent of our gross property, plant, and equipment is comprised of our interstate natural gas pipeline assets. They are subject to regulation, which limits recovery to historical cost. While amounts in excess of historical cost are not recoverable under current FERC practices, we anticipate being allowed to recover and earn a return based on increased actual cost incurred to replace existing assets. Cost-based regulations, along with competition and other market factors, may limit our ability to recover such increased costs. For our gathering and processing assets, operating costs are influenced to a greater extent by both competition for specialized services and specific price changes in crude oil and natural gas and related commodities than by changes in general inflation. Crude oil, natural gas, and NGL prices are particularly sensitive to the market perceptions concerning the supply and demand balance in the near future, as well as general economic conditions. However, our exposure to certain of these price changes is reduced through the fee-based nature of certain of our services and the use of hedging instruments.
Environmental
We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own (see Note 17 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements). We are monitoring these sites in a coordinated effort with other potentially responsible parties, the EPA, or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Current estimates of the most likely costs of such activities are approximately $38 million, all of which are included in Accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet at December 31, 2017. We will seek recovery of the accrued costs related to remediation activities by our interstate gas pipelines totaling approximately $7 million through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2017, we paid approximately $6 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $10 million in 2018 for these activities. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At December 31, 2017, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.
The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. More recent rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, air quality standards for one hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. On October 1, 2015, the EPA issued its rule regarding National Ambient Air Quality Standards for ground-level ozone, setting a stricter standard of 70 parts per billion. We are monitoring the rule's implementation as the reduction will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.
Our interstate natural gas pipelines consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates.
34
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
Our current interest rate risk exposure is related primarily to our debt portfolio. Our debt portfolio is primarily comprised of fixed rate debt, which mitigates the impact of fluctuations in interest rates. Any borrowings under the credit facilities and any issuances under WPZ’s commercial paper program could be at a variable interest rate and could expose us to the risk of increasing interest rates. The maturity of our long-term debt portfolio is partially influenced by the expected lives of our operating assets. (See Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)
The tables below provide information by maturity date about our interest rate risk-sensitive instruments as of December 31, 2017 and 2016. The fair value of our publicly traded long-term debt is valued using indicative year-end traded bond market prices. Private debt is valued based on market rates and the prices of similar securities with similar terms and credit ratings.
2018 | 2019 | 2020 | 2021 | 2022 | Thereafter (1) | Total | Fair Value December 31, 2017 | |||||||||||||||||||||||||
(Millions) | ||||||||||||||||||||||||||||||||
Long-term debt, including current portion: | ||||||||||||||||||||||||||||||||
Fixed rate | $ | 502 | $ | 33 | $ | 2,123 | $ | 873 | $ | 2,003 | $ | 15,131 | $ | 20,665 | $ | 22,735 | ||||||||||||||||
Weighted-average interest rate | 5.1 | % | 5.1 | % | 5.1 | % | 5.1 | % | 5.2 | % | 5.7 | % | ||||||||||||||||||||
Variable rate (2) | $ | — | $ | — | $ | — | $ | 270 | $ | — | $ | — | $ | 270 | $ | 270 | ||||||||||||||||
2017 | 2018 | 2019 | 2020 | 2021 | Thereafter (1) | Total | Fair Value December 31, 2016 | |||||||||||||||||||||||||
(Millions) | ||||||||||||||||||||||||||||||||
Long-term debt, including current portion: | ||||||||||||||||||||||||||||||||
Fixed rate | $ | 785 | $ | 500 | $ | 32 | $ | 2,121 | $ | 871 | $ | 17,475 | $ | 21,784 | $ | 22,465 | ||||||||||||||||
Weighted-average interest rate | 5.2 | % | 5.2 | % | 5.2 | % | 5.2 | % | 5.2 | % | 5.6 | % | ||||||||||||||||||||
Variable rate (3) | $ | — | $ | 850 | $ | — | $ | 775 | $ | — | $ | — | $ | 1,625 | $ | 1,625 | ||||||||||||||||
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 $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
35
to many factors, including changes in energy commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted, and changes in interest rates. At December 31, 2017 and 2016, our derivative activity was not material. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)
36
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
The Stockholders and the Board of Directors of
The Williams Companies, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheet of The Williams Companies, Inc. (the “Company”) as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2017, and the related notes and financial statement schedules listed in the index at Item 9.01(d) in this Current Report Form 8-K (collectively referred to as the “consolidated financial statements”). In our opinion, based on our audits and the reports of other auditors, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company at December 31, 2017 and 2016, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.
We did not audit the financial statements of Gulfstream Natural Gas System, L.L.C. (“Gulfstream”), a limited liability corporation in which the Company has a 50 percent interest. In the consolidated financial statements, the Company’s investment in Gulfstream was $244 million and $261 million as of December 31, 2017 and 2016, respectively, and the Company’s equity earnings in the net income of Gulfstream were $75 million in 2017, $69 million in 2016 and $65 million in 2015. Gulfstream’s financial statements were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Gulfstream, is based solely on the reports of the other auditors.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 22, 2018 expressed an unqualified opinion thereon.
Adoption of New Accounting Standards
As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for the presentation of pension and postretirement benefit costs as well as the presentation of cash distributions received from equity method investees in 2017, 2016, and 2015.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits and the reports of other auditors provide a reasonable basis for our opinion.
/s/ Ernst & Young LLP
37
We have served as the Company’s auditor since 1962.
Tulsa, Oklahoma
February 22, 2018,
except as it relates to the changes due to the application of Accounting Standards Updates 2017-07 and 2016-15 described under the Accounting standards issued and adopted heading in Note 1, and the other matters disclosed in Note 19, as to which the date is May 3, 2018
38
Report of Independent Registered Public Accounting Firm
To the Management Committee and Members of Gulfstream Natural Gas System, L.L.C.:
Opinion on the Financial Statements
We have audited the balance sheet of Gulfstream Natural Gas System, L.L.C. (the “Company”) as of December 31, 2017, and the related statements of operations, comprehensive income, cash flows, and members’ equity for the year then ended, including the related notes (collectively referred to as the “financial statements;” not presented herein). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit of these financial statements in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud.
Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 22, 2018
We have served as the Company’s auditor since 2018.
39
Report of Independent Registered Public Accounting Firm
To the Members of Gulfstream Natural Gas System, L.L.C.
We have audited the balance sheet of Gulfstream Natural Gas System, L.L.C. (the "Company") as of December 31, 2016, and the related statement of operations, comprehensive income, cash flows, and members’ equity for each of the two years in the period ended December 31, 2016. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Gulfstream Natural Gas System, L.L.C. as of December 31, 2016, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 22, 2017
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The Williams Companies, Inc.
Consolidated Statement of Operations
Years Ended December 31, | ||||||||||||
2017 | 2016 | 2015 | ||||||||||
(Millions, except per-share amounts) | ||||||||||||
Revenues: | ||||||||||||
Service revenues | $ | 5,312 | $ | 5,171 | $ | 5,164 | ||||||
Product sales | 2,719 | 2,328 | 2,196 | |||||||||
Total revenues | 8,031 | 7,499 | 7,360 | |||||||||
Costs and expenses: | ||||||||||||
Product costs | 2,300 | 1,725 | 1,779 | |||||||||
Operating and maintenance expenses | 1,576 | 1,592 | 1,659 | |||||||||
Depreciation and amortization expenses | 1,736 | 1,763 | 1,738 | |||||||||
Selling, general, and administrative expenses | 594 | 722 | 736 | |||||||||
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 | ) | — | — | ||||||||
Regulatory charges resulting from Tax Reform (Note 1) | 674 | — | — | |||||||||
Insurance recoveries – Geismar Incident | (9 | ) | (7 | ) | (126 | ) | ||||||
Other (income) expense – net | 80 | 142 | 40 | |||||||||
Total costs and expenses | 7,104 | 6,810 | 7,133 | |||||||||
Operating income (loss) | 927 | 689 | 227 | |||||||||
Equity earnings (losses) | 434 | 397 | 335 | |||||||||
Impairment of equity-method investments (Note 16) | — | (430 | ) | (1,359 | ) | |||||||
Other investing income (loss) – net | 282 | 63 | 27 | |||||||||
Interest incurred | (1,116 | ) | (1,217 | ) | (1,118 | ) | ||||||
Interest capitalized | 33 | 38 | 74 | |||||||||
Other income (expense) – net | (25 | ) | 85 | 101 | ||||||||
Income (loss) before income taxes | 535 | (375 | ) | (1,713 | ) | |||||||
Provision (benefit) for income taxes | (1,974 | ) | (25 | ) | (399 | ) | ||||||
Net income (loss) | 2,509 | (350 | ) | (1,314 | ) | |||||||
Less: Net income (loss) attributable to noncontrolling interests | 335 | 74 | (743 | ) | ||||||||
Net income (loss) attributable to The Williams Companies, Inc. | $ | 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 | |||||||||
See accompanying notes.
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The Williams Companies, Inc.
Consolidated Statement of Comprehensive Income (Loss)
Years Ended December 31, | ||||||||||||
2017 | 2016 | 2015 | ||||||||||
(Millions) | ||||||||||||
Net income (loss) | $ | 2,509 | $ | (350 | ) | $ | (1,314 | ) | ||||
Other comprehensive income (loss): | ||||||||||||
Cash flow hedging activities: | ||||||||||||
Net unrealized gain (loss) from derivative instruments, net of taxes of $2, ($1), and $0 in 2017, 2016, and 2015, respectively | (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 | ) | |||||||
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 | ) | ||||||||
Reclassification into earnings upon sale of foreign entities, net of taxes of ($36) in 2016 | — | 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 | |||||||||
Other comprehensive income (loss) | 100 | 172 | (171 | ) | ||||||||
Comprehensive income (loss) | 2,609 | (178 | ) | (1,485 | ) | |||||||
Less: Comprehensive income (loss) attributable to noncontrolling interests | 334 | 143 | (813 | ) | ||||||||
Comprehensive income (loss) attributable to The Williams Companies, Inc. | $ | 2,275 | $ | (321 | ) | $ | (672 | ) | ||||
See accompanying notes.
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The Williams Companies, Inc.
Consolidated Balance Sheet
December 31, | ||||||||
2017 | 2016 | |||||||
(Millions, except per-share amounts) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 899 | $ | 170 | ||||
Trade accounts and other receivables (net of allowance of $9 at December 31, 2017 and $6 at December 31, 2016) | 976 | 938 | ||||||
Inventories | 113 | 138 | ||||||
Other current assets and deferred charges | 191 | 216 | ||||||
Total current assets | 2,179 | 1,462 | ||||||
Investments | 6,552 | 6,701 | ||||||
Property, plant, and equipment – net | 28,211 | 28,428 | ||||||
Intangible assets – net of accumulated amortization | 8,791 | 9,663 | ||||||
Regulatory assets, deferred charges, and other | 619 | 581 | ||||||
Total assets | $ | 46,352 | $ | 46,835 | ||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 978 | $ | 623 | ||||
Accrued liabilities | 1,167 | 1,448 | ||||||
Commercial paper | — | 93 | ||||||
Long-term debt due within one year | 501 | 785 | ||||||
Total current liabilities | 2,646 | 2,949 | ||||||
Long-term debt | 20,434 | 22,624 | ||||||
Deferred income tax liabilities | 3,147 | 4,238 | ||||||
Regulatory liabilities, deferred income, and other | 3,950 | 2,978 | ||||||
Contingent liabilities and commitments (Note 17) | ||||||||
Equity: | ||||||||
Stockholders’ equity: | ||||||||
Common stock (960 million shares authorized at $1 par value; 861 million shares issued at December 31, 2017 and 785 million shares issued at December 31, 2016) | 861 | 785 | ||||||
Capital in excess of par value | 18,508 | 14,887 | ||||||
Retained deficit | (8,434 | ) | (9,649 | ) | ||||
Accumulated other comprehensive income (loss) | (238 | ) | (339 | ) | ||||
Treasury stock, at cost (35 million shares of common stock) | (1,041 | ) | (1,041 | ) | ||||
Total stockholders’ equity | 9,656 | 4,643 | ||||||
Noncontrolling interests in consolidated subsidiaries | 6,519 | 9,403 | ||||||
Total equity | 16,175 | 14,046 | ||||||
Total liabilities and equity | $ | 46,352 | $ | 46,835 | ||||
See accompanying notes.
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The Williams Companies, Inc.
Consolidated Statement of Changes in Equity
The Williams Companies, Inc., Stockholders | |||||||||||||||||||||||||||||||
Common Stock | Capital in Excess of Par Value | Retained Deficit | Accumulated Other Comprehensive Income (Loss) | Treasury Stock | Total Stockholders’ Equity | Noncontrolling Interests | Total Equity | ||||||||||||||||||||||||
(Millions) | |||||||||||||||||||||||||||||||
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 | ||||||||||||||||||||
Net income (loss) | — | — | (424 | ) | — | — | (424 | ) | 74 | (350 | ) | ||||||||||||||||||||
Other comprehensive income (loss) | — | — | — | 103 | — | 103 | 69 | 172 | |||||||||||||||||||||||
Cash dividends – common stock (Note 14) | — | — | (1,261 | ) | — | — | (1,261 | ) | — | (1,261 | ) | ||||||||||||||||||||
Dividends and distributions to noncontrolling interests | — | — | — | — | — | — | (940 | ) | (940 | ) | |||||||||||||||||||||
Stock-based compensation and related common stock issuances, net of tax | 1 | 56 | — | — | — | 57 | — | 57 | |||||||||||||||||||||||
Sales of limited partner units of Williams Partners L.P. | — | — | — | — | — | — | 114 | 114 | |||||||||||||||||||||||
Changes in ownership of consolidated subsidiaries, net | — | 12 | — | — | — | 12 | (18 | ) | (6 | ) | |||||||||||||||||||||
Contributions from noncontrolling interests | — | — | — | — | — | — | 29 | 29 | |||||||||||||||||||||||
Other | — | 12 | (4 | ) | — | — | 8 | (2 | ) | 6 | |||||||||||||||||||||
Net increase (decrease) in equity | 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 | ||||||||||||||||||||
Net income (loss) | — | — | 2,174 | — | — | 2,174 | 335 | 2,509 | |||||||||||||||||||||||
Other comprehensive income (loss) | — | — | — | 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 | ) | ||||||||||||||||||||
Dividends and distributions to noncontrolling interests | — | — | — | — | — | — | (883 | ) | (883 | ) | |||||||||||||||||||||
Stock-based compensation and related common stock issuances, net of tax | 1 | 73 | — | — | — | 74 | — | 74 | |||||||||||||||||||||||
Adoption of ASU 2016-09 (Note 1) | — | 1 | 36 | — | — | 37 | — | 37 | |||||||||||||||||||||||
Sales of limited partner units of Williams Partners L.P. | — | — | — | — | — | — | 61 | 61 | |||||||||||||||||||||||
Changes in ownership of consolidated subsidiaries, net | — | 1,497 | — | — | — | 1,497 | (2,407 | ) | (910 | ) | |||||||||||||||||||||
Contributions from noncontrolling interests | — | — | — | — | — | — | 17 | 17 | |||||||||||||||||||||||
Other | — | 7 | (3 | ) | — | — | 4 | (6 | ) | (2 | ) | ||||||||||||||||||||
Net increase (decrease) in equity | 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 | ||||||||||||
See accompanying notes.
44
The Williams Companies, Inc.
Consolidated Statement of Cash Flows
Years Ended December 31, | ||||||||||||
2017 | 2016 | 2015 | ||||||||||
(Millions) | ||||||||||||
OPERATING ACTIVITIES: | ||||||||||||
Net income (loss) | $ | 2,509 | $ | (350 | ) | $ | (1,314 | ) | ||||
Adjustments to reconcile to net cash provided (used) by operating activities: | ||||||||||||
Depreciation and amortization | 1,736 | 1,763 | 1,738 | |||||||||
Provision (benefit) for deferred income taxes | (2,012 | ) | (26 | ) | (337 | ) | ||||||
Equity (earnings) losses | (434 | ) | (397 | ) | (335 | ) | ||||||
Distributions from unconsolidated affiliates | 784 | 742 | 619 | |||||||||
Net (gain) loss on disposition of equity-method investments | (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 | ) | — | — | ||||||||
Amortization of stock-based awards | 78 | 73 | 82 | |||||||||
Regulatory charges resulting from Tax Reform (Note 1) | 776 | — | — | |||||||||
Cash provided (used) by changes in current assets and liabilities: | ||||||||||||
Accounts and notes receivable | (88 | ) | 82 | 39 | ||||||||
Inventories | 8 | (25 | ) | 105 | ||||||||
Other current assets and deferred charges | (21 | ) | (4 | ) | 4 | |||||||
Accounts payable | 118 | 35 | (88 | ) | ||||||||
Accrued liabilities | (92 | ) | 512 | 54 | ||||||||
Other, including changes in noncurrent assets and liabilities | (158 | ) | 429 | (125 | ) | |||||||
Net cash provided (used) by operating activities | 3,089 | 4,155 | 3,114 | |||||||||
FINANCING ACTIVITIES: | ||||||||||||
Proceeds from (payments of) commercial paper – net | (93 | ) | (409 | ) | (306 | ) | ||||||
Proceeds from long-term debt | 3,333 | 6,528 | 9,772 | |||||||||
Payments of long-term debt | (5,925 | ) | (7,091 | ) | (6,516 | ) | ||||||
Proceeds from issuance of common stock | 2,131 | 9 | 27 | |||||||||
Proceeds from sale of limited partner units of consolidated partnership | — | 114 | 59 | |||||||||
Dividends paid | (992 | ) | (1,261 | ) | (1,836 | ) | ||||||
Dividends and distributions paid to noncontrolling interests | (822 | ) | (940 | ) | (942 | ) | ||||||
Contributions from noncontrolling interests | 17 | 29 | 111 | |||||||||
Payments for debt issuance costs | (17 | ) | (9 | ) | (35 | ) | ||||||
Special distribution from Gulfstream | — | — | 396 | |||||||||
Contribution to Gulfstream for repayment of debt | — | (148 | ) | (248 | ) | |||||||
Other – net | (92 | ) | (16 | ) | (31 | ) | ||||||
Net cash provided (used) by financing activities | (2,460 | ) | (3,194 | ) | 451 | |||||||
INVESTING ACTIVITIES: | ||||||||||||
Property, plant, and equipment: | ||||||||||||
Capital expenditures (1) | (2,399 | ) | (2,051 | ) | (3,167 | ) | ||||||
Dispositions – net | (41 | ) | 30 | 3 | ||||||||
Contributions in aid of construction | 426 | 218 | 87 | |||||||||
Proceeds from sale of businesses, net of cash divested | 2,067 | 1,020 | — | |||||||||
Proceeds from dispositions of equity-method investments | 200 | 34 | — | |||||||||
Purchases of businesses, net of cash acquired | — | — | (112 | ) | ||||||||
Purchases of and contributions to equity-method investments | (132 | ) | (177 | ) | (595 | ) | ||||||
Other – net | (21 | ) | 35 | 79 | ||||||||
Net cash provided (used) by investing activities | 100 | (891 | ) | (3,705 | ) | |||||||
Increase (decrease) in cash and cash equivalents | 729 | 70 | (140 | ) | ||||||||
Cash and cash equivalents at beginning of year | 170 | 100 | 240 | |||||||||
Cash and cash equivalents at end of year | $ | 899 | $ | 170 | $ | 100 | ||||||
_________ | ||||||||||||
(1) Increases to property, plant, and equipment | $ | (2,662 | ) | $ | (1,912 | ) | $ | (3,024 | ) | |||
Changes in related accounts payable and accrued liabilities | 263 | (139 | ) | (143 | ) | |||||||
Capital expenditures | $ | (2,399 | ) | $ | (2,051 | ) | $ | (3,167 | ) | |||
See accompanying notes.
45
The Williams Companies, Inc. | ||
Notes to Consolidated Financial Statements | ||
Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
General
Unless the context clearly indicates otherwise, references in this report to “Williams,” “we,” “our,” “us,” or like terms refer to The Williams Companies, Inc. and its subsidiaries. Unless the context clearly indicates otherwise, references to “Williams,” “we,” “our,” and “us” include the operations in which we own interests accounted for as equity-method investments that are not consolidated in our financial statements. When we refer to our equity investees by name, we are referring exclusively to their businesses and operations.
Financial Repositioning
In January 2017, we entered into agreements with Williams Partners L.P. (WPZ), wherein we permanently waived the general partner’s incentive distribution rights (IDRs) and converted our 2 percent general partner interest in WPZ to a noneconomic interest in exchange for 289 million newly issued WPZ common units. Pursuant to this agreement, we also purchased approximately 277 thousand WPZ common units for $10 million. Additionally, we purchased approximately 59 million common units of WPZ at a price of $36.08586 per unit in a private placement transaction, funded with proceeds from our equity offering (see Note 14 – Stockholders' Equity). According to the terms of this agreement, concurrent with WPZ’s quarterly distributions in February 2017 and May 2017, we paid additional consideration totaling $56 million to WPZ for these units. Subsequent to these transactions and as of December 31, 2017, we own a 74 percent limited partner interest in WPZ.
Termination of WPZ Merger Agreement
On May 12, 2015, we entered into an agreement for a unit-for-stock transaction whereby we would have acquired all of the publicly held outstanding common units of WPZ in exchange for shares of our common stock (WPZ Merger Agreement).
On September 28, 2015, we entered into a Termination Agreement and Release (Termination Agreement), terminating the WPZ Merger Agreement. Under the terms of the Termination Agreement, we were required to pay a $428 million termination fee to WPZ, at which time we owned approximately 60 percent, including the interests of the general partner and IDRs. Such termination fee settled through a reduction of quarterly incentive distributions we were entitled to receive from WPZ (such reduction not to exceed $209 million per quarter). The distributions from WPZ in November 2015, February 2016, and May 2016 were reduced by $209 million, $209 million, and $10 million, respectively, related to this termination fee.
ACMP Merger
On February 2, 2015, Williams Partners L.P. merged with and into Access Midstream Partners, L.P. (ACMP Merger). For the purpose of these financial statements and notes, WPZ refers to the renamed merged partnership, while Pre-merger Access Midstream Partners, L.P. (ACMP) and Pre-merger Williams Partners L.P. (Pre-merger WPZ) refer to the separate partnerships prior to the consummation of the ACMP Merger and subsequent name change. The net assets of Pre-merger WPZ and ACMP were combined at our historical basis. Our basis in ACMP reflected our business combination accounting resulting from acquiring control of ACMP on July 1, 2014.
Description of Business
We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located principally in the United States. We have one reportable segment, Williams Partners. All remaining business activities are included in Other.
46
The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
Williams Partners
Williams Partners consists of our consolidated master limited partnership, WPZ, and primarily includes gas pipeline and midstream businesses.
WPZ’s gas pipeline businesses primarily consist of two interstate natural gas pipelines, which are Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline LLC (Northwest Pipeline), and several joint venture investments in interstate and intrastate natural gas pipeline systems, including a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), and a 41 percent interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), which is developing a pipeline project (see Note 3 – Variable Interest Entities).
WPZ’s midstream businesses primarily consist of (1) natural gas gathering, treating, compression, and processing; (2) natural gas liquid (NGL) fractionation, storage, and transportation; (3) crude oil production handling and transportation; and (4) olefins production (see Note 2 – Acquisitions and Divestitures). The primary service areas are concentrated in major producing basins in Colorado, Texas, Oklahoma, Kansas, New Mexico, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio, which include the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, and Utica shale plays as well as the Mid-Continent region.
The midstream businesses include equity-method investments in natural gas gathering and processing assets and NGL fractionation and transportation assets, including a 62 percent equity-method investment in Utica East Ohio Midstream, LLC (UEOM), a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 58 percent equity-method investment in Caiman Energy II, LLC (Caiman II), a 60 percent equity-method investment in Discovery Producer Services, LLC (Discovery), a 50 percent equity-method investment in Overland Pass Pipeline, LLC (OPPL), and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average 66 percent interest in multiple gathering systems in the Marcellus Shale (Appalachia Midstream Investments), as well as our previously owned 50 percent equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see Note 5 – Investing Activities).
The midstream businesses also included our Canadian midstream operations, which were comprised of an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility at Redwater, Alberta. In September 2016, we completed the sale of our Canadian operations. (See Note 2 – Acquisitions and Divestitures.)
Other
Other is comprised of business activities that are not operating segments, as well as corporate operations. Other also includes certain domestic olefins pipeline assets as well as certain Canadian assets, which included a liquids extraction plant located near Fort McMurray, Alberta, that began operations in March 2016, and a propane dehydrogenation facility which was under development. In September 2016, the Canadian assets were sold. (See Note 2 – Acquisitions and Divestitures.)
Basis of Presentation
Consolidated master limited partnership
As of December 31, 2017, we owned approximately 74 percent of the interests in WPZ, a variable interest entity (VIE) (see Note 3 – Variable Interest Entities).
Pursuant to WPZ’s distribution reinvestment program, 1,606,448 common units were issued to the public during 2017 associated with reinvested distributions of $61 million. These common unit issuances, the Financial Repositioning, WPZ’s quarterly distribution of additional paid-in-kind Class B units to us, and other equity issuances by WPZ had the combined net impact of decreasing Noncontrolling interests in consolidated subsidiaries by $2.407 billion, and increasing Capital in excess of par value by $1.497 billion and Deferred income tax liabilities by $910 million in the Consolidated Balance Sheet.
47
The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
WPZ is self-funding and maintains separate lines of bank credit and cash management accounts and also has a commercial paper program. (See Note 13 – Debt, Banking Arrangements, and Leases.) Cash distributions from WPZ to all partners, including us, are governed by WPZ’s partnership agreement.
Discontinued operations
Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our continuing operations.
Significant risks and uncertainties
We may monetize assets that are not core to our strategy which could result in impairments of certain equity-method investments, property, plant, and equipment, and intangible assets. Such impairments could potentially be caused by indications of fair value implied through the monetization process or, in the case of asset dispositions that are part of a broader asset group, the impact of the loss of future estimated cash flows.
Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of certain ventures in which we own an undivided interest. Our judgment is required to evaluate whether we control an entity. Key areas of that evaluation include:
• | Determining whether an entity is a VIE; |
• | Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that we and our related parties have over those activities through our variable interests; |
• | Identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether we are a VIE’s primary beneficiary; |
• | Evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant decisions that would be expected to be made in the ordinary course of business such that we do not have the power to control such entities. |
We apply the equity method of accounting to investments over which we exercise significant influence but do not control.
Equity-method investment basis differences
Differences between the cost of our equity-method investments and our underlying equity in the net assets of investees are accounted for as if the investees were consolidated subsidiaries. Equity earnings (losses) in the Consolidated Statement of Operations includes our allocable share of net income (loss) of investees adjusted for any depreciation and amortization, as applicable, associated with basis differences.
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
48
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; |
• | Realization of deferred income tax assets; |
• | Depreciation and/or amortization of equity-method investment basis differences; |
• | Asset retirement obligations; |
• | Pension and postretirement valuation variables; |
• | Measurement of regulatory liabilities; |
• | Measurement of deferred income tax assets and liabilities. |
These estimates are discussed further throughout these notes.
Regulatory accounting
Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC). Their rates, which are established by the FERC, are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, we have determined that it is appropriate under Accounting Standards Codification (ASC) Topic 980, “Regulated Operations,” to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are established. Accounting for these operations that are regulated can differ from the accounting requirements for nonregulated operations. For example, for regulated operations, allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in the process of construction and is capitalized as a cost of property, plant, and equipment because it constitutes an actual cost of construction under established regulatory practices; nonregulated operations are only allowed to capitalize the cost of debt funds related to construction activities, while a component for equity is prohibited. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, pension and other postretirement benefits, and rate allowances for deferred income taxes at a historically higher federal income tax rate.
In December 2017, the Tax Cuts and Jobs Act was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent (Tax Reform) (see Note 7 – Provision (Benefit) for Income Taxes). In accordance with ASC 980-740-25-2, Transco and Northwest Pipeline have recognized regulatory liabilities to reflect the probable return to customers through future rates of the future decrease in income taxes payable associated with Tax Reform. These liabilities represent an obligation to return amounts directly to our customers. While a majority of our customers have entered into tariff rates based on our cost-of-service proceedings and related rate base therein, certain other contracts with customers reflect contractually-based rates that are designed to recover the cost of providing those services, including an allowance for income taxes, with no expected future rate adjustment for the term of those contracts. This relative mix of contracts for services was considered in determining the probable amount to be returned to customers through future rates. The regulatory liabilities were recorded in December 2017 through regulatory charges to operating income totaling $674 million. The timing and actual amount of such return will be subject to future negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing service.
49
The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
Certain of our equity-method investees recorded similar regulatory liabilities, for which our Equity earnings (losses) in the Consolidated Statement of Operations have been reduced by $11 million related to our proportionate share of the associated regulatory charges.
Our regulatory assets associated with the effects of deferred taxes on equity funds used during construction were also impacted by Tax Reform and were reduced by $102 million in December 2017 through a charge to Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations (see Note 6 – Other Income and Expenses). This amount, along with the previously described charges for establishing the regulatory liabilities resulting from Tax Reform, is reported within Regulatory charges resulting from Tax Reform within the Consolidated Statement of Cash Flows.
Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2017 and 2016 are as follows:
December 31, | |||||||
2017 | 2016 | ||||||
(Millions) | |||||||
Current assets reported within Other current assets and deferred charges | $ | 102 | $ | 91 | |||
Noncurrent assets reported within Regulatory assets, deferred charges, and other | 376 | 387 | |||||
Total regulated assets | $ | 478 | $ | 478 | |||
Current liabilities reported within Accrued liabilities | $ | 18 | $ | 11 | |||
Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other | 1,250 | 498 | |||||
Total regulated liabilities | $ | 1,268 | $ | 509 | |||
Cash and cash equivalents
Cash and cash equivalents in the Consolidated Balance Sheet includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.
Accounts receivable
Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted.
Inventories
Inventories in the Consolidated Balance Sheet primarily consist of natural gas liquids, olefins, natural gas in underground storage, and materials and supplies and are stated at the lower of cost or net realizable value. The cost of inventories is primarily determined using the average-cost method.
Property, plant, and equipment
Property, plant, and equipment is initially recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values.
50
The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply an accelerated depreciation method.
Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation. Other gains or losses are recorded in Other (income) expense – net included in Operating income (loss) in the Consolidated Statement of Operations.
Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment.
We record a liability and increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. As regulated entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that is attributable to capitalized ARO cost to a regulatory asset as we expect to recover these amounts in future rates. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in Operating and maintenance expenses in the Consolidated Statement of Operations, except for regulated entities, for which the liability is offset by a regulatory asset. The regulatory asset is amortized commensurate with our collection of those costs in rates.
Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium.
Goodwill
Goodwill included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet represents the excess of the consideration, plus the fair value of any noncontrolling interest or any previously held equity interest, over the fair value of the net assets acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount. Generally, the evaluation of goodwill for impairment involves a two-step quantitative test, although under certain circumstances an initial qualitative evaluation may be sufficient to conclude goodwill is not impaired. If a quantitative assessment is performed, we compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess. Judgments and assumptions are inherent in our estimate of fair value. Effective October 1, 2017, we early adopted Accounting Standards Update (ASU) 2017-04 “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment” (ASU 2017-04), which removed the computation of the implied fair value of goodwill from the measurement process.
Other intangible assets
Our identifiable intangible assets included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet are primarily related to gas gathering, processing, and fractionation contractual customer relationships. Our intangible assets are amortized on a straight-line basis over the period in which these assets contribute to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining useful life.
Impairment of property, plant, and equipment, other identifiable intangible assets, and investments
We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events or changes in circumstances indicate, in our judgment, that the carrying value of such assets may not be recoverable.
51
The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
When an indicator of impairment has occurred, we compare our estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.
For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.
We evaluate our investments for impairment when events or changes in circumstances indicate, in our judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements as an impairment charge.
Judgments and assumptions are inherent in our estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal.
Deferred income
We record a liability for deferred income related to cash received from customers in advance of providing our services. Such amounts are generally recognized in revenue upon satisfying our performance obligations, primarily providing services based on units of production or over remaining contractual service periods ranging from 1 to 25 years. Deferred income is reflected within Accrued liabilities and Regulatory liabilities, deferred income, and other on the Consolidated Balance Sheet. (See Note 12 – Accrued Liabilities.)
WPZ received an aggregate amount of $240 million in three equal installments as certain milestones of Transco’s Hillabee Expansion Project were met related to an agreement to resolve several matters in relation to the project. (See Note 12 – Accrued Liabilities.) During the third quarter of 2017, WPZ received the final installment and placed the project into service. As a result of placing the project into service, WPZ reclassified the refundable deposits to deferred income and expects to recognize income associated with these receipts over the term of an underlying contract.
During 2016, we received cash proceeds totaling $820 million associated with restructuring certain gas gathering contracts in the Barnett Shale and Mid-Continent regions. The proceeds were recorded as deferred income and are being amortized into income.
In October 2016, we received $104 million of newly constructed assets as part of a noncash investing transaction with a customer for which we provide production handling and other services. The transaction was recorded in Property, plant, and equipment – net and deferred income in the Consolidated Balance Sheet and is being amortized based on units of production through 2024. Due to the noncash nature of this transaction, it is not presented within the Consolidated Statement of Cash Flows.
Contingent liabilities
We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration
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Notes to Consolidated Financial Statements – (Continued) | ||||
of any potential recovery from third parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.
Cash flows from revolving credit facilities and commercial paper program
Proceeds and payments related to borrowings under our credit facilities are reflected in the financing activities in the Consolidated Statement of Cash Flows on a gross basis. Proceeds and payments related to borrowings under our commercial paper program are reflected in the financing activities in the Consolidated Statement of Cash Flows on a net basis, as the outstanding notes generally have maturity dates less than three months from the date of issuance. (See Note 13 – Debt, Banking Arrangements, and Leases.)
Treasury stock
Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as Treasury stock in the Consolidated Balance Sheet. Gains and losses on the subsequent reissuance of shares are credited or charged to Capital in excess of par value in the Consolidated Balance Sheet using the average-cost method.
Derivative instruments and hedging activities
We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of energy commodities. We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Other current assets and deferred charges; Regulatory assets, deferred charges, and other; Accrued liabilities; or Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.)
The accounting for the changes in fair value of a commodity derivative can be summarized as follows:
Derivative Treatment | Accounting Method | |
Normal purchases and normal sales exception | Accrual accounting | |
Designated in a qualifying hedging relationship | Hedge accounting | |
All other derivatives | Mark-to-market accounting | |
We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.
We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in Product sales or Product costs in the Consolidated Statement of Operations.
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Notes to Consolidated Financial Statements – (Continued) | ||||
For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in Accumulated other comprehensive income (loss) (AOCI) in the Consolidated Balance Sheet and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in Product sales or Product costs in the Consolidated Statement of Operations. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in Product sales or Product costs in the Consolidated Statement of Operations at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by us.
For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in Product sales or Product costs in the Consolidated Statement of Operations.
Certain gains and losses on derivative instruments included in the Consolidated Statement of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception.
Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives for NGL processing activities and which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis.
Revenue recognition
Revenues
As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks.
Service revenues
Revenues from our interstate natural gas pipeline businesses include services pursuant to long-term firm transportation and storage agreements. These agreements provide for a reservation charge based on the volume of contracted capacity and a commodity charge based on the volume of gas delivered, both at rates specified in our FERC tariffs. We recognize revenues for reservation charges ratably over the contract period regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges, from both firm and interruptible transportation services and storage injection and withdrawal services, are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility.
Certain revenues from our midstream operations include those derived from natural gas gathering, processing, treating, and compression services and are performed under volumetric-based fee contracts. These revenues are recorded when services have been performed.
Certain of our gas gathering and processing agreements have minimum volume commitments. If a customer under such an agreement fails to meet its minimum volume commitment for a specified period, generally measured on an annual basis, it is obligated to pay a contractually determined fee based upon the shortfall between actual production volumes and the minimum volume commitment for that period. The revenue associated with minimum volume commitments is recognized in the period that the actual shortfall is determined and is no longer subject to future reduction or offset, which is generally at the end of the annual period or fourth quarter.
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Notes to Consolidated Financial Statements – (Continued) | ||||
Crude oil gathering and transportation revenues and offshore production handling fees are recognized when the services have been performed. Certain offshore production handling contracts contain fixed payment terms that result in the deferral of revenues until such services have been performed or such capacity has been made available.
Storage revenues from our midstream operations associated with prepaid contracted storage capacity contracts are recognized on a straight-line basis over the life of the contract as services are provided.
Product sales
In the course of providing transportation services to customers of our interstate natural gas pipeline businesses, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided for in our FERC tariffs. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances.
We market NGLs, crude oil, and natural gas that we purchase from our producer customers as part of the overall service provided to producers. Revenues from marketing activities are recognized when the products have been sold and delivered.
Under our keep-whole and percent-of-liquids processing contracts, we retain the rights to all or a portion of the NGLs extracted from the producers’ natural gas stream and recognize revenues when the extracted NGLs are sold and delivered.
Our former domestic olefins business produced olefins from purchased or produced feedstock and we recognized revenues when the olefins were sold and delivered.
Our Canadian businesses that were sold in September 2016 had processing and fractionation operations where we retained certain NGLs and olefins from an upgrader’s offgas stream and we recognized revenues when the fractionated products were sold and delivered.
Interest capitalized
We capitalize interest during construction on major projects with construction periods of at least 3 months and a total project cost in excess of $1 million. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds (equity AFUDC). The latter is included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations. The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by nonregulated companies are based on our average interest rate on debt.
Employee stock-based awards
We recognize compensation expense on employee stock-based awards on a straight-line basis; forfeitures are recognized when they occur. (See Note 15 – Equity-Based Compensation.)
Pension and other postretirement benefits
The funded status of each of the pension and other postretirement benefit plans is recognized separately in the Consolidated Balance Sheet as either an asset or liability. The funded status is the difference between the fair value of plan assets and the plan’s benefit obligation. The plans’ benefit obligations and net periodic benefit costs (credits) are actuarially determined and impacted by various assumptions and estimates. (See Note 9 – Employee Benefit Plans.)
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Notes to Consolidated Financial Statements – (Continued) | ||||
The discount rates are determined separately for each of our pension and other postretirement benefit plans based on an approach specific to our plans. The year-end discount rates are determined considering a yield curve comprised of high-quality corporate bonds and the timing of the expected benefit cash flows of each plan.
The expected long-term rates of return on plan assets are determined by combining a review of the historical returns within the portfolio, the investment strategy included in the plans’ investment policy statement, and capital market projections for the asset classes in which the portfolio is invested, as well as the weighting of each asset class.
Unrecognized actuarial gains and losses and unrecognized prior service costs and credits are deferred and recorded in AOCI or, for Transco and Northwest Pipeline, as a regulatory asset or liability, until amortized as a component of net periodic benefit cost (credit). Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation or the market-related value of plan assets are amortized over the participants’ average remaining future years of service, which is approximately 13 years for our pension plans and approximately 7 years for our other postretirement benefit plans.
The expected return on plan assets component of net periodic benefit cost (credit) is calculated using the market-related value of plan assets. For our pension plans, the market-related value of plan assets is equal to the fair value of plan assets adjusted to reflect the amortization of gains or losses associated with the difference between the expected and actual return on plan assets over a 5-year period. Additionally, the market-related value of assets may be no more than 110 percent or less than 90 percent of the fair value of plan assets at the beginning of the year. The market-related value of plan assets for our other postretirement benefit plans is equal to the unadjusted fair value of plan assets at the beginning of the year.
Income taxes
We include the operations of our domestic corporate subsidiaries and income from our subsidiary partnerships in our consolidated federal income tax return and also file tax returns in various foreign and state jurisdictions as required. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of our assets and liabilities. Our judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets.
Earnings (loss) per common share
Basic earnings (loss) per common share in the Consolidated Statement of Operations is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share in the Consolidated Statement of Operations includes any dilutive effect of stock options, nonvested restricted stock units, and convertible debt, unless otherwise noted. Diluted earnings (loss) per common share are calculated using the treasury-stock method.
Foreign currency translation
Certain of our foreign subsidiaries that used the Canadian dollar as their functional currency were sold in 2016. The assets and liabilities of such foreign subsidiaries were translated at the spot rate in effect at the applicable reporting date, and the combined statements of operations were translated into the U.S. dollar at the average exchange rates in effect during the applicable period. The resulting cumulative translation adjustment was recorded as a separate component of AOCI in the Consolidated Balance Sheet.
Transactions denominated in currencies other than the functional currency were recorded based on exchange rates at the time such transactions arose. Subsequent changes in exchange rates when the transactions were settled resulted in transaction gains and losses which were reflected in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Operations. Substantially all of our Canadian operations were sold in September 2016.
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Notes to Consolidated Financial Statements – (Continued) | ||||
Accounting standards issued and adopted
Effective January 1, 2017, we adopted ASU 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting” (ASU 2016-09). ASU 2016-09 changed the accounting for income taxes such that all excess tax benefits and all tax deficiencies are now recognized as a discrete item in the provision for income taxes in the financial reporting period they occur and the recognition of tax benefits is no longer delayed until the tax benefit is realized through a reduction in income taxes payable. These changes were applied prospectively beginning in 2017. We recorded a cumulative-effect adjustment as of January 1, 2017, decreasing Retained deficit by $37 million in the Consolidated Balance Sheet to recognize tax benefits that were not previously recognized. ASU 2016-09 requires entities to classify excess tax benefits as an operating activity on the statement of cash flows. We applied this part of the guidance prospectively beginning in 2017; therefore, the cash flows for prior periods were not adjusted. In recognizing compensation cost from share-based payments, ASU 2016-09 allows entities to make an accounting policy election to either recognize forfeitures when they occur or estimate the number of forfeitures expected to occur. We are recognizing forfeitures when they occur and as a result of the change in our accounting policy, we increased our Retained deficit for an insignificant cumulative-effect adjustment as of January 1, 2017. ASU 2016-09 requires entities to classify as a financing activity, on the statement of cash flows, cash paid by an employer to a taxing authority when directly withholding shares from an employee’s award to satisfy the employer’s statutory tax withholding obligation. This guidance was applied retrospectively.
Effective October 1, 2017, we early adopted ASU 2017-04 “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” ASU 2017-04 modified the concept of goodwill impairment to represent the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. Under ASU 2017-04, entities are no longer required to determine the implied fair value of goodwill by assigning the fair value of a reporting unit to its individual assets and liabilities as if that reporting unit had been acquired in a business combination. Our Williams Partners reportable segment has $47 million of goodwill included in Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet (see Note 11 – Goodwill and Other Intangible Assets).
Effective January 1, 2018, we adopted 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 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 Operating income (loss). Only the service cost component is now eligible for capitalization when applicable. The presentation aspect of ASU 2017-07 must be applied retrospectively and the capitalization requirement prospectively. The adoption of ASU 2017-07 had the following impact to our Consolidated Statement of Operations:
Years Ended December 31, | ||||||||||||
2017 | 2016 | 2015 | ||||||||||
(Millions) | ||||||||||||
Operating and maintenance expenses | $ | (9 | ) | $ | 12 | $ | 4 | |||||
Selling, general, and administrative expenses | (14 | ) | (1 | ) | (5 | ) | ||||||
Operating income (loss) | 23 | (11 | ) | 1 | ||||||||
Other income (expense) – net below Operating income (loss) | (23 | ) | 11 | (1 | ) | |||||||
Effective January 1, 2018, we adopted ASU 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). Among other things, ASU 2016-15 permits an accounting policy election to classify distributions received from equity-method investees using either the cumulative earnings approach or the nature of distribution approach. We have elected to apply the nature of distribution approach and have retrospectively revised the accompanying Consolidated Statement of Cash Flows in accordance with ASU 2016-15. Amounts previously presented as Distributions from unconsolidated affiliates in excess of cumulative earnings and
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Notes to Consolidated Financial Statements – (Continued) | ||||
certain amounts in Other – net within Investing Activities are now presented as part of Distributions from unconsolidated affiliates within Operating Activities, resulting in increases to Net cash provided (used) by operating activities of $533 million, $475 million, and $406 million for the years ended December 31, 2017, 2016, and 2015, respectively, with corresponding reductions in Net cash provided (used) by investing activities for those periods.
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 June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. The standard requires varying transition methods for the different categories of amendments. Although we do not expect ASU 2016-13 to have a significant impact, it will impact our trade receivables as the related allowance for credit losses will be recognized earlier under the expected loss model.
In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach to lease classification similar to current lease accounting, and causes lessees to recognize leases on the balance sheet as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset, with an exception for leases with a term of one year or less. Additional disclosures will also be required regarding the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01 “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842” (ASU 2018-01). Per ASU 2018-01, land easements and rights-of-way are required to be assessed under ASU 2016-02 to determine whether the arrangements are or contain a lease. ASU 2018-01 permits an entity to elect a transition practical expedient to not apply ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not previously assessed under the previous lease guidance in ASC Topic 840 “Leases.” ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. ASU 2016-02 currently requires a modified retrospective transition for financing or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements.
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Notes to Consolidated Financial Statements – (Continued) | ||||
In January 2018, the FASB proposed an accounting standard update titled “Leases (Topic 842): Targeted Improvements,” which is an update to ASU 2016-02 allowing entities an additional transition method to the existing requirements whereby an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. We expect to adopt ASU 2016-02 effective January 1, 2019. We are in the process of reviewing contracts to identify leases based on the modified definition of a lease, implementing a financial lease accounting system, and evaluating internal control changes to support management in the accounting for and disclosure of leasing activities. While we are still in the process of completing our implementation evaluation of ASU 2016-02, we currently believe the most significant changes relate to the recognition of a lease liability and offsetting right-of-use asset in our consolidated balance sheet for operating leases. We are also evaluating ASU 2016-02’s currently available and proposed practical expedients on adoption.
In May 2014, the FASB issued ASU 2014-09 establishing ASC Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016. We are adopting ASC 606 utilizing the modified retrospective transition approach, effective January 1, 2018, by recognizing the cumulative effect of initially applying ASC 606 for periods prior to January 1, 2018, which we expect to result in a decrease of approximately $255 million, net of tax, to the opening balance of Total equity in the Consolidated Balance Sheet.
We are in the final stages of evaluating the impact ASC 606 will have on our financial statements. For each revenue contract type, we have conducted a formal contract review process to evaluate the impact of ASC 606. We have substantially completed our evaluation. During the fourth quarter, we concluded on certain technical matters, including the evaluation of significant financing components, tiered pricing structures, and minimum volume commitments, and certain contracts for which we received prepayments for services. The adjustment to Total equity upon adoption of ASC 606 is primarily comprised of the impact to the timing of recognition of deferred revenue (contract liabilities) associated with certain contracts which underwent modifications in periods prior to January 1, 2018. Under the provisions of ASC 606, when a contract modification does not increase both the scope and price of the contract, and the remaining goods and services are distinct from the goods and services transferred prior to the modification, the modification is treated as a termination of the existing contract and the creation of a new contract. The new contract requires that the transaction price, including any remaining deferred revenue from the old contract, be allocated to the performance obligations over the term of the new contract. The contract modifications adjustments are partially offset by the impact of changes to the timing of recognizing revenue which is subject to the constraint on estimates of variable consideration of certain contracts. The constraint of variable consideration will result in the acceleration of revenue recognition and corresponding de-recognition of deferred revenue for certain contracts (as compared to the previous revenue recognition model) as a result of our assessment that it is probable such recognition would not result in a significant revenue reversal in the future. Additionally, under ASC 606, our revenues will increase in situations where we receive noncash consideration, which exists primarily in certain of our gas processing contracts where we receive commodities as full or partial consideration for services provided. This increase in revenues will be offset by a similar increase in costs and expenses when the commodities received are subsequently sold. Based on commodities received during 2017 as consideration for services and market prices during 2017, the increase in revenues and costs would have been approximately $350 million. Financial systems and internal controls necessary for adoption were implemented effective January 1, 2018.
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Notes to Consolidated Financial Statements – (Continued) | ||||
Note 2 – Acquisitions and Divestitures
Eagle Ford Gathering System
In May 2015, WPZ acquired a gathering system comprised of approximately 140 miles of pipeline and a sour gas compression facility in the Eagle Ford Shale for $112 million. The acquisition was accounted for as a business combination, and the allocation of the acquisition-date fair value of the major classes of assets acquired includes $80 million of Property, plant, and equipment – net and $32 million of Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet. Changes to the preliminary allocation disclosed in the second quarter of 2015 reflect an increase of $20 million in Property, plant, and equipment – net, and a decrease of $20 million in Intangible assets – net of accumulated amortization.
Sale of Geismar Interest
In July 2017, WPZ completed the sale of Williams Olefins, L.L.C., a wholly owned subsidiary which owned our 88.5 percent undivided interest in the Geismar, Louisiana, olefins plant (Geismar Interest) for total consideration of $2.084 billion in cash. We received a final working capital adjustment of $12 million in October 2017. Upon closing of the sale, WPZ entered into a long-term supply and transportation agreement with the purchaser to provide feedstock to the plant via its Bayou Ethane pipeline system. The assets and liabilities of the Geismar olefins plant were designated as held for sale within the Williams Partners segment during the first quarter of 2017. As a result of this sale, we recorded a gain of $1.095 billion in the third quarter of 2017. Following this sale, the cash proceeds were used to repay WPZ’s $850 million term loan. Proceeds have also been funding a portion of the capital and investment expenditures that are a part of WPZ’s growth portfolio.
The following table presents the results of operations for the Geismar Interest, excluding the gain noted above:
Years Ended December 31, | |||||||
2017 | 2016 | ||||||
(Millions) | |||||||
Income (loss) before income taxes of the Geismar Interest | $ | 26 | $ | 141 | |||
Income (loss) before income taxes of the Geismar Interest attributable to The Williams Companies, Inc. | 19 | 85 | |||||
Sale of Canadian Operations
In September 2016, we completed the sale of subsidiaries conducting Canadian operations, including subsidiaries of WPZ, (such subsidiaries, the Canadian disposal group). Consideration received totaled $1.020 billion, net of $31 million of cash divested and subject to customary working capital adjustments. In connection with the sale, we waived $150 million of incentive distributions otherwise payable by WPZ to us in the fourth quarter of 2016 in recognition of certain affiliate contracts wherein WPZ’s Canadian operations provided services to certain of our other businesses. The proceeds were primarily used to reduce borrowings on credit facilities.
During the second quarter of 2016, we designated these operations as held for sale. As a result, we measured the fair value of the disposal group as of June 30, 2016, resulting in an impairment charge of $747 million, reflected in Impairment of certain assets in the Consolidated Statement of Operations. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) During the second half of 2016 we recorded an additional loss of $66 million upon completion of the sale, primarily reflecting revisions to the sales price and estimated contingent consideration and including a $15 million benefit related to transactions to hedge our foreign currency exchange risk on the Canadian proceeds, reflected in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Operations. The total loss consists of a loss of $34 million at Williams Partners and $32 million at Other.
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The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
The following table presents 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 3 – Variable Interest Entities
WPZ
We own a 74 percent interest in WPZ, a master limited partnership that is a VIE due to the limited partners’ lack of substantive voting rights, such as either participating rights or kick-out rights that can be exercised with a simple majority of the vote of the limited partners. We are the primary beneficiary of WPZ because we have the power, through our general partner interest, to direct the activities that most significantly impact WPZ’s economic performance.
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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 percent interest in Gulfstar One LLC (Gulfstar One), a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. Gulfstar One includes a proprietary floating-production system, Gulfstar FPS, and associated pipelines which provide production handling and gathering services in the eastern deepwater Gulf of Mexico. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Gulfstar One’s economic performance.
Constitution
WPZ owns a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments under its long-term firm transportation contracts, is a VIE. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Constitution’s economic performance. WPZ, as operator of
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The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
Constitution, is responsible for constructing the proposed pipeline connecting its gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. The total remaining cost of the project is estimated to be approximately $740 million, which would be funded with capital contributions from WPZ and the other equity partners on a proportional basis.
In December 2014, Constitution received approval from the Federal Energy Regulatory Commission (FERC) to construct and operate its proposed pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied the necessary water quality certification under Section 401 of the Clean Water Act for the New York portion of the pipeline. In May 2016, Constitution appealed the NYSDEC’s denial of the Section 401 certification to the United States Court of Appeals for the Second Circuit, and in August 2017 the court issued a decision denying in part and dismissing in part Constitution’s appeal. The court expressly declined to rule on Constitution’s argument that the delay in the NYSDEC’s decision on Constitution’s Section 401 application constitutes a waiver of the certification requirement. The court determined that it lacked jurisdiction to address that contention, and found that jurisdiction over the waiver issue lies exclusively with the United States Court of Appeals for the District of Columbia Circuit. As to the denial itself, the court determined that NYSDEC’s action was not arbitrary or capricious. Constitution filed a petition for rehearing with the Second Circuit Court of Appeals, but in October the court denied our petition.
In October 2017, WPZ filed a petition for declaratory order requesting the FERC to find that, by operation of law, the Section 401 certification requirement for the New York State portion of Constitution’s pipeline project was waived due to the failure by the NYSDEC to act on Constitution’s Section 401 application within a reasonable period of time as required by the express terms of such statute. In January 2018, the FERC denied WPZ’s petition, finding that Section 401 provides that a state waives certification only when it does not act on an application within one year from the date of the application.
The project’s sponsors remain committed to the project, and, in that regard, we are pursuing two separate and independent paths in order to overturn the NYSDEC’s denial of the Section 401 certification. In January 2018, we filed a petition with the United States Supreme Court to review the decision of the Second Circuit Court of Appeals that upheld the merits of the NYSDEC’s denial of the Section 401 certification. And, in February 2018, we filed a request with the FERC for rehearing of its finding that the NYSDEC did not waive the Section 401 certification requirement. If the FERC denies such request, we will file a petition for review with the D.C. Circuit Court of Appeals.
We estimate that the target in-service date for the project would be approximately 10 to 12 months following any court or FERC decision that the NYSDEC denial order was improper or that the NYSDEC waived the Section 401 certification requirement. An unfavorable resolution could result in the impairment of a significant portion of the capitalized project costs, which total $381 million on a consolidated basis at December 31, 2017, and are included within Property, plant, and equipment – net in the Consolidated Balance Sheet. Beginning in April 2016, we discontinued capitalization of development costs related to this project. It is also possible that we could incur certain supplier-related costs in the event of a prolonged delay or termination of the project.
Cardinal
WPZ owns a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal), a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Cardinal’s economic performance. Future expansion activity is expected to be funded with capital contributions from WPZ and the other equity partner on a proportional basis.
Jackalope
WPZ owns a 50 percent interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope), a subsidiary that provides gathering and processing services for the Powder River basin and is a VIE due to certain risks shared with customers. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Jackalope’s economic performance. Future expansion activity is expected to be funded with capital contributions from WPZ and the other equity partner on a proportional basis.
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The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
Note 4 – Related Party Transactions
Transactions with Equity-Method Investees
We have purchases from our equity-method investees included in Product costs in the Consolidated Statement of Operations of $226 million, $180 million, and $187 million for the years ended 2017, 2016, and 2015, respectively. We have $20 million and $19 million included in Accounts payable in the Consolidated Balance Sheet with our equity-method investees at December 31, 2017 and 2016, respectively.
WPZ has operating agreements with certain equity-method investees. These operating agreements typically provide for reimbursement or payment to WPZ for certain direct operational payroll and employee benefit costs, materials, supplies, and other charges and also for management services. We supplied a portion of these services, primarily those related to employees since WPZ does not have any employees, to certain equity-method investees. The total charges to equity-method investees for these fees are $67 million, $66 million, and $64 million for the years ended 2017, 2016, and 2015, respectively.
Board of Directors
A former member of our Board of Directors, who was elected in 2013 and resigned during 2016, is also the current chairman, president, and chief executive officer of an energy services company that is a customer of ours. We recorded $144 million and $111 million in Service revenues in the Consolidated Statement of Operations from this company for transportation and storage of natural gas for the years ended December 31, 2016 and 2015, respectively.
Note 5 – Investing Activities
Impairment of equity-method investments
The following table presents other-than-temporary impairment charges related to certain equity-method investments (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk):
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 | |||||
Acquisition of Additional Interests in Appalachia Midstream Investments
During the first quarter of 2017, WPZ exchanged all of its 50 percent interest in DBJV for an increased interest in two natural gas gathering systems that are part of the Appalachia Midstream Investments and $155 million in cash. This transaction was recorded based on our estimate of the fair value of the interests received as we have more insight to this value as we operate the underlying assets. Following this exchange, WPZ has an approximate average 66 percent interest in the Appalachia Midstream Investments. We continue to account for this investment under the equity-method due to the significant participatory rights of our partners such that we do not exercise control. WPZ also sold all of its interest in Ranch Westex JV LLC (Ranch Westex) for $45 million. These transactions resulted in a total gain of $269 million reflected in Other investing income (loss) – net in the Consolidated Statement of Operations.
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The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
The fair value of the increased interests in the Appalachia Midstream Investments received as consideration was estimated to be $1.1 billion using an income approach based on expected cash flows and an appropriate discount rate (a Level 3 measurement within the fair value hierarchy). The determination of estimated future cash flows involved significant assumptions regarding gathering volumes, rates, and related capital spending. A 9.5 percent discount rate was utilized and reflected our estimate of the cost of capital as impacted by market conditions and risks associated with the underlying business.
Acquisition of Additional Interest in UEOM
In June 2015, WPZ acquired an approximate 13 percent additional interest in its equity-method investment, UEOM, for $357 million. Following the acquisition WPZ owns approximately 62 percent of UEOM. However, WPZ continues to account for this as an equity-method investment because WPZ does not control UEOM due to the significant participatory rights of its partner. In connection with the acquisition of the additional interest, we agreed to waive approximately $2 million of our WPZ IDR payments each quarter through 2017. See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies for discussion of agreement with WPZ wherein we permanently waived IDR payment obligations from WPZ.
Equity earnings (losses)
Equity earnings (losses) in 2015 includes a loss of $19 million associated with WPZ’s share of underlying property impairments at certain of the Appalachia Midstream Investments.
Other investing income (loss) – net
In 2016, we recognized a $27 million gain from the sale of an equity-method investment interest in a gathering system that was part of the Appalachia Midstream Investments.
Other investing income (loss) – net also includes $36 million and $27 million of interest income for 2016 and 2015, respectively, associated with a receivable related to the sale of certain former Venezuela assets. Due to changes in circumstances that led to late payments and increased uncertainty regarding the recovery of the receivable, we began accounting for the receivable under a cost recovery model in first quarter 2015. Subsequently, we received payments greater than the remaining carrying amount of the receivable, which resulted in the recognition of interest income.
Investments
Ownership Interest at December 31, 2017 | 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. |
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The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
We have differences between the carrying value of our equity-method investments and the underlying equity in the net assets of the investees of $1.8 billion at December 31, 2017 and $1.9 billion at December 31, 2016. For 2017 these differences primarily relate to our investments in Appalachia Midstream Investments and UEOM resulting from property, plant, and equipment, as well as customer-based intangible assets and goodwill. For 2016, the difference also includes DBJV.
Purchases of and contributions to equity-method investments
We generally fund our portion of significant expansion or development projects of these investees through additional capital contributions. These transactions increased the carrying value of our investments and included:
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.
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The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
Summarized Financial Position and Results of Operations of All Equity-Method Investments
December 31, | |||||||
2017 | 2016 | ||||||
(Millions) | |||||||
Assets (liabilities): | |||||||
Current assets | $ | 447 | $ | 508 | |||
Noncurrent assets | 9,181 | 9,695 | |||||
Current liabilities | (295 | ) | (412 | ) | |||
Noncurrent liabilities | (1,538 | ) | (1,484 | ) | |||
Years Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(Millions) | |||||||||||
Gross revenue | $ | 1,961 | $ | 1,883 | $ | 1,707 | |||||
Operating income | 871 | 799 | 690 | ||||||||
Net income | 806 | 726 | 611 | ||||||||
Note 6 – Other Income and Expenses
The following table presents certain gains or losses reflected in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Operations:
Years Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(Millions) | |||||||||||
Williams Partners | |||||||||||
Loss on sale of Canadian operations (Note 2) | $ | 4 | $ | 34 | $ | — | |||||
Amortization of regulatory assets associated with asset retirement obligations | 33 | 33 | 33 | ||||||||
Accrual of regulatory liability related to overcollection of certain employee expenses | 22 | 25 | 20 | ||||||||
Project development costs related to Constitution (Note 3) | 16 | 28 | — | ||||||||
Gains on contract settlements and terminations | (15 | ) | — | — | |||||||
Gain on sale of Refinery Grade Propylene Splitter | (12 | ) | — | — | |||||||
Net foreign currency exchange (gains) losses (1) | — | 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 | ) | — | |||||||
________________
(1) | Primarily relates to gains and losses incurred on foreign currency transactions and the remeasurement of U.S. dollar-denominated current assets and liabilities within our former Canadian operations (see Note 2 – Acquisitions and Divestitures). |
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The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
ACMP Acquisition, Merger, and Transition
Certain ACMP acquisition, merger, and transition costs included in the Consolidated Statement of Operations are as follows:
• | Selling, general, and administrative expenses includes $26 million in 2015 primarily related to professional advisory fees within the Williams Partners segment. |
• | Selling, general, and administrative expenses includes $32 million in 2015 of general corporate expenses associated with integration and realignment of resources within the Other segment. |
• | Operating and maintenance expenses includes $12 million in 2015 primarily related to employee transition costs within the Williams Partners segment. |
Additional Items
Certain additional items included in the Consolidated Statement of Operations are as follows:
• | Service revenues includes $66 million, $58 million, and $239 million recognized in the fourth quarter of 2017, 2016, and 2015, respectively, from minimum volume commitment fees in the Barnett Shale and Mid-Continent regions within the Williams Partners segment. |
• | Service revenues for the year ended December 31, 2016, includes $173 million associated with the amortization of deferred income related to the restructuring of certain gas gathering contracts in the Barnett Shale and Mid-Continent regions within the Williams Partners segment. |
• | Service revenues were reduced by $15 million for the year ended December 31, 2016, related to potential refunds associated with a ruling received in certain rate case litigation within the Williams Partners segment. |
• | Selling, general, and administrative expenses includes $9 million and $47 million for the years ended December 31, 2017 and 2016, respectively, of costs associated with our evaluation of strategic alternatives within the Other segment. Selling, general, and administrative expenses also includes $61 million for the year ended December 31, 2016, of project development costs related to a proposed propane dehydrogenation facility in Alberta, Canada within the Other segment. Beginning in the first quarter of 2016, these costs did not qualify for capitalization. |
• | Selling, general, and administrative expenses and Operating and maintenance expenses includes $22 million in severance and other related costs for the year ended December 31, 2017, for the Williams Partners segment. The year ended December 31, 2016, included $42 million in severance and other related costs associated with an approximate 10 percent reduction in workforce in the first quarter of 2016, primarily within the Williams Partners segment. |
• | Other income (expense) – net below Operating income (loss) includes $71 million, $66 million, and $77 million for equity AFUDC for the years ended December 31, 2017, 2016, and 2015, respectively. Other income (expense) – net below Operating income (loss) also includes $52 million, $23 million and $18 million for the years ended December 31, 2017, 2016 and 2015, respectively, of income associated with regulatory assets related to the effects of deferred taxes on equity funds used during construction. |
• | 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 |
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The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
and $63 million within the Other segment (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies).
• | Other income (expense) – net below Operating income (loss) includes $35 million of settlement charge expense in 2017 related to the program to pay out certain deferred vested pension benefits for the Williams Partners segment and $35 million for the Other segment (see Note 9 – Employee Benefit Plans). |
• | Other income (expense) – net below Operating income (loss) for the year ended December 31, 2017, includes a net gain of $30 million associated with the February 23, 2017, early retirement of $750 million of 6.125 percent senior unsecured notes that were due in 2022 and a net loss of $3 million associated with the July 3, 2017, early retirement of of $1.4 billion of 4.875 percent senior unsecured notes that were due in 2023. The net gain for the February 23, 2017, early retirement within the Other segment reflects $53 million of unamortized premium, partially offset by $23 million in premiums paid. The net loss for the July 3, 2017, early retirement within the Other segment reflects $51 million of unamortized premium, offset by $54 million in premiums paid (see Note 13 – Debt, Banking Arrangements, and Leases). |
Note 7 – Provision (Benefit) for Income Taxes
The Provision (benefit) for income taxes includes:
Years Ended December 31, | |||||||||||
2017 | 2016 | 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 | ) | ||
Reconciliations from the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes are as follows:
Years Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(Millions) | |||||||||||
Provision (benefit) at statutory rate | $ | 187 | $ | (131 | ) | $ | (600 | ) | |||
Increases (decreases) in taxes resulting from: | |||||||||||
Impact of nontaxable noncontrolling interests | (117 | ) | (22 | ) | 263 | ||||||
Federal Tax Reform rate change | (1,932 | ) | — | — | |||||||
State income taxes (net of federal benefit) | (17 | ) | 3 | (21 | ) | ||||||
State deferred income tax rate change | 26 | 43 | — | ||||||||
Foreign operations – net (including tax effect of Canadian Sale) | (127 | ) | 78 | 8 | |||||||
Translation adjustment of certain unrecognized tax benefits | — | (1 | ) | (71 | ) | ||||||
Other – net | 6 | 5 | 22 | ||||||||
Provision (benefit) for income taxes | $ | (1,974 | ) | $ | (25 | ) | $ | (399 | ) | ||
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The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
Income (loss) before income taxes includes $7 million and $885 million of foreign loss in 2017 and 2016, respectively, and $20 million of foreign income in 2015.
Foreign operations – net (including tax effect of Canadian Sale) increased in 2016 due to a valuation allowance associated with impairments and losses on the sale of our Canadian operations (see Note 2 – Acquisitions and Divestitures) and the reversal of anticipatory foreign tax credits, partially offset by the tax effect of the impairments associated with our Canadian disposition.
On December 22, 2017, Tax Reform was enacted. Most of the provisions of Tax Reform are not effective until after January 1, 2018. However, the deferred tax impact of reducing the U.S. corporate tax rate from 35 percent to 21 percent is recognized in the period of enactment. This remeasurement resulted in a reduction of our deferred tax liabilities of approximately $1.9 billion, with a corresponding net adjustment to Provision (benefit) for income taxes. Under the guidance provided by Securities and Exchange Commission Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act, we are recording provisional adjustments related to the impact of Tax Reform, including items such as direct expensing of assets placed into service after September 27, 2017. We anticipate that additional guidance from the Internal Revenue Service (IRS) will be released to guide us in determining what assets are eligible for direct expensing in 2017. We are also recording provisional adjustments for valuation allowances associated with State losses and credits (see following table), since, at this time, we cannot assess the impact that the interest expense disallowance will have on our estimated future taxable income. We are not reducing our Minimum tax credit (see following table) for sequestration until we receive further guidance on that matter.
The Translation adjustment of certain unrecognized tax benefits in 2016 and 2015 reflects the impact of changes in foreign currency exchange rates on the remeasurement of a foreign currency denominated unrecognized tax benefit, including associated penalties and interest.
The 2015 federal and state income tax provisions include the tax effect of a $2.7 billion impairment loss associated with certain goodwill, equity-method investments, and other assets. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.)
During the course of audits of our business by domestic and foreign tax authorities, we frequently face challenges regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions and the allocation of income among various tax jurisdictions. In evaluating the liability associated with our various filing positions, we apply the two-step process of recognition and measurement. In association with this liability, we record an estimate of related interest and tax exposure as a component of our tax provision. The impact of this accrual is included within Other – net in our reconciliation of the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes.
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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 $28 million and $5 million in 2017 and 2016, respectively. Cash refunds for income taxes (net of payments and discontinued operations) were $136 million in 2015.
As of December 31, 2017, we had approximately $50 million of unrecognized tax benefits. If recognized, income tax expense would be reduced by $50 million and $49 million for 2017 and 2016, respectively, including the effect of these changes on other tax attributes, with state income tax amounts included net of federal tax effect. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
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The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
2017 | 2016 | ||||||
(Millions) | |||||||
Balance at beginning of period | $ | 50 | $ | 55 | |||
Reductions for tax positions of prior years | — | (4 | ) | ||||
Changes due to currency translation | — | (1 | ) | ||||
Balance at end of period | $ | 50 | $ | 50 | |||
We recognize related interest and penalties as a component of Provision (benefit) for income taxes. Total interest and penalties recognized as part of income tax provision were benefits of $400 thousand and $22 million for 2017 and 2015, respectively, and expenses of $300 thousand for 2016. Approximately $2 million and $3 million of interest and penalties primarily relating to uncertain tax positions have been accrued as of December 31, 2017 and 2016, respectively.
During the next 12 months, we do not expect ultimate resolution of any unrecognized tax benefit associated with domestic or international matters to have a material impact on our unrecognized tax benefit position.
Consolidated U.S. Federal income tax returns are open to IRS examination for years after 2010. As of December 31, 2017, examinations of tax returns for 2011 through 2013 are currently in process. We do not expect material changes in our financial position resulting from these examinations. The statute of limitations for most states expires one year after expiration of the IRS statute. Generally, tax returns for our previously owned Canadian entities are open to audit for tax years after 2012. Tax years 2013 and 2014 are currently under examination. We have indemnified the purchaser for any adjustments to Canadian tax returns for periods prior to the sale of our Canadian operations in September 2016.
On September 13, 2013, the IRS issued final regulations providing guidance on the treatment of amounts paid to acquire, produce, or improve tangible property. On August 18, 2014, the IRS issued final regulations providing guidance on the dispositions of such property. The implementation date for these regulations was January 1, 2014. The IRS is expected to issue additional procedural guidance regarding how the requirements may be implemented for the gas transmission and distribution industry. Pending the issuance of this additional procedural guidance from the IRS, we cannot at this time estimate the impact of implementing the regulations for our gas transmission business, although we anticipate that it will result in an immaterial balance-sheet-only impact.
Note 8 – Earnings (Loss) Per Common Share
Years Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(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 | ) | |||
Basic weighted-average shares | 826,177 | 750,673 | 749,271 | ||||||||
Effect of dilutive securities: | |||||||||||
Nonvested restricted stock units | 1,704 | — | — | ||||||||
Stock options | 637 | — | — | ||||||||
Diluted weighted-average shares (1) | 828,518 | 750,673 | 749,271 | ||||||||
Earnings (loss) per common share: | |||||||||||
Basic | $ | 2.63 | $ | (.57 | ) | $ | (.76 | ) | |||
Diluted | $ | 2.62 | $ | (.57 | ) | $ | (.76 | ) | |||
________________
(1) | For the years ended December 31, 2016 and December 31, 2015, 0.6 million and 1.7 million weighted-average nonvested restricted stock units, and 0.5 million and 1.5 million weighted-average stock options have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to The Williams Companies, Inc. |
72
The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
Note 9 – Employee Benefit Plans
We have noncontributory defined benefit pension plans in which all eligible employees participate. Currently, eligible employees earn benefits primarily based on a cash balance formula. Various other formulas, as defined in the plan documents, are utilized to calculate the retirement benefits for plan participants not covered by the cash balance formula. At the time of retirement, participants may elect, to the extent they are eligible for the various options, to receive annuity payments, a lump-sum payment, or a combination of annuity and lump-sum payments. In addition to our pension plans, we currently provide subsidized retiree medical and life insurance benefits (other postretirement benefits) to certain eligible participants. Generally, employees hired after December 31, 1991, are not eligible for the subsidized retiree medical benefits, except for participants that were employees or retirees of Transco Energy Company on December 31, 1995, and other miscellaneous defined participant groups. Subsidized retiree medical benefits for eligible participants age 65 and older are paid through contributions to health reimbursement accounts. Subsidized retiree medical benefits for eligible participants under age 65 are provided through a self-insured medical plan sponsored by us. The self-insured retiree medical plan provides for retiree contributions and contains other cost-sharing features such as deductibles, co-payments, and co-insurance. The accounting for these plans anticipates estimated future increases to our contribution levels to the health reimbursement accounts for participants age 65 and older, as well as future cost-sharing that is consistent with our expressed intent to increase the retiree contribution level generally in line with health care cost increases for participants under age 65.
In September 2017, we initiated a program to pay out certain deferred vested pension benefits to reduce investment risk, cash funding volatility, and administrative costs. In December 2017, the lump-sum payments were made and the annuity payments were commenced in relation to this program. As a result of these lump-sum payments, as well as lump-sum benefit payments made throughout 2017, settlement accounting was required. We settled $261 million in liabilities of our pension plans and recognized a pre-tax, non-cash settlement charge of $71 million, which is substantially reported in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations (see Note 6 – Other Income and Expenses). These amounts are included within the subsequent tables of changes in benefit obligations and plan assets, net periodic benefit cost (credit), and other changes in plan assets and benefit obligations recognized in other comprehensive income (loss) before taxes.
73
The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
Funded Status
The following table presents the changes in benefit obligations and plan assets for pension benefits and other postretirement benefits for the years indicated:
Pension Benefits | Other Postretirement Benefits | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(Millions) | |||||||||||||||
Change in benefit obligation: | |||||||||||||||
Benefit obligation at beginning of year | $ | 1,466 | $ | 1,464 | $ | 197 | $ | 202 | |||||||
Service cost | 50 | 54 | 1 | 1 | |||||||||||
Interest cost | 59 | 62 | 8 | 8 | |||||||||||
Plan participants’ contributions | — | — | 3 | 2 | |||||||||||
Benefits paid | (35 | ) | (130 | ) | (14 | ) | (15 | ) | |||||||
Actuarial loss (gain) | 40 | 20 | 11 | (1 | ) | ||||||||||
Settlements | (261 | ) | (4 | ) | — | — | |||||||||
Net increase (decrease) in benefit obligation | (147 | ) | 2 | 9 | (5 | ) | |||||||||
Benefit obligation at end of year | 1,319 | 1,466 | 206 | 197 | |||||||||||
Change in plan assets: | |||||||||||||||
Fair value of plan assets at beginning of year | 1,254 | 1,241 | 208 | 201 | |||||||||||
Actual return on plan assets | 184 | 82 | 25 | 13 | |||||||||||
Employer contributions | 85 | 65 | 5 | 7 | |||||||||||
Plan participants’ contributions | — | — | 3 | 2 | |||||||||||
Benefits paid | (35 | ) | (130 | ) | (14 | ) | (15 | ) | |||||||
Settlements | (261 | ) | (4 | ) | — | — | |||||||||
Net increase (decrease) in fair value of plan assets | (27 | ) | 13 | 19 | 7 | ||||||||||
Fair value of plan assets at end of year | 1,227 | 1,254 | 227 | 208 | |||||||||||
Funded status — overfunded (underfunded) | $ | (92 | ) | $ | (212 | ) | $ | 21 | $ | 11 | |||||
Accumulated benefit obligation | $ | 1,294 | $ | 1,440 | |||||||||||
The overfunded (underfunded) status of our pension plans and other postretirement benefit plans presented in the previous table are recognized in the Consolidated Balance Sheet within the following accounts:
December 31, | |||||||
2017 | 2016 | ||||||
(Millions) | |||||||
Underfunded pension plans: | |||||||
Current liabilities | $ | (2 | ) | $ | (2 | ) | |
Noncurrent liabilities | (90 | ) | (210 | ) | |||
Overfunded (underfunded) other postretirement benefit plans: | |||||||
Current liabilities | (6 | ) | (7 | ) | |||
Noncurrent assets (liabilities) | 27 | 18 | |||||
The plan assets within our other postretirement benefit plans are intended to be used for the payment of benefits for certain groups of participants. The Current liabilities for the other postretirement benefit plans represent the current portion of benefits expected to be payable in the subsequent year for the groups of participants whose benefits are not expected to be paid from plan assets.
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The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
The pension plans’ benefit obligation Actuarial loss (gain) of $40 million in 2017 is primarily due to the impact of a decrease in the discount rates utilized to calculate the benefit obligation. The pension plans’ benefit obligation Actuarial loss (gain) of $20 million in 2016 is primarily due to the impact of a decrease in the discount rates utilized to calculate the benefit obligation.
The 2017 benefit obligation Actuarial loss (gain) of $11 million for our other postretirement benefit plans is primarily due to a decrease in the discount rate used to calculate the benefit obligation.
At December 31, 2017 and 2016, all of our pension plans had a projected benefit obligation and accumulated benefit obligation in excess of plan assets.
Pre-tax amounts not yet recognized in Net periodic benefit cost (credit) at December 31 are as follows:
Pension Benefits | Other Postretirement Benefits | ||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||
(Millions) | |||||||||||||||
Amounts included in Accumulated other comprehensive income (loss): | |||||||||||||||
Prior service credit | $ | — | $ | — | $ | — | $ | 5 | |||||||
Net actuarial loss | (375 | ) | (535 | ) | (21 | ) | (18 | ) | |||||||
Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline: | |||||||||||||||
Prior service credit | N/A | N/A | $ | 2 | $ | 10 | |||||||||
Net actuarial gain | N/A | N/A | 14 | 8 | |||||||||||
In addition to the regulatory liabilities included in the previous table, differences in the amount of actuarially determined Net periodic benefit cost (credit) for our other postretirement benefit plans and the other postretirement benefit costs recovered in rates for Transco and Northwest Pipeline are deferred as a regulatory asset or liability. We have regulatory liabilities of $108 million at December 31, 2017 and $94 million at December 31, 2016, related to these deferrals. Additionally, Transco recognizes a regulatory liability for rate collections in excess of its amount funded to the tax-qualified pension plans. At December 31, 2017 and 2016, these regulatory liabilities were $33 million and $21 million, respectively. These pension and other postretirement plans amounts will be reflected in future rates based on the rate structures of these gas pipelines.
Net Periodic Benefit Cost (Credit)
Net periodic benefit cost (credit) for the years ended December 31 consist of the following:
Pension Benefits | 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 | ) | ||||||||
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The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
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 | ||||||||||||||||||||||
2017 | 2016 | 2015 | 2017 | 2016 | 2015 | ||||||||||||||||||
(Millions) | |||||||||||||||||||||||
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss): | |||||||||||||||||||||||
Net actuarial gain (loss) | $ | 62 | $ | (23 | ) | $ | 5 | $ | (3 | ) | $ | — | $ | 8 | |||||||||
Amortization of prior service credit | — | — | — | (5 | ) | (6 | ) | (6 | ) | ||||||||||||||
Amortization of net actuarial loss | 27 | 30 | 42 | — | — | 2 | |||||||||||||||||
Net actuarial loss from settlements | 71 | 2 | 2 | — | — | — | |||||||||||||||||
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) | $ | 160 | $ | 9 | $ | 49 | $ | (8 | ) | $ | (6 | ) | $ | 4 | |||||||||
Other changes in plan assets and benefit obligations for our other postretirement benefit plans associated with Transco and Northwest Pipeline are recognized in regulatory assets and liabilities. Amounts recognized in regulatory assets and liabilities for the years ended December 31 consist of the following:
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 | — | |||||
76
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 | ||||||||||
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 | |||||||
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 | ||||||||||||||||
2017 | 2016 | 2015 | 2017 | 2016 | 2015 | ||||||||||||
Discount rate | 4.17 | % | 4.37 | % | 3.96 | % | 4.27 | % | 4.50 | % | 4.12 | % | |||||
Expected long-term rate of return on plan assets | 6.45 | 6.85 | 6.38 | 5.53 | 6.11 | 5.70 | |||||||||||
Rate of compensation increase | 4.87 | 4.88 | 4.62 | 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 2018 is 8.0 percent. This rate decreases to 4.5 percent by 2026. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
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 37 percent of the other postretirement benefit plan assets are subject to income tax; therefore, certain investments are managed in a tax efficient manner.
The investment policy for the pension plans includes a general target asset allocation at December 31, 2017, of 46 percent equity securities and 54 percent fixed income securities. The target allocation includes the investments in equity and fixed income mutual funds and commingled investment funds. The investment policy allows for a broad range of asset allocations that permit the plans to de-risk in response to changes in the plans’ funded status.
Equity securities may include U.S. equities and non-U.S. equities. Investment in Williams’ securities or an entity in which Williams has a majority ownership is prohibited except where these securities may be owned in a commingled investment fund in which the plans’ trusts invest. No more than 5 percent of the total stock portfolio valued at market may be invested in the common stock of any one corporation.
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The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
Fixed income securities may consist of U.S. as well as international instruments, including emerging markets. The fixed income strategies may invest in government, corporate, asset-backed securities, and mortgage-backed obligations. The weighted-average credit rating of the fixed income strategies must be at least “investment grade” including ratings by Moody’s and/or Standard & Poor’s. No more than 5 percent of the total fixed income portfolio may be invested in the fixed income securities of any one issuer with the exception of bond index funds and U.S. government guaranteed and agency securities.
The following securities and transactions are not authorized: unregistered securities, commodities or commodity contracts, short sales or margin transactions, or other leveraging strategies. Investment strategies using direct investments in derivative securities require approval and, historically, have not been used; however, these instruments may be used in mutual funds and commingled investment funds held by the plans’ trusts. Additionally, real estate equity, natural resource property, venture capital, leveraged buyouts, and other high-return, high-risk investments are generally restricted.
There are no significant concentrations of risk within the plans’ investment securities because of the diversity of the types of investments, diversity of the various industries, and the diversity of the fund managers and investment strategies. Generally, the investments held in the plans are publicly traded, therefore, minimizing liquidity risk in the portfolio.
The fair values of our pension plan assets at December 31, 2017 and 2016 by asset class are as follows:
2017 | |||||||||||||||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | ||||||||||||
(Millions) | |||||||||||||||
Pension assets: | |||||||||||||||
Cash management fund | $ | 17 | $ | — | $ | — | $ | 17 | |||||||
Equity securities: | |||||||||||||||
U.S. large cap | 62 | — | — | 62 | |||||||||||
U.S. small cap | 54 | — | — | 54 | |||||||||||
Fixed income securities (1): | |||||||||||||||
U.S. Treasury securities | 103 | — | — | 103 | |||||||||||
Government and municipal bonds | — | 15 | — | 15 | |||||||||||
Mortgage and asset-backed securities | — | 47 | — | 47 | |||||||||||
Corporate bonds | — | 158 | — | 158 | |||||||||||
Insurance company investment contracts and other | — | 5 | — | 5 | |||||||||||
$ | 236 | $ | 225 | $ | — | 461 | |||||||||
Commingled investment funds measured at net asset value practical expedient (2): | |||||||||||||||
Equities — U.S. large cap | 265 | ||||||||||||||
Equities — International small cap | 26 | ||||||||||||||
Equities — International emerging markets | 41 | ||||||||||||||
Equities — International developed markets | 110 | ||||||||||||||
Fixed income — U.S. long duration | 205 | ||||||||||||||
Fixed income — Corporate bonds | 119 | ||||||||||||||
Total assets at fair value at December 31, 2017 | $ | 1,227 | |||||||||||||
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The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
2016 | |||||||||||||||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | ||||||||||||
(Millions) | |||||||||||||||
Pension assets: | |||||||||||||||
Cash management fund | $ | 14 | $ | — | $ | — | $ | 14 | |||||||
Equity securities: | |||||||||||||||
U.S. large cap | 87 | — | — | 87 | |||||||||||
U.S. small cap | 77 | — | — | 77 | |||||||||||
Fixed income securities (1): | |||||||||||||||
U.S. Treasury securities | 68 | — | — | 68 | |||||||||||
Government and municipal bonds | — | 10 | — | 10 | |||||||||||
Mortgage and asset-backed securities | — | 80 | — | 80 | |||||||||||
Corporate bonds | — | 148 | — | 148 | |||||||||||
Insurance company investment contracts and other | — | 5 | — | 5 | |||||||||||
$ | 246 | $ | 243 | $ | — | 489 | |||||||||
Commingled investment funds measured at net asset value practical expedient (2): | |||||||||||||||
Equities — U.S. large cap | 369 | ||||||||||||||
Equities — International small cap | 27 | ||||||||||||||
Equities — International emerging markets | 50 | ||||||||||||||
Equities — International developed markets | 149 | ||||||||||||||
Fixed income — U.S. long duration | 88 | ||||||||||||||
Fixed income — Corporate bonds | 82 | ||||||||||||||
Total assets at fair value at December 31, 2016 | $ | 1,254 | |||||||||||||
79
The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
The fair values of our other postretirement benefits plan assets at December 31, 2017 and 2016 by asset class are as follows:
2017 | |||||||||||||||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | ||||||||||||
(Millions) | |||||||||||||||
Other postretirement benefit assets: | |||||||||||||||
Cash management funds | $ | 11 | $ | — | $ | — | $ | 11 | |||||||
Equity securities: | |||||||||||||||
U.S. large cap | 25 | — | — | 25 | |||||||||||
U.S. small cap | 14 | — | — | 14 | |||||||||||
International developed markets large cap growth | — | 6 | — | 6 | |||||||||||
Fixed income securities (1): | |||||||||||||||
U.S. Treasury securities | 12 | — | — | 12 | |||||||||||
Government and municipal bonds | — | 2 | — | 2 | |||||||||||
Mortgage and asset-backed securities | — | 5 | — | 5 | |||||||||||
Corporate bonds | — | 19 | — | 19 | |||||||||||
Mutual fund — Municipal bonds | 43 | — | — | 43 | |||||||||||
$ | 105 | $ | 32 | $ | — | 137 | |||||||||
Commingled investment funds measured at net asset value practical expedient (2): | |||||||||||||||
Equities — U.S. large cap | 31 | ||||||||||||||
Equities — International small cap | 3 | ||||||||||||||
Equities — International emerging markets | 5 | ||||||||||||||
Equities — International developed markets | 13 | ||||||||||||||
Fixed income — U.S. long duration | 24 | ||||||||||||||
Fixed income — Corporate bonds | 14 | ||||||||||||||
Total assets at fair value at December 31, 2017 | $ | 227 | |||||||||||||
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The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
2016 | |||||||||||||||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | ||||||||||||
(Millions) | |||||||||||||||
Other postretirement benefit assets: | |||||||||||||||
Cash management funds | $ | 11 | $ | — | $ | — | $ | 11 | |||||||
Equity securities: | |||||||||||||||
U.S. large cap | 24 | — | — | 24 | |||||||||||
U.S. small cap | 15 | — | — | 15 | |||||||||||
International developed markets large cap growth | — | 5 | — | 5 | |||||||||||
Fixed income securities (1): | |||||||||||||||
U.S. Treasury securities | 7 | — | — | 7 | |||||||||||
Government and municipal bonds | — | 1 | — | 1 | |||||||||||
Mortgage and asset-backed securities | — | 8 | — | 8 | |||||||||||
Corporate bonds | — | 15 | — | 15 | |||||||||||
Mutual fund — Municipal bonds | 42 | — | — | 42 | |||||||||||
$ | 99 | $ | 29 | $ | — | 128 | |||||||||
Commingled investment funds measured at net asset value practical expedient (2): | |||||||||||||||
Equities — U.S. large cap | 38 | ||||||||||||||
Equities — International small cap | 3 | ||||||||||||||
Equities — International emerging markets | 5 | ||||||||||||||
Equities — International developed markets | 16 | ||||||||||||||
Fixed income — U.S. long duration | 9 | ||||||||||||||
Fixed income — Corporate bonds | 9 | ||||||||||||||
Total assets at fair value at December 31, 2016 | $ | 208 | |||||||||||||
____________
(1) | The weighted-average credit quality rating of the fixed income security portfolio is investment grade with a weighted-average duration of approximately 12 years for 2017 and 8 years for 2016. |
(2) | The stated intents of the funds vary based on each commingled fund’s investment objective. These objectives generally include strategies to replicate or outperform various market indices. Certain standard withdrawal restrictions generally apply, which may include redemption notification period restrictions ranging from 10 to 30 days. Additionally, the fund managers retain the right to restrict withdrawals from and/or purchases into the funds so as not to disadvantage other investors in the funds. Generally, the funds also reserve the right to make all or a portion of the redemption in-kind rather than in cash or a combination of cash and in-kind. |
The fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement of an asset.
Shares of the cash management funds and mutual funds are valued at fair value based on published market prices as of the close of business on the last business day of the year, which represents the net asset values of the shares held.
The fair values of equity securities traded on U.S. exchanges are derived from quoted market prices as of the close of business on the last business day of the year. The fair values of equity securities traded on foreign exchanges are also derived from quoted market prices as of the close of business on an active foreign exchange on the last business
81
The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
day of the year. However, the valuation requires translation of the foreign currency to U.S. dollars and this translation is considered an observable input to the valuation.
The fair values of all commingled investment funds are determined based on the net asset values per unit of each of the funds. The net asset values per unit represent the aggregate values of the funds’ assets at fair value less liabilities, divided by the number of units outstanding.
The fair values of fixed income securities, except U.S. Treasury securities, are determined using pricing models. These pricing models incorporate observable inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads for similar securities to determine fair value. The U.S. Treasury securities are valued at fair value based on closing prices on the last business day of the year reported in the active market in which the security is traded.
There have been no significant changes in the preceding valuation methodologies used at December 31, 2017 and 2016. Additionally, there were no transfers or reclassifications of investments between Level 1 and Level 2 from December 2016 to December 2017. If transfers between levels had occurred, the transfers would have been recognized as of the end of the period.
Plan Benefit Payments and Employer Contributions
Following are the expected benefits to be paid by the plans. These estimates are based on the same assumptions previously discussed and reflect future service as appropriate. The actuarial assumptions are based on long-term expectations and include, but are not limited to, assumptions as to average expected retirement age and form of benefit payment. Actual benefit payments could differ significantly from expected benefit payments if near-term participant behaviors differ significantly from the actuarial assumptions.
Pension Benefits | Other Postretirement Benefits | ||||||
(Millions) | |||||||
2018 | $ | 91 | $ | 13 | |||
2019 | 90 | 13 | |||||
2020 | 92 | 14 | |||||
2021 | 96 | 13 | |||||
2022 | 96 | 13 | |||||
2023-2027 | 486 | 60 | |||||
In 2018, we expect to contribute approximately $80 million to our tax-qualified pension plans and approximately $5 million to our nonqualified pension plans, for a total of approximately $85 million, and approximately $6 million to our other postretirement benefit plans.
Defined Contribution Plans
We also maintain defined contribution plans for the benefit of substantially all of our employees. Generally, plan participants may contribute a portion of their compensation on a pre-tax and after-tax basis in accordance with the plans’ guidelines. We match employees’ contributions up to certain limits. Our matching contributions charged to expense were $34 million in 2017, $36 million in 2016, and $39 million in 2015.
82
The Williams Companies, Inc. | ||||
Notes to Consolidated Financial Statements – (Continued) | ||||
Note 10 – Property, Plant, and Equipment
The following table presents nonregulated and regulated Property, plant, and equipment – net as presented on the Consolidated Balance Sheet for the years ended:
Estimated Useful Life (1) (Years) | Depreciation Rates (1) (%) | December 31, | |||||||||
2017 | 2016 | ||||||||||
(Millions) | |||||||||||
Nonregulated: | |||||||||||
Natural gas gathering and processing facilities (2) | 5 - 40 | $ | 18,440 | $ | 19,523 | ||||||
Construction in progress | Not applicable | 566 | 412 | ||||||||
Other (2) | 2 - 45 | 2,776 | 3,092 | ||||||||
Regulated: | |||||||||||
Natural gas transmission facilities | 1.20 - 6.97 | 14,460 | 12,692 | ||||||||
Construction in progress | Not applicable | Not applicable | 1,637 | 1,603 | |||||||
Other | 5 - 45 | 1.35 - 33.33 | 1,634 | 1,590 | |||||||
Total property, plant, and equipment, at cost | 39,513 | 38,912 | |||||||||
Accumulated depreciation and amortization | (11,302 | ) | (10,484 | ) | |||||||
Property, plant, and equipment — net | $ | 28,211 | $ | 28,428 | |||||||
__________
(1) | Estimated useful life and depreciation rates are presented as of December 31, 2017. Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC. |
(2) | The 2016 presentation has been changed to reflect $890 million of right-of-way assets previously presented in Natural gas gathering and processing facilities, now in Other. |
Depreciation and amortization expense for Property, plant, and equipment – net was $1.389 billion, $1.407 billion, and $1.382 billion in 2017, 2016, and 2015, respectively.
Regulated Property, plant, and equipment – net includes approximately $626 million and $665 million at December 31, 2017 and 2016, respectively, related to amounts in excess of the original cost of the regulated facilities within our gas pipeline businesses as a result of our prior acquisitions. This amount is being amortized over 40 years using the straight-line amortization method. Current FERC policy does not permit recovery through rates for amounts in excess of original cost of construction.
Asset Retirement Obligations
Our accrued obligations relate to underground storage caverns, offshore platforms and pipelines, fractionation and compression facilities, gas gathering well connections and pipelines, and gas transmission pipelines and facilities. At the end of the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any related surface equipment, to restore land and remove surface equipment at gas processing, fractionation, and compression facilities, to dismantle offshore platforms and appropriately abandon offshore pipelines, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground.
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Notes to Consolidated Financial Statements – (Continued) | ||||
The following table presents the significant changes to our ARO, of which $946 million and $801 million are included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued liabilities at December 31, 2017 and 2016, respectively.
December 31, | |||||||
2017 | 2016 | ||||||
(Millions) | |||||||
Beginning balance | $ | 862 | $ | 915 | |||
Liabilities incurred | 33 | 24 | |||||
Liabilities settled | (16 | ) | (8 | ) | |||
Accretion expense (1) | 141 | 69 | |||||
Revisions (2) | (22 | ) | (138 | ) | |||
Ending balance | $ | 998 | $ | 862 | |||
___________
(1) | The increase in accretion expense for 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 2017 revisions reflect changes in removal cost estimates and decreases in the estimated remaining useful life of certain assets and discount rates used in the annual review process. The 2016 revisions reflect changes in removal cost estimates, increases in the estimated remaining useful life of certain assets, and decreases in the inflation rate and discount rates used in the annual review process. |
The funds Transco collects through a portion of its rates to fund its ARO are deposited into an external trust account dedicated to funding its ARO (ARO Trust). (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) Under its current rate settlement, Transco’s annual funding obligation is approximately $36 million, with installments to be deposited monthly.
Note 11 – Goodwill and Other Intangible Assets
Goodwill
At December 31, 2017, 2016, and 2015, our Consolidated Balance Sheet includes $47 million of goodwill in Intangible assets – net of accumulated amortization, reported in the Williams Partners segment. Our goodwill is not subject to amortization, but is evaluated at least annually for impairment or more frequently if impairment indicators are present. We did not identify or recognize any impairments to goodwill in connection with our annual evaluation of goodwill for impairment (performed as of October 1) during the years ended December 31, 2017 and 2016. During 2015, we performed an interim assessment and an annual assessment as of September 30, 2015 and October 1, 2015, respectively, of certain goodwill within the Williams Partners segment. The estimated fair value of the reporting units evaluated exceeded their carrying amounts, and thus no impairment was identified. We performed an additional goodwill impairment evaluation as of December 31, 2015, of the goodwill recorded within the Williams Partners segment. As a result of this evaluation, we recorded goodwill impairment charges totaling $1.098 billion. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.)
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Other Intangible Assets
The gross carrying amount and accumulated amortization of other intangible assets, included in Intangible assets – net of accumulated amortization, at December 31 are as follows:
2017 | 2016 | ||||||||||||||
Gross Carrying Amount | Accumulated Amortization | Gross Carrying Amount | Accumulated Amortization | ||||||||||||
(Millions) | |||||||||||||||
Contractual customer relationships | $ | 10,027 | $ | (1,283 | ) | $ | 10,635 | $ | (1,019 | ) | |||||
Other intangible assets primarily relate to gas gathering, processing, and fractionation contractual customer relationships recognized in acquisitions including ACMP and Eagle Ford (see Note 2 – Acquisitions and Divestitures). The decrease in the gross carrying amount of other intangible assets during 2017 is primarily related to the impairment of certain gathering operations in the Mid-Continent and Marcellus South regions (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk). The write-off of accumulated amortization related to the impaired assets is the primary reason for the difference between the change in accumulated amortization during 2017 indicated above and the amortization expense for 2017 noted below. Other intangible assets are being amortized on a straight-line basis over an initial period of 30 years which represents a portion of the term over which the contractual customer relationships are expected to contribute to our cash flows.
We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts with customers. Based on the estimated future revenues during the contract periods (as estimated at the time of the acquisition), the weighted-average period prior to the next renewal or extension of the contractual customer relationships associated with the Eagle Ford acquisition was approximately 10 years. Although a significant portion of the expected future cash flows associated with these contractual customer relationships are dependent on our ability to renew or extend the arrangements beyond the initial contract periods, these expected future cash flows are significantly influenced by the scope and pace of our producer customers’ drilling programs. Once producer customers’ wells are connected to our gathering infrastructure, their likelihood of switching to another provider before the wells are abandoned is reduced due to the significant capital investment required.
The amortization expense related to other intangible assets was $347 million, $356 million, and $353 million in 2017, 2016, and 2015, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $337 million.
Note 12 – Accrued Liabilities
December 31, | |||||||
2017 | 2016 | ||||||
(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 | ||||
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.)
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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.
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Notes to Consolidated Financial Statements – (Continued) | ||||
Note 13 – Debt, Banking Arrangements, and Leases
Long-Term Debt
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 | |||
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Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, sell assets, and incur additional debt. Default of these agreements could also restrict our ability to make certain distributions or repurchase equity.
The following table presents aggregate minimum maturities of long-term debt, excluding net unamortized debt premium (discount) and debt issuance costs, for each of the next five years:
December 31, 2017 | |||
(Millions) | |||
2018 | $ | 502 | |
2019 | 33 | ||
2020 | 2,123 | ||
2021 | 1,143 | ||
2022 | 2,003 | ||
Issuances and retirements
On July 6, 2017, WPZ repaid its $850 million variable interest rate term loan that was due December 2018 using proceeds from the sale of its Geismar Interest.
On June 5, 2017, WPZ issued $1.45 billion of 3.75 percent senior unsecured notes due 2027. WPZ used the proceeds for general partnership purposes, primarily the July 3, 2017, repayment of $1.4 billion of 4.875 percent senior unsecured notes that were due in 2023.
On April 3, 2017, Northwest Pipeline issued $250 million of 4.0 percent senior unsecured notes due 2027 to investors in a private debt placement. Northwest Pipeline used the net proceeds to retire $185 million of 5.95 percent senior unsecured notes that matured on April 15, 2017, and for general corporate purposes. As part of the issuance, Northwest Pipeline entered into a registration rights agreement with the initial purchasers of the unsecured notes. Under the terms of the agreement, Northwest Pipeline was obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 365 days from closing and to use commercially reasonable efforts to complete the exchange offer. Northwest Pipeline has filed the registration statement, which became effective in January 2018. The exchange offer is expected to be completed in the first quarter of 2018.
On February 23, 2017, using proceeds received from the Financial Repositioning (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies), WPZ early retired $750 million of 6.125 percent senior unsecured notes that were due in 2022.
WPZ retired $600 million of 7.25 percent senior unsecured notes that matured on February 1, 2017.
Northwest Pipeline retired $175 million of 7 percent senior unsecured notes that matured on June 15, 2016.
Transco retired $200 million of 6.4 percent senior unsecured notes that matured on April 15, 2016.
On January 22, 2016, Transco issued $1 billion of 7.85 percent senior unsecured notes due 2026 to investors in a private debt placement. In January 2017, Transco completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended. Transco used the net proceeds to repay debt and to fund capital expenditures.
Other financing obligation
During the construction of Transco’s Dalton expansion project, WPZ received funding from a partner for its proportionate share of construction costs related to its undivided ownership interest in the project. Amounts received were recorded within noncurrent liabilities and 100 percent of the costs associated with construction were capitalized
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on our Consolidated Balance Sheet. Upon placing the project in service during the third quarter of 2017, WPZ began leasing this partner’s undivided interest in the lateral, including the associated pipeline capacity, and reclassified approximately $237 million of funding previously received from its partner from noncurrent liabilities to debt to reflect the financing obligation payable to its partner over an expected term of 35 years.
Credit Facilities
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.
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Notes to Consolidated Financial Statements – (Continued) | ||||
As of February 20, 2018, there are no amounts outstanding under our long-term credit facility.
WPZ long-term credit facilities
On February 2, 2015, WPZ along with Transco, Northwest Pipeline, the lenders named therein, and an administrative agent entered into the Second Amended & Restated Credit Agreement with aggregate commitments available of $3.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. In November 2017, the maturity date of the credit facility was extended to February 2, 2021. However, the co-borrowers may request an additional extension of the maturity date for a one year period to allow a maturity date as late as February 2, 2022, under certain circumstances. The agreement allows for swing line loans up to an aggregate amount of $150 million, subject to available capacity under the credit facility, and letters of credit commitments of $1.125 billion. Transco and Northwest Pipeline are each able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers.
The agreement governing this credit facility contains the following terms and conditions:
• | Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, enter into certain restrictive agreements, and allow any material change in the nature of its business. |
• | If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments for all borrowers and accelerate the maturity of any loans of the defaulting borrower under the credit facility agreement and exercise other rights and remedies. |
• | Other than swing line loans, each time funds are borrowed, the borrower must choose whether such borrowing will be an alternate base rate borrowing or a Eurodollar borrowing. If such borrowing is an alternate base rate borrowing, interest is calculated on the basis of the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus one half of 1 percent, and (c) a periodic fixed rate equal to the LIBOR plus 1 percent, plus, in the case of each of (a), (b), and (c), an applicable margin. If the borrowing is a Eurodollar borrowing, interest is calculated on the basis of LIBOR for the relevant period plus an applicable margin. Interest on swing line loans is calculated as the sum of the alternate base rate plus an applicable margin. The borrower is required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings. |
Significant financial covenants under the agreement require the ratio of debt to EBITDA, each as defined in the credit facility, be no greater than 5.00 to 1, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the ratio of debt to EBITDA is to be no greater than 5.5 to 1.
The ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for each Transco and Northwest Pipeline. WPZ is in compliance with these financial covenants as measured at December 31, 2017.
As of February 20, 2018, there are no amounts outstanding under the WPZ long-term credit facility.
Commercial Paper Program
On February 2, 2015, WPZ amended and restated the commercial paper program for the ACMP Merger and to allow a maximum outstanding amount of unsecured commercial paper notes of $3 billion. The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. Proceeds from these notes are used for general partnership purposes, including funding capital expenditures, working capital, and partnership distributions. At
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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 $62 million in 2017, $64 million in 2016, and $69 million in 2015 and primarily included in Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement of Operations.
Note 14 – Stockholders' Equity
Cash dividends declared per common share were $1.20, $1.68, and $2.45 for 2017, 2016, and 2015, respectively. On February 21, 2018, our board of directors approved a regular quarterly dividend of $0.34 per share payable on March 26, 2018.
In January 2017, we issued 65 million shares of common stock in a public offering at a price of $29.00 per share. In February 2017, we issued 9.75 million shares of common stock pursuant to the full exercise of the underwriter’s option to purchase additional shares. The net proceeds of approximately $2.1 billion were used to purchase newly issued common units in WPZ as part of our Financial Repositioning. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)
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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:
Component | Reclassifications | Classification | ||||
(Millions) | ||||||
Cash flow hedges: | ||||||
Energy commodity contracts | $ | 7 | Product sales and Product costs | |||
Pension and other postretirement benefits: | ||||||
Amortization of prior service cost (credit) included in net periodic benefit cost (credit) | (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 | ||||
Total before tax | 100 | |||||
Income tax benefit | (36 | ) | Provision (benefit) for income taxes | |||
Net of income tax | 64 | |||||
Noncontrolling interest | (2 | ) | Net income (loss) attributable to noncontrolling interests | |||
Reclassifications during the period | $ | 62 | ||||
Note 15 – Equity-Based Compensation
Williams’ Plan Information
On May 17, 2007, our stockholders approved The Williams Companies, Inc. 2007 Incentive Plan (the Plan) that provides common-stock-based awards to both employees and nonmanagement directors and reserved 19 million new shares for issuance. On May 20, 2010 and May 22, 2014, our stockholders approved amendments and restatements of the Plan to increase by 11 million and 10 million, respectively, the number of new shares authorized for making awards under the Plan, among other changes. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. At December 31, 2017, 26 million shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 15 million shares were available for future grants.
Additionally, on May 17, 2007, our stockholders approved an Employee Stock Purchase Plan (ESPP) which authorized up to 2 million new shares of our common stock to be available for sale under the ESPP. On May 22, 2014, our stockholders approved an amendment and restatement of the ESPP to increase by 1.6 million the number of new shares authorized for sale under the ESPP. Employees purchased 272 thousand shares at an average price of $25.83
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Notes to Consolidated Financial Statements – (Continued) | ||||
per share during 2017. Approximately 1.1 million shares were available for purchase under the ESPP at December 31, 2017.
Operating and maintenance expenses and Selling, general, and administrative expenses include equity-based compensation expense for the years ended December 31, 2017, 2016, and 2015 of $70 million, $53 million, and $56 million, respectively. Income tax benefit recognized related to the stock-based compensation expense for the years ended December 31, 2017, 2016, and 2015 was $17 million, $20 million, and $21 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2017, was $61 million, comprised of $4 million related to stock options and $57 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.8 years.
Stock Options
The following summary reflects stock option activity and related information for the year ended December 31, 2017:
Stock Options | 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 | ||||||||
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The 2017 expected dividend yield is based on the 2017 dividend forecast and the grant-date market price of our stock. Our expected future volatility is determined using the historical volatility of our stock and implied volatility on our traded options. Historical volatility is based on the blended 10-year historical volatility of our stock and certain peer companies. The risk-free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life of the option is based on historical exercise behavior and expected future experience.
Nonvested Restricted Stock Units
The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2017:
Restricted Stock Units Outstanding | Shares | Weighted- Average Fair Value (1) | ||||
(Millions) | ||||||
Nonvested at December 31, 2016 | 3.9 | $ | 35.19 | |||
Granted | 2.0 | $ | 29.47 | |||
Forfeited | (0.8 | ) | $ | 39.21 | ||
Vested | (0.9 | ) | $ | 38.30 | ||
Nonvested at December 31, 2017 | 4.2 | $ | 31.02 | |||
______________
(1) | Performance-based restricted stock units are valued utilizing a Monte Carlo valuation method using measures of total shareholder return. All other restricted stock units are valued at the grant-date market price. Restricted stock units generally vest after three years. |
Value of Restricted Stock Units | 2017 | 2016 | 2015 | ||||||||
Weighted-average grant date fair value of restricted stock units granted during the year, per share | $ | 29.47 | $ | 26.51 | $ | 40.15 | |||||
Total fair value of restricted stock units vested during the year ($’s in millions) | $ | 33 | $ | 32 | $ | 42 | |||||
Performance-based restricted stock units granted under the Plan represent 31 percent of nonvested restricted stock units outstanding at December 31, 2017. These grants may be earned at the end of the vesting period based on actual performance against a performance target. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original grant amount.
WPZ’s Plan Information
During 2014, certain employees of ACMP’s general partner received equity-based compensation through ACMP’s equity-based compensation program. These awards were converted to WPZ equity-based awards in accordance with the terms of the ACMP Merger. No additional grants of restricted common units were awarded through WPZ’s equity-based compensation programs, and no additional grants are expected in the future. Equity-based compensation expense of $8 million, $20 million, and $29 million related to WPZ’s equity-based compensation program is included in Operating and maintenance expenses and Selling, general, and administrative expenses for the years ended December 31, 2017, 2016, and 2015, respectively. The total fair value of the restricted common units vested during 2017, 2016, and 2015 was $24 million, $34 million, and $5 million, respectively. As of December 31, 2017, there were 76 thousand nonvested units outstanding and $1 million of unrecognized compensation expense attributable to the outstanding awards which will be recognized in 2018.
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Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, commercial paper, and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.
Fair Value Measurements Using | |||||||||||||||||||
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 | ) | ||||||||||
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Fair Value Methods
We use the following methods and assumptions in estimating the fair value of our financial instruments:
Assets and liabilities measured at fair value on a recurring basis
ARO Trust investments: Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust that is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market, is classified as available-for-sale, and is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.
Energy derivatives: Energy derivatives include commodity-based exchange-traded contracts and over-the-counter contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives assets are reported in Other current assets and deferred charges and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Energy derivatives liabilities are reported in Accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the years ended December 31, 2017 or 2016.
Additional fair value disclosures
Other receivables: Other receivables consist of margin deposits, which are reported in Other current assets and deferred charges in the Consolidated Balance Sheet. The disclosed fair value of our margin deposits is considered to approximate the carrying value generally due to the short-term nature of these items.
Long-term debt, including current portion: The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair value of the financing obligation associated with our Dalton lateral, which is included within long-term debt, was determined using an income approach (see Note 13 – Debt, Banking Arrangements, and Leases).
Guarantees: Guarantees primarily consist of a guarantee we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on a lease performance obligation that extends through 2042. Guarantees also include an indemnification related to a disposed operation.
To estimate the fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying value of the WilTel guarantee is reported in Accrued liabilities in the Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately $30 million at December 31, 2017. Our exposure declines systematically through the remaining term of WilTel’s obligation.
The fair value of the guarantee associated with the indemnification related to a disposed operation was estimated using an income approach that considered probability-weighted scenarios of potential levels of future performance. The terms of the indemnification do not limit the maximum potential future payments associated with the guarantee.
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The carrying value of this guarantee is reported in Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.
We are required by our revolving credit agreements to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.
Nonrecurring fair value measurements
We performed an interim assessment of the goodwill associated with our former Central and Northeast G&P reporting units as of September 30, 2015, and the annual assessment of goodwill associated with our Northeast G&P and West reporting units as of October 1, 2015. No impairment charges were required following these evaluations.
During the fourth quarter of 2015, we observed a significant decline in the market values of WPZ and comparable midstream companies within the industry. This served to reduce our estimate of enterprise value and increased our estimates of discount rates. As a result, we performed an impairment assessment as of December 31, 2015, of the goodwill associated with these reporting units, all within the Williams Partners segment.
We estimated the fair value of each reporting unit based on an income approach utilizing discount rates specific to the underlying businesses of each reporting unit. These discount rates considered variables unique to each business area, including equity yields of comparable midstream businesses, expectations for future growth, and customer performance considerations. Weighted-average discount rates utilized ranged from approximately 10 percent to 13 percent across the three reporting units.
As a result of the increases in discount rates during the fourth quarter of 2015, coupled with certain reductions in estimated future cash flows determined during the same period, the fair values of the former Central and Northeast G&P reporting units were determined to be below their respective carrying values. For these measurements, the book basis of each reporting unit was reduced by the associated deferred tax liabilities. We then calculated the implied fair value of goodwill by performing a hypothetical application of the acquisition method wherein the estimated fair value was allocated to the underlying assets and liabilities of each reporting unit. As a result of these Level 3 measurements, we determined that the previously recorded goodwill associated with each reporting unit was fully impaired, resulting in a fourth-quarter 2015 noncash charge of $1,098 million, reflected in Impairment of goodwill in the Consolidated Statement of Operations. For the West reporting unit, the estimated fair value exceeded the carrying value and no impairment was recorded.
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The following table presents impairments of assets and investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy.
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 | 2017 | 2016 | 2015 | |||||||||||||||
(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 | ||||||||||||||||
Other equity-method investment | Investments | Williams Partners | 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 | |||||||||||||||||
______________
(1) | Relates to certain gathering operations in the Mid-Continent region. During the third quarter of 2017, we received solicitations and engaged in negotiations for the sale of certain of these assets which led to our impairment evaluation. The estimated fair value was determined using an income approach and incorporated market inputs based on ongoing negotiations for a potential sale of a portion of the underlying assets. For the income approach, we utilized a discount rate of 10.2 percent, reflecting an estimated cost of capital and risks associated with the underlying assets. |
(2) | Relates to certain gathering operations in the Marcellus South region resulting from an anticipated decline in future volumes following a third-quarter 2017 shut-in by the primary producer. The estimated fair value was determined by the income approach utilizing a discount rate of 11.1 percent, reflecting an estimated cost of capital and risks associated with the underlying assets. |
(3) | Relates to an NGL pipeline near the Houston Ship Channel region which we anticipate will be underutilized for the foreseeable future. The estimated fair value was primarily determined by using a market approach based on our analysis of observable inputs in the principal market. |
(4) | Relates primarily to project development costs associated with an olefins pipeline project in the Gulf Coast region, the likelihood of completion of which is now considered remote. The estimated fair value of the remaining pipe and equipment considered a market approach based on our analysis of observable inputs in the principal market, as well as an estimate of replacement cost. |
(5) | Relates to our Canadian operations. We designated these operations as held for sale as of June 30, 2016. As a result, we measured the fair value of the disposal group, resulting in an impairment charge. The estimated fair value was determined by a market approach based primarily on inputs received in the marketing process and reflected our estimate of the potential assumed proceeds. We disposed of our Canadian operations through a sale during the third quarter of 2016. (See Note 2 – Acquisitions and Divestitures). |
(6) | Relates to certain gathering assets within the Mid-Continent region. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market. |
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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. |
(8) | Relates to an olefins pipeline project, the completion of which is considered remote due to lack of customer interest. The assessed fair value primarily represents the estimated fair value of unused pipeline measured using a market approach based on our analysis of observable inputs in the principal market. |
(9) | Relates to certain surplus equipment. The estimated fair value was determined by a market approach based on our analysis of observable inputs in the principal market. |
(10) | Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be lower than the carrying value. |
(11) | Relates to Williams Partners’ previously held interest in Ranch Westex and multiple Appalachia Midstream Investments currently held. The historical carrying value of these equity-method investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We estimated the fair value of these Appalachia Midstream Investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes, rates, and related capital spending. The discount rate utilized for the Appalachia Midstream Investments evaluation was 10.2 percent and reflected an estimated cost of capital as impacted by market conditions and risks associated with the underlying businesses. In addition to utilizing an income approach, we also considered a market approach for certain Appalachia Midstream Investments and Ranch Westex based on an agreement reached in February 2017 to exchange our interests in DBJV and Ranch Westex for additional interests in certain Appalachia Midstream Investments and cash. (See Note 5 – Investing Activities). |
(12) | Relates to Williams Partners’ previously held interest in DBJV and currently held equity-method investment in Laurel Mountain. Our carrying values in these equity-method investments had been written down to fair value at December 31, 2015. Our first-quarter 2016 analysis reflected higher discount rates for both of these equity-method investments, along with lower natural gas prices for Laurel Mountain. We estimated the fair value of these equity-method investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from 13.0 percent to 13.3 percent and reflected increases in the estimated cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses. |
(13) | Relates to Williams Partners’ previously held interest in DBJV, as well as equity-method investments in certain of the Appalachia Midstream Investments, UEOM, and Laurel Mountain, all of which are currently held. We estimated the fair value of these equity-method investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from 10.8 percent to 14.4 percent and reflected further fourth-quarter 2015 increases in the estimated cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses. |
(14) | Relates to Williams Partners’ previously held interest in DBJV and certain of the Appalachia Midstream Investments currently held. The historical carrying value of these equity-method investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We estimated the fair value of these equity-method investments using an income approach based on expected future cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant assumptions regarding gathering volumes and related capital spending. Discount rates utilized were 11.8 percent and 8.8 percent for DBJV and certain of the Appalachia Midstream Investments, respectively, and reflected an estimated cost of capital as impacted by market conditions, and risks associated with the underlying businesses. |
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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 | |||
Customers include producers, distribution companies, industrial users, gas marketers, and pipelines primarily located in the continental United States. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. Based upon this evaluation, we may obtain collateral to support receivables. As of December 31, 2017 and 2016, Chesapeake Energy Corporation, and its affiliates (Chesapeake), a customer within our Williams Partners segment, accounted for $176 million and $133 million, respectively, of the consolidated Trade accounts and other receivables balances.
Revenues
In 2017, 2016, and 2015, Chesapeake accounted for 10 percent, 14 percent, and 18 percent, respectively, of our consolidated revenues.
Note 17 – Contingent Liabilities and Commitments
Reporting of Natural Gas-Related Information to Trade Publications
Direct and indirect purchasers of natural gas in various states filed an individual and class actions against us, our former affiliate WPX Energy, Inc. (WPX) and its subsidiaries, and others alleging the manipulation of published gas price indices and seeking unspecified amounts of damages. Such actions were transferred to the Nevada federal district court for consolidation of discovery and pre-trial issues. We have agreed to indemnify WPX and its subsidiaries related to this matter.
In the individual action, filed by Farmland Industries Inc. (Farmland), the court issued an order on May 24, 2016, granting one of our co-defendant’s motion for summary judgment as to Farmland’s claims. On January 5, 2017, the court extended such ruling to us, entering final judgment in our favor. Farmland has appealed.
In the putative class actions, on March 30, 2017, the court issued an order denying the plaintiffs’ motions for class certification. On June 13, 2017, the United States Court of Appeals for the Ninth Circuit granted the plaintiffs’ petition for permission to appeal the order, and the appeal is now pending.
Because of the uncertainty around the remaining pending unresolved issues, we cannot reasonably estimate a range of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of these actions and our related indemnification obligation could result in a potential loss that may be material to our results of operations. In connection with this indemnification, we have an accrued liability balance associated with this matter, and as a result, have exposure to future developments in this matter.
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Alaska Refinery Contamination Litigation
We are involved in litigation arising from our ownership and operation of the North Pole Refinery in North Pole, Alaska, from 1980 until 2004, through our wholly-owned subsidiaries, Williams Alaska Petroleum Inc. (WAPI) and MAPCO Inc. We sold the refinery to Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., in 2004. The litigation involves three cases, with filing dates ranging from 2010 to 2014. The actions arise from sulfolane contamination allegedly emanating from the refinery. A putative class action lawsuit was filed by James West in 2010 naming us, WAPI, and FHRA as defendants. We and FHRA filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination. In 2011, we and FHRA settled the claim with James West. Certain claims by FHRA against us were resolved by the Alaska Supreme Court in our favor. FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-site sulfolane remain pending. The State of Alaska filed its action in March 2014, seeking damages. The City of North Pole (North Pole) filed its lawsuit in November 2014, seeking past and future damages, as well as punitive damages. Both we and WAPI asserted counterclaims against the State of Alaska and North Pole, and cross-claims against FHRA. FHRA has also filed cross-claims against us.
The underlying factual basis and claims in the cases are similar and may duplicate exposure. As such, in February 2017, the three cases were consolidated into one action in state court containing the remaining claims from the James West case and those of the State of Alaska and North Pole. A trial encompassing all three cases was originally scheduled to commence in May 2017, but has been continued. A new trial date has not been scheduled. Due to the ongoing assessment of the level and extent of sulfolane contamination, the lack of an articulated cleanup level for sulfolane, and the lack of a concrete remedial proposal and cost estimate, we are unable to estimate a range of exposure to the State of Alaska or North Pole at this time. We currently estimate that our reasonably possible loss exposure to FHRA could range from an insignificant amount up to $32 million, although uncertainties inherent in the litigation process, expert evaluations, and jury dynamics might cause our exposure to exceed that amount.
Independent of the litigation matter described in the preceding paragraphs, in 2013, the Alaska Department of Environmental Conservation indicated that it views FHRA and us as responsible parties, and that it intended to enter a compliance order to address the environmental remediation of sulfolane and other possible contaminants including cleanup work outside the refinery’s boundaries. To date, no compliance order has been issued. Due to the ongoing assessment of the level and extent of sulfolane contamination, the ultimate cost of remediation and division of costs among the potentially responsible parties, and the previously described separate litigation, we are unable to estimate a range of exposure at this time.
Royalty Matters
Certain of our customers, including one major customer, have been named in various lawsuits alleging underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases filed in Pennsylvania based on allegations that we improperly participated with that major customer in causing the alleged royalty underpayments. We believe that the claims asserted are subject to indemnity obligations owed to us by that major customer. Due to the preliminary status of the cases, we are unable to estimate a range of potential loss at this time.
Shareholder Litigation
A purported shareholder filed a class action lawsuit in the Delaware Court of Chancery on January 15, 2016. The putative class action complaint alleged that the individual members of our Board of Directors breached their fiduciary duties by, among other things, agreeing to the WPZ Merger Agreement, which purportedly reduced the merger consideration to have been received in the subsequently proposed but now terminated merger with Energy Transfer Equity, L.P. (Energy Transfer). The plaintiff filed a motion to voluntarily dismiss, which the court granted on January 13, 2017. On September 2, 2016, the same purported shareholder filed a derivative action claiming that the members of our Board of Directors breached their fiduciary duties by executing the WPZ Merger Agreement as a defensive measure against Energy Transfer. On September 28, 2016, we requested the court dismiss this action, and on May 15, 2017, the
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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 us not closing the WPZ Merger Agreement when announcing the WPZ Merger Agreement. The complaint seeks, among other things, damages and an award of costs and attorneys’ fees. The plaintiff filed an amended complaint on August 31, 2016. On October 17, 2016, we requested the court dismiss the action, and on March 8, 2017, the court dismissed the complaint with prejudice. On April 7, 2017, the plaintiff filed a notice of appeal.
We cannot reasonably estimate a range of potential loss related to these matters at this time.
Litigation Against Energy Transfer and Related Parties
On April 6, 2016, we filed suit in Delaware Chancery Court against Energy Transfer and LE GP, LLC (the general partner for Energy Transfer) alleging willful and material breaches of the Agreement and Plan of Merger (Merger Agreement) with Energy Transfer resulting from the private offering by Energy Transfer on March 8, 2016, of Series A Convertible Preferred Units (Special Offering) to certain Energy Transfer insiders and other accredited investors. The suit seeks, among other things, an injunction ordering the defendants to unwind the Special Offering and to specifically perform their obligations under the Merger Agreement. On April 19, 2016, we filed an amended complaint seeking the same relief. On May 3, 2016, Energy Transfer and LE GP, LLC filed an answer and counterclaims.
On May 13, 2016, we filed a separate complaint in Delaware Chancery Court against Energy Transfer, LE GP, LLC, and the other Energy Transfer affiliates that are parties to the Merger Agreement, alleging material breaches of the Merger Agreement for failing to cooperate and use necessary efforts to obtain a tax opinion required under the Merger Agreement (Tax Opinion) and for otherwise failing to use necessary efforts to consummate the merger under the Merger Agreement wherein we would be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger). The suit sought, among other things, a declaratory judgment and injunction preventing Energy Transfer from terminating or otherwise avoiding its obligations under the Merger Agreement due to any failure to obtain the Tax Opinion.
The Court of Chancery coordinated the Special Offering and Tax Opinion suits. On May 20, 2016, the Energy Transfer defendants filed amended affirmative defenses and verified counterclaims in the Special Offering and Tax Opinion suits, alleging certain breaches of the Merger Agreement by us and seeking, among other things, a declaration that we were not entitled to specific performance, that Energy Transfer could terminate the ETC Merger, and that Energy Transfer is entitled to a $1.48 billion termination fee. On June 24, 2016, following a two-day trial, the court issued a Memorandum Opinion and Order denying our requested relief in the Tax Opinion suit. The court did not rule on the substance of our claims related to the Special Offering or on the substance of Energy Transfer’s counterclaims. On June 27, 2016, we filed an appeal of the court’s decision with the Supreme Court of Delaware, seeking reversal and remand to pursue damages. On March 23, 2017, the Supreme Court of Delaware affirmed the Court of Chancery’s ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied on April 5, 2017.
On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the Merger Agreement by defendants. On September 23, 2016, Energy Transfer filed a second amended and supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things, payment of the $1.48 billion termination fee due to our alleged breaches of the Merger Agreement. On December 1, 2017, the court granted our motion to dismiss certain of Energy Transfer’s counterclaims, including its claim seeking payment of the $1.48 billion termination fee. On December 8, 2017, Energy Transfer filed a motion for reargument with the Court of Chancery.
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Environmental Matters
We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of December 31, 2017, we have accrued liabilities totaling $38 million for these matters, as discussed below. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At December 31, 2017, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.
The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. More recent rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, air quality standards for one hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. On October 1, 2015, the EPA issued its rule regarding National Ambient Air Quality Standards for ground-level ozone, setting a stricter standard of 70 parts per billion. We are monitoring the rule’s implementation as the reduction will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.
Continuing operations
Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At December 31, 2017, we have accrued liabilities of $7 million for these costs. We expect that these costs will be recoverable through rates.
We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December 31, 2017, we have accrued liabilities totaling $8 million for these costs.
Former operations, including operations classified as discontinued
We have potential obligations in connection with assets and businesses we no longer operate. These potential obligations include remediation activities at the direction of federal and state environmental authorities and the indemnification of the purchasers of certain of these assets and businesses for environmental and other liabilities existing at the time the sale was consummated. Our responsibilities relate to the operations of the assets and businesses described below.
• | Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations; |
• | Former petroleum products and natural gas pipelines; |
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• | Former petroleum refining facilities; |
• | Former exploration and production and mining operations; |
• | Former electricity and natural gas marketing and trading operations. |
At December 31, 2017, we have accrued environmental liabilities of $23 million related to these matters.
Other Divestiture Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way, and other representations that we have provided.
At December 31, 2017, other than as previously disclosed, we are not aware of any material claims against us involving the indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made.
In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations, none of which are expected to be material to our expected future annual results of operations, liquidity, and financial position.
Summary
We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity, and financial position. These calculations have been made without consideration of any potential recovery from third parties.
Commitments
Commitments for construction and acquisition of property, plant, and equipment are approximately $348 million at December 31, 2017.
Note 18 – Segment Disclosures
We have one reportable segment, Williams Partners. All remaining business activities are included in Other. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)
Our segment presentation of Williams Partners, which includes our consolidated master limited partnership, is reflective of the parent-level focus by our chief operating decision-maker, considering the resource allocation and governance provisions associated with the master limited partnership structure. This partnership maintains capital and cash management structures that are separate from ours. It is self-funding and maintains its own lines of bank credit and cash management accounts. These factors serve to differentiate the management of this entity as a whole.
Performance Measurement
We evaluate segment operating performance based upon Modified EBITDA (earnings before interest, taxes, depreciation, and amortization). This measure represents the basis of our internal financial reporting and is the primary
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Notes to Consolidated Financial Statements – (Continued) | ||||
performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments.
We define Modified EBITDA as follows:
•Net income (loss) before:
◦Provision (benefit) for income taxes;
◦Interest incurred, net of interest capitalized;
◦Equity earnings (losses);
◦Gain on remeasurement of equity-method investment;
◦Impairment of equity-method investments;
◦Other investing income (loss) – net;
◦Impairment of goodwill;
◦Depreciation and amortization expenses;
◦Accretion expense associated with asset retirement obligations for nonregulated operations.
• | This measure is further adjusted to include our proportionate share (based on ownership interest) of Modified EBITDA from our equity-method investments calculated consistently with the definition described above. |
The following geographic area data includes Revenues from external customers based on product shipment origin and Long-lived assets based upon physical location:
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 | ||||||||||
Long-lived assets are comprised of property, plant, and equipment, goodwill, and other intangible assets.
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Notes to Consolidated Financial Statements – (Continued) | ||||
The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Operations and Other financial information:
Williams Partners | Other | Eliminations | Total | ||||||||||||
(Millions) | |||||||||||||||
2017 | |||||||||||||||
Segment revenues: | |||||||||||||||
Service revenues | |||||||||||||||
External | $ | 5,291 | $ | 21 | $ | — | $ | 5,312 | |||||||
Internal | 1 | 11 | (12 | ) | — | ||||||||||
Total service revenues | 5,292 | 32 | (12 | ) | 5,312 | ||||||||||
Product sales | |||||||||||||||
External | 2,718 | 1 | — | 2,719 | |||||||||||
Internal | — | — | — | — | |||||||||||
Total product sales | 2,718 | 1 | — | 2,719 | |||||||||||
Total revenues | $ | 8,010 | $ | 33 | $ | (12 | ) | $ | 8,031 | ||||||
Other financial information: | |||||||||||||||
Additions to long-lived assets | $ | 2,792 | $ | 22 | $ | — | $ | 2,814 | |||||||
Proportional Modified EBITDA of equity-method investments | 795 | — | — | 795 | |||||||||||
2016 | |||||||||||||||
Segment revenues: | |||||||||||||||
Service revenues | |||||||||||||||
External | $ | 5,140 | $ | 31 | $ | — | $ | 5,171 | |||||||
Internal | 33 | 19 | (52 | ) | — | ||||||||||
Total service revenues | 5,173 | 50 | (52 | ) | 5,171 | ||||||||||
Product sales | |||||||||||||||
External | 2,318 | 10 | — | 2,328 | |||||||||||
Internal | — | 16 | (16 | ) | — | ||||||||||
Total product sales | 2,318 | 26 | (16 | ) | 2,328 | ||||||||||
Total revenues | $ | 7,491 | $ | 76 | $ | (68 | ) | $ | 7,499 | ||||||
Other financial information: | |||||||||||||||
Additions to long-lived assets | $ | 2,102 | $ | 44 | $ | (1 | ) | $ | 2,145 | ||||||
Proportional Modified EBITDA of equity-method investments | 754 | — | — | 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 | |||||||||||
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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, | |||||||||||||||||
2017 | 2016 | 2015 | |||||||||||||||
(Millions) | |||||||||||||||||
Modified EBITDA by segment: | |||||||||||||||||
Williams Partners | $ | 3,616 | $ | 3,864 | $ | 4,003 | |||||||||||
Other | (150 | ) | (542 | ) | (112 | ) | |||||||||||
3,466 | 3,322 | 3,891 | |||||||||||||||
Accretion expense associated with asset retirement obligations for nonregulated operations | (33 | ) | (31 | ) | (28 | ) | |||||||||||
Depreciation and amortization expenses | (1,736 | ) | (1,763 | ) | (1,738 | ) | |||||||||||
Impairment of goodwill | — | — | (1,098 | ) | |||||||||||||
Equity earnings (losses) | 434 | 397 | 335 | ||||||||||||||
Impairment of equity-method investments | — | (430 | ) | (1,359 | ) | ||||||||||||
Other investing income (loss) – net | 282 | 63 | 27 | ||||||||||||||
Proportional Modified EBITDA of equity-method investments | (795 | ) | (754 | ) | (699 | ) | |||||||||||
Interest expense | (1,083 | ) | (1,179 | ) | (1,044 | ) | |||||||||||
(Provision) benefit for income taxes | 1,974 | 25 | 399 | ||||||||||||||
Net income (loss) | $ | 2,509 | $ | (350 | ) | $ | (1,314 | ) | |||||||||
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 | ||||||||
Note 19 – Subsequent Events
Debt Items
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 intends to use the net proceeds to retire $250 million of 6.05 percent senior unsecured notes due June 2018, and for general corporate purposes, including the funding of capital expenditures.
Significant Risks and Uncertainties
On March 15, 2018, the FERC issued a policy statement regarding the recovery of income tax costs in rates of natural gas pipelines. The FERC found that an impermissible double recovery results from granting a Master Limited
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Notes to Consolidated Financial Statements – (Continued) | ||||
Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. 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. The FERC also issued a Notice of Proposed Rulemaking proposing a 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 associated with Tax Reform and this policy statement. Furthermore, the FERC 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 accumulated deferred income tax 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.
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Quarterly Financial Data | ||
(Unaudited) | ||
Summarized quarterly financial data are as follows:
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||
(Millions, except per-share amounts) | |||||||||||||||
2017 | |||||||||||||||
Revenues | $ | 1,988 | $ | 1,924 | $ | 1,891 | $ | 2,228 | |||||||
Product costs | 579 | 537 | 504 | 680 | |||||||||||
Net income (loss) | 569 | 193 | 125 | 1,622 | |||||||||||
Amounts attributable to The Williams Companies, Inc.: | |||||||||||||||
Net income (loss) | 373 | 81 | 33 | 1,687 | |||||||||||
Basic earnings (loss) per common share | .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 | ) | ||||||||
The sum of earnings (loss) per share for the four quarters may not equal the total earnings (loss) per share for the year due to changes in the average number of common shares outstanding and rounding.
2017
Net income (loss) for fourth-quarter 2017 includes:
• | $1.923 billion benefit for income taxes resulting from Tax Reform rate change (see Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements); |
• | $674 million of regulatory charges resulting from Tax Reform and $102 million of charges associated with regulatory asset-related deferred taxes on equity funds used during construction due to Tax Reform (see Note 6 – Other Income and Expenses). |
Net income (loss) for third-quarter 2017 includes includes:
• | $1.095 billion gain on the sale of Williams Olefins, L.L.C., a wholly owned subsidiary which owned our interest in the Geismar, Louisiana, olefins plant (Geismar Interest) (see Note 2 – Acquisitions and Divestitures); |
• | $1.210 billion impairment on certain assets (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk). |
Net income (loss) for first-quarter 2017 includes a gain of $269 million associated with the disposition of certain equity-method investments (see Note 5 – Investing Activities).
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Quarterly Financial Data – (Continued) | ||
(Unaudited) | ||
2016
Net income (loss) for fourth-quarter 2016 includes:
• | $173 million of income associated with the amortization of deferred income related to the restructuring of certain gas gathering contracts in the Barnett Shale and Mid-Continent regions and $58 million of related minimum volume commitment fees (see Note 6 – Other Income and Expenses); |
• | $318 million impairment loss on certain equity-method investments (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk). |
Net income (loss) for second-quarter 2016 includes a $747 million impairment loss on Canadian assets (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk).
Net income (loss) for first-quarter 2016 includes a $112 million impairment loss on certain equity-method investments (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk).
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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.
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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.
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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.
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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.
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Schedule II — Valuation and Qualifying Accounts
Additions | |||||||||||||||||||
Beginning Balance | Charged (Credited) To Costs and Expenses | Other | Deductions | Ending Balance | |||||||||||||||
(Millions) | |||||||||||||||||||
2017 | |||||||||||||||||||
Deferred tax asset valuation allowance (1) | $ | 334 | $ | (110 | ) | $ | — | $ | — | $ | 224 | ||||||||
2016 | |||||||||||||||||||
Deferred tax asset valuation allowance (1) | 190 | 144 | — | — | 334 | ||||||||||||||
2015 | |||||||||||||||||||
Deferred tax asset valuation allowance (1) | 206 | (16 | ) | — | — | 190 | |||||||||||||
__________
(1) Deducted from related assets.
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