WILLIAMS COMPANIES, INC.
10-Ks and 10-Qs
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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þ
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the quarterly period ended
September 30, 2016
or
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¨
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period from _____________ to ____________
_
Commission file number 1-4174
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THE WILLIAMS COMPANIES, INC.
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(Exact name of registrant as specified in its charter)
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DELAWARE
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73-0569878
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(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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ONE WILLIAMS CENTER
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||
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TULSA, OKLAHOMA
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74172-0172
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(Address of principal executive offices)
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(Zip Code)
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Registrant’s telephone number, including area code: (918) 573-2000
NO CHANGE
(Former name, former address and former fiscal year, if changed since last report.)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes
þ
No
¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
þ
Yes
¨
No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
(Check one):
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Large accelerated filer
þ
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Accelerated filer
¨
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Non-accelerated filer
¨
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Smaller reporting company
¨
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(Do not check if a smaller reporting company)
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.) Yes
¨
No
þ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
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Class
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Shares Outstanding at October 27, 2016
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Common Stock, $1 par value
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750,837,361
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The Williams Companies, Inc.
Index
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Page
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||
The reports, filings, and other public announcements of The Williams Companies, Inc. (Williams) may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act). These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.
All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “guidance,” “outlook,” “in service date” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:
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•
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Expected levels of cash distributions by Williams Partners L.P. (WPZ) with respect to general partner interests, incentive distribution rights and limited partner interests;
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•
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Levels of dividends to Williams stockholders;
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•
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Future credit ratings of Williams and WPZ;
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•
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Amounts and nature of future capital expenditures;
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1
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•
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Expansion of our business and operations;
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•
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Financial condition and liquidity;
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•
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Business strategy;
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•
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Cash flow from operations or results of operations;
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•
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Seasonality of certain business components;
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•
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Natural gas, natural gas liquids, and olefins prices, supply, and demand;
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•
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Demand for our services.
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Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:
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•
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Whether WPZ will produce sufficient cash flows to provide the level of cash distributions, including incentive distribution rights (IDRs), that we expect;
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•
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Whether we are able to pay current and expected levels of dividends;
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•
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Whether we will be able to effectively execute our financing plan including the receipt of anticipated levels of proceeds from planned asset sales;
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•
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Availability of supplies, including lower than anticipated volumes from third parties served by our midstream business, and market demand;
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•
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Volatility of pricing including the effect of lower than anticipated energy commodity prices and margins;
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•
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Inflation, interest rates, fluctuation in foreign exchange rates and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on customers and suppliers);
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•
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The strength and financial resources of our competitors and the effects of competition;
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•
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Whether we are able to successfully identify, evaluate and timely execute our capital projects and other investment opportunities in accordance with our forecasted capital expenditures budget;
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•
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Our ability to successfully expand our facilities and operations;
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•
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Development of alternative energy sources;
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•
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Availability of adequate insurance coverage and the impact of operational and developmental hazards and unforeseen interruptions;
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2
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•
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The impact of existing and future laws, regulations, the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain permits and achieve favorable rate proceeding outcomes;
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•
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Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;
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•
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Changes in maintenance and construction costs;
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•
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Changes in the current geopolitical situation;
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•
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Our exposure to the credit risk of our customers and counterparties;
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•
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Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally-recognized credit rating agencies and the availability and cost of capital;
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•
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The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;
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•
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Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities;
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•
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Acts of terrorism, including cybersecurity threats and related disruptions;
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•
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Additional risks described in our filings with the SEC.
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Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.
Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K filed with the SEC on February 26, 2016 and in Part II, Item 1A. Risk Factors in our Quarterly Reports on Form 10-Q.
3
DEFINITIONS
The following is a listing of certain abbreviations, acronyms, and other industry terminology used throughout this Form 10-Q.
Measurements
:
Barrel
: One barrel of petroleum products that equals 42 U.S. gallons
Bcf
: One billion cubic feet of natural gas
Bcf/d
: One billion cubic feet of natural gas per day
British Thermal Unit (Btu)
: A unit of energy needed to raise the temperature of one pound of water by one degree
Fahrenheit
Dekatherms (Dth)
: A unit of energy equal to one million British thermal units
Mbbls/d
: One thousand barrels per day
Mdth/d
: One thousand dekatherms per day
MMcf/d
: One million cubic feet per day
MMdth
: One million dekatherms or approximately one trillion British thermal units
MMdth/d
: One million dekatherms per day
Tbtu
: One trillion British thermal units
Consolidated Entities
:
ACMP:
Access Midstream Partners, L.P. prior to its merger with Pre-merger WPZ
Cardinal:
Cardinal Gas Services, L.L.C.
Constitution:
Constitution Pipeline Company, LLC
Gulfstar One:
Gulfstar One LLC
Jackalope:
Jackalope Gas Gathering Services, L.L.C.
Northwest Pipeline:
Northwest Pipeline LLC
Pre-merger WPZ:
Williams Partners L.P. prior to its merger with ACMP
Transco:
Transcontinental Gas Pipe Line Company, LLC
WPZ:
Williams Partners L.P.
Partially Owned Entities
: Entities in which we do not own a 100 percent ownership interest and which, as of
September 30, 2016
, 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
4
Government and Regulatory:
EPA:
Environmental Protection Agency
FERC:
Federal Energy Regulatory Commission
SEC:
Securities and Exchange Commission
Other
:
DRIP
: Distribution Reinvestment Program
Energy Transfer or ETE:
Energy Transfer Equity, L.P.
ETC:
Energy Transfer Corp LP
Merger Agreement
: Merger Agreement and Plan of Merger of Williams with Energy Transfer and certain of its affiliates
ETC Merger:
Merger wherein Williams was to be merged into ETC
Fractionation:
The process by which a mixed stream of natural gas liquids is separated into constituent products, such as ethane, propane, and butane
GAAP:
U.S. generally accepted accounting principles
IDR:
Incentive distribution right
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 any applicable Btu replacement cost, plant fuel, and third-party transportation and fractionation
PDH facility:
Propane dehydrogenation facility
5
The Williams Companies, Inc.
(Unaudited)
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Three Months Ended
September 30, |
Nine Months Ended
September 30, |
||||||||||||||
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2016
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2015
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2016
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2015
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(Millions, except per-share amounts)
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|||||||||||||||
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Revenues:
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|||||||||||||||
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Service revenues
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$
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1,247
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$
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1,239
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$
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3,678
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$
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3,677
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Product sales
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658
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560
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1,623
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1,677
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Total revenues
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1,905
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1,799
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5,301
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5,354
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||||||
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Costs and expenses:
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Product costs
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461
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426
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1,180
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1,382
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||||||
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Operating and maintenance expenses
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394
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403
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1,179
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1,227
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Depreciation and amortization expenses
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435
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432
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1,326
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1,287
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Selling, general, and administrative expenses
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177
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177
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556
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547
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Net insurance recoveries – Geismar Incident
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—
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—
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—
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(126
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)
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|||||||
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Impairment of long-lived assets
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1
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2
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811
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29
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Other (income) expense – net
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92
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3
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130
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33
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Total costs and expenses
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1,560
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1,443
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5,182
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4,379
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||||||
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Operating income (loss)
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345
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|
356
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|
119
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975
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Equity earnings (losses)
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104
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|
92
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|
302
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|
|
236
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||||||
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Impairment of equity-method investments
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—
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(461
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)
|
(112
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)
|
(461
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)
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|||||||
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Other investing income (loss) – net
|
28
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|
18
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|
64
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|
27
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|||||||
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Interest incurred
|
(304
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)
|
|
(280
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)
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(916
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)
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|
(831
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)
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||||
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Interest capitalized
|
7
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|
|
17
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|
|
30
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|
|
55
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||||
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Other income (expense) – net
|
20
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|
20
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52
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|
|
70
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|
||||||
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Income (loss) before income taxes
|
200
|
|
(238
|
)
|
(461
|
)
|
|
71
|
|
||||||
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Provision (benefit) for income taxes
|
69
|
|
(65
|
)
|
(74
|
)
|
|
48
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|
||||||
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Net income (loss)
|
131
|
|
(173
|
)
|
(387
|
)
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|
23
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||||||
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Less: Net income (loss) attributable to noncontrolling interests
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70
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|
(133
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)
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22
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(121
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)
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Net income (loss) attributable to The Williams Companies, Inc.
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$
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61
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$
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(40
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)
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$
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(409
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)
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$
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144
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Amounts attributable to The Williams Companies, Inc.:
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|||||||||||||||
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Basic earnings (loss) per common share:
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|||||||||||||||
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Net income (loss)
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$
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.08
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$
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(.05
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)
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$
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(.55
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)
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$
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.19
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|||
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Weighted-average shares (thousands)
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750,754
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749,824
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750,579
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749,059
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|||||||
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Diluted earnings (loss) per common share:
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|||||||||||||||
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Net income (loss)
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$
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.08
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$
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(.05
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)
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$
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(.55
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)
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$
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.19
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|||
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Weighted-average shares (thousands)
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751,858
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749,824
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750,579
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752,621
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|||||||
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Cash dividends declared per common share
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$
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.20
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$
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.64
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$
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1.48
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$
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1.81
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|||
See accompanying notes.
6
The Williams Companies, Inc.
Consolidated Statement of Comprehensive Income (Loss)
(Unaudited)
|
Three Months Ended
September 30, |
Nine Months Ended
September 30, |
||||||||||||||
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2016
|
2015
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2016
|
2015
|
||||||||||||
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(Millions)
|
|||||||||||||||
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Net income (loss)
|
$
|
131
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|
$
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(173
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)
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$
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(387
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)
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$
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23
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|||
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Other comprehensive income (loss):
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|||||||||||||||
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Cash flow hedging activities:
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|||||||||||||||
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Net unrealized gain (loss) from derivative instruments, net of taxes.
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2
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|
6
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|
2
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6
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|||||||
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Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes.
|
—
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(4
|
)
|
—
|
|
(4
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)
|
|||||||
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Foreign currency translation activities:
|
|||||||||||||||
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Foreign currency translation adjustments, net of taxes of ($25) and ($37) in 2016 and $14 and $24 in 2015, respectively.
|
(49
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)
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(74
|
)
|
50
|
|
(159
|
)
|
|||||||
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Reclassification into earnings upon sale of foreign entities, net of taxes of ($36) in 2016.
|
119
|
|
—
|
|
119
|
|
—
|
|
|||||||
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Pension and other postretirement benefits:
|
|||||||||||||||
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Amortization of prior service cost (credit) included in net periodic benefit cost, net of taxes of $0 and $1 in 2016 and $1 and $2 and 2015, respectively.
|
(1
|
)
|
—
|
|
(3
|
)
|
(2
|
)
|
|||||||
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Net actuarial gain (loss) arising during the year, net of taxes of $2.
|
—
|
|
—
|
|
(3
|
)
|
—
|
|
|||||||
|
Amortization of actuarial (gain) loss included in net periodic benefit cost, net of taxes of ($3) and ($9) in 2016 and ($5) and ($13) in 2015, respectively.
|
5
|
|
7
|
|
15
|
|
21
|
|
|||||||
|
Other comprehensive income (loss)
|
76
|
|
(65
|
)
|
180
|
|
(138
|
)
|
|||||||
|
Comprehensive income (loss)
|
207
|
|
(238
|
)
|
(207
|
)
|
(115
|
)
|
|||||||
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Less: Comprehensive income (loss) attributable to noncontrolling interests
|
108
|
|
(157
|
)
|
91
|
|
(175
|
)
|
|||||||
|
Comprehensive income (loss) attributable to The Williams Companies, Inc.
|
$
|
99
|
|
$
|
(81
|
)
|
$
|
(298
|
)
|
$
|
60
|
|
|||
See accompanying notes.
7
The Williams Companies, Inc.
(Unaudited)
|
September 30,
2016 |
December 31,
2015 |
|||||||
|
(Millions, except per-share amounts)
|
||||||||
|
ASSETS
|
||||||||
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Current assets:
|
||||||||
|
Cash and cash equivalents
|
$
|
77
|
|
$
|
100
|
|
||
|
Trade accounts and other receivables (net of allowance of $5 at September 30, 2016 and $3 at December 31, 2015)
|
854
|
|
1,041
|
|
||||
|
Deferred income tax assets
|
38
|
|
42
|
|
||||
|
Inventories
|
120
|
|
127
|
|
||||
|
Other current assets and deferred charges
|
538
|
|
217
|
|
||||
|
Total current assets
|
1,627
|
|
1,527
|
|
||||
|
Investments
|
7,084
|
|
7,336
|
|
||||
|
Property, plant, and equipment, at cost
|
38,461
|
|
39,039
|
|
||||
|
Accumulated depreciation and amortization
|
(10,198
|
)
|
(9,460
|
)
|
||||
|
Property, plant, and equipment – net
|
28,263
|
|
29,579
|
|
||||
|
Intangible assets – net of accumulated amortization
|
9,752
|
|
10,017
|
|
||||
|
Regulatory assets, deferred charges, and other
|
562
|
|
561
|
|
||||
|
Total assets
|
$
|
47,288
|
|
$
|
49,020
|
|
||
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LIABILITIES AND EQUITY
|
||||||||
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Current liabilities:
|
||||||||
|
Accounts payable
|
$
|
619
|
|
$
|
744
|
|
||
|
Accrued liabilities
|
1,059
|
|
1,078
|
|
||||
|
Commercial paper
|
2
|
|
499
|
|
||||
|
Long-term debt due within one year
|
785
|
|
176
|
|
||||
|
Total current liabilities
|
2,465
|
|
2,497
|
|
||||
|
Long-term debt
|
23,932
|
|
23,812
|
|
||||
|
Deferred income tax liabilities
|
4,271
|
|
4,218
|
|
||||
|
Regulatory liabilities, deferred income, and other
|
2,396
|
|
2,268
|
|
||||
|
Contingent liabilities (Note 12)
|
|
|
||||||
|
Equity:
|
||||||||
|
Stockholders’ equity:
|
||||||||
|
Common stock (960 million shares authorized at $1 par value;
785 million shares issued at September 30, 2016 and 784 million shares issued at December 31, 2015) |
785
|
|
784
|
|
||||
|
Capital in excess of par value
|
14,930
|
|
14,807
|
|
||||
|
Retained deficit
|
(9,483
|
)
|
(7,960
|
)
|
||||
|
Accumulated other comprehensive income (loss)
|
(331
|
)
|
(442
|
)
|
||||
|
Treasury stock, at cost (35 million shares of common stock)
|
(1,041
|
)
|
(1,041
|
)
|
||||
|
Total stockholders’ equity
|
4,860
|
|
6,148
|
|
||||
|
Noncontrolling interests in consolidated subsidiaries
|
9,364
|
|
10,077
|
|
||||
|
Total equity
|
14,224
|
|
16,225
|
|
||||
|
Total liabilities and equity
|
$
|
47,288
|
|
$
|
49,020
|
|
||
See accompanying notes.
8
The Williams Companies, Inc.
Consolidated Statement of Changes in Equity
(Unaudited)
|
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, 2015
|
$
|
784
|
|
$
|
14,807
|
|
$
|
(7,960
|
)
|
$
|
(442
|
)
|
$
|
(1,041
|
)
|
$
|
6,148
|
|
$
|
10,077
|
|
$
|
16,225
|
|
|||||||
|
Net income (loss)
|
—
|
|
—
|
|
(409
|
)
|
—
|
|
—
|
|
(409
|
)
|
22
|
|
(387
|
)
|
|||||||||||||||
|
Other comprehensive income (loss)
|
—
|
|
—
|
|
—
|
|
111
|
|
—
|
|
111
|
|
69
|
|
180
|
|
|||||||||||||||
|
Cash dividends – common stock
|
—
|
|
—
|
|
(1,111
|
)
|
—
|
|
—
|
|
(1,111
|
)
|
—
|
|
(1,111
|
)
|
|||||||||||||||
|
Dividends and distributions to noncontrolling interests
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(715
|
)
|
(715
|
)
|
|||||||||||||||
|
Stock-based compensation and related common stock issuances, net of tax
|
1
|
|
40
|
|
—
|
|
—
|
|
—
|
|
41
|
|
—
|
|
41
|
|
|||||||||||||||
|
Changes in ownership of consolidated subsidiaries, net
|
—
|
|
71
|
|
—
|
|
—
|
|
—
|
|
71
|
|
(113
|
)
|
(42
|
)
|
|||||||||||||||
|
Contributions from noncontrolling interests
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
27
|
|
27
|
|
|||||||||||||||
|
Other
|
—
|
|
12
|
|
(3
|
)
|
—
|
|
—
|
|
9
|
|
(3
|
)
|
6
|
|
|||||||||||||||
|
Net increase (decrease) in equity
|
1
|
|
123
|
|
(1,523
|
)
|
111
|
|
—
|
|
(1,288
|
)
|
(713
|
)
|
(2,001
|
)
|
|||||||||||||||
|
Balance – September 30, 2016
|
$
|
785
|
|
$
|
14,930
|
|
$
|
(9,483
|
)
|
$
|
(331
|
)
|
$
|
(1,041
|
)
|
$
|
4,860
|
|
$
|
9,364
|
|
$
|
14,224
|
|
|||||||
See accompanying notes.
9
The Williams Companies, Inc.
(Unaudited)
|
|
Nine Months Ended
September 30, |
||||||
|
2016
|
2015
|
||||||
|
(Millions)
|
|||||||
|
OPERATING ACTIVITIES:
|
|||||||
|
Net income (loss)
|
$
|
(387
|
)
|
$
|
23
|
|
|
|
Adjustments to reconcile to net cash provided (used) by operating activities:
|
|||||||
|
Depreciation and amortization
|
1,326
|
|
1,287
|
|
|||
|
Provision (benefit) for deferred income taxes
|
(74
|
)
|
41
|
|
|||
|
Impairment of equity-method investments
|
112
|
|
461
|
|
|||
|
Impairment of and net (gain) loss on sale of assets and businesses
|
867
|
|
35
|
|
|||
|
Amortization of stock-based awards
|
55
|
|
65
|
|
|||
|
Cash provided (used) by changes in current assets and liabilities:
|
|||||||
|
Accounts and notes receivable
|
172
|
|
374
|
|
|||
|
Inventories
|
(7
|
)
|
76
|
|
|||
|
Other current assets and deferred charges
|
(11
|
)
|
(6
|
)
|
|||
|
Accounts payable
|
(16
|
)
|
(137
|
)
|
|||
|
Accrued liabilities
|
124
|
|
(16
|
)
|
|||
|
Other, including changes in noncurrent assets and liabilities
|
(79
|
)
|
(117
|
)
|
|||
|
Net cash provided (used) by operating activities
|
2,082
|
|
2,086
|
|
|||
|
FINANCING ACTIVITIES:
|
|||||||
|
Proceeds from (payments of) commercial paper – net
|
(499
|
)
|
727
|
|
|||
|
Proceeds from long-term debt
|
5,708
|
|
6,885
|
|
|||
|
Payments of long-term debt
|
(4,966
|
)
|
(5,563
|
)
|
|||
|
Proceeds from issuance of common stock
|
8
|
|
27
|
|
|||
|
Dividends paid
|
(1,111
|
)
|
(1,356
|
)
|
|||
|
Dividends and distributions paid to noncontrolling interests
|
(715
|
)
|
(704
|
)
|
|||
|
Contributions from noncontrolling interests
|
27
|
|
85
|
|
|||
|
Payments for debt issuance costs
|
(8
|
)
|
(33
|
)
|
|||
|
Special distribution from Gulfstream
|
—
|
|
396
|
|
|||
|
Contribution to Gulfstream for repayment of debt
|
(148
|
)
|
—
|
|
|||
|
Other – net
|
(1
|
)
|
42
|
|
|||
|
Net cash provided (used) by financing activities
|
(1,705
|
)
|
506
|
|
|||
|
INVESTING ACTIVITIES:
|
|||||||
|
Property, plant, and equipment:
|
|||||||
|
Capital expenditures (1)
|
(1,577
|
)
|
(2,425
|
)
|
|||
|
Net proceeds from dispositions
|
29
|
|
3
|
|
|||
|
Proceeds from sale of businesses, net of cash divested
|
712
|
|
—
|
|
|||
|
Purchases of businesses, net of cash acquired
|
—
|
|
(112
|
)
|
|||
|
Purchases of and contributions to equity-method investments
|
(132
|
)
|
(529
|
)
|
|||
|
Distributions from unconsolidated affiliates in excess of cumulative earnings
|
341
|
|
251
|
|
|||
|
Other – net
|
227
|
|
105
|
|
|||
|
Net cash provided (used) by investing activities
|
(400
|
)
|
(2,707
|
)
|
|||
|
Increase (decrease) in cash and cash equivalents
|
(23
|
)
|
(115
|
)
|
|||
|
Cash and cash equivalents at beginning of year
|
100
|
|
240
|
|
|||
|
Cash and cash equivalents at end of period
|
$
|
77
|
|
$
|
125
|
|
|
|
_____________
|
|||||||
|
(1) Increases to property, plant, and equipment
|
$
|
(1,468
|
)
|
$
|
(2,311
|
)
|
|
|
Changes in related accounts payable and accrued liabilities
|
(109
|
)
|
(114
|
)
|
|||
|
Capital expenditures
|
$
|
(1,577
|
)
|
$
|
(2,425
|
)
|
|
See accompanying notes.
10
The Williams Companies, Inc.
Notes to Consolidated Financial Statements
(Unaudited)
Note 1 – General, Description of Business, and Basis of Presentation
General
Our accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2015, in our Annual Report on Form 10-K. The accompanying unaudited financial statements include all normal recurring adjustments and others that, in the opinion of management, are necessary to present fairly our interim financial statements.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
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.
Energy Transfer Merger Agreement
On September 28, 2015, we entered into an Agreement and Plan of Merger (Merger Agreement) with Energy Transfer Equity, L.P. (Energy Transfer) and certain of its affiliates under which we would be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger), with ETC surviving the ETC Merger. The general terms of the Merger Agreement were previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2015.
ETC filed its initial Form S-4 registration statement on November 24, 2015, and on May 25, 2016, the Form S-4 was declared “effective” by the U.S. Securities and Exchange Commission. On June 9, 2016, the Federal Trade Commission cleared the ETC Merger subject to certain conditions that we and Energy Transfer agreed to undertake, to be satisfied following a closing of the ETC Merger, including the sale of certain assets.
On April 6, 2016, we announced that we commenced litigation against Energy Transfer in response to the private offering by Energy Transfer of Series A Convertible Preferred Units that Energy Transfer disclosed on March 9, 2016.
On May 3, 2016, Energy Transfer and LE GP, LLC (the general partner for Energy Transfer) filed an answer and counterclaim. The counterclaim asserted that we materially breached our obligations under the Merger Agreement.
On May 13, 2016, we announced that we filed a separate action in the Delaware Court of Chancery seeking a declaratory judgment and injunction preventing Energy Transfer from terminating or otherwise avoiding its obligations under the Merger Agreement by asking the court to prohibit Energy Transfer from relying on either (i) any failure to close the transaction by the “Outside Date” of June 28, 2016 (Outside Date) or (ii) any failure to obtain a Section 721(a) tax opinion from Latham & Watkins LLP (Energy Transfer’s outside counsel) (Latham), as a basis for Energy Transfer to avoid fulfilling its obligation to close the proposed transactions with us. We alleged that Energy Transfer breached the Merger Agreement through a pattern of delay and obstruction designed to allow Energy Transfer to avoid its contractual commitments.
On May 20, 2016, Energy Transfer filed its affirmative defenses and counterclaim and sought, among other things, a declaratory judgment that, in the event Latham failed to deliver the Section 721(a) tax opinion prior to the Outside
11
Notes (Continued)
Date, Energy Transfer would be entitled to terminate the Merger Agreement without liability due to the failure of a closing condition. Energy Transfer also asserted that we breached the Merger Agreement, due to our Board of Directors modifying or qualifying its approval and recommendation of the ETC Merger in addition to other alleged breaches.
On June 17, 2016, our Board of Directors declared a special dividend in the amount of
$0.10
per share of our common stock, pursuant to the terms of the Merger Agreement. The special dividend was contingent on the consummation of the ETC Merger and would be payable to our holders of record at the close of business on the last business day prior to the closing of the ETC Merger.
On June 24, 2016, the Delaware Court of Chancery issued an opinion finding that Energy Transfer was contractually entitled to terminate the Merger Agreement in the event Latham was unable to deliver the required Section 721(a) tax opinion prior to the Outside Date in the Merger Agreement.
On June 27, 2016, our stockholders voted to approve the Merger Agreement and the transactions contemplated thereby. We also filed papers commencing an appeal in the Delaware Supreme Court of the Delaware Court of Chancery's June 24, 2016 ruling relating to the Merger Agreement.
On June 29, 2016, Energy Transfer announced that Latham had advised Energy Transfer that it was unable to deliver the Section 721(a) tax opinion as of the Outside Date. Energy Transfer subsequently provided us written notice terminating the Merger Agreement, citing the alleged failure of conditions under the Merger Agreement. (See
Note 12 – Contingent Liabilities
.)
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, prior to our entry into the Merger Agreement, we entered into a Termination Agreement and Release (Termination Agreement), terminating the WPZ Merger Agreement. Under the terms of the Termination Agreement, we were required to pay a
$428 million
termination fee to WPZ, of which we currently own approximately
60 percent
, including the interests of the general partner and incentive distribution rights (IDRs). Such termination fee settled through a reduction of quarterly incentive distributions we are entitled to receive from WPZ (such reduction not to exceed
$209 million
per quarter). The 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, Williams Partners L.P. (WPZ) refers to the renamed merged partnership, while Pre-merger Access Midstream Partners, L.P. (ACMP) and Pre-merger Williams Partners L.P. (Pre-merger WPZ) refer to the separate partnerships prior to the consummation of the ACMP Merger and subsequent name change. The net assets of Pre-merger WPZ and ACMP were combined at our historical basis. Our basis in ACMP reflected our business combination accounting resulting from acquiring control of ACMP on July 1, 2014.
Description of Business
We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located principally in the United States and are organized into the Williams Partners and Williams NGL & Petchem Services reportable segments. All remaining business activities are included in Other.
Williams Partners
Williams Partners consists of our consolidated master limited partnership, WPZ, and primarily includes gas pipeline and midstream businesses.
12
Notes (Continued)
WPZ’s gas pipeline businesses primarily consist of
two
interstate natural gas pipelines, which are Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline LLC (Northwest Pipeline), and several joint venture investments in interstate and intrastate natural gas pipeline systems, including a
50 percent
equity-method investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), and a
41 percent
interest in Constitution Pipeline Company, LLC (Constitution) (a consolidated entity), which is under development.
WPZ’s midstream businesses primarily consist of (1) natural gas gathering, treating, compression, and processing; (2) natural gas liquid (NGL) fractionation, storage, and transportation; (3) crude oil production handling and transportation; and (4) olefins production. The primary service areas are concentrated in major producing basins in Colorado, Texas, Oklahoma, Kansas, New Mexico, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio which include the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, and Utica shale plays as well as the Mid-Continent region.
The midstream businesses include equity-method investments in natural gas gathering and processing assets and NGL fractionation and transportation assets, including a
62 percent
equity-method investment in Utica East Ohio Midstream, LLC (UEOM), a
50 percent
equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region, a
69 percent
equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a
58 percent
equity-method investment in Caiman Energy II, LLC (Caiman II), a
60 percent
equity-method investment in Discovery Producer Services LLC (Discovery), a
50 percent
equity-method investment in Overland Pass Pipeline, LLC (OPPL), and Appalachia Midstream Services, LLC, which owns equity-method investments with an approximate average
45 percent
interest in multiple gathering systems in the Marcellus Shale (Appalachia Midstream Investments).
The midstream businesses also include our Canadian midstream operations, which are 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 – Divestiture
.)
Williams NGL & Petchem Services
Williams NGL & Petchem Services includes certain domestic olefins pipeline assets, a liquids extraction plant near Fort McMurray, Alberta, that began operations in March 2016, and a propane dehydrogenation facility under development in Canada. In September 2016, we completed the sale of our Canadian operations. (See
Note 2 – Divestiture
.)
Other
Other includes other business activities that are not operating segments, as well as corporate operations.
Basis of Presentation
Consolidated master limited partnership
As of
September 30, 2016
, we own approximately
60 percent
of the interests in WPZ, a variable interest entity (VIE) (see
Note 3 – Variable Interest Entities
), including the interests of the general partner, which are wholly owned by us, and IDRs.
In August 2016, WPZ completed an equity issuance of
6,975,446
common units sold to us in a private placement transaction for an aggregate purchase price of approximately
$250 million
. In addition, we contributed the proportionate share necessary to maintain our
2 percent
general partner interest.
WPZ is self-funding and maintains separate lines of bank credit and cash management accounts and also has a commercial paper program. (See
Note 9 – Debt and Banking Arrangements
.) Cash distributions from WPZ to us, including any associated with our IDRs, occur through the normal partnership distributions from WPZ to all partners.
13
Notes (Continued)
Significant risks and uncertainties
At the end of the third quarter of 2016, we became aware of changes involving certain of DBJV’s customer contracts, which impacted our estimates of DBJV’s future cash flows. As such, we evaluated this investment for impairment at September 30, 2016, and through the date of this filing, and determined that no impairment was necessary. The carrying value of our investment in DBJV at September 30, 2016, is
$964 million
.
We estimated the fair value of this investment using an income approach. The computations considered our estimate of the future cash flows associated with the underlying business. We have recently entered into initial discussions with the system operator regarding the terms and economic assumptions of these contract changes. Depending upon the outcome of these discussions, we may not approve of the contract changes and it is possible that we could exercise our rights pursuant to the operating agreement and move to arbitration proceedings to address these contracts and other matters potentially impacting the future cash flows of DBJV. As a result, it is reasonably possible that the ultimate outcome could adversely affect our estimates of future cash flows and could ultimately result in a future impairment of our investment in DBJV.
Accounting standards issued but not yet adopted
In August 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). ASU 2016-15 provides specific guidance on eight cash flow classification issues, including debt prepayment or debt extinguishment costs and distributions received from equity method investees, to reduce diversity in practice. The new standard is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted. The new standard requires a retrospective transition. We are evaluating the impact of the new standard 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. The new standard is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. The new standard requires varying transition methods for the different categories of amendments. We are evaluating the impact of the new standard on our consolidated financial statements.
In March 2016, the FASB issued ASU 2016-09 “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting” (ASU 2016-09). The objective of ASU 2016-09 is to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The new standard is effective for interim and annual periods beginning after December 15, 2016. Early adoption is permitted; all of the amendments included in the new standard must be adopted in the same period. The new standard requires varying transition methods for the different categories of amendments. We are evaluating the impact of the new standard on our consolidated financial statements.
In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. The new standard clarifies the definition of a lease, requires a dual approach to lease classification similar to current lease classifications, and causes lessees to recognize leases on the balance sheet as a lease liability with a corresponding right-of-use asset. The new standard is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. The new standard requires a modified retrospective transition for capital or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. We are evaluating the impact of the new standard on our consolidated financial statements.
In November 2015, the FASB issued ASU 2015-17 “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes” (ASU 2015-17). ASU 2015-17 requires that deferred income tax liabilities and assets be presented as
14
Notes (Continued)
noncurrent in a classified statement of financial position. The new standard is effective for interim and annual periods beginning after December 15, 2016, with either prospective or retrospective presentation allowed. Early adoption is permitted. Adoption of this standard will result in a change to the presentation of deferred taxes in our Consolidated Balance Sheet as the current deferred tax balance will be reclassified to a noncurrent deferred tax balance. The standard will have no impact on our Consolidated Statement of Operations and Consolidated Statement of Cash Flows.
In May 2014, the FASB issued ASU 2014-09 establishing Accounting Standards Codification (ASC) Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016. We continue to evaluate both the impact of this new standard on our consolidated financial statements and the transition method we will utilize for adoption.
Note 2 – Divestiture
In September 2016, we completed the sale of subsidiaries conducting Canadian operations, including subsidiaries of WPZ, (such subsidiaries, the disposal group), for total consideration of
$1.02 billion
, including
$712 million
of cash proceeds, net of
$31 million
of cash divested and subject to customary working capital adjustments. The total consideration also includes
$243 million
of escrowed proceeds expected to be fully received in late 2016 or early 2017 pending clearance by the Canadian Revenue Agency, and
$81 million
of other contingent consideration, both reflected in
Other current assets and deferred charges
in the
Consolidated Balance Sheet
. In connection with the sale, we agreed to waive
$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. We used the cash proceeds from the transactions to reduce borrowings on credit facilities.
The other contingent consideration primarily relates to proceeds deposited into an escrow account pending the buyer’s receipt of certain governmental incentives being pursued. Our estimate of the fair value of this contingent consideration reflects management’s probability-weighted scenarios of the buyer being awarded the associated incentives prior to a March 31, 2017, end-date specified in the sales agreement. The loss on sale will be impacted in future periods by the ultimate disposition of the escrowed proceeds, either being adjusted to reflect the receipt of the actual amount of proceeds or increased to reflect the derecognition of the associated asset in the event that the buyer is not awarded the incentives by March 31, 2017.
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 long-lived assets
in the
Consolidated Statement of Operations
. (See
Note 11 – Fair Value Measurements and Guarantees
.) We recorded an additional loss of
$65 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, during the third quarter of 2016 reflected in
Other (income) expense – net
within
Costs and expenses
in the
Consolidated Statement of Operations
. The total loss consists of a loss of
$32 million
at Williams Partners and
$33 million
at Williams NGL & Petchem Services.
15
Notes (Continued)
The following table presents the results of operations for the disposal group, excluding the impairment and loss noted above.
|
Three Months Ended September 30,
|
Nine Months Ended September 30,
|
||||||||||||||
|
2016
|
2015
|
2016
|
2015
|
||||||||||||
|
(Millions)
|
|||||||||||||||
|
Income (loss) before income taxes of disposal group
|
$
|
(9
|
)
|
$
|
6
|
|
$
|
(98
|
)
|
$
|
13
|
|
|||
|
Income (loss) before income taxes of disposal group attributable to The Williams Companies, Inc.
|
(16
|
)
|
6
|
|
(95
|
)
|
11
|
|
|||||||
Note 3 – Variable Interest Entities
On January 1, 2016, we adopted ASU 2015-02 “Amendments to the Consolidation Analysis," which eliminated certain presumptions related to a general partner interest in a master limited partnership. As a result of adopting this new accounting standard, our consolidated master limited partnership is now a VIE. We are the primary beneficiary of WPZ because we have the power to direct the activities that most significantly impact WPZ’s economic performance.
The 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.
|
|
September 30,
2016 |
|
December 31, 2015
|
|
Classification
|
||||
|
|
(Millions)
|
|
|
||||||
|
Assets (liabilities):
|
|
|
|
|
|
||||
|
Cash and cash equivalents
|
$
|
68
|
|
$
|
73
|
|
|
Cash and cash equivalents
|
|
|
Trade accounts and other receivables
–
net
|
837
|
|
1,026
|
|
Trade accounts and other receivables – net,
|
||||
|
Inventories
|
120
|
|
127
|
|
Inventories
|
||||
|
Other current assets
|
379
|
|
190
|
|
Other current assets and deferred charges
|
||||
|
Investments
|
7,084
|
|
7,336
|
|
Investments
|
||||
|
Property, plant and equipment
–
net
|
27,839
|
|
28,593
|
|
|
Property, plant and equipment – net
|
|||
|
Intangible assets
–
net
|
9,751
|
|
10,016
|
|
Intangible assets – net of accumulated amortization
|
||||
|
Regulatory assets, deferred charges, and other noncurrent assets
|
458
|
|
479
|
|
Regulatory assets, deferred charges, and other
|
||||
|
Accounts payable
|
(592
|
)
|
(625
|
)
|
|
Accounts payable
|
|||
|
Accrued liabilities including current asset retirement obligations
|
(801
|
)
|
(757
|
)
|
Accrued liabilities
|
||||
|
Commercial paper
|
(2
|
)
|
(499
|
)
|
Commercial paper
|
||||
|
Long-term debt due within one year
|
(785
|
)
|
(176
|
)
|
Long-term debt due within one year
|
||||
|
Long-term debt
|
(18,918
|
)
|
(19,001
|
)
|
Long-term debt
|
||||
|
Deferred income tax liabilities
|
(17
|
)
|
(119
|
)
|
Deferred income tax liabilities
|
||||
|
Noncurrent asset retirement obligations
|
(792
|
)
|
(857
|
)
|
Regulatory liabilities, deferred income, and other
|
||||
|
Regulatory liabilities, deferred income and other noncurrent liabilities
|
(1,314
|
)
|
(1,066
|
)
|
|
Regulatory liabilities, deferred income, and other
|
|||
16
Notes (Continued)
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 for the Tubular Bells oil and gas discovery 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. Construction of an expansion project is underway that will provide production handling and gathering services for the Gunflint oil and gas discovery in the eastern deepwater Gulf of Mexico. The expansion project is expected to be completed in two phases. The first phase went into service in July of 2016 and the second phase is expected to go into service in the fourth quarter of 2016. The current estimate of the total remaining construction cost for the expansion project is approximately
$19 million
, which is expected to be funded with revenues received from customers and capital contributions from WPZ and the other equity partner on a proportional basis.
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 construction manager for 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
$687 million
, which is expected to be funded with capital contributions from WPZ and the other equity partners on a proportional basis.
In December 2014, we received approval from the Federal Energy Regulatory Commission to construct and operate the Constitution pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied a necessary water quality certification for the New York portion of the Constitution pipeline. We remain steadfastly committed to the project, and in May 2016, Constitution appealed the NYSDEC's denial of the certification and filed an action in federal court seeking a declaration that the State of New York's authority to exercise permitting jurisdiction over certain other environmental matters is preempted by federal law. In light of the NYSDEC's denial of the water quality certification and the actions taken to challenge the decision, the project in-service date is targeted as early as the second half of 2018, which assumes that the legal challenge process is satisfactorily and promptly concluded. An unfavorable resolution could result in the impairment of a significant portion of the capitalized project costs, which total
$381 million
on a consolidated basis at September 30, 2016, and are included within
Property, plant, and equipment, at cost
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 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.
17
Notes (Continued)
Note 4 – Investing Activities
Investing Income
The
three and nine
months ended
September 30, 2016
, includes a
$27 million
gain from the sale of an equity-method investment interest in a gathering system that was part of WPZ’s Appalachia Midstream Investments within the Williams Partners segment.
During the third quarter of 2015, we recognized a loss of
$16 million
within
Equity earnings (losses)
in the Consolidated Statement of Operations associated with our share of underlying property impairments at certain of the Appalachia Midstream Investments. This item is reported within the Williams Partners segment.
Impairments
The
nine
months ended
September 30, 2016
, includes
$59 million
and
$50 million
of other-than-temporary impairment charges related to WPZ’s equity-method investments in DBJV and Laurel Mountain, respectively (see
Note 11 – Fair Value Measurements and Guarantees
) within the Williams Partners segment.
During the third quarter of 2015, we recognized other-than-temporary impairment charges of
$458 million
and
$3 million
related to WPZ’s equity-method investments in DBJV and certain of the Appalachia Midstream Investments, respectively (see
Note 11 – Fair Value Measurements and Guarantees
.) These items are reported within the Williams Partners segment.
Interest income and other
The
nine
months ended
September 30, 2016
, includes
$36 million
, and the
three and nine
months ended
September 30, 2015
, includes
$18 million
and
$27 million
, respectively, of income associated with payments received on a receivable related to the sale of certain former Venezuela assets reflected in
Other investing income (loss) – net
in the
Consolidated Statement of Operations
. Although the carrying amount of the receivable is
zero
, there is one remaining payment due to us (see
Note 11 – Fair Value Measurements and Guarantees
).
Investments
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.
18
Notes (Continued)
Note 5 – Other Income and Expenses
The following table presents certain gains or losses reflected in
Other (income) expense – net
within
Costs and expenses
in our
Consolidated Statement of Operations
:
|
Three Months Ended
September 30, |
Nine Months Ended
September 30, |
||||||||||||||
|
2016
|
2015
|
2016
|
2015
|
||||||||||||
|
(Millions)
|
|||||||||||||||
|
Williams Partners
|
|||||||||||||||
|
Amortization of regulatory assets associated with asset retirement obligations
|
$
|
8
|
|
$
|
8
|
|
$
|
25
|
|
$
|
25
|
|
|||
|
Accrual of regulatory liability related to overcollection of certain employee expenses
|
6
|
|
5
|
|
19
|
|
15
|
|
|||||||
|
Project development costs related to Constitution (see Note 3)
|
11
|
|
—
|
|
19
|
|
—
|
|
|||||||
|
Net foreign currency exchange (gains) losses (1)
|
—
|
|
(4
|
)
|
11
|
|
(8
|
)
|
|||||||
|
Loss on sale of Canadian operations (see Note 2)
|
32
|
|
—
|
|
32
|
|
—
|
|
|||||||
|
Williams NGL & Petchem Services
|
|||||||||||||||
|
Gain on sale of unused pipe
|
—
|
|
—
|
|
(10
|
)
|
—
|
|
|||||||
|
Loss on sale of Canadian operations (see Note 2)
|
33
|
|
—
|
|
33
|
|
—
|
|
|||||||
|
(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 – Divestiture
.)
|
ACMP Merger and Transition
Nine
months ended
September 30, 2016
Selling, general, and administrative expenses
includes
$5 million
for the
nine
months ended
September 30, 2016
, associated with the ACMP Merger and transition. These costs are reflected within the Williams Partners segment.
Three and nine
months ended
September 30, 2015
Selling, general, and administrative expenses
includes
$1 million
and
$35 million
for the three and
nine
months ended
September 30, 2015
, respectively, primarily related to professional advisory fees and employee transition costs associated with the ACMP Merger and transition. These costs are primarily reflected within the Williams Partners segment.
Selling, general, and administrative expenses
also includes
$7 million
and
$20 million
for the three and
nine
months ended
September 30, 2015
, respectively, of general corporate expenses associated with integration and re-alignment of resources.
Operating and maintenance expenses
includes
$10 million
for the
nine
months ended
September 30, 2015
, of transition costs reported from the ACMP Merger within the Williams Partners segment.
Interest incurred
includes transaction-related financing costs of
$2 million
for the
nine
months ended
September 30, 2015
, from the ACMP Merger.
Geismar Incident
On June 13, 2013, an explosion and fire occurred at Williams Partners’ Geismar olefins plant. The incident rendered the facility temporarily inoperable (Geismar Incident). We received
$126 million
of insurance recoveries during the
nine
months ended
September 30, 2015
, reported within the Williams Partners segment and reflected as gains in
Net insurance recoveries - Geismar Incident
.
19
Notes (Continued)
Additional Items
Three and nine
months ended
September 30, 2016
Service revenues
have been reduced by
$15 million
for the
nine
months ended
September 30, 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
$21 million
and
$40 million
for the three and
nine
months ended
September 30, 2016
, respectively, of costs associated with our evaluation of strategic alternatives and related costs within Other.
Selling, general, and administrative expenses
also includes
$16 million
and
$61 million
for the three and
nine
months ended
September 30, 2016
, respectively, of project development costs related to a proposed propane dehydrogenation facility in Alberta within the Williams NGL & Petchem Services segment. Beginning in the first quarter of 2016, these costs did not qualify for capitalization based on our strategy to limit further investment and either sell the project or obtain a partner to fund additional development.
Selling, general, and administrative expenses
and
Operating and maintenance expenses
include
$26 million
for the
nine
months ended
September 30, 2016
,
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
$23 million
and
$62 million
for the three and
nine
months ended
September 30, 2016
, respectively, for allowance for equity funds used during construction primarily within the Williams Partners segment.
Three and nine
months ended
September 30, 2015
Selling, general, and administrative expenses
includes
$18 million
and
$25 million
for the three and
nine
months ended
September 30, 2015
, respectively, of costs associated with our evaluation of strategic alternatives and related costs within Other.
Other income (expense) – net
below
Operating income (loss)
includes
$26 million
and
$70 million
for the three and
nine
months ended
September 30, 2015
, respectively, for allowance for equity funds used during construction primarily within the Williams Partners segment.
Other income (expense) – net
below
Operating income (loss)
also includes a
$14 million
gain for the
nine
months ended
September 30, 2015
, resulting from the early retirement of certain debt.
Note 6 – Provision (Benefit) for Income Taxes
The
Provision (benefit) for income taxes
includes:
|
Three Months Ended
September 30, |
Nine Months Ended
September 30, |
||||||||||||||
|
2016
|
2015
|
2016
|
2015
|
||||||||||||
|
(Millions)
|
|||||||||||||||
|
Current:
|
|||||||||||||||
|
Federal
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
|||
|
State
|
1
|
|
—
|
|
1
|
|
1
|
|
|||||||
|
Foreign
|
—
|
|
2
|
|
(1
|
)
|
6
|
|
|||||||
|
1
|
|
2
|
|
—
|
|
7
|
|
||||||||
|
Deferred:
|
|||||||||||||||
|
Federal
|
8
|
|
(60
|
)
|
(49
|
)
|
38
|
|
|||||||
|
State
|
71
|
|
(6
|
)
|
60
|
|
(4
|
)
|
|||||||
|
Foreign
|
(11
|
)
|
(1
|
)
|
(85
|
)
|
7
|
|
|||||||
|
68
|
|
(67
|
)
|
(74
|
)
|
41
|
|
||||||||
|
Provision (benefit) for income taxes
|
$
|
69
|
|
$
|
(65
|
)
|
$
|
(74
|
)
|
$
|
48
|
|
|||
20
Notes (Continued)
The effective income tax rate for the three months ended
September 30, 2016
, is less than the federal statutory rate primarily due to the impact of the allocation of income to nontaxable noncontrolling interests and the effects of taxes on foreign operations, partially offset by the effect of state income taxes, including a
$43 million
provision related to an increase in the deferred state income tax rate (net of federal benefit).
The effective income tax rate for the
nine
months ended
September 30, 2016
, is less than the federal statutory rate primarily due to the effects of taxes on foreign operations, which includes the reversal of anticipatory foreign tax credits and a valuation allowance associated with impairments and losses on the sale of our Canadian operations (see
Note 2 – Divestiture
), and the effect of state income taxes, including a
$43 million
provision related to an increase in the deferred state income tax rate (net of federal benefit). These decreases are partially offset by the impact of the allocation of income to nontaxable noncontrolling interests. The foreign income tax provision includes the tax effect of the impairments associated with our Canadian disposition.
The effective income tax rate for the three months ended
September 30, 2015
, is less than the federal statutory rate primarily due to the impact of the allocation of income to nontaxable noncontrolling interests, partially offset by the effect of state income taxes and taxes on foreign operations.
The effective income tax rate for the
nine
months ended
September 30, 2015
, is greater than the federal statutory rate primarily due to a
$14 million
tax provision associated with an adjustment to the prior year taxable foreign income and taxes on foreign operations, partially offset by the impact of the allocation of income to nontaxable noncontrolling interests and the effect of state income taxes.
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.
|
Three Months Ended
September 30, |
Nine Months Ended
September 30, |
||||||||||||||
|
2016
|
2015
|
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
|
$
|
61
|
|
$
|
(40
|
)
|
$
|
(409
|
)
|
$
|
144
|
|
|||
|
Basic weighted-average shares
|
750,754
|
|
749,824
|
|
750,579
|
|
749,059
|
|
|||||||
|
Effect of dilutive securities:
|
|||||||||||||||
|
Nonvested restricted stock units
|
568
|
|
—
|
|
—
|
|
1,900
|
|
|||||||
|
Stock options
|
536
|
|
—
|
|
—
|
|
1,662
|
|
|||||||
|
Diluted weighted-average shares
|
751,858
|
|
749,824
|
|
750,579
|
|
752,621
|
|
|||||||
|
Earnings (loss) per common share:
|
|||||||||||||||
|
Basic
|
$
|
.08
|
|
$
|
(.05
|
)
|
$
|
(.55
|
)
|
$
|
.19
|
|
|||
|
Diluted
|
$
|
.08
|
|
$
|
(.05
|
)
|
$
|
(.55
|
)
|
$
|
.19
|
|
|||
21
Notes (Continued)
Note 8 – Employee Benefit Plans
Net periodic benefit cost (credit)
is as follows:
|
|
Pension Benefits
|
||||||||||||||
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
|
|
(Millions)
|
||||||||||||||
|
Components of net periodic benefit cost:
|
|
|
|
|
|
|
|
||||||||
|
Service cost
|
$
|
13
|
|
|
$
|
15
|
|
|
$
|
40
|
|
|
$
|
44
|
|
|
Interest cost
|
16
|
|
|
14
|
|
|
47
|
|
|
43
|
|
||||
|
Expected return on plan assets
|
(22
|
)
|
|
(19
|
)
|
|
(64
|
)
|
|
(56
|
)
|
||||
|
Amortization of net actuarial loss
|
8
|
|
|
11
|
|
|
23
|
|
|
32
|
|
||||
|
Net actuarial loss from settlements
|
—
|
|
|
1
|
|
|
1
|
|
|
1
|
|
||||
|
Net periodic benefit cost
|
$
|
15
|
|
|
$
|
22
|
|
|
$
|
47
|
|
|
$
|
64
|
|
|
Other Postretirement Benefits
|
|||||||||||||||
|
Three Months Ended
September 30, |
Nine Months Ended
September 30, |
||||||||||||||
|
2016
|
2015
|
2016
|
2015
|
||||||||||||
|
(Millions)
|
|||||||||||||||
|
Components of net periodic benefit cost (credit):
|
|||||||||||||||
|
Service cost
|
$
|
—
|
|
$
|
—
|
|
$
|
1
|
|
$
|
1
|
|
|||
|
Interest cost
|
2
|
|
3
|
|
6
|
|
7
|
|
|||||||
|
Expected return on plan assets
|
(3
|
)
|
(3
|
)
|
(9
|
)
|
(9
|
)
|
|||||||
|
Amortization of prior service credit
|
(3
|
)
|
(4
|
)
|
(11
|
)
|
(12
|
)
|
|||||||
|
Amortization of net actuarial loss
|
—
|
|
—
|
|
—
|
|
1
|
|
|||||||
|
Reclassification to regulatory liability
|
1
|
|
1
|
|
3
|
|
3
|
|
|||||||
|
Net periodic benefit cost (credit)
|
$
|
(3
|
)
|
$
|
(3
|
)
|
$
|
(10
|
)
|
$
|
(9
|
)
|
|||
Amortization of prior service credit
and
net actuarial loss
included in
net periodic benefit
cost (credit)
for our other postretirement benefit plans associated with Transco and Northwest Pipeline are recorded to
regulatory assets/liabilities
instead of
other comprehensive income (loss).
The amounts of
amortization of prior service credit
recognized in
regulatory liabilities
were
$2 million
and
$3 million
for the three months ended
September 30, 2016
and
2015
, respectively, and
$7 million
and
$8 million
for the
nine
months ended
September 30, 2016
and
2015
, respectively.
During the
nine
months ended
September 30, 2016
, we contributed
$64 million
to our pension plans and
$5 million
to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately
$1 million
to our pension plans and approximately
$1 million
to our other postretirement benefit plans in the remainder of 2016.
Note 9 – Debt and Banking Arrangements
Issuances and retirements
On January 22, 2016, Transco issued
$1 billion
of
7.85 percent
senior unsecured notes due 2026 to investors in a private debt placement. Transco used the net proceeds to repay debt and to fund capital expenditures. As part of the new issuance, Transco entered into a registration rights agreement with the initial purchasers of the unsecured notes.
22
Notes (Continued)
Transco is 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. Transco is required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If Transco fails to fulfill these obligations, additional interest will accrue on the affected securities. The rate of additional interest will be
0.25 percent
per annum on the principal amount of the affected securities for the first 90-day period immediately following the occurrence of default, increasing by an additional
0.25 percent
per annum with respect to each subsequent 90-day period thereafter, up to a maximum amount for all such defaults of
0.5 percent
annually. Following the cure of any registration defaults, the accrual of additional interest will cease.
Transco retired
$200 million
of
6.4 percent
senior unsecured notes that matured on April 15, 2016.
Northwest Pipeline retired
$175 million
of
7 percent
senior unsecured notes that matured on June 15, 2016.
Commercial Paper Program
As of September 30, 2016, WPZ had
$2 million
of
Commercial paper
outstanding under its
$3 billion
commercial paper program with a weighted average interest rate of
1.30 percent
.
Credit Facilities
|
September 30, 2016
|
|||||||
|
Stated Capacity
|
Outstanding
|
||||||
|
(Millions)
|
|||||||
|
WMB
|
|||||||
|
Long-term credit facility
|
$
|
1,500
|
|
$
|
850
|
|
|
|
Letters of credit under certain bilateral bank agreements
|
14
|
|
|||||
|
Letters of credit under sublimit
|
—
|
|
|||||
|
WPZ
|
|||||||
|
Long-term credit facility (1)
|
3,500
|
|
1,230
|
|
|||
|
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 WPZ’s credit facility inclusive of any outstanding amounts under its commercial paper program.
|
23
Notes (Continued)
The following table presents the changes in
Accumulated other comprehensive income (loss)
(AOCI)
by component, net of income taxes:
|
Cash
Flow
Hedges
|
Foreign
Currency
Translation
|
Pension and
Other Post
Retirement
Benefits
|
Total
|
||||||||||||
|
(Millions)
|
|||||||||||||||
|
Balance at December 31, 2015
|
$
|
(1
|
)
|
$
|
(103
|
)
|
$
|
(338
|
)
|
$
|
(442
|
)
|
|||
|
Other comprehensive income (loss)
before reclassifications
|
1
|
|
25
|
|
(3
|
)
|
23
|
|
|||||||
|
Amounts reclassified from
accumulated
other comprehensive income (loss)
|
—
|
|
76
|
|
12
|
|
88
|
|
|||||||
|
Other comprehensive income (loss)
|
1
|
|
101
|
|
9
|
|
111
|
|
|||||||
|
Balance at September 30, 2016
|
$
|
—
|
|
$
|
(2
|
)
|
$
|
(329
|
)
|
$
|
(331
|
)
|
|||
Reclassifications out of
AOCI
are presented in the following table by component for the
nine
months ended
September 30, 2016
:
|
Component
|
Reclassifications
|
Classification
|
||||
|
(Millions)
|
||||||
|
Pension and other postretirement benefits:
|
||||||
|
Amortization of prior service cost (credit) included in net periodic benefit cost
|
$
|
(4
|
)
|
Note 8 – Employee Benefit Plans
|
||
|
Amortization of actuarial (gain) loss included in net periodic benefit cost
|
24
|
|
|
|||
|
Total pension and other postretirement benefits
|
20
|
|
||||
|
Foreign currency translation:
|
||||||
|
Reclassification of cumulative foreign currency translation adjustment upon sale of foreign entities
|
155
|
|
Other (income) expense-net
|
|||
|
Total before tax
|
175
|
|
||||
|
Income tax benefit
|
(44
|
)
|
Provision (benefit) for income taxes
|
|||
|
Net of income tax
|
131
|
|
||||
|
Noncontrolling interest
|
(43
|
)
|
Net income (loss) attributable to noncontrolling interests
|
|||
|
Reclassifications during the period
|
$
|
88
|
|
|||
24
Notes (Continued)
Note 11 – Fair Value Measurements and Guarantees
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 September 30, 2016:
|
||||||||||||||||||||
|
Measured on a recurring basis:
|
||||||||||||||||||||
|
ARO Trust investments
|
$
|
93
|
|
$
|
93
|
|
$
|
93
|
|
$
|
—
|
|
$
|
—
|
|
|||||
|
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
|
(7
|
)
|
(7
|
)
|
(1
|
)
|
—
|
|
(6
|
)
|
||||||||||
|
Additional disclosures:
|
||||||||||||||||||||
|
Contingent consideration (see Note 2)
|
81
|
|
81
|
|
—
|
|
—
|
|
81
|
|
||||||||||
|
Other receivables
|
14
|
|
16
|
|
14
|
|
—
|
|
2
|
|
||||||||||
|
Long-term debt, including current portion
(1)
|
(24,717
|
)
|
(25,789
|
)
|
—
|
|
(25,789
|
)
|
—
|
|
||||||||||
|
Guarantees
|
(45
|
)
|
(30
|
)
|
—
|
|
(14
|
)
|
(16
|
)
|
||||||||||
|
Assets (liabilities) at December 31, 2015:
|
||||||||||||||||||||
|
Measured on a recurring basis:
|
||||||||||||||||||||
|
ARO Trust investments
|
$
|
67
|
|
$
|
67
|
|
$
|
67
|
|
$
|
—
|
|
$
|
—
|
|
|||||
|
Energy derivatives assets not designated as hedging instruments
|
5
|
|
5
|
|
—
|
|
3
|
|
2
|
|
||||||||||
|
Energy derivatives liabilities not designated as hedging instruments
|
(2
|
)
|
(2
|
)
|
—
|
|
—
|
|
(2
|
)
|
||||||||||
|
Additional disclosures:
|
||||||||||||||||||||
|
Other receivables
|
12
|
|
30
|
|
10
|
|
2
|
|
18
|
|
||||||||||
|
Long-term debt, including current portion (1)
|
(23,987
|
)
|
(19,606
|
)
|
—
|
|
(19,606
|
)
|
—
|
|
||||||||||
|
Guarantee
|
(29
|
)
|
(16
|
)
|
—
|
|
(16
|
)
|
—
|
|
||||||||||
___________________________________
(1) Excludes capital leases.
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 (ARO Trust) that is specifically designated to fund future asset retirement obligations (ARO). 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.
25
Notes (Continued)
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
nine
months ended
September 30, 2016
or
2015
.
Additional fair value disclosures
Other receivables:
Other receivables primarily consists 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.
Other receivables also includes a receivable related to the sale of certain former Venezuela assets. The disclosed fair value of this receivable is determined by an income approach. We calculated the net present value of a probability-weighted set of cash flows utilizing assumptions based on contractual terms, historical payment patterns by the counterparty, future probabilities of default, our likelihood of using arbitration if the counterparty does not perform, and discount rates. We determined the fair value of the receivable to be
$2 million
and
$18 million
at
September 30, 2016
and December 31, 2015, respectively. We began accounting for the receivable under a cost recovery model in first-quarter 2015. Subsequently, we received payments greater than the carrying amount of the receivable and as a result, the carrying value of this receivable is
zero
at
September 30, 2016
and December 31, 2015. We have the right to receive one remaining quarterly installment of
$15 million
plus interest.
Long-term debt
:
The disclosed fair value of our long-term debt is determined 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.
Guarantees
:
Guarantees primarily consist of a guarantee we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on a lease performance obligation that extends through 2042. Guarantees also include an indemnification related to a disposed operation.
To estimate the disclosed fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying value of the WilTel guarantee is reported in
Accrued liabilities
in the Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately
$32 million
at
September 30, 2016
. Our exposure declines systematically throughout the remaining term of WilTel’s obligation.
The fair value of the guarantee associated with the indemnification related to a disposed operation was estimated using an income approach that considered probability-weighted scenarios of potential levels of future performance. The terms of the indemnification do not limit the maximum potential future payments associated with the guarantee. The carrying value of this guarantee is reported in
Regulatory liabilities, deferred income, and other
in the Consolidated Balance Sheet.
We are required by our revolving credit 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.
26
Notes (Continued)
Nonrecurring fair value measurements
The following table presents impairments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy.
|
Impairments
|
|||||||||||||||
|
Nine Months Ended September 30,
|
|||||||||||||||
|
Classification
|
Segment
|
Date of Measurement
|
Fair Value
|
2016
|
2015
|
||||||||||
|
(Millions)
|
|||||||||||||||
|
Surplus equipment (1)
|
Property, plant, and equipment – net
|
Williams Partners
|
June 30, 2015
|
$
|
17
|
|
$
|
20
|
|
||||||
|
Canadian operations (2)
|
Assets held for sale
|
Williams Partners
|
June 30, 2016
|
924
|
|
$
|
341
|
|
|||||||
|
Canadian operations (2)
|
Assets held for sale
|
Williams NGL & Petchem Services
|
June 30, 2016
|
206
|
|
406
|
|
||||||||
|
Certain gathering operations (3)
|
Property, plant, and equipment – net
|
Williams Partners
|
June 30, 2016
|
18
|
|
48
|
|
||||||||
|
Level 3 fair value measurements of long-lived assets
|
795
|
|
20
|
|
|||||||||||
|
Other impairments (4)
|
16
|
|
9
|
|
|||||||||||
|
Impairment of long-lived assets
|
$
|
811
|
|
$
|
29
|
|
|||||||||
|
Equity-method investments (5)
|
Investments
|
Williams Partners
|
September 30, 2015
|
$
|
1,203
|
|
$
|
461
|
|
||||||
|
Equity-method investments (6)
|
Investments
|
Williams Partners
|
March 31, 2016
|
1,294
|
|
$
|
109
|
|
|||||||
|
Other equity-method investment
|
Investments
|
Williams Partners
|
March 31, 2016
|
—
|
|
3
|
|
||||||||
|
Impairment of equity-method investments
|
$
|
112
|
|
$
|
461
|
|
|||||||||
______________
|
(1)
|
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.
|
|
(2)
|
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 reflects 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 – Divestiture
.
|
|
(3)
|
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.
|
|
(4)
|
Reflects multiple individually insignificant impairments of other certain assets that may no longer be in use or are surplus in nature for which the fair value was determined to be zero or an insignificant salvage value.
|
|
(5)
|
Relates to Williams Partners’ equity-method investments in DBJV and certain of the Appalachia Midstream Investments. The historical carrying value of these investments was initially recorded based on estimated fair value during the third quarter of 2014 in conjunction with our acquisition of ACMP. We estimated the fair value of these 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
|
27
Notes (Continued)
certain of the Appalachia Midstream Investments, respectively, and reflected our cost of capital as impacted by market conditions, and risks associated with the underlying businesses.
|
(6)
|
Relates to Williams Partners’ equity-method investments in DBJV and 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 investments, along with lower natural gas prices for Laurel Mountain. We estimated the fair value of these 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 our cost of capital, revised estimates of expected future cash flows, and risks associated with the underlying businesses.
|
Note 12 – Contingent Liabilities
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 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. Farmland claims the order did not grant summary judgment for us and other similarly-situated defendants; we disagreed, and we with other defendants have filed a motion for entry of judgment in our favor. On August 24, 2016, the court denied the motion as to us and two other similarly-situated defendants; we with the two other defendants have filed motions to reconsider.
Because of the uncertainty around the remaining pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of these actions and our related indemnification obligation could result in a potential loss that may be material to our results of operations. In connection with this indemnification, we have an accrued liability balance associated with this matter, and as a result, have exposure to future developments in this matter.
Geismar Incident
On June 13, 2013, an explosion and fire occurred at our Geismar olefins plant and rendered the facility temporarily inoperable. We are addressing the following contingent liabilities in connection with the Geismar Incident.
On October 21, 2013, the U.S. Environmental Protection Agency (EPA) issued an Inspection Report pursuant to the Clean Air Act’s Risk Management Program following its inspection of the facility on June 24 through June 28, 2013. The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating procedures, employee training, and other matters. On June 16, 2014, we received a request for information related to the Geismar Incident from the EPA under Section 114 of the Clean Air Act to which we responded on August 13, 2014. The EPA could issue penalties pertaining to final determinations.
Multiple lawsuits, including class actions for alleged offsite impacts, property damage, customer claims, and personal injury, have been filed against us. To date, we have settled certain of the personal injury claims for an aggregate immaterial amount that we have recovered from our insurers. The first trial, for four plaintiffs claiming personal injury, began on September 6, 2016, in Louisiana state court in Iberville Parish, Louisiana. On September 26, 2016, the jury returned a verdict against us, our subsidiary Williams Olefins, LLC, and two individual defendants, awarding damages of approximately
$13.6 million
, a portion of which was paid in a prior partial settlement and recovered from our insurers and the remainder of which has been charged to expense in the third quarter of 2016 along with an equal offsetting amount reflecting probable insurance recovery. We and the other defendants intend to appeal the verdict. Trial dates
28
Notes (Continued)
for additional plaintiffs are scheduled in November 2016, January 2017, April 2017, and August 2017. We believe it is probable that additional losses will be incurred on some lawsuits, while for others we believe it is only reasonably possible that losses will be incurred. However, due to ongoing litigation involving defenses to liability, the number of individual plaintiffs, limited information as to the nature and extent of all plaintiffs’ damages, and the ultimate outcome of all appeals, we are unable to reliably estimate any such losses at this time. We believe that it is probable that any ultimate losses incurred will be covered by our general liability insurance policy, which has an aggregate limit of
$610 million
applicable to this event and retention (deductible) of
$2 million
per occurrence.
Alaska Refinery Contamination Litigation
In 2010, James West filed a class action lawsuit in state court in Fairbanks, Alaska on behalf of individual property owners whose water contained sulfolane contamination allegedly emanating from the Flint Hills Oil Refinery in North Pole, Alaska. The suit named our subsidiary, Williams Alaska Petroleum Inc. (WAPI), and Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., as defendants. We owned and operated the refinery until 2004 when we sold it to FHRA. We and FHRA made claims under the pollution liability insurance policy issued in connection with the sale of the North Pole refinery to FHRA. We and FHRA also filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination.
In 2011, we and FHRA settled the James West claim. We and FHRA subsequently filed motions for summary judgment on the other’s claims. On July 8, 2014, the court dismissed all FHRA’s claims and entered judgment for us. On August 6, 2014, FHRA appealed the court’s decision to the Alaska Supreme Court, which heard oral arguments in October of 2015, and issued a decision on August 26, 2016. The Alaska Supreme Court affirmed dismissal of FHRA’s equitable claims and statutory claims for damages related to sulfolane located on the refinery property. The Alaska Supreme Court remanded FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-site sulfolane for further resolution by the trial court. We currently estimate that our reasonably possible loss exposure in this matter 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.
On March 6, 2014, the State of Alaska filed suit against FHRA, WAPI, and us in state court in Fairbanks seeking injunctive relief and damages in connection with sulfolane contamination of the water supply near the Flint Hills Oil Refinery in North Pole, Alaska. On May 5, 2014, FHRA filed cross-claims against us in the State of Alaska suit. FHRA also seeks injunctive relief and damages.
On November 26, 2014, the City of North Pole (North Pole) filed suit in Alaska state court in Fairbanks against FHRA, WAPI, and us alleging nuisance and violations of municipal and state statutes based upon the same alleged sulfolane contamination of the water supply. North Pole claims an unspecified amount of past and future damages as well as punitive damages against WAPI. FHRA filed cross-claims against us.
In October of 2015, the court consolidated the State of Alaska and North Pole cases. On February 29, 2016, we and WAPI filed Amended Answers in the consolidated cases. Both we and WAPI asserted counter claims against both the State of Alaska and North Pole, and cross claims against FHRA. A trial is scheduled to commence May 30, 2017. All or a portion of the exposure in this consolidated State of Alaska and North Pole action may duplicate exposure in the James West case. 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 at this time.
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. Due to the ongoing assessment of the level and extent of sulfolane contamination and the ultimate cost of remediation and division of costs among the potentially responsible parties, we are unable to estimate a range of exposure at this time.
29
Notes (Continued)
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 in Texas, Pennsylvania, and Ohio based on allegations that we improperly participated with that major customer in causing the alleged royalty underpayments. We have also received subpoenas from the United States Department of Justice and the Pennsylvania Attorney General requesting documents relating to the agreements between us and our major customer and calculations of the major customer’s royalty payments. On December 9, 2015, the Pennsylvania Attorney General filed a civil suit against one of our major customers and us alleging breaches of the Pennsylvania Unfair Trade Practices and Consumer Protection Law, and on February 8, 2016, the Pennsylvania Attorney General filed an amended complaint in such civil suit, which omitted us as a party. We believe that the claims asserted are subject to indemnity obligations owed to us by that major customer. Our customer and plaintiffs in the Texas cases reached a settlement, and therefore all claims asserted (or possibly asserted) by any such plaintiffs against us in the Texas cases have been fully dismissed with prejudice. Due to the preliminary status of the remaining cases, we are unable to estimate a range of potential loss at this time.
Shareholder Litigation
In July 2015, a purported shareholder of us filed a putative class and derivative action on behalf of us in the Court of Chancery of the State of Delaware. The action named as defendants certain members of our Board of Directors as well as WPZ, and named us as a nominal defendant. On December 4, 2015, the plaintiff filed an amended complaint, alleging that the preliminary proxy statement filed in connection with our proposed merger with Energy Transfer is false and misleading. As relief, the complaint requested, among other things, an injunction requiring us to make supplemental disclosures and an award of costs and attorneys’ fees. On December 9, 2015, we moved to dismiss the amended complaint in its entirety, and on March 7, 2016, the court granted our motion.
Between October 2015 and December 2015, purported shareholders of us filed six putative class action lawsuits in the Delaware Court of Chancery that were consolidated into a single suit on January 13, 2016. This consolidated putative class action lawsuit relates to our proposed merger with Energy Transfer. The complaint asserts various claims against the individual members of our Board of Directors, including that they breached their fiduciary duties by agreeing to sell us through an allegedly unfair process and for an allegedly unfair price and by allegedly failing to disclose allegedly material information about the merger. The complaint seeks, among other things, an injunction against the merger and an award of costs and attorneys’ fees. On March 22, 2016, the court granted the parties’ proposed order in the consolidated action to stay the proceedings pending the close of the transaction with Energy Transfer. The plaintiffs have not filed an amended complaint.
A purported shareholder filed a separate class action lawsuit in the Delaware Court of Chancery on January 15, 2016. The putative class action complaint alleges 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 be received in the subsequent proposed merger with Energy Transfer. The complaint seeks damages and an award of costs and attorneys’ fees. On April 22, 2016, the plaintiff filed an amended complaint pleading substantially the same claims for the same basic relief. On May 6, 2016, we requested the court dismiss the lawsuit. 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 filed a Motion to Dismiss.
Another putative class action lawsuit was filed in U.S. District Court in Delaware on January 19, 2016, but the plaintiff filed a notice for voluntary dismissal on March 7, 2016, which the court accepted.
Additionally a putative class action lawsuit in U.S. District Court in Oklahoma, filed January 14, 2016, that claimed that certain disclosures about the merger violate certain federal securities laws and that the defendants are liable for such violations, was dismissed on April 28, 2016, for failure to state a claim. The plaintiff, who was seeking injunctive relief, subsequently amended his complaint. On June 16, 2016, the parties entered into a settlement agreement resolving
30
Notes (Continued)
all claims in exchange for certain supplemental disclosures, and pursuant to which we agreed to pay the plaintiff’s fees and expenses capped at
$170,000
.
On March 7, 2016, a purported unitholder of WPZ filed a putative class action on behalf of certain purchasers of WPZ units in U.S. District Court in Oklahoma. The action names as defendants us, WPZ, Williams Partners GP LLC, Alan S. Armstrong, and Donald R. Chappel and alleges violations of certain federal securities laws for failure to disclose Energy Transfer’s intention to pursue a purchase of us conditioned on us not closing the WPZ Merger Agreement when announcing the WPZ Merger Agreement. The complaint seeks, among other things, damages and an award of costs and attorneys’ fees. The plaintiff filed an amended complaint on August 31, 2016. We cannot reasonably estimate a range of potential loss 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 alleging willful and material breaches of the Merger Agreement 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 ETC Merger. The suit seeks, 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 are not entitled to specific performance, that Energy Transfer may 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. The appeal has been fully briefed for consideration by the Supreme Court of Delaware. 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.
Opal 2014 Incident Subpoena
On July 14, 2016, our subsidiary, Williams Field Services Company, LLC (WFS), received a grand jury subpoena from the U.S. District Court for the District of Wyoming. The subpoena requests documents and information from WFS relating to, among other things, the April 23, 2014, explosion and fire at its natural gas processing facility in Lincoln County, Wyoming, near the town of Opal. We and WFS intend to cooperate fully with this investigation. It is not possible at this time to predict the outcome of this investigation, including whether the investigation will result in any action or proceeding against WFS, or to reasonably estimate any potential loss related thereto. We currently believe that this matter will not have a material adverse effect on our consolidated results of operations, financial position, or liquidity.
31
Notes (Continued)
Environmental Matters
We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the EPA, and 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
September 30, 2016
, we have accrued liabilities totaling
$37 million
for these matters, as discussed below. Our accrual reflects the most likely costs of cleanup, which are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. Certain assessment studies are still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty about the actual number of contaminated sites ultimately identified, the actual amount and extent of contamination discovered, and the final cleanup standards mandated by the EPA and other governmental authorities.
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, new 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 new rule regarding National Ambient Air Quality Standards for ground-level ozone, setting a new standard of
70 parts per billion
. We are monitoring the rule’s implementation and evaluating potential impacts to our operations. For these and other new regulations, we are unable to estimate the costs of asset additions or modifications necessary to comply due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.
Continuing operations
Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At
September 30, 2016
, 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
September 30, 2016
, we have accrued liabilities totaling
$7 million
for these costs.
Former operations, including operations classified as discontinued
We have potential obligations in connection with assets and businesses we no longer operate. These potential obligations include remediation activities at the direction of federal and state environmental authorities and the indemnification of the purchasers of certain of these assets and businesses for environmental and other liabilities existing at the time the sale was consummated. Our responsibilities relate to the operations of the assets and businesses described below.
|
•
|
Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations;
|
|
•
|
Former petroleum products and natural gas pipelines;
|
|
•
|
Former petroleum refining facilities;
|
|
•
|
Former exploration and production and mining operations;
|
32
Notes (Continued)
|
•
|
Former electricity and natural gas marketing and trading operations.
|
At
September 30, 2016
, 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
September 30, 2016
, 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.
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.
Note 13 – Segment Disclosures
Our reportable segments are Williams Partners and Williams NGL & Petchem Services. All remaining business activities are included in Other. (See
Note 1 – General, Description of Business, and Basis of Presentation
.)
Performance Measurement
We evaluate segment operating performance based upon
Modified EBITDA
(earnings before interest, taxes, depreciation, and amortization). This measure represents the basis of our internal financial reporting and is the primary performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments.
We define
Modified EBITDA
as follows:
•
Net income (loss) before:
◦
Provision (benefit) for income taxes;
◦
Interest incurred, net of interest capitalized;
◦
Equity earnings (losses);
◦
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.
33
Notes (Continued)
|
•
|
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.
|
34
Notes (Continued)
The following table reflects the reconciliation of
Segment revenues
to
Total revenues
as reported in the
Consolidated Statement of Operations
and
Total assets
by reportable segment.
|
Williams
Partners
|
Williams
NGL & Petchem
Services (1)
|
Other
|
Eliminations
|
Total
|
|||||||||||||||
|
(Millions)
|
|||||||||||||||||||
|
Three Months Ended September 30, 2016
|
|||||||||||||||||||
|
Segment revenues:
|
|||||||||||||||||||
|
Service revenues
|
|||||||||||||||||||
|
External
|
$
|
1,241
|
|
$
|
—
|
|
$
|
6
|
|
$
|
—
|
|
$
|
1,247
|
|
||||
|
Internal
|
11
|
|
—
|
|
4
|
|
(15
|
)
|
—
|
|
|||||||||
|
Total service revenues
|
1,252
|
|
—
|
|
10
|
|
(15
|
)
|
1,247
|
|
|||||||||
|
Product sales
|
|||||||||||||||||||
|
External
|
655
|
|
3
|
|
—
|
|
—
|
|
658
|
|
|||||||||
|
Internal
|
—
|
|
5
|
|
—
|
|
(5
|
)
|
—
|
|
|||||||||
|
Total product sales
|
655
|
|
8
|
|
—
|
|
(5
|
)
|
658
|
|
|||||||||
|
Total revenues
|
$
|
1,907
|
|
$
|
8
|
|
$
|
10
|
|
$
|
(20
|
)
|
$
|
1,905
|
|
||||
|
Three Months Ended September 30, 2015
|
|||||||||||||||||||
|
Segment revenues:
|
|||||||||||||||||||
|
Service revenues
|
|||||||||||||||||||
|
External
|
$
|
1,232
|
|
$
|
1
|
|
$
|
6
|
|
$
|
—
|
|
$
|
1,239
|
|
||||
|
Internal
|
—
|
|
—
|
|
64
|
|
(64
|
)
|
—
|
|
|||||||||
|
Total service revenues
|
1,232
|
|
1
|
|
70
|
|
(64
|
)
|
1,239
|
|
|||||||||
|
Product sales
|
|||||||||||||||||||
|
External
|
560
|
|
—
|
|
—
|
|
—
|
|
560
|
|
|||||||||
|
Internal
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|||||||||
|
Total product sales
|
560
|
|
—
|
|
—
|
|
—
|
|
560
|
|
|||||||||
|
Total revenues
|
$
|
1,792
|
|
$
|
1
|
|
$
|
70
|
|
$
|
(64
|
)
|
$
|
1,799
|
|
||||
|
Nine Months Ended September 30, 2016
|
|||||||||||||||||||
|
Segment revenues:
|
|||||||||||||||||||
|
Service revenues
|
|||||||||||||||||||
|
External
|
$
|
3,656
|
|
$
|
2
|
|
$
|
20
|
|
$
|
—
|
|
$
|
3,678
|
|
||||
|
Internal
|
32
|
|
—
|
|
19
|
|
(51
|
)
|
—
|
|
|||||||||
|
Total service revenues
|
3,688
|
|
2
|
|
39
|
|
(51
|
)
|
3,678
|
|
|||||||||
|
Product sales
|
|||||||||||||||||||
|
External
|
1,613
|
|
10
|
|
—
|
|
—
|
|
1,623
|
|
|||||||||
|
Internal
|
—
|
|
15
|
|
—
|
|
(15
|
)
|
—
|
|
|||||||||
|
Total product sales
|
1,613
|
|
25
|
|
—
|
|
(15
|
)
|
1,623
|
|
|||||||||
|
Total revenues
|
$
|
5,301
|
|
$
|
27
|
|
$
|
39
|
|
$
|
(66
|
)
|
$
|
5,301
|
|
||||
|
Nine Months Ended September 30, 2015
|
|||||||||||||||||||
|
Segment revenues:
|
|||||||||||||||||||
|
Service revenues
|
|||||||||||||||||||
|
External
|
$
|
3,655
|
|
$
|
2
|
|
$
|
20
|
|
$
|
—
|
|
$
|
3,677
|
|
||||
|
Internal
|
—
|
|
—
|
|
123
|
|
(123
|
)
|
—
|
|
|||||||||
|
Total service revenues
|
3,655
|
|
2
|
|
143
|
|
(123
|
)
|
3,677
|
|
|||||||||
|
Product sales
|
|||||||||||||||||||
|
External
|
1,677
|
|
—
|
|
—
|
|
—
|
|
1,677
|
|
|||||||||
|
Internal
|
1
|
|
—
|
|
—
|
|
(1
|
)
|
—
|
|
|||||||||
|
Total product sales
|
1,678
|
|
—
|
|
—
|
|
(1
|
)
|
1,677
|
|
|||||||||
|
Total revenues
|
$
|
5,333
|
|
$
|
2
|
|
$
|
143
|
|
$
|
(124
|
)
|
$
|
5,354
|
|
||||
|
September 30, 2016
|
|||||||||||||||||||
|
Total assets
|
$
|
46,538
|
|
$
|
409
|
|
$
|
737
|
|
$
|
(396
|
)
|
$
|
47,288
|
|
||||
|
December 31, 2015
|
|||||||||||||||||||
|
Total assets
|
$
|
47,870
|
|
$
|
835
|
|
$
|
850
|
|
$
|
(535
|
)
|
$
|
49,020
|
|
||||
_______________
|
(1)
|
Includes certain projects under development and thus nominal reported revenues to date.
|
35
Notes (Continued)
The following table reflects the reconciliation of
Modified EBITDA
to
Net income (loss)
as reported in the
Consolidated Statement of Operations
.
|
Three Months Ended
September 30, |
Nine Months Ended
September 30, |
||||||||||||||
|
2016
|
2015
|
2016
|
2015
|
||||||||||||
|
(Millions)
|
|||||||||||||||
|
Modified EBITDA by segment:
|
|||||||||||||||
|
Williams Partners
|
$
|
1,070
|
|
$
|
1,021
|
|
$
|
2,629
|
|
$
|
2,891
|
|
|||
|
Williams NGL & Petchem Services
|
(62
|
)
|
(5
|
)
|
(529
|
)
|
(13
|
)
|
|||||||
|
Other
|
(5
|
)
|
(17
|
)
|
(5
|
)
|
(21
|
)
|
|||||||
|
1,003
|
|
999
|
|
2,095
|
|
2,857
|
|
||||||||
|
Accretion expense associated with asset retirement obligations for nonregulated operations
|
(9
|
)
|
(6
|
)
|
(24
|
)
|
(21
|
)
|
|||||||
|
Depreciation and amortization expenses
|
(435
|
)
|
(432
|
)
|
(1,326
|
)
|
(1,287
|
)
|
|||||||
|
Equity earnings (losses)
|
104
|
|
92
|
|
302
|
|
236
|
|
|||||||
|
Impairment of equity-method investments
|
—
|
|
(461
|
)
|
(112
|
)
|
(461
|
)
|
|||||||
|
Other investing income (loss) – net
|
28
|
|
18
|
|
64
|
|
27
|
|
|||||||
|
Proportional Modified EBITDA of equity-method investments
|
(194
|
)
|
(185
|
)
|
(574
|
)
|
(504
|
)
|
|||||||
|
Interest expense
|
(297
|
)
|
(263
|
)
|
(886
|
)
|
(776
|
)
|
|||||||
|
(Provision) benefit for income taxes
|
(69
|
)
|
65
|
|
74
|
|
(48
|
)
|
|||||||
|
Net income (loss)
|
$
|
131
|
|
$
|
(173
|
)
|
$
|
(387
|
)
|
$
|
23
|
|
|||
36
Item 2
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, NGLs, and olefins. Our operations are located principally in the United States and are organized into the Williams Partners and Williams NGL & Petchem Services reportable segments. All remaining business activities are included in Other.
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; an olefin production business, and is comprised of several wholly owned and partially owned subsidiaries and joint project investments. As of
September 30, 2016
, we own approximately 60 percent of the interests in WPZ, including the interests of the general partner, which is wholly owned by us, and IDRs.
Williams Partners’ gas pipeline businesses consist primarily of Transco and Northwest Pipeline. The gas pipeline business also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent equity-method investment interest in Gulfstream and a 41 percent interest in Constitution (a consolidated entity), which is under development. As of December 31, 2015, Transco and Northwest Pipeline owned and operated a combined total of approximately 13,600 miles of pipelines with a total annual throughput of approximately 4,136 Tbtu of natural gas and peak-day delivery capacity of approximately 15 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 Geismar Olefins Facility Monetization below.) The primary service areas are concentrated in major producing basins in Colorado, Texas, Oklahoma, Kansas, New Mexico, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio which include the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, and Utica shale plays as well as the Mid-Continent region.
The midstream businesses include equity-method investments in natural gas gathering and processing assets and NGL fractionation and transportation assets, including a
62 percent
equity-method investment in UEOM, a
50 percent
equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region, a
69 percent
equity-method investment in Laurel Mountain, a
58 percent
equity-method investment in Caiman II, a
60 percent
equity-method investment in Discovery, a
50 percent
equity-method investment in OPPL, and Appalachia Midstream Services, LLC, which owns an approximate average
45 percent
equity-method investment interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).
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. (See
Note 2 – Divestiture
of Notes to Consolidated Financial Statements.)
Williams Partners’ ongoing strategy is to safely and reliably operate large-scale, interstate natural gas transmission and midstream infrastructures where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers and investing in growing markets, including the deepwater Gulf of Mexico, the Marcellus Shale, the Gulf Coast Region, and areas of increasing natural gas demand.
Williams Partners’ 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
37
Management’s Discussion and Analysis (Continued)
or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.
Williams NGL & Petchem Services
Williams NGL & Petchem Services includes certain domestic olefins pipeline assets as well as the previously owned Canadian assets which included a liquids extraction plant near Fort McMurray, Alberta, that began operations in March 2016 and a propane dehydrogenation facility under development in Canada. In September 2016, these Canadian operations were sold. (See
Note 2 – Divestiture
of Notes to Consolidated Financial Statements.)
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 of this Form 10-Q and our Annual Report on Form 10-K dated February 26, 2016.
Dividends
As previously announced, we reduced our regular quarterly dividend from $.64 per share to $.20 per share in the third quarter 2016, reflecting a 69 percent decrease from the previous quarter and from the same period last year. The dividend reduction is expected to allow Williams to reinvest additional funds into Williams Partners. The dividends were paid in
September 2016
.
Overview of
Nine Months Ended
September 30, 2016
Net income (loss) attributable to The Williams Companies, Inc.
, for the
nine
months ended
September 30, 2016
, decreased
$553 million
compared to the
nine
months ended
September 30, 2015
, reflecting increased impairment charges and loss on sale associated with our Canadian operations, the absence of $126 million of insurance recoveries, and higher interest incurred. The decrease also includes an unfavorable change in net income attributable to noncontrolling interests driven primarily by the impact of reduced incentive distributions from WPZ associated with the termination of the WPZ Merger Agreement as well as higher WPZ income. These declines were partially offset by the favorable impact of lower impairments of equity-method investments, an increase in olefins margins associated with our Geismar plant, higher equity earnings, and decreases in operating and maintenance expenses. See additional discussion in Results of Operations.
Sale of Canadian Operations
In September 2016, we completed the sale of our Canadian operations for total consideration of
$1.02 billion
, including $
712 million
of cash proceeds, net of $
31 million
of cash divested and subject to customary working capital adjustments. We recognized an impairment charge of $
747 million
during the second quarter of 2016 related to these operations and an additional loss of $
65 million
upon completion of the sale. (See Note 2 – Divestiture of Notes to Consolidated Financial Statements.)
Energy Transfer Merger Agreement
On September 28, 2015, we entered into an Agreement with Energy Transfer and certain of its affiliates. The Merger Agreement provided that, subject to the satisfaction of customary closing conditions, we would be merged with and into the newly formed ETC, with ETC surviving the ETC Merger. The general terms of the Merger Agreement were previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2015.
ETC filed its initial Form S-4 registration statement on November 24, 2015, and on May 25, 2016, the Form S-4 was declared “effective” by the SEC. On June 9, 2016, the United States Federal Trade Commission cleared the ETC Merger subject to certain conditions that we and Energy Transfer agreed to undertake, to be satisfied following a closing of the ETC Merger, including the sale of certain assets.
38
Management’s Discussion and Analysis (Continued)
On April 6, 2016, we announced that we have commenced litigation against Energy Transfer, in response to the private offering by Energy Transfer of Series A Convertible Preferred Units that Energy Transfer disclosed on March 9, 2016.
On May 3, 2016, Energy Transfer and LE GP, LLC (the general partner for Energy Transfer) filed an answer and counterclaim. The counterclaim asserts that we materially breached our obligations under the Merger Agreement.
On May 13, 2016, we announced that we filed a separate action in the Delaware Court of Chancery seeking a declaratory judgment and injunction preventing Energy Transfer from terminating or otherwise avoiding its obligations under the Merger Agreement by asking the Court to prohibit Energy Transfer from relying on either (i) any failure to close the transaction by the “Outside Date” of June 28, 2016 (Outside Date) or (ii) any failure to obtain a Section 721(a) tax opinion from Latham & Watkins LLP (Energy Transfer’s outside counsel) (Latham), as a basis for Energy Transfer to avoid fulfilling its obligation to close the proposed transactions with us. We alleged that Energy Transfer breached the Merger Agreement through a pattern of delay and obstruction designed to allow Energy Transfer to avoid its contractual commitments.
On May 20, 2016, Energy Transfer filed its affirmative defenses and counterclaim and sought, among other things, a declaratory judgment that, in the event Latham failed to deliver the Section 721(a) tax opinion prior to the Outside Date, Energy Transfer would be entitled to terminate the Merger Agreement without liability due to the failure of a closing condition. Energy Transfer also asserted that we breached the Merger Agreement, due to our Board of Directors modifying or qualifying its approval and recommendation of the ETC Merger in addition to other alleged breaches.
On June 17, 2016, our Board of Directors declared a special dividend in the amount of
$0.10
per share of our common stock, pursuant to the terms of the Merger Agreement. The special dividend was contingent on the consummation of the ETC Merger and would be payable to our holders of record at the close of business on the last business day prior to the closing of the ETC Merger.
On June 24, 2016, the Delaware Court of Chancery issued an opinion finding that Energy Transfer is contractually entitled to terminate its Merger Agreement with us in the event Latham was unable to deliver the required Section 721(a) tax opinion prior to the Outside Date in the Merger Agreement.
On June 27, 2016, our stockholders voted to approve the Merger Agreement and the transactions contemplated thereby. We also filed papers commencing an appeal in the Delaware Supreme Court of the Delaware Court of Chancery’s June 24, 2016 ruling relating to the Merger Agreement.
On June 29, 2016, Energy Transfer announced that Latham had advised Energy Transfer that it was unable to deliver the Section 721(a) tax opinion as of the Outside Date. Energy Transfer subsequently provided us written notice terminating the Merger Agreement, citing the alleged failure of conditions under the Merger Agreement. (See
Note 12 – Contingent Liabilities
of Notes to Consolidated Financial Statements.)
Williams recognizes the practical fact that ETE has refused to close the merger. Williams has concluded that it is in the best interests of its stockholders to seek, among other remedies, monetary damages from ETE for its breaches. So, while taking appropriate actions to enforce its rights and deliver benefits of the Merger Agreement to its stockholders, Williams will renew its focus on connecting the best natural gas supplies to the best markets.
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, prior to our entry into the Merger Agreement, we entered into a Termination Agreement and Release (Termination Agreement), terminating the WPZ Merger Agreement. Under the terms of the Termination Agreement, we were required to pay a
$428 million
termination fee to WPZ, of which we currently own approximately
60 percent
, including the interests of the general partner and IDRs. Such termination fee settled through a reduction of quarterly incentive distributions we are entitled to receive from WPZ (such reduction not to exceed
$209 million
per
39
Management’s Discussion and Analysis (Continued)
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.
Organizational Realignment
In September 2016, we announced organizational changes aiming to simplify our structure, increase direct operational alignment to advance our natural gas-focused strategy, and drive continued focus on customer service and execution. Effective beginning in 2017, we plan to implement the changes, which will combine the management of certain of our operations and reduce the overall number of operating areas managed within our business.
Williams Partners
Geismar Olefins Facility Monetization
In September 2016, Williams Partners announced the initiation of a process to explore monetization of its ownership interest in the Geismar, Louisiana olefins plant and complex. The potential monetization process may result in a sale or a long-term, fee-for-service tolling agreement and would be consistent with our strategy to narrow our focus and allocate capital to our natural gas-focused business.
Barnett Shale and Mid-Continent Contract Restructurings
In August 2016, Williams Partners conditionally committed to execute a new gas gathering agreement in the Barnett Shale. The agreement was executed in the fourth quarter of 2016, in conjunction with our existing customer, Chesapeake Energy Corporation, closing the sale of its Barnett Shale properties to another producer. That other producer, which has an investment grade credit rating, is now our customer under the new gas gathering agreement. The restructured agreement provided a $754 million up-front cash payment to us primarily in exchange for eliminating future minimum volume commitments. The restructured agreement also provides for revised gathering rates. Based on current commodity price assumptions, we generally expect the up-front cash proceeds and the ongoing cash flows generated by gathering services, to represent equivalent net present value of cash flows as compared to expected performance under the existing agreement. Additionally, Williams Partners agreed to a revised contract in the Mid-Continent region, also with Chesapeake Energy Corporation. The revised contract was executed in the third quarter of 2016 and provided an up-front cash payment to us of $66 million primarily in exchange for changing from a cost of service contract to fixed-fee terms. We expect the majority of the up-front cash proceeds from both these agreements will be recognized as deferred revenue and amortized into income in future periods. In the near term, we do not expect that our trend of reported results will be significantly impacted by the effect of the discount associated with the up-front cash proceeds relative to the original minimum volume commitments and reduced gathering rates. It is anticipated that both agreements will reduce customer concentration risk and provide support to realize additional drilling and improved volumes in these regions.
Powder River Basin Contract Restructuring
In October 2016, in conjunction with our partner in the Bucking Horse natural gas processing plant and Jackalope Gas Gathering System, we announced an agreement with Chesapeake Energy Corporation to restructure gathering and processing contracts in the Powder River Basin. The restructured contracts become effective in January 2017, subject to final approvals, and are expected to replace the current cost-of-service arrangement with minimum annual revenue guarantees that support the transition to a new fixed-fee structure over the next five to seven years. In the near term, we do not expect that our trend of reported results will be significantly impacted by the restructured terms.
Rock Springs Expansion
In August 2016, the Rock Springs expansion was placed into service. The project expanded Transco’s existing natural gas transmission system from New Jersey to a generation facility in Maryland and increased capacity by 192 Mdth/d.
40
Management’s Discussion and Analysis (Continued)
Redwater Expansion
In March 2016, we completed the expansion of our Redwater facilities in support of a long-term agreement to provide gas processing services to a second bitumen upgrader in Canada’s oil sands near Fort McMurray, Alberta. The expanded Redwater facility receives NGL/olefins mixtures from the second bitumen upgrader and fractionates the mixtures into an ethane/ethylene mix, propane, polymer grade propylene, normal butane, an alkylation feed and condensate. We sold these operations in September 2016. (See
Note 2 – Divestiture
of Notes to Consolidated Financial Statements.)
Williams NGL & Petchem Services
Horizon Liquids Extraction Plant
In March 2016, we completed a new liquids extraction plant near Fort McMurray, Alberta. The Boreal pipeline was extended to enable transportation of the NGL/olefins mixture from the new liquids extraction plant to Williams Partners’ expanded Redwater facilities. The plant increased the amount of NGLs produced in Canada to a total of approximately 40 Mbbls/d. To mitigate ethane price risk associated with our processing services, we had a long-term agreement with a minimum price for ethane sales to a third-party customer. We sold these operations in September 2016. (See
Note 2 – Divestiture
of Notes to Consolidated Financial Statements.)
Volatile Commodity Prices
NGL per-unit margins were approximately 18 percent lower in the first
nine
months of 2016 compared to the same period of 2015. The primary drivers for the
nine
-month comparative period decrease were a 9 percent decline
in
per-unit
non
-
ethane prices, a 39 percent decline in ethane prices, and a change in the relative mix of NGL products produced, which has shifted to a higher proportion of lower-margin ethane products
.
These unfavorable impacts were partially offset by an approximate 25 percent decline in per-unit natural gas feedstock prices. NGL per-unit margins were approximately 7 percent lower for the quarter ending
September 30, 2016
, compared to the quarter ending June 30, 2016. The decline in NGL per-unit margins between the
third
and second quarter of 2016 was due primarily to an increase in natural gas prices of approximately 40 percent in the quarter ending
September 30, 2016
, compared to the quarter ending June 30, 2016.
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.
41
Management’s Discussion and Analysis (Continued)
The following graph illustrates the effects of margin volatility and NGL production and sales volumes, as well as the margin differential between ethane and non-ethane products and the relative mix of those products.
|
The potential impact of commodity price volatility on our business for the remainder of 2016 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 seek to accomplish this through further developing our scale positions in current key markets and basins and entering new demand driven growth markets and basins where we can become the large-scale service provider. We will 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.
In response to challenging market conditions, our business plan announced in January of 2016 included significant actions to reduce costs and funding needs, such as reductions in capital investment, a reduction in workforce, and the sale of our Canadian operations. Furthermore, we have also recently announced additional measures, including the previously discussed organizational realignment and the process to explore the monetization of our ownership interest in the Geismar olefins facility.
Our growth capital and investment expenditures in 2016 are expected to total $1.9 billion. Approximately $1.3 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 non-interstate pipeline growth capital spending in 2016 primarily reflects investment in gathering and processing systems limited primarily to known new producer volumes, including volumes that support Transco expansion projects in addition to wells drilled and
42
Management’s Discussion and Analysis (Continued)
completed awaiting connecting infrastructure. We also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.
As previously discussed, we have announced a quarterly dividend of $0.20 per share, or $0.80 annually, beginning with the third-quarter of 2016. Additionally, WPZ has implemented a DRIP in which we plan to participate. This dividend level will allow us to reinvest through the DRIP program, which is expected to enhance WPZ’s ability to maintain its distribution, while providing the partnership with the flexibility to reduce debt and maintain its investment grade ratings.
Fee-based businesses are a significant component of our portfolio and serve to somewhat reduce the influence of commodity price fluctuations on our operating results and cash flows. However, producer activities have been impacted by lower energy commodity prices, which have affected our gathering volumes. The credit profiles of certain of our producer customers are increasingly challenged by the current market conditions. These conditions as well as further or prolonged declines in energy commodity prices may also result in noncash impairments of our assets.
We continue to be approached by certain customers seeking to revise certain of our gathering and processing contracts, due in part to the low energy commodity price environment. In these situations, we generally seek to reasonably consider customer needs while maintaining or improving the overall value of our contracts. Any such revisions may impact the level and timing of expected future cash flows, requiring that we evaluate the recoverability of the underlying assets, which could result in noncash impairments.
Commodity NGL margins are highly dependent upon regional supply/demand balances of natural gas while olefins are impacted by global supply and demand fundamentals. We anticipate the following trends in energy commodity prices in 2016, compared to 2015, that may impact our operating results and cash flows:
|
•
|
Natural gas prices are expected to be lower;
|
|
•
|
NGL prices are expected to be somewhat consistent;
|
|
•
|
Olefins prices, including propylene, ethylene, and the overall ethylene crack spread, are expected to be lower.
|
In 2016, our operating results include increases from our fee-based businesses placed in service over the last two years, increases in our olefins volumes associated with a full year of operations at our Geismar plant following its 2015 repair and expansion, and lower operating and general and administrative expenses associated with cost reduction initiatives.
Potential risks and obstacles that could impact the execution of our plan include:
|
•
|
Downgrade of our credit ratings and associated increase in cost of borrowings;
|
|
•
|
Higher cost of capital and/or limited availability of capital due to a change in our financial condition, interest rates, and/or market or industry conditions;
|
|
•
|
Counterparty credit and performance risk, including that of Chesapeake Energy Corporation and its affiliates;
|
|
•
|
Lower than anticipated energy commodity prices and margins;
|
|
•
|
Lower than anticipated volumes from third parties served by our midstream business;
|
|
•
|
Unexpected significant increases in capital expenditures or delays in capital project execution;
|
|
•
|
Changes in the political and regulatory environments including the risk of delay in permits needed for regulatory projects;
|
|
•
|
Lower than expected distributions, including IDRs, from WPZ;
|
43
Management’s Discussion and Analysis (Continued)
|
•
|
General economic, financial markets, or further industry downturn;
|
|
•
|
Lower than expected levels of cash flow from operations;
|
|
•
|
Physical damages to facilities, including damage to offshore facilities by named windstorms;
|
|
•
|
Reduced availability of insurance coverage.
|
We continue to address these risks through maintaining a strong financial position and liquidity, as well as through managing a diversified portfolio of energy infrastructure assets which continue to serve key markets and basins in the United States.
Expansion Projects
Our ongoing major expansion projects include the following:
Williams Partners
Eagle Ford
We plan to expand our gathering infrastructure in the Eagle Ford region in order to meet our customers’ production plans. The expansion of the gathering infrastructure includes the addition of new facilities, well connections, and gathering pipeline to the existing systems.
Oak Grove Expansion
We plan to expand our processing capacity at our Oak Grove facility by adding a second 200 MMcf/d cryogenic natural gas processing plant, which, based on our customers’ needs, is expected to be placed into service in 2020.
Gathering System Expansion
We will continue to expand the gathering systems in the Marcellus and Utica shale regions that are needed to meet our customers’ production plans. The expansion of the gathering infrastructure includes additional compression and gathering pipeline to the existing system.
Constitution Pipeline
In December 2014, we received approval from the FERC to construct and operate the jointly owned Constitution pipeline, which will have an expected capacity of 650 Mdth/d. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied a necessary water quality certification for the New York portion of the pipeline. We remain steadfastly committed to the project, and in May 2016, Constitution appealed the NYSDEC’s denial of the certification and filed an action in federal court seeking a declaration that the State of New York’s authority to exercise permitting jurisdiction over certain other environmental matters is preempted by federal law. (See
Note 3 – Variable Interest Entities
of Notes to Consolidated Financial Statements.) We currently own 41 percent of Constitution with three other parties holding 25 percent, 24 percent, and 10 percent, respectively. We will be the operator of Constitution. The 126-mile Constitution pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York, as well as to a local distribution company serving New York and Pennsylvania. In light of the NYSDEC’s denial of the water quality certification and the actions taken to challenge the decision, the target in-service date has been revised to as early as the second half of 2018, which assumes that the legal challenge process is satisfactorily and promptly concluded.
Garden State
In April 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 210 in New Jersey to a new interconnection on our Trenton Woodbury Lateral in New Jersey. The project will be constructed in phases and is expected to
44
Management’s Discussion and Analysis (Continued)
increase capacity by 180 Mdth/d. We plan to place the initial phase of the project into service during the first half of 2017 and the remaining portion in the fourth quarter of 2017, assuming timely receipt of all necessary regulatory approvals.
Norphlet Project
In March 2016, we announced that we have reached an agreement to provide deepwater gas gathering services to the Appomattox development in the Gulf of Mexico. The project will provide offshore gas gathering services to our existing Transco lateral, which will provide transmission services onshore to our Mobile Bay processing facility. We also plan to make modifications to our Main Pass 261 Platform to install an alternate delivery route from the platform, as well as modifications to our Mobile Bay processing facility. The project is scheduled to go into service during the second quarter of 2020.
Hillabee
In February 2016, the FERC issued a certificate order for the initial phases of Transco’s Hillabee Expansion Project. The project involves an expansion of Transco’s existing natural gas transmission system from Station 85 in west central Alabama to a proposed new interconnection with the Sabal Trail project in Alabama. The project will be constructed in phases, and all of the project expansion capacity will be leased to Sabal Trail. We plan to place the initial phase of the project into service concurrent with the in-service date of the Sabal Trail project, which is planned to occur as early as the second quarter of 2017. The in-service date of the second phase of the project 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 will pay us an aggregate amount of $240 million in three equal installments as certain milestones of the project are met. The first $80 million payment was received in March 2016 and the second installment was received in September 2016. WPZ expects to recognize income associated with these receipts over the term of the capacity lease agreement.
Gulf Trace
In October 2015, we received approval from the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 65 in St. Helena Parish, Louisiana to a new interconnection with Sabine Pass Liquefaction in Cameron Parish, Louisiana. We plan to place the project into service during the first quarter of 2017 and it is expected to increase capacity by 1,200 Mdth/d.
New York Bay Expansion
In July 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Pennsylvania to the Rockaway Delivery Lateral transfer point and the Narrows meter station in Richmond County, New York. We plan to place the project into service during the fourth quarter of 2017, and it is expected to increase capacity by 115 Mdth/d.
Atlantic Sunrise
In March 2015, we filed an application with the FERC to expand Transco’s existing natural gas transmission system along with greenfield facilities to provide incremental firm transportation capacity from the northeastern Marcellus producing area to markets along Transco’s mainline as far south as Station 85 in west central Alabama. We expect to place a portion of the project facilities into service during the second half of 2017 and are targeting a full in-service during mid-2018, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 1,700 Mdth/d.
45
Management’s Discussion and Analysis (Continued)
Virginia Southside II
In July 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 210 in New Jersey and Station 165 in Virginia to a new lateral extending from our Brunswick Lateral in Virginia. We plan to place the project into service during the fourth quarter of 2017, assuming timely receipt of all necessary regulatory approvals, and it is expected to increase capacity by 250 Mdth/d.
Dalton
In August 2016, we obtained approval from the FERC to expand Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm transportation capacity from Station 210 in New Jersey to markets in northwest Georgia. We plan to place the project into service in 2017 and it is expected to increase capacity by 448 Mdth/d.
Gulf Connector
In August 2016, we filed an application with the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 65 in Louisiana to delivery points in Wharton and San Patricio Counties, Texas. The project will be constructed in phases, with the initial phase of the project expected to be in service during the second half of 2018 and the remaining phase in 2019, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 475 Mdth/d.
Williams NGL & Petchem Services
Gulf Coast NGL and Olefin Infrastructure Expansion
Certain previously acquired liquids pipelines in the Gulf Coast region are expected to be combined with an organic build-out of several projects to expand our petrochemical services in that region. The projects include the construction and commissioning of pipeline systems capable of transporting various purity natural gas liquids and olefins products in the Gulf Coast region. In response to the current conditions in the midstream industry, we are slowing the pace of development and may seek partners for these projects.
Critical Accounting Estimates
Goodwill
During the first quarter of 2016, we observed a decline in WMB’s stock price and WPZ’s unit price and increases in equity yields within the midstream industry. This served to increase our estimates of discount rates. Accordingly, as of March 31, 2016, we performed a qualitative interim assessment of the goodwill, all of which is reported within the West reporting unit. The estimated fair value of the West reporting unit significantly exceeded its carrying amount at the end of the first quarter and no impairment of goodwill was recognized. For purposes of this measurement, the book basis of the reporting unit was reduced by the associated deferred tax liabilities.
We did not perform an interim assessment at the end of the third quarter of 2016 as WPZ’s weighted-average cost of capital and equity yields of comparable midstream businesses, which drive discount rates, decreased compared to first quarter.
Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and market measures utilized. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of an impairment charge in the consolidated financial statements.
Equity-Method Investments
In response to declining market conditions in the first quarter of 2016, we assessed whether the carrying amounts of certain of our equity-method investments exceeded their fair value. As a result, we recognized other-than-temporary impairment charges of $59 million and $50 million in the first-quarter related to our equity-method investments in the
46
Management’s Discussion and Analysis (Continued)
DBJV and Laurel Mountain (LMM), respectively. Our carrying values in these equity-method investments had been written down to fair value at December 31, 2015. Our first-quarter analysis reflected higher discount rates for both DBJV and LMM, along with lower natural gas prices for LMM.
We estimated the fair value of these investments using an income approach and discount rates ranging from 13.0 percent to 13.3 percent. 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.
We estimated that an overall increase in the discount rates utilized of 50 basis points would have resulted in additional impairment charges on our at-risk equity-method investments of approximately $107 million.
Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and market measures utilized. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of a different impairment charge in the consolidated financial statements.
Subsequent to the first quarter the discount rates decreased significantly and no additional impairments have been recognized.
At the end of the third quarter of 2016, we became aware of changes involving certain of DBJV’s customer contracts, which impacted our estimates of DBJV’s future cash flows. As such, we evaluated this investment for impairment at September 30, 2016, and through the date of this filing and determined that no impairment was necessary. The carrying value of our investment in DBJV at September 30, 2016, is $964 million.
We estimated the fair value of this investment using an income approach and applied a discount rate of 10.9 percent. The computations considered our estimate of the future cash flows associated with the underlying business. We have recently entered into initial discussions with the system operator regarding the terms and economic assumptions of these contract changes. Depending upon the outcome of these discussions, we may not approve of the contract changes and it is possible that we could exercise our rights pursuant to the operating agreement and move to arbitration proceedings to address these contracts and other matters potentially impacting the future cash flows of DBJV. As a result, it is reasonably possible that the ultimate outcome could adversely affect our estimates of future cash flows and could ultimately result in a future impairment of our investment in DBJV.
At September 30, 2016, our Consolidated Balance Sheet includes approximately $7.1 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:
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•
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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;
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47
Management’s Discussion and Analysis (Continued)
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•
|
Significant delays in or lack of producer development or significant declines in producer volumes in markets served by investees;
|
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•
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Significant delays in or failure to complete significant growth projects of investees.
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Constitution Pipeline Capitalized Project Costs
As of September 30, 2016,
Property, plant, and equipment, at cost
in our Consolidated Balance Sheet includes approximately $381 million of capitalized project costs for Constitution, for which WPZ is the construction manager and owns a 41 percent consolidated interest. In December 2014, we received approval from the FERC to construct and operate this jointly owned pipeline. However, in April 2016, the New York State Department of Environmental Conservation (NYSDEC) denied a necessary water quality certification for the New York portion of the Constitution pipeline. We remain steadfastly committed to the project, and in May 2016, Constitution appealed the NYSDEC's denial of the certification and filed an action in federal court seeking a declaration that the State of New York's authority to exercise permitting jurisdiction over certain other environmental matters is preempted by federal law.
As a result of the denial by the NYSDEC, we evaluated the capitalized project costs for impairment as of March 31, 2016, and determined that no impairment was necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including a scenario assuming successful resolution with the NYSDEC and construction of the pipeline, as well as a scenario where the project does not proceed. We continue to monitor the capitalized project costs associated with Constitution for potential impairment.
Long-lived 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 second quarter of 2016, certain Mid-Continent gas gathering systems were assessed for impairment due to a potential disposition of those systems in the future. Based on market observed information for these gas gathering systems, these assets were written down to their fair value. As a result, we recognized an impairment of $48 million in the Williams Partners segment.
Divestiture of Canadian Operations
As further discussed in
Note 2 – Divestiture
of Notes to Consolidated Financial Statements, we completed the sale of our Canadian operations in September 2016. The determination of the loss on sale reflects our estimate of the fair value of approximately $81 million of contingent consideration. This contingent consideration primarily relates to
proceeds deposited into an escrow account pending the buyer’s receipt of certain governmental incentives being pursued. Our estimate of the fair value reflects our management’s probability-weighted scenarios of the buyer being awarded the associated incentives prior to a March 31, 2017, end-date specified in the sales agreement. The loss on sale will be impacted in future periods by the ultimate disposition of the escrowed proceeds, either being adjusted to reflect the receipt of the actual amount of proceeds or increased to reflect the derecognition of the associated asset in the event that the buyer is not awarded the incentives by March 31, 2017.
48
Management’s Discussion and Analysis (Continued)
Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for the three and
nine
months ended
September 30, 2016
, compared to the three and
nine
months ended
September 30, 2015
. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
|
Three Months Ended
September 30, |
Nine Months Ended
September 30, |
||||||||||||||||||||||||||
|
2016
|
2015
|
$ Change*
|
% Change*
|
2016
|
2015
|
$ Change*
|
% Change*
|
||||||||||||||||||||
|
(Millions)
|
(Millions)
|
||||||||||||||||||||||||||
|
Revenues:
|
|||||||||||||||||||||||||||
|
Service revenues
|
$
|
1,247
|
|
$
|
1,239
|
|
+8
|
|
+1
|
%
|
$
|
3,678
|
|
$
|
3,677
|
|
+1
|
|
—
|
%
|
|||||||
|
Product sales
|
658
|
|
560
|
|
+98
|
|
+18
|
%
|
1,623
|
|
1,677
|
|
-54
|
|
-3
|
%
|
|||||||||||
|
Total revenues
|
1,905
|
|
1,799
|
|
5,301
|
|
5,354
|
|
|||||||||||||||||||
|
Costs and expenses:
|
|||||||||||||||||||||||||||
|
Product costs
|
461
|
|
426
|
|
-35
|
|
-8
|
%
|
1,180
|
|
1,382
|
|
+202
|
|
+15
|
%
|
|||||||||||
|
Operating and maintenance expenses
|
394
|
|
403
|
|
+9
|
|
+2
|
%
|
1,179
|
|
1,227
|
|
+48
|
|
+4
|
%
|
|||||||||||
|
Depreciation and amortization expenses
|
435
|
|
432
|
|
-3
|
|
-1
|
%
|
1,326
|
|
1,287
|
|
-39
|
|
-3
|
%
|
|||||||||||
|
Selling, general, and administrative expenses
|
177
|
|
177
|
|
—
|
|
—
|
%
|
556
|
|
547
|
|
-9
|
|
-2
|
%
|
|||||||||||
|
Net insurance recoveries – Geismar Incident
|
—
|
|
—
|
|
—
|
|
NM
|
|
—
|
|
(126
|
)
|
-126
|
|
-100
|
%
|
|||||||||||
|
Impairment of long-lived assets
|
1
|
|
2
|
|
+1
|
|
+50
|
%
|
811
|
|
29
|
|
-782
|
|
NM
|
|
|||||||||||
|
Other (income) expense – net
|
92
|
|
3
|
|
-89
|
|
NM
|
|
130
|
|
33
|
|
-97
|
|
NM
|
|
|||||||||||
|
Total costs and expenses
|
1,560
|
|
1,443
|
|
5,182
|
|
4,379
|
|
|||||||||||||||||||
|
Operating income (loss)
|
345
|
|
356
|
|
119
|
|
975
|
|
|||||||||||||||||||
|
Equity earnings (losses)
|
104
|
|
92
|
|
+12
|
|
+13
|
%
|
302
|
|
236
|
|
+66
|
|
+28
|
%
|
|||||||||||
|
Impairment of equity-method investments
|
—
|
|
(461
|
)
|
+461
|
|
+100
|
%
|
(112
|
)
|
(461
|
)
|
+349
|
|
+76
|
%
|
|||||||||||
|
Other investing income (loss) – net
|
28
|
|
18
|
|
+10
|
|
+56
|
%
|
64
|
|
27
|
|
+37
|
|
+137
|
%
|
|||||||||||
|
Interest expense
|
(297
|
)
|
(263
|
)
|
-34
|
|
-13
|
%
|
(886
|
)
|
(776
|
)
|
-110
|
|
-14
|
%
|
|||||||||||
|
Other income (expense) – net
|
20
|
|
20
|
|
—
|
|
—
|
%
|
52
|
|
70
|
|
-18
|
|
-26
|
%
|
|||||||||||
|
Income (loss) before income taxes
|
200
|
|
(238
|
)
|
(461
|
)
|
71
|
|
|||||||||||||||||||
|
Provision (benefit) for income taxes
|
69
|
|
(65
|
)
|
-134
|
|
NM
|
|
(74
|
)
|
48
|
|
+122
|
|
NM
|
|
|||||||||||
|
Net income (loss)
|
131
|
|
(173
|
)
|
(387
|
)
|
23
|
|
|||||||||||||||||||
|
Less: Net income (loss) attributable to noncontrolling interests
|
70
|
|
(133
|
)
|
-203
|
|
NM
|
|
22
|
|
(121
|
)
|
-143
|
|
NM
|
|
|||||||||||
|
Net income (loss) attributable to The Williams Companies, Inc.
|
$
|
61
|
|
$
|
(40
|
)
|
$
|
(409
|
)
|
$
|
144
|
|
|||||||||||||||
|
|
|
*
|
+ = 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.
|
49
Management’s Discussion and Analysis (Continued)
Three months ended
September 30, 2016
vs. three months ended
September 30, 2015
Service revenues
improved due to growth associated with expansion projects placed in service in 2015 and 2016, including projects in the eastern Gulf Coast region, Transco’s natural gas transportation system, and in the Appalachian basin. These increases were partially offset by lower gathering rates in the Eagle Ford Shale.
Product sales
increased due to higher marketing revenues, higher olefins sales, and increased revenues from our equity NGLs primarily due to higher volumes. The increase in marketing revenues are driven by higher NGL and natural gas prices and crude oil volumes, partially offset by lower NGL and natural gas volumes and crude oil prices. The increase in olefin sales are primarily associated with higher ethylene prices at our Geismar plant.
The increase in
Product costs
includes higher marketing purchases primarily due to the same factors that increased marketing revenues. In addition, natural gas purchases associated with the production of equity NGLs increased, partially offset by lower olefin feedstock purchases. Natural gas purchases increased reflecting higher volumes. The decline in olefin feedstock purchases is primarily due to lower propylene production volumes.
Operating and maintenance expenses
reflect decreases in primarily outside service and labor-related costs resulting from our cost containment efforts and first-quarter 2016 workforce reductions, substantially offset by higher pipeline testing and general maintenance at Transco.
Selling, general, and administrative expenses
reflect a $16 million increase related to project development costs associated with the Canadian PDH facility that we began expensing in 2016, substantially offset by the absence of ACMP transition-related costs in 2015 as well as lower labor-related costs resulting from our first-quarter 2016 workforce reductions and cost containment efforts.
Other (income) expense – net
within
Operating income (loss)
includes a loss on the sale of our Canadian operations that were sold in September 2016 (see
Note 2 – Divestiture
of Notes to Consolidated Financial Statements), as well as project development costs at Constitution as we discontinued capitalization of these costs in April 2016. (See
Note 3 – Variable Interest Entities
of Notes to Consolidated Financial Statements.)
Operating income (loss)
changed unfavorably primarily due to the loss on the sale of our Canadian operations and project development costs associated with the Canadian PDH facility and Constitution, partially offset by higher olefin margins associated with improved ethylene prices at our Geismar plant and lower costs and expenses primarily related to cost containment efforts and workforce reductions.
Equity earnings (losses)
changed favorably primarily due to a $7 million increase at UEOM. Additionally, lower impairments recognized within our Appalachia Midstream Investments were substantially offset by lower operating results.
Impairment of equity-method investments
reflects 2015 impairment charges associated with certain equity-method investments. (See
Note 4 – Investing Activities
of Notes to Consolidated Financial Statements.)
Other investing income (loss) – net
changed favorably due to a 2016 gain on the sale of an equity-method investment interest in a gathering system that was part of our Appalachia Midstream Investments gathering system, partially offset by the absence of interest income received in 2015 associated with a receivable related to the sale of certain former Venezuela assets. (See
Note 4 – Investing Activities
of Notes to Consolidated Financial Statements.)
Interest expense
increased due to higher
Interest incurred
of $24 million primarily attributable to new debt issuances in 2016 and 2015 as well as lower
Interest capitalized
of $10 million primarily related to Canadian construction projects that have been placed into service. (See
Note 9 – Debt and Banking Arrangements
of Notes to Consolidated Financial Statements.)
Provision (benefit) for income taxes
changed unfavorably primarily due to higher pretax income. See
Note 6 – 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 periods.
50
Management’s Discussion and Analysis (Continued)
The unfavorable change in
Net income (loss) attributable to noncontrolling interests
is primarily due to higher operating results at WPZ.
Nine
months ended
September 30, 2016
vs.
nine
months ended
September 30, 2015
Service revenues
were consistent, but include increases associated with
expansion projects placed in service in 2015 and 2016 as well as higher rates and volumes in the Haynesville area primarily attributable to a new contract executed in 2015. These increases were offset by a decrease related to lower volumes attributable to suspending operations in order to facilitate the tie-in of the Gunflint expansion at Gulfstar One, a decrease in storage revenues at Transco, and lower gathering rates in the Eagle Ford Shale.
Product sales
decreased due to reduced marketing revenues primarily associated with lower NGL volumes and lower crude oil, non-ethane, and natural gas prices, partially offset by higher crude oil and natural gas volumes. Olefins sales increased primarily due to the increased volumes at our Geismar plant as a result of the plant operating at higher production levels in 2016, partially offset by lower olefin sales from other olefin operations associated with lower volumes and per-unit sales prices.
The decrease in
Product costs
includes lower marketing purchases primarily associated with a decline in per-unit costs across most products and lower volumes in addition to lower olefin feedstock purchases. 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 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, as well as the absence of ACMP transition related costs recognized in 2015, partially offset by $14 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.
Selling, general, and administrative expenses
increased primarily due to certain project development costs associated with the Canadian PDH facility that we began expensing in 2016, as well as $14 million of higher costs associated with our evaluation of strategic alternatives and $12 million of severance and related costs recognized in 2016. These increases were significantly offset by 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.
Net insurance recoveries – Geismar Incident
changed unfavorably reflecting the absence of $126 million of insurance proceeds received in the second quarter of 2015.
Impairment of long-lived assets
reflects 2016 impairments of our Canadian operations and certain Mid-Continent assets (see
Note 11 – Fair Value Measurements and Guarantees
). Impairments recognized in 2015 relate primarily to surplus equipment write-offs.
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 Canadian operations, partially offset by a $10 million gain on the sale of unused pipe in 2016.
Operating income (loss)
changed unfavorably primarily due to impairments of long-lived assets in 2016, the absence of insurance proceeds received in the second quarter of 2015, a loss on the sale of our Canadian operations, expensed Canadian PDH facility project development costs, and higher depreciation expenses related to new projects placed in service. These decreases were partially offset by higher olefin margins related to the Geismar plant operating at higher production levels, lower costs related to the merger and integration of ACMP, and lower costs and expenses primarily associated with cost containment efforts.
51
Management’s Discussion and Analysis (Continued)
Equity earnings (losses)
changed favorably primarily due to a $23 million increase at Discovery driven by the completion of the Keathley Canyon Connector in the first quarter of 2015. Additionally, UEOM and OPPL increased $16 million and $14 million, respectively.
Impairment of equity-method investments
reflects first-quarter 2016 impairment charges associated with our DBJV and Laurel Mountain equity-method investments, while the 2015 impairment charge relates to our equity-method investment in DBJV. (See
Note 4 – Investing Activities
of Notes to Consolidated Financial Statements.)
Other investing income (loss) – net
changed favorably due to a 2016 gain on the sale of an equity-method investment interest in a gathering system that was part of our Appalachia Midstream Investments and higher interest income associated with a receivable related to the sale of certain former Venezuela assets. (See
Note 4 – Investing Activities
of Notes to Consolidated Financial Statements.)
Interest expense
increased due to higher
Interest incurred
of $85 million primarily attributable to new debt issuances in 2016 and 2015 and lower
Interest capitalized
of $25 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 9 – Debt and Banking Arrangements
of Notes to Consolidated Financial Statements.)
Other income (expense) – net
below
Operating income (loss)
changed unfavorably primarily due to the absence of a $14 million gain on early debt retirement in 2015 and a decrease in allowance for equity funds used during construction (AFUDC) due to decreased spending on Constitution.
Provision (benefit) for income taxes
changed favorably primarily due to lower pretax income. See
Note 6 – 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 periods.
The unfavorable change in
Net income (loss) attributable to noncontrolling interests
is primarily due to the impact of decreased income allocated to the WPZ general partner driven by the impact of reduced incentive distributions from WPZ associated with the termination of the WPZ Merger Agreement, higher operating results at WPZ, and the absence of the accelerated amortization of a beneficial conversion feature from the first quarter of 2015.
Period-Over-Period Operating Results - Segments
We evaluate segment operating performance based upon
Modified EBITDA
.
Note 13 – 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.
52
Management’s Discussion and Analysis (Continued)
Williams Partners
|
Three Months Ended
September 30, |
Nine Months Ended
September 30, |
||||||||||||||
|
2016
|
2015
|
2016
|
2015
|
||||||||||||
|
(Millions)
|
|||||||||||||||
|
Service revenues
|
$
|
1,252
|
|
$
|
1,232
|
|
$
|
3,688
|
|
$
|
3,655
|
|
|||
|
Product sales
|
655
|
|
560
|
|
1,613
|
|
1,678
|
|
|||||||
|
Segment revenues
|
1,907
|
|
1,792
|
|
5,301
|
|
5,333
|
|
|||||||
|
Product costs
|
(463
|
)
|
(426
|
)
|
(1,183
|
)
|
(1,383
|
)
|
|||||||
|
Other segment costs and expenses
|
(567
|
)
|
(528
|
)
|
(1,660
|
)
|
(1,660
|
)
|
|||||||
|
Net insurance recoveries – Geismar Incident
|
—
|
|
—
|
|
—
|
|
126
|
|
|||||||
|
Impairment of long-lived assets
|
(1
|
)
|
(2
|
)
|
(403
|
)
|
(29
|
)
|
|||||||
|
Proportional Modified EBITDA of equity-method investments
|
194
|
|
185
|
|
574
|
|
504
|
|
|||||||
|
Williams Partners Modified EBITDA
|
$
|
1,070
|
|
$
|
1,021
|
|
$
|
2,629
|
|
$
|
2,891
|
|
|||
|
NGL margin
|
$
|
45
|
|
$
|
37
|
|
$
|
119
|
|
$
|
118
|
|
|||
|
Olefin margin
|
122
|
|
85
|
|
267
|
|
155
|
|
|||||||
Three months ended
September 30, 2016
vs. three months ended
September 30, 2015
Modified EBITDA
increased primarily due to higher olefins margins associated with improved ethylene prices at our Geismar plant and higher service revenues, as well as favorable changes in operating and maintenance and general and administrative expenses. These increases were partially offset by a $32 million loss recognized on the sale of the Canadian operations.
Service revenues
increased primarily due to higher volumes primarily in the eastern Gulf Coast region, including a temporary increase related to disrupted operations of a competitor, the impact of new volumes at Gulfstar One related to the Gunflint expansion being placed in service in the third quarter of 2016, and higher volumes at Devils Tower related to Kodiak field production which began earlier this year. Additionally, Transco’s natural gas transportation fee revenues increased primarily associated with expansion projects placed in service in 2015 and 2016, and transportation and fractionation revenue associated with Williams NGL & Petchem’s Horizon liquids extraction plant in Canada was higher as the plant was placed into service in March 2016. The Canadian operations were sold in late September 2016. These increases were partially offset by lower gathering rates in the Eagle Ford Shale.
Product sales
increased primarily due to:
|
•
|
A $59 million increase in marketing revenues primarily due to higher NGL, natural gas, and propylene prices and crude oil volumes, partially offset by lower NGL and natural gas volumes and crude oil prices (partially offset in marketing purchases);
|
|
•
|
A $28 million increase in olefin sales primarily due to a $27 million increase from our Geismar plant reflecting $24 million in primarily higher ethylene prices;
|
|
•
|
A $20 million increase in revenues from our equity NGLs primarily due to 27 percent higher NGL volumes driven by a temporary increase in volumes due to disrupted operations of a competitor;
|
|
•
|
A $13 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.
|
53
Management’s Discussion and Analysis (Continued)
Product costs
increased primarily due to:
|
•
|
A $39 million increase in marketing purchases primarily due to the same factors that increased marketing sales (partially offset in marketing revenues);
|
|
•
|
A $12 million increase in natural gas purchases associated with the production of equity NGLs reflecting higher volumes;
|
|
•
|
A $9 million decrease in olefin feedstock purchases primarily due to lower propylene production volumes;
|
|
•
|
A $13 million decrease in system management gas costs (offset in
Product sales
).
|
The increase in
Other segment costs and expenses
includes a $32 million loss on the sale of our Canadian operations. In addition, operating expenses at Transco increased primarily related to higher contract services for pipeline testing and general maintenance; project development costs at Constitution are higher as we discontinued capitalization of these costs in April 2016, and AFUDC also changed unfavorably associated with a decrease in spending on Constitution. These increases are partially offset by lower costs and expenses primarily reflecting decreases in outside services costs and labor-related costs resulting from ongoing cost containment efforts and our first-quarter 2016 workforce reductions.
The increase in
Proportional Modified EBITDA of equity-method investments
is primarily due to improved results at UEOM reflecting higher processing volumes. Appalachia Midstream Investments reflect lower operating results, offset by lower impairments in 2016.
Nine
months ended
September 30, 2016
vs.
nine
months ended
September 30, 2015
Modified EBITDA
decreased primarily due to higher impairments and loss on sale associated with our Canadian operations and the absence of insurance recoveries associated with the Geismar Incident. These increases were partially offset by higher olefin margins related to the Geismar plant operating at higher production levels in 2016, higher earnings related to our equity-method investments, including the completion of the Keathley Canyon Connector at Discovery in the first quarter of 2015, and lower segment costs and expenses. Additionally, higher service revenues related to projects placed in service improved
Modified EBITDA.
The increase in
Service revenues
is primarily due to an increase in Transco’s natural gas transportation fee revenues primarily associated with expansion projects placed in service in 2015 and 2016 and new transportation and fractionation revenue associated with Williams NGL & Petchem’s Horizon liquids extraction plant in Canada, as well as higher rates and volumes in the Haynesville area primarily attributable to a new contract executed in 2015 and new Gulfstar One volumes from the Gunflint development production.
The Canadian operations were sold in late September 2016. These increases were partially offset by a decrease in the eastern Gulf Coast region fee revenues primarily related to lower volumes associated with the impact of 2016 producers’ operational issues and suspending Gulfstar One operations in order to facilitate the tie-in of the Gunflint expansion, as well as a decrease in Transco’s storage revenue related to potential refunds associated with a ruling received in certain rate case litigation in 2016 and lower gathering rates in the Eagle Ford Shale.
Product sales
decreased primarily due to:
|
•
|
A $93 million decrease in marketing revenues primarily due to lower NGL volumes and lower crude oil, non-ethane, and natural gas prices, partially offset by higher crude oil and natural gas volumes and propylene prices (more than offset in marketing purchases);
|
|
•
|
A $34 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;
|
|
•
|
An $8 million decrease in revenues from our equity NGLs due to a $33 million decrease associated with lower NGL prices, partially offset by a $25 million increase associated with higher volumes driven by a temporary increase in volumes due to disrupted operations of a competitor;
|
54
Management’s Discussion and Analysis (Continued)
|
•
|
An $82 million increase in olefin sales comprised of a $152 million increase from our Geismar plant that returned to service in late March 2015, partially offset by a $70 million decrease from other olefin operations. The increase at Geismar includes $189 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, partially offset by $37 million in lower per-unit sales prices. The decrease in other olefin sales are associated with both lower volumes and lower per-unit sales prices.
|
The decrease in
Product costs
includes:
|
•
|
A $124 million decrease in marketing purchases primarily due to the same factors that increased marketing sales (partially offset in marketing revenues);
|
|
•
|
A $34 million decrease in system management gas costs (offset in
Product sales
);
|
|
•
|
A $30 million decrease in olefin feedstock purchases is primarily comprised of $81 million in lower purchases at our other olefin operations, partially offset by $55 million of higher purchases due primarily to increased volumes at our Geismar plant resulting from higher productions levels. The lower costs at our other olefin operations are comprised of $57 million in lower per-unit feedstock costs and $24 million in primarily lower propylene volumes;
|
|
•
|
A $9 million decrease in natural gas purchases associated with the production of equity NGLs reflecting a decrease of $32 million due to lower natural gas prices, partially offset by a $23 million increase associated with higher volumes.
|
The decrease in
Other segment costs and expenses
is primarily due to lower costs and expenses reflecting decreases in primarily labor-related and outside services costs resulting from our first-quarter 2016 workforce reductions and ongoing cost containment efforts, as well as lower ACMP Merger and transition-related expenses of $43 million. These decreases are partially offset by the $32 million loss on sale of our Canadian operations, $25 million of severance and related costs associated with workforce reductions incurred in the first quarter of 2016, $19 million higher project development costs at Constitution, and $18 million higher contract services for pipeline testing and general maintenance at Transco. Additionally, the decrease in
Other segment costs and expenses
includes a $19 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 Canadian operations, the absence of a $14 million gain recognized in second-quarter 2015 resulting from the early retirement of certain debt, and an unfavorable change in AFUDC associated with a decrease in spending on Constitution.
Net insurance recoveries – Geismar Incident
decreased reflecting the absence of $126 million of insurance proceeds received in the second quarter of 2015.
Impairment of long-lived assets
increased primarily due to 2016 impairments of $341 million associated with our Canadian operations and $48 million associated with certain gathering assets, partially offset by the absence of $20 million of impairment charges associated with certain surplus equipment within our Ohio Valley Midstream business recognized in 2015. (See
Note 11 – Fair Value Measurements and Guarantees
of Notes to Consolidated Financial Statements.)
The increase in
Proportional Modified EBITDA of equity-method investments
is primarily due to a $25 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, UEOM contributed a $20 million increase associated with higher processing volumes and an increase in our ownership percentage, Caiman II contributed a $14 million increase resulting from higher volumes due to assets placed into service in 2015, and OPPL contributed a $14 million increase primarily due to higher transportation volumes and lower expenses. These increases were partially offset by a $12 million decrease from Appalachia Midstream Investments primarily due to lower fee revenues driven by lower rates, partially offset by lower impairments.
55
Management’s Discussion and Analysis (Continued)
Williams NGL & Petchem Services
|
Three Months Ended
September 30, |
Nine Months Ended
September 30, |
||||||||||||||
|
2016
|
2015
|
2016
|
2015
|
||||||||||||
|
(Millions)
|
|||||||||||||||
|
Service revenues
|
$
|
—
|
|
$
|
1
|
|
$
|
2
|
|
$
|
2
|
|
|||
|
Product sales
|
8
|
|
—
|
|
25
|
|
—
|
|
|||||||
|
Segment revenues
|
8
|
|
1
|
|
27
|
|
2
|
|
|||||||
|
Product costs
|
(4
|
)
|
—
|
|
(13
|
)
|
—
|
|
|||||||
|
Other segment costs and expenses
|
(66
|
)
|
(6
|
)
|
(135
|
)
|
(15
|
)
|
|||||||
|
Impairment of long-lived assets
|
—
|
|
—
|
|
(408
|
)
|
—
|
|
|||||||
|
Williams NGL & Petchem Services Modified EBITDA
|
$
|
(62
|
)
|
$
|
(5
|
)
|
$
|
(529
|
)
|
$
|
(13
|
)
|
|||
Three months ended
September 30, 2016
vs. three months ended
September 30, 2015
The increase in
Product sales
and
Product costs
is primarily due to the Horizon liquids extraction plant coming online in March 2016.
The increase in
Other segment costs and expenses
is primarily due to a
$33 million
loss on the sale of our Canadian operations in September 2016. (See
Note 2 – Divestiture
of Notes to Consolidated Financial Statements.) Additionally, the increase includes $12 million of transportation and fractionation fees associated with our new Horizon volumes and $16 million of certain project development costs associated with the Canadian PDH facility that we began expensing in 2016
.
(See
Note 5 – Other Income and Expenses
of Notes to Consolidated Financial Statements.)
Nine
months ended
September 30, 2016
vs.
nine
months ended
September 30, 2015
The increase in
Product sales
and
Product costs
is primarily due to the Horizon liquids extraction plant coming online in March 2016.
The unfavorable change in
Other segment costs and expenses
is primarily due to $61 million of certain project development costs associated with the Canadian PDH facility that we began expensing in 2016. (See
Note 5 – Other Income and Expenses
of Notes to Consolidated Financial Statements.) Additionally, the increase includes $33 million of transportation and fractionation fees associated with our new Horizon volumes and a
$33 million
loss on the sale of our Canadian operations in September 2016. (See
Note 2 – Divestiture
of Notes to Consolidated Financial Statements.) These increases in costs were partially offset by a $10 million gain on the sale of unused pipe.
Impairment of long-lived assets
primarily reflects the 2016 impairment of our Canadian operations. (See
Note 11 – Fair Value Measurements and Guarantees
of Notes to Consolidated Financial Statements.)
Other
|
Three Months Ended September 30,
|
Nine Months Ended September 30,
|
||||||||||||||
|
2016
|
2015
|
2016
|
2015
|
||||||||||||
|
(Millions)
|
|||||||||||||||
|
Other Modified EBITDA
|
$
|
(5
|
)
|
$
|
(17
|
)
|
$
|
(5
|
)
|
$
|
(21
|
)
|
|||
Three months ended
September 30, 2016
vs. three months ended
September 30, 2015
Modified EBITDA
improved primarily due to a $6 million decrease in ACMP merger and transition related costs.
56
Management’s Discussion and Analysis (Continued)
Nine
months ended
September 30, 2016
vs.
nine
months ended
September 30, 2015
Modified EBITDA
improved primarily due to a $21 million decrease in ACMP merger and transition related costs, as well as the impact of various other individually insignificant items, partially offset by a $15 million increase in costs related to our evaluation of strategic alternatives.
57
Management’s Discussion and Analysis (Continued)
Management’s Discussion and Analysis of Financial Condition and Liquidity
Outlook
We continue to transition to an overall business mix that is increasingly fee-based. Although our cash flows are impacted by fluctuations in energy commodity prices, that impact is somewhat mitigated by certain of our cash flow streams that are not directly impacted by short-term commodity price movements, including:
|
•
|
Firm demand and capacity reservation transportation revenues under long-term contracts;
|
|
•
|
Fee-based revenues from certain gathering and processing services.
|
However, we are indirectly exposed to longer duration depressed energy commodity prices and the related impact on drilling activities and volumes available for gathering and processing services.
We believe we have, or have access to, the financial resources and liquidity necessary to meet our requirements for working capital, capital and investment expenditures, dividends and distributions, debt service payments, and tax payments, while maintaining a sufficient level of liquidity. In particular, as previously discussed in Company Outlook, our expected growth capital and investment expenditures total approximately $1.9 billion in 2016. We retain the flexibility to adjust planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities. We expect additional proceeds from amounts held in escrow from the sale of our Canadian operations by early 2017. (See
Note 2 – Divestiture
of Notes to Consolidated Financial Statements.)
As previously discussed, we reduced our quarterly dividend to $0.20 in the third quarter of 2016.
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 2016. Our internal and external sources of consolidated liquidity include:
|
•
|
Cash and cash equivalents on hand;
|
|
•
|
Cash generated from operations, including cash distributions from WPZ and our equity-method investees based on our level of ownership and incentive distribution rights;
|
|
•
|
Cash proceeds from issuances of debt and/or equity securities;
|
|
•
|
Use of our credit facility;
|
|
•
|
Proceeds from sale of our Canadian operations. (See
Note 2 – Divestiture
of Notes to Consolidated Financial Statements.)
|
WPZ is expected to fund its cash needs through its cash flows from operations, its credit facilities and/or commercial paper program, and its access to capital markets (including issuances under its equity distribution agreement), as well as Transco’s January 2016 debt issuance described further below, and proceeds from sale of WPZ’s Canadian operations. (See
Note 2 – Divestiture
of Notes to Consolidated Financial Statements.) WPZ also established a distribution reinvestment program (DRIP) in the third quarter of 2016.
We intend to reinvest approximately $1.7 billion into WPZ through 2017, funded primarily by our reduced quarterly cash dividend which will allow us to annually retain approximately $1.3 billion for reinvestment. We reinvested $250 million into WPZ in the third quarter of 2016 via a private purchase of common units, and we plan to reinvest $250 million in the fourth quarter of 2016 via the DRIP. The remaining $1.2 billion is planned to be reinvested in 2017 via the DRIP.
58
Management’s Discussion and Analysis (Continued)
We anticipate the more significant uses of cash to be:
|
•
|
Working capital requirements;
|
|
•
|
Maintenance and expansion capital and investment expenditures;
|
|
•
|
Interest on our long-term debt;
|
|
•
|
Repayment of current debt maturities;
|
|
•
|
Investment in WPZ through its DRIP;
|
|
•
|
Quarterly dividends to our shareholders.
|
Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook
.
As of
September 30, 2016
, we had a working capital deficit (current liabilities, inclusive of
$785 million
in
Long-term debt due within one year
, in excess of current assets) of $838 million. Our available liquidity is as follows:
|
September 30, 2016
|
|||||||||||
|
Available Liquidity
|
WPZ
|
WMB
|
Total
|
||||||||
|
(Millions)
|
|||||||||||
|
Cash and cash equivalents
|
$
|
68
|
|
$
|
9
|
|
$
|
77
|
|
||
|
Capacity available under our $1.5 billion credit facility (1)
|
650
|
|
650
|
|
|||||||
|
Capacity available to WPZ under its $3.5 billion credit facility, less amounts outstanding under its $3 billion commercial paper program (2)
|
2,268
|
|
2,268
|
|
|||||||
|
$
|
2,336
|
|
$
|
659
|
|
$
|
2,995
|
|
|||
|
(1)
|
Through
September 30, 2016
, the highest amount outstanding under our credit facility during 2016 was $1.224 billion. At
September 30, 2016
, we were in compliance with the financial covenants associated with this credit facility. Borrowing capacity available under this facility as of October 28, 2016, was $650 million.
|
|
(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. Through
September 30, 2016
, the highest amount outstanding under WPZ’s commercial paper program and credit facility during 2016 was $2.326 billion. At
September 30, 2016
, WPZ was in compliance with the financial covenants associated with this credit facility. See
Note 9 – Debt and Banking Arrangements
of Notes to Consolidated Financial Statements for additional information on WPZ’s commercial paper program. Borrowing capacity available under WPZ’s $3.5 billion credit facility as of October 28, 2016, was $2.427 billion.
|
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.
WPZ Incentive Distribution Rights
Our ownership interest in WPZ includes the right to incentive distributions determined in accordance with WPZ’s partnership agreement. In connection with the sale of our Canadian operations in the third quarter of 2016, we agreed to waive $150 million of incentive distributions otherwise payable by WPZ to us in the fourth quarter of 2016. (See
Note 2 – Divestiture
of Notes to Consolidated Financial Statements.)
59
Management’s Discussion and Analysis (Continued)
We have also agreed to temporarily waive incentive distributions of approximately $2 million per quarter in connection with WPZ’s acquisition of an approximate 13 percent additional interest in UEOM on June 10, 2015. The waiver will continue through the quarter ending September 30, 2017.
We were required to pay a $428 million termination fee to WPZ, associated with the Termination Agreement (as described in
Note 1 – General, Description of Business, and Basis of Presentation
of Notes to Consolidated Financial Statements), which settled through a reduction of quarterly incentive distributions we are entitled to receive from WPZ (such reduction not to exceed $209 million per quarter). The November 2015, February 2016, and May 2016 distributions from WPZ were reduced by $209 million, $209 million, and $10 million, respectively, related to this termination fee.
Debt Issuances and Retirements
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. Transco used the net proceeds from the offering to repay debt and to fund capital expenditures.
Registrations
In September 2016, WPZ filed a registration statement for its new DRIP discussed above.
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, and WPZ also 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. From February 2015 through
September 30, 2016
, WPZ has received net proceeds of approximately $59 million from equity issued under this registration.
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.
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
|
Negative
|
BB
|
BB
|
|||
|
Moody’s Investors Service
|
Negative
|
Ba2
|
N/A
|
||||
|
Fitch Ratings
|
Stable
|
BB+
|
N/A
|
||||
|
WPZ:
|
S&P Global Ratings
|
Negative
|
BBB-
|
BBB-
|
|||
|
Moody’s Investors Service
|
Negative
|
Baa3
|
N/A
|
||||
|
Fitch Ratings
|
Stable
|
BBB-
|
N/A
|
||||
60
Management’s Discussion and Analysis (Continued)
Considering our credit ratings as of
September 30, 2016
, we estimate that we could be required to provide up to $18 million in additional collateral of either cash or letters of credit with third parties under existing contracts. At the present time, we have not provided any additional collateral to third parties but no assurance can be given that we will not be requested to provide collateral in the future. As of
September 30, 2016
, we estimate that a downgrade to a rating below investment grade for WPZ could require it to provide up to $447 million in additional collateral with third parties.
Sources (Uses) of Cash
The following table summarizes the increase (decrease) in cash and cash equivalents for each of the periods presented:
|
Nine Months Ended
September 30, |
|||||||
|
2016
|
2015
|
||||||
|
(Millions)
|
|||||||
|
Net cash provided (used) by:
|
|||||||
|
Operating activities
|
$
|
2,082
|
|
$
|
2,086
|
|
|
|
Financing activities
|
(1,705
|
)
|
506
|
|
|||
|
Investing activities
|
(400
|
)
|
(2,707
|
)
|
|||
|
Increase (decrease) in cash and cash equivalents
|
$
|
(23
|
)
|
$
|
(115
|
)
|
|
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
,
Impairment of equity-method investments
,
and
Impairment of and net (gain) loss on sale of assets and businesses
.
Our
Net cash provided (used) by operating activities
for the nine months ended September 30, 2016 is consistent with the same period in 2015.
Financing activities
Significant transactions include:
|
•
|
$499 million
in
2016
of net payments of WPZ’s commercial paper;
|
|
•
|
$727 million
in
2015
of net proceeds from WPZ’s commercial paper;
|
|
•
|
$998 million in
2016
and $2.992 billion in
2015
net received from WPZ’s debt offerings;
|
|
•
|
$375 million in
2016
and $1.533 billion in
2015
paid on WPZ’s debt retirements;
|
|
•
|
$2.045 billion in
2016
and $1.435 billion in
2015
received from our credit facility borrowings;
|
|
•
|
$1.845 billion in
2016
and $1.43 billion in
2015
paid on our credit facility borrowings;
|
|
•
|
$2.665 billion in
2016
and $2.457 billion in
2015
received from WPZ’s credit facility borrowings;
|
|
•
|
$2.745 billion in
2016
and $2.597 billion in
2015
paid on WPZ’s credit facility borrowings;
|
|
•
|
$1.111 billion in
2016
and $1.356 billion in
2015
paid for quarterly dividends on common stock;
|
|
•
|
$715 million
in
2016
and
$704 million
in
2015
paid for dividends and distributions to noncontrolling interests;
|
|
•
|
$148 million in
2016
paid in contribution to Gulfstream for repayment of debt;
|
61
Management’s Discussion and Analysis (Continued)
|
•
|
$396 million in
2015
received in special distribution from Gulfstream.
|
Investing activities
Significant transactions include:
|
•
|
Capital expenditures of $1.577 billion in
2016
and $2.425 billion in
2015
;
|
|
•
|
$712 million
in
2016
received in net proceeds from sale of Canadian operations;
|
|
•
|
$112 million in 2015 paid to purchase a gathering system comprised of approximately 140 miles of pipeline and a sour gas compression facility in the Eagle Ford shale;
|
|
•
|
Purchases of and contributions to our equity-method investments of
$132 million
in
2016
and
$529 million
in
2015
;
|
|
•
|
Distributions from unconsolidated affiliates in excess of cumulative earnings of
$341 million
in
2016
and
$251 million
in
2015
.
|
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 9 – Debt and Banking Arrangements
,
Note 11 – Fair Value Measurements and Guarantees
, and
Note 12 – Contingent Liabilities
of Notes to Consolidated Financial Statements. We do not believe these guarantees or the possible fulfillment of them will prevent us from meeting our liquidity needs.
62
Item 3
Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
Our current interest rate risk exposure is related primarily to our debt portfolio and has not materially changed during the first
nine
months of
2016
.
Foreign Currency Risk
In September 2016, we disposed of our Canadian operations, which comprised substantially all of our foreign operations. We continue to be exposed to fluctuations in foreign currency exchange rates due to local currency denominated proceeds in escrow and contingent consideration associated with that disposition. (See
Note 2 – Divestiture
of Notes to Consolidated Financial Statements.)
63
Item 4
Controls and Procedures
Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Securities Exchange Act) (Disclosure Controls) or our internal control over financial reporting (Internal Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and Internal Controls will be modified as systems change and conditions warrant.
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.
Changes in Internal Control Over Financial Reporting
There have been no changes during the
third
quarter of
2016
that have materially affected, or are reasonably likely to materially affect, our Internal Control over Financial Reporting.
Environmental
Certain reportable legal proceedings involving governmental authorities under federal, state, and local laws regulating the discharge of materials into the environment are described below. While it is not possible for us to predict the final outcome of the proceedings which are still pending, we do not anticipate a material effect on our consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings.
In November 2013, we became aware of deficiencies with the air permit for the Fort Beeler gas processing facility located in West Virginia. We notified the EPA and the West Virginia Department of Environmental Protection and worked to bring the Fort Beeler facility into full compliance. On April 26, 2016, the EPA executed a consent order resolving various air permitting and emissions issues requiring payment of $140,000 in civil penalties which was paid on May 13, 2016. We do not anticipate penalties being imposed by the West Virginia Department of Environmental Protection.
On January 21, 2016, we received a Compliance Order from the Pennsylvania Department of Environmental Protection requiring the correction of several alleged deficiencies arising out of the construction of the Springville Gathering Line, the Pennsylvania Mainline Gathering Line, and the 2008 Core Zone Gathering Line. The Order also identifies civil penalties in the amount of approximately $712,000. We are working with the Pennsylvania Department
64
of Environmental Protection to address certain issues and are in the process of negotiating the Order and the associated penalty.
Other
The additional information called for by this item is provided in
Note 12 – Contingent Liabilities
of the Notes to Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this item.
Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2015, as well as Part II, Item 1A. Risk Factors in our Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2016 and June 30, 2016, include certain risk factors that could materially affect our business, financial condition, or future results. Except as listed below, the risk factors stated in our periodic reports remain applicable, however, the risk factors listed below are no longer applicable:
|
•
|
The pendency of the proposed ETC Merger could adversely affect our business and operations.
|
|
•
|
There can be no assurance when or even if the proposed ETC Merger will be completed.
|
|
•
|
The Merger Agreement contains provisions that could discourage a potential competing acquirer of us or could result in any competing proposal being at a lower price than it might otherwise be.
|
|
•
|
The integration of our business following the proposed ETC Merger will involve considerable risks and may not be successful.
|
|
•
|
Stockholder litigation could prevent or delay the closing of the proposed ETC Merger or otherwise negatively impact our business and operations.
|
|
•
|
We have filed lawsuits against ETE, LE GP, LLC and Kelcy L. Warren in relation to ETE’s private offering and issuance of Series A Convertible Preferred Units (Convertible Units). If we are unsuccessful in our lawsuits, our current stockholders may not realize all of the anticipated benefits contemplated by the Merger Agreement and may be disadvantaged relative to the holders of the Convertible Units.
|
|
•
|
Possible actions by stockholders to gain control of our board of directors may have negative effects on the Company.
|
65
|
Exhibit
No.
|
Description
|
|||
|
§Exhibit 2.1
|
—
|
Agreement and Plan of Merger dated as of May 12, 2015, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P., and WPZ GP LLC (filed on May 13, 2015 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
|
||
|
Exhibit 2.2
|
—
|
Amendment No 1. to Agreement and Plan of Merger dated as of May 1, 2016, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC and Energy Transfer Equity GP, LLC (filed on May 3, 2016 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
|
||
|
§Exhibit 2.3
|
—
|
Agreement and Plan of Merger dated as of September 28, 2015, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC and Energy Transfer Equity GP, LLC (filed on October 1, 2015 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
|
||
|
§Exhibit 2.4
|
—
|
Share Purchase Agreement by and between The Williams Companies International Holdings B.V. and Inter Pipeline Ltd. and The Williams Companies, Inc., dated August 8, 2016 (filed on August 12, 2016 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (file No. 001-04174) and incorporated herein by reference).
|
||
|
§Exhibit 2.5
|
—
|
Share Purchase Agreement by and between Williams Energy Canada LP and Inter Pipeline Ltd. and Williams Partners L.P., dated August 8, 2016 (filed on August 12, 2016 as Exhibit 2.2 to The Williams Companies, Inc.’s current report on Form 8-K (file No. 001-04174) and incorporated herein by reference).
|
||
|
Exhibit 3.1
|
—
|
Amended and Restated Certificate of Incorporation as supplemented (filed on May 26, 2010, as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
|
||
|
Exhibit 3.2
|
—
|
By-Laws (filed on August 24, 2015, as Exhibit 3 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
|
||
|
Exhibit 10.1
|
—
|
Termination Agreement and Release, dated as of September 28, 2015, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P. and WPZ GP LLC (filed on September 28, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
|
||
|
Exhibit 10.2
|
—
|
First Amendment to The Williams Companies Inc. Executive Severance Pay Plan (filed July 19, 2016, as Exhibit 10.1 to the Williams Companies Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
|
||
|
Exhibit 10.3
|
—
|
The Williams Companies, Inc. Executive Severance Pay Plan, dated November 14, 2012 (filed July 19, 2016, as Exhibit 10.2 to the Williams Companies Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
|
||
|
*Exhibit 12
|
—
|
Computation of Ratio of Earnings to Fixed Charges.
|
||
|
*Exhibit 31.1
|
—
|
Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
||
66
|
Exhibit
No.
|
Description
|
|||
|
*Exhibit 31.2
|
—
|
Certification of Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
||
|
**Exhibit 32
|
—
|
Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
||
|
*Exhibit 101.INS
|
—
|
XBRL Instance Document.
|
||
|
*Exhibit 101.SCH
|
—
|
XBRL Taxonomy Extension Schema.
|
||
|
*Exhibit 101.CAL
|
—
|
XBRL Taxonomy Extension Calculation Linkbase.
|
||
|
*Exhibit 101.DEF
|
—
|
XBRL Taxonomy Extension Definition Linkbase.
|
||
|
*Exhibit 101.LAB
|
—
|
XBRL Taxonomy Extension Label Linkbase.
|
||
|
*Exhibit 101.PRE
|
—
|
XBRL Taxonomy Extension Presentation Linkbase.
|
||
* Filed herewith.
** Furnished herewith.
|
§
|
Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.
|
67
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
T
HE
W
ILLIAMS
C
OMPANIES
, I
NC
.
|
|
|
(Registrant)
|
|
|
/s/ T
ED
T. T
IMMERMANS
|
|
|
Ted T. Timmermans
|
|
|
Vice President, Controller and Chief Accounting Officer (Duly Authorized Officer and Principal Accounting Officer)
|
|
October 31, 2016
EXHIBIT INDEX
|
Exhibit
No.
|
Description
|
|||
|
§Exhibit 2.1
|
—
|
Agreement and Plan of Merger dated as of May 12, 2015, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P., and WPZ GP LLC (filed on May 13, 2015 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
|
||
|
Exhibit 2.2
|
—
|
Amendment No 1. to Agreement and Plan of Merger dated as of May 1, 2016, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC and Energy Transfer Equity GP, LLC (filed on May 3, 2016 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
|
||
|
§Exhibit 2.3
|
—
|
Agreement and Plan of Merger dated as of September 28, 2015, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC and Energy Transfer Equity GP, LLC (filed on October 1, 2015 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
|
||
|
§Exhibit 2.4
|
—
|
Share Purchase Agreement by and between The Williams Companies International Holdings B.V. and Inter Pipeline Ltd. and The Williams Companies, Inc., dated August 8, 2016 (filed on August 12, 2016 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (file No. 001-04174) and incorporated herein by reference).
|
||
|
§Exhibit 2.5
|
—
|
Share Purchase Agreement by and between Williams Energy Canada LP and Inter Pipeline Ltd. and Williams Partners L.P., dated August 8, 2016 (filed on August 12, 2016 as Exhibit 2.2 to The Williams Companies, Inc.’s current report on Form 8-K (file No. 001-04174) and incorporated herein by reference).
|
||
|
Exhibit 3.1
|
—
|
Amended and Restated Certificate of Incorporation as supplemented (filed on May 26, 2010, as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
|
||
|
Exhibit 3.2
|
—
|
By-Laws (filed on August 24, 2015, as Exhibit 3 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
|
||
|
Exhibit 10.1
|
—
|
Termination Agreement and Release, dated as of September 28, 2015, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P. and WPZ GP LLC (filed on September 28, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8‑K (File No. 001-34831) and incorporated herein by reference).
|
||
|
Exhibit 10.2
|
—
|
First Amendment to The Williams Companies Inc. Executive Severance Pay Plan (filed July 19, 2016, as Exhibit 10.1 to the Williams Companies Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
|
||
|
Exhibit 10.3
|
—
|
The Williams Companies, Inc. Executive Severance Pay Plan, dated November 14, 2012 (filed July 19, 2016, as Exhibit 10.2 to the Williams Companies Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
|
||
|
*Exhibit 12
|
—
|
Computation of Ratio of Earnings to Fixed Charges.
|
||
|
*Exhibit 31.1
|
—
|
Certification of Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
||
|
Exhibit
No.
|
Description
|
|||
|
*Exhibit 31.2
|
—
|
Certification of Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
||
|
**Exhibit 32
|
—
|
Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
||
|
*Exhibit 101.INS
|
—
|
XBRL Instance Document.
|
||
|
*Exhibit 101.SCH
|
—
|
XBRL Taxonomy Extension Schema.
|
||
|
*Exhibit 101.CAL
|
—
|
XBRL Taxonomy Extension Calculation Linkbase.
|
||
|
*Exhibit 101.DEF
|
—
|
XBRL Taxonomy Extension Definition Linkbase.
|
||
|
*Exhibit 101.LAB
|
—
|
XBRL Taxonomy Extension Label Linkbase.
|
||
|
*Exhibit 101.PRE
|
—
|
XBRL Taxonomy Extension Presentation Linkbase.
|
||
* Filed herewith.
** Furnished herewith.
|
§
|
Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.
|
TABLE OF CONTENTS
Part I Financial InformationNote 1 General, Description Of Business, and Basis Of PresentationNote 12 Contingent LiabilitiesNote 2 DivestitureNote 3 Variable Interest EntitiesNote 9 Debt and Banking ArrangementsNote 11 Fair Value Measurements and GuaranteesNote 4 Investing ActivitiesNote 5 Other Income and ExpensesNote 6 Provision (benefit) For Income TaxesNote 7 Earnings (loss) Per Common ShareNote 8 Employee Benefit PlansNote 10 Stockholders EquityNote 13 Segment DisclosuresPart II. Other InformationItem 1. Legal ProceedingsItem 1A. Risk FactorsItem 6. Exhibits