QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2021
or
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____________ to _____________
Commission file number 1-4174
THE WILLIAMS COMPANIES, INC.
(Exact name of registrant as specified in its charter)
Delaware
73-0569878
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
One Williams Center
Tulsa, Oklahoma
74172-0172
(Address of principal executive offices)
(Zip Code)
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)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
Common Stock, $1.00 par value
WMB
New York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes☑No☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
☑
Accelerated filer
☐
Non-accelerated filer
☐
Smaller reporting company
☐
Emerging growth company
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.) Yes☐No☑
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
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
1
forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcomes 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:
•Levels of dividends to Williams stockholders;
•Future credit ratings of Williams and its affiliates;
•Amounts and nature of future capital expenditures;
•Expansion and growth of our business and operations;
•Expected in-service dates for capital projects;
•Financial condition and liquidity;
•Business strategy;
•Cash flow from operations or results of operations;
•Seasonality of certain business components;
•Natural gas, natural gas liquids, and crude oil prices, supply, and demand;
•Demand for our services;
•The impact of the coronavirus (COVID-19) pandemic.
Forward-looking statements are based on numerous assumptions, uncertainties, and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:
•Availability of supplies, market demand, and volatility of prices;
•Development and rate of adoption of alternative energy sources;
•The impact of existing and future laws and regulations, the regulatory environment, environmental matters, and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate proceeding outcomes;
•Our exposure to the credit risk of our customers and counterparties;
•Our ability to acquire new businesses and assets and successfully integrate those operations and assets into existing businesses as well as successfully expand our facilities, and to consummate asset sales on acceptable terms;
•Whether we are able to successfully identify, evaluate, and timely execute our capital projects and investment opportunities;
2
•The strength and financial resources of our competitors and the effects of competition;
•The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;
•Whether we will be able to effectively execute our financing plan;
•Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social, and governance practices;
•The physical and financial risks associated with climate change;
•The impacts of operational and developmental hazards and unforeseen interruptions;
•The risks resulting from outbreaks or other public health crises, including COVID-19;
•Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities;
•Acts of terrorism, cybersecurity incidents, and related disruptions;
•Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;
•Changes in maintenance and construction costs, as well as our ability to obtain sufficient construction-related inputs, including skilled labor;
•Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on customers and suppliers);
•Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally recognized credit rating agencies, and the availability and cost of capital;
•The ability of the members of the Organization of Petroleum Exporting Countries (OPEC) and other oil exporting nations to agree to and maintain oil price and production controls and the impact on domestic production;
•Changes in the current geopolitical situation;
•Changes in U.S. governmental administration and policies;
•Whether we are able to pay current and expected levels of dividends;
•Additional risks described in our filings with the Securities and Exchange Commission (SEC).
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 for the year ended December 31, 2020, as supplemented by the disclosure in Part II, Item 1A. Risk Factors in this Quarterly Report on Form 10-Q.
The following is a listing of certain abbreviations, acronyms, and other industry terminology that may be used throughout this Form 10-Q.
Measurements:
Barrel: One barrel of petroleum products that equals 42 U.S. gallons
Mbbls/d: One thousand barrels per day
Bcf: One billion cubic feet of natural gas
Bcf/d: One billion cubic feet of natural gas per day
MMcf/d: One million cubic feet per day
British Thermal Unit (Btu): A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit
MMbtu: One million British thermal units
Tbtu: One trillion British thermal units
Dekatherms (Dth): A unit of energy equal to one million British thermal units
Mdth/d: One thousand dekatherms per day
MMdth: One million dekatherms or approximately one trillion British thermal units
MMdth/d: One million dekatherms per day
Consolidated Entities:
Caiman II: Caiman Energy II, LLC, (renamed Blue Racer Midstream Holdings, LLC, effective February 2, 2021) a former equity-method investment which is a wholly owned consolidated entity following our acquisition of a controlling interest of Caiman II in November 2020 and the remaining interest in September 2021
Cardinal: Cardinal Gas Services, L.L.C.
Gulfstar One: Gulfstar One LLC
Northeast JV: Ohio Valley Midstream LLC
Northwest Pipeline: Northwest Pipeline LLC
Transco: Transcontinental Gas Pipe Line Company, LLC
Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of September 30, 2021, we account for as equity-method investments, including principally the following:
Exchange Act, the: Securities and Exchange Act of 1934, as amended
FERC: Federal Energy Regulatory Commission
IRS: Internal Revenue Service
SEC: Securities and Exchange Commission
Other:
EBITDA: Earnings before interest, taxes, depreciation, and amortization
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
LNG: Liquefied natural gas; natural gas which has been liquefied at cryogenic temperatures
MVC: Minimum volume commitments
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, transportation, and fractionation
Consolidated Statement of Comprehensive Income (Loss)
(Unaudited)
Three Months Ended September 30,
Nine Months Ended September 30,
2021
2020
2021
2020
(Millions)
Net income (loss)
$
173
$
323
$
930
$
68
Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $5 and $14 in 2021 and $— and $— in 2020
(17)
—
(43)
—
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of ($5) and ($7) in 2021 and $— and $— in 2020
15
—
21
—
Pension and other postretirement benefits:
Net actuarial gain (loss) arising during the year, net of taxes of $— and $— in 2021 and ($4) and ($7) in 2020
—
11
—
20
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($1) and ($3) in 2021 and ($1) and ($6) in 2020
3
5
9
19
Other comprehensive income (loss)
1
16
(13)
39
Comprehensive income (loss)
174
339
917
107
Less: Comprehensive income (loss) attributable to noncontrolling interests
8
14
35
(27)
Comprehensive income (loss) attributable to The Williams Companies, Inc.
Intangible assets – net of accumulated amortization
7,481
7,444
Regulatory assets, deferred charges, and other
1,220
1,204
Total assets
$
45,985
$
44,165
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable
$
1,674
$
482
Accrued liabilities
1,242
944
Long-term debt due within one year
2,024
893
Total current liabilities
4,940
2,319
Long-term debt
20,338
21,451
Deferred income tax liabilities
2,233
1,923
Regulatory liabilities, deferred income, and other
4,555
3,889
Contingent liabilities and commitments (Note 13)
Equity:
Stockholders’ equity:
Preferred stock
35
35
Common stock ($1 par value; 1,470 million shares authorized at September 30, 2021 and December 31, 2020; 1,249 million shares issued at September 30, 2021 and 1,248 million shares issued at December 31, 2020)
1,249
1,248
Capital in excess of par value
24,425
24,371
Retained deficit
(13,361)
(12,748)
Accumulated other comprehensive income (loss)
(109)
(96)
Treasury stock, at cost (35 million shares of common stock)
(1,041)
(1,041)
Total stockholders’ equity
11,198
11,769
Noncontrolling interests in consolidated subsidiaries
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, 2020, 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.
Description of Business
We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located in the United States and are presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, West, and Sequent, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. All remaining business activities, including our recently acquired upstream operations, as well as corporate activities are included in Other.
Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline LLC (Northwest Pipeline), as well as natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One LLC (Gulfstar One) (a consolidated variable interest entity, or VIE), which is a proprietary floating production system, a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C., and a 60 percent equity-method investment in Discovery Producer Services LLC (Discovery).
Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in Ohio Valley Midstream LLC (Northeast JV) (a consolidated VIE) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated VIE) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 50 percent equity-method investment in Blue Racer Midstream LLC (Blue Racer) (we previously effectively owned a 29 percent indirect interest in Blue Racer through our 58 percent equity-method investment in Caiman Energy II, LLC (Caiman II) until acquiring a controlling interest of Caiman II in November 2020 and the remaining interest in September 2021), and Appalachia Midstream Services, LLC, a wholly owned subsidiary that owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region (Appalachia Midstream Investments).
West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the
Anadarko and Permian basins. This segment also includes our natural gas liquid (NGL) and natural gas marketing business (excluding the activities within the Sequent segment described below), storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in Overland Pass Pipeline Company LLC, a 50 percent equity-method investment in Rocky Mountain Midstream Holdings LLC (RMM), a 20 percent equity-method investment in Targa Train 7 LLC (Targa Train 7) (a nonconsolidated VIE), and a 15 percent interest in Brazos Permian II, LLC (Brazos Permian II) (a nonconsolidated VIE).
Sequent includes the operations of Sequent Energy Management, L.P. and Sequent Energy Canada, Corp. (collectively, Sequent) acquired on July 1, 2021. Sequent focuses on risk management and the marketing, trading, storage, and transportation of natural gas for a diverse set of natural gas utilities, municipalities, power generators, and producers, and moves gas to markets through transportation and storage agreements on strategically positioned assets, including along our Transco system. See Note 3 – Acquisitions.
Basis of Presentation
Significant risks and uncertainties
We believe that the carrying value of certain of our property, plant, and equipment and other identifiable intangible assets, notably certain acquired assets accounted for as business combinations between 2012 and 2014, may be in excess of current fair value. However, the carrying value of these assets, in our judgment, continues to be recoverable. It is reasonably possible that future strategic decisions, including transactions such as monetizing non-core assets or contributing assets to new ventures with third parties, as well as unfavorable changes in expected producer activities, could impact our assumptions and ultimately result in impairments of these assets. Such transactions or developments may also indicate that certain of our equity-method investments have experienced other-than-temporary declines in value, which could result in impairment.
Note 2 – Variable Interest Entities
Consolidated VIEs
As of September 30, 2021, we consolidate the following VIEs:
Northeast JV
We own a 65 percent interest in the Northeast JV, a subsidiary that is a VIE due to certain of our voting rights being disproportionate to our obligation to absorb losses and substantially all of the Northeast JV’s activities being performed on our behalf. We are the primary beneficiary because we have the power to direct the activities that most significantly impact the Northeast JV’s economic performance. The Northeast JV provides midstream services for producers in the Marcellus Shale and Utica Shale regions. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner on a proportional basis.
Gulfstar One
We own a 51 percent interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. Gulfstar One includes a proprietary floating production system, Gulfstar FPS, and associated pipelines that provide production handling and gathering services in the eastern deepwater Gulf of Mexico. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance.
Cardinal
We own a66 percent interest in Cardinal, a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Cardinal’s economic performance. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner on a proportional basis.
The following table presents amounts included in the Consolidated Balance Sheet that are only for the use or obligation of our consolidated VIEs:
September 30, 2021
December 31, 2020
(Millions)
Assets (liabilities):
Cash and cash equivalents
$
147
$
107
Trade accounts and other receivables – net
134
148
Other current assets and deferred charges
6
7
Property, plant, and equipment – net
5,364
5,514
Intangible assets – net of accumulated amortization
2,295
2,376
Regulatory assets, deferred charges, and other
15
15
Accounts payable
(85)
(42)
Accrued liabilities
(26)
(34)
Regulatory liabilities, deferred income, and other
(289)
(289)
Nonconsolidated VIEs
Targa Train 7
We own a 20 percent interest in Targa Train 7, which provides fractionation services at Mt. Belvieu and is a VIE due primarily to our limited participating rights as the minority equity holder. At September 30, 2021, the carrying value of our investment in Targa Train 7 was $48 million. Our maximum exposure to loss is limited to the carrying value of our investment.
Brazos Permian II
We own a 15 percent interest in Brazos Permian II, which provides gathering and processing services in the Delaware basin and is a VIE due primarily to our limited participating rights as the minority equity holder. During the first quarter of 2020, we recorded an impairment of our equity-method investment in Brazos Permian II. Our maximum exposure to loss is limited to the carrying value of our investment.
Note 3 – Acquisitions
Sequent
On July 1, 2021, we completed the acquisition of 100 percent of Sequent. Total consideration for this acquisition was $159 million, which included $109 million related to working capital. Of the total consideration, $134 million of cash was paid in the third quarter of 2021 and $25 million was accrued in the same period for post-closing working capital adjustments.
Sequent focuses on risk management and the marketing, trading, storage, and transportation of natural gas for a diverse set of natural gas utilities and producers, and moves gas to markets through transportation and storage agreements on strategically positioned assets, including along our Transco system. The purpose of the acquisition was to expand our natural gas marketing activities as well as optimize our pipeline and storage capabilities with expansions into new markets to reach incremental gas-fired power generation, liquified natural gas exports, and future renewable natural gas and other emerging opportunities.
The acquisition of Sequent was accounted for as a business combination, which requires, among other things, that identifiable assets acquired and liabilities assumed be recognized at their acquisition date fair values.
Pro forma revenues and earnings as if the Sequent acquisition had been completed on January 1, 2020, are not materially different from our historical results for the three and nine months ended September 30, 2021 and 2020.
During the period from the acquisition date of July 1, 2021 to September 30, 2021, Sequent contributed product sales of $54 million, net loss on commodity derivatives of $322 million, and unfavorable Modified EBITDA (as defined in Note 14 – Segment Disclosures) of $281 million. Both the net loss on commodity derivatives and Modified EBITDA amounts reflect a net unrealized loss on commodity derivatives of $277 million for the period.
Costs related to this acquisition are approximately $3 million and are included in Selling, general, and administrative expenses in our Consolidated Statement of Income.
The following table presents the allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in the Sequent segment, and liabilities assumed at July 1, 2021. The fair value of accounts receivable acquired equals contractual amounts receivable. Preliminary fair value measurements were made for certain acquired assets and liabilities, primarily intangible assets; however, adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date, as new information related to facts and circumstances as of the acquisition date may be identified. The fair value of the intangible assets were measured using an income approach. The inventory acquired relates to natural gas in underground storage. The fair value of this inventory was based on the market price of the underlying commodity at the acquisition date. See Note 11 – Fair Value Measurements and Guarantees for the valuation techniques used to measure fair value of derivative assets and liabilities.
(Millions)
Cash and cash equivalents
$
8
Trade accounts and other receivables – net
498
Inventories
121
Other current assets and deferred charges
4
Commodity derivatives included in other current assets and deferred charges
57
Property, plant, and equipment – net
5
Intangible assets
306
Regulatory assets, deferred charges, and other
3
Commodity derivatives included in regulatory assets, deferred charges, and other
49
Total assets acquired
$
1,051
Accounts payable
$
514
Accrued liabilities
46
Commodity derivatives included in accrued liabilities
116
Regulatory liabilities, deferred income, and other
1
Commodity derivatives included in regulatory liabilities, deferred income, and other
215
Total liabilities assumed
$
892
Net assets acquired
$
159
Accounts Receivable and Accounts Payable
Sequent provides services to retail and wholesale gas marketers, utility companies, upstream producers, and industrial customers. These counterparties utilize netting agreements that enable Sequent to net receivables and payables by counterparty upon settlement. Sequent also nets across product lines and against cash collateral, provided the netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, Sequent’s counterparties are settled net, they are recorded on a gross basis in the Consolidated Balance Sheet as accounts receivable and accounts payable.
Intangible assets are primarily related to transportation and storage capacity contracts. The basis for determining the value of these intangible assets was estimated future net cash flows to be derived from acquired transportation and storage capacity contracts that provide future economic benefits due to their market location, discounted using an industry weighted-average cost of capital. This intangible asset is being amortized based on the expected benefit period over which the underlying contracts are expected to contribute to our cash flows ranging from 1 year to 10 years. As a result, we expect a significant portion of the amortization to be recognized within the first few years of this range. We recognized $21 million of amortization expense during the third quarter of 2021.
Commodity Derivatives
Sequent purchases natural gas for storage when the current market price paid to buy and transport natural gas plus the cost to store and finance the natural gas is less than an estimated, forward market price that can be received in the future, resulting in positive net product sales. Commodity-based exchange-traded futures contracts and over-the-counter (OTC) contracts are used to sell natural gas at that future price to substantially protect the natural gas revenues that will ultimately be realized when the stored natural gas is sold. Additionally, Sequent enters into transactions to secure transportation capacity between delivery points in order to serve its customers and various markets. Commodity-based exchange-traded futures contracts and OTC contracts are used to capture the price differential or spread between the locations served by the capacity in order to substantially protect the natural gas revenues that will ultimately be realized when the physical flow of natural gas between delivery points occurs. Some commodity-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the natural gas marketing operations. These contracts generally meet the definition of derivatives and are carried at fair value in the Consolidated Balance Sheet, with changes in fair value recorded in Net gain (loss) on commodity derivatives in the Consolidated Statement of Income in the period of change. These contracts are not designated as hedges for accounting purposes.
The physical purchase, transportation, storage, and sale of natural gas are accounted for on a weighted-average cost or accrual basis, as appropriate, rather than on the fair value basis utilized for the derivatives used to mitigate the natural gas price risk associated with the storage and transportation portfolio. Monthly demand charges are incurred for the contracted storage and transportation capacity and payments associated with asset management agreements, and these demand charges and payments are recognized on the Consolidated Statement of Income in the period they are incurred. Sequent experiences significant earnings volatility from the fair value accounting required for the derivatives used to hedge a portion of the economic value of the underlying transportation and storage portfolio. However, the unrealized fair value measurement gains and losses are offset by valuation changes in the economic value of the underlying transportation and storage portfolio, which is not accounted for on a fair value basis. (see Note 12 – Derivatives).
Concentration of Credit Risk
Sequent has a concentration of credit risk as its top 20 counterparties represented 54 percent, or $267 million, of the total counterparty exposure as of September 30, 2021.
Sequent uses established credit policies to determine and monitor the creditworthiness of counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include U.S. government securities. Sequent also utilizes netting agreements whenever possible to mitigate exposure to counterparty credit risk. When more than one derivative transaction with the same counterparty is outstanding and a legally enforceable netting agreement exists with that counterparty, the “net” mark-to-market exposure represents a reasonable measure of Sequent’s credit risk with that counterparty.
Regulated interstate natural gas transportation and storage
$
1,880
$
328
$
—
$
—
$
—
$
—
$
—
$
(17)
$
2,191
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration
—
—
250
966
838
—
—
(76)
1,978
Commodity consideration
—
—
34
4
126
—
—
—
164
Other
8
—
15
145
39
—
—
(12)
195
Total service revenues
1,888
328
299
1,115
1,003
—
—
(105)
4,528
Product sales
50
—
178
75
2,983
960
216
(343)
4,119
Total revenues from contracts with customers
1,938
328
477
1,190
3,986
960
216
(448)
8,647
Other revenues (1)
3
1
8
19
(83)
903
(3)
(11)
837
Other adjustments (2)
—
—
—
—
—
(2,131)
—
17
(2,114)
Total revenues
$
1,941
$
329
$
485
$
1,209
$
3,903
$
(268)
$
213
$
(442)
$
7,370
Nine Months Ended September 30, 2020
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage
$
1,796
$
336
$
—
$
—
$
—
$
—
$
—
$
(6)
$
2,126
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration
—
—
262
952
884
—
—
(58)
2,040
Commodity consideration
—
—
14
5
74
—
—
—
93
Other
8
—
19
123
46
—
—
(11)
185
Total service revenues
1,804
336
295
1,080
1,004
—
—
(75)
4,444
Product sales
61
—
75
42
1,056
—
—
(96)
1,138
Total revenues from contracts with customers
1,865
336
370
1,122
2,060
—
—
(171)
5,582
Other revenues (1)
4
—
6
16
5
—
25
(11)
45
Total revenues
$
1,869
$
336
$
376
$
1,138
$
2,065
$
—
$
25
$
(182)
$
5,627
______________________________
(1)Revenues not derived from contracts with customers consist of leasing revenues associated with our headquarters building and management fees that we receive for certain services we provide to operated equity-method investments, which are reported in Service revenues in the Consolidated Statement of Income, and realized and unrealized gains and losses associated with our derivative contracts (except for those requiring physical delivery), which are reported in Net gain (loss) on commodity derivatives in the Consolidated Statement of Income.
(2)Other adjustments relate to costs of Sequent’s risk management activities. As Sequent is acting as an agent for its customers, its revenues are presented net of the related costs of those activities in the Consolidated Statement of Income.
The following table presents a reconciliation of our contract assets:
Three Months Ended September 30,
Nine Months Ended September 30,
2021
2020
2021
2020
(Millions)
Balance at beginning of period
$
38
$
30
$
12
$
8
Revenue recognized in excess of amounts invoiced
51
36
134
105
Minimum volume commitments invoiced
(39)
(24)
(96)
(71)
Balance at end of period
$
50
$
42
$
50
$
42
Contract Liabilities
The following table presents a reconciliation of our contract liabilities:
Three Months Ended September 30,
Nine Months Ended September 30,
2021
2020
2021
2020
(Millions)
Balance at beginning of period
$
1,193
$
1,203
$
1,209
$
1,215
Payments received and deferred
14
14
99
116
Significant financing component
3
3
8
8
Contract liability acquired
1
—
1
—
Recognized in revenue
(48)
(50)
(154)
(169)
Balance at end of period
$
1,163
$
1,170
$
1,163
$
1,170
Remaining Performance Obligations
Remaining performance obligations primarily include reservation charges on contracted capacity for our gas pipeline firm transportation contracts with customers, storage capacity contracts, long-term contracts containing minimum volume commitments associated with our midstream businesses, and fixed payments associated with offshore production handling. For our interstate natural gas pipeline businesses, remaining performance obligations reflect the rates for such services in our current Federal Energy Regulatory Commission (FERC) tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes are not currently known.
Our remaining performance obligations exclude variable consideration, including contracts with variable consideration for which we have elected the practical expedient for consideration recognized in revenue as billed. Certain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term of the contract. The remaining performance obligation amounts as of September 30, 2021, do not consider potential future performance obligations for which the renewal has not been exercised and exclude contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service. Consideration received prior to September 30, 2021, that will be recognized in future periods is also excluded from our remaining performance obligations and is instead reflected in contract liabilities.
The following table presents the amount of the contract liabilities balance expected to be recognized as revenue when performance obligations are satisfied and the transaction price allocated to the remaining performance obligations under certain contracts as of September 30, 2021.
Contract Liabilities
Remaining Performance Obligations
(Millions)
2021 (three months)
$
45
$
875
2022 (one year)
139
3,465
2023 (one year)
124
3,184
2024 (one year)
120
2,870
2025 (one year)
105
2,367
Thereafter
630
18,326
Total
$
1,163
$
31,087
Accounts Receivable
The following is a summary of our Trade accounts and other receivables – net:
September 30, 2021
December 31, 2020
(Millions)
Accounts receivable related to revenues from contracts with customers (1)
$
1,472
$
892
Other accounts receivable (2)
514
107
Trade accounts and other receivables – net
$
1,986
$
999
(1)Includes $298 million related to our Sequent segment as of September 30, 2021.
(2)Includes $441 million related to our Sequent segment as of September 30, 2021.
Note 5 – Investing Activities
Equity Earnings (Losses)
Equity earnings (losses) for the nine months ended September 30, 2020, includes a $78 million loss associated with the first-quarter 2020 full impairment of goodwill recognized by our investee RMM, which was allocated entirely to our member interest per the terms of the membership agreement.
Impairment of Equity-Method Investments
Impairment of equity-method investments for the nine months ended September 30, 2020, includes $938 million associated with the first-quarter 2020 impairment of certain equity-method investments (see Note 11 – Fair Value Measurements and Guarantees).
The Provision (benefit) for income taxes includes:
Three Months Ended September 30,
Nine Months Ended September 30,
2021
2020
2021
2020
(Millions)
Current:
Federal
$
1
$
—
$
(1)
$
(28)
State
1
—
1
—
2
—
—
(28)
Deferred:
Federal
40
97
240
56
State
11
14
73
(4)
51
111
313
52
Provision (benefit) for income taxes
$
53
$
111
$
313
$
24
The effective income tax rates for the total provision (benefit) for both the three and nine months ended September 30, 2021 and 2020 are greater than the federal statutory rate, primarily due to 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.
Note 7 – Earnings (Loss) Per Common Share
Three Months Ended September 30,
Nine Months Ended September 30,
2021
2020
2021
2020
(Dollars in millions, except per-share amounts; shares in thousands)
Net income (loss) available to common stockholders
The components of Net periodic benefit cost (credit) other than the Service cost component are included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Income.
During the nine months ended September 30, 2021, we contributed $4 million to our pension plans and $4 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $1 million to our other postretirement benefit plans and no further contributions to our pension plans in the remainder of 2021.
Note 9 – Debt and Banking Arrangements
Long-Term Debt
Issuances and retirements
On October 8, 2021, we completed a public offering of $600 million of 2.6 percent senior unsecured notes due 2031. The new 2031 notes are an additional issuance of the $900 million of 2.6 percent senior unsecured notes due 2031 issued on March 2, 2021 and will trade interchangeably with such notes. Also, on October 8, 2021, we completed a public offering of $650 million of 3.5 percent senior unsecured notes due 2051.
On September 1, 2021, we retired $371 million of 7.875 percent senior unsecured notes due 2021.
On August 16, 2021, we retired $500 million of 4.0 percent senior unsecured notes due 2021.
At September 30, 2021, noCommercial paper was outstanding under our $4 billion commercial paper program. In connection with our amended and restated credit agreement described below, we reduced the size of our commercial paper program to $3.5 billion.
Credit Facilities
September 30, 2021
Stated Capacity
Outstanding
(Millions)
Long-term credit facility (1)
$
4,500
$
—
Letters of credit under certain bilateral bank agreements
17
(1)In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program.
Revolving credit facility
In October 2021, we along with Transco and Northwest Pipeline, the lenders named therein, and an administrative agent entered into an amended and restated credit agreement (Credit Agreement) that reduced aggregate commitments available from $4.5 billion to $3.75 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. The Credit Agreement was effective on October 8, 2021. The maturity date of the credit facility is October 8, 2026. However, the co-borrowers may request up to two extensions of the maturity date each for an additional one-year period to allow a maturity date as late as October 8, 2028, under certain circumstances. The Credit Agreement allows for swing line loans up to an aggregate of $200 million, subject to available capacity under the credit facility, and letters of credit commitments of $500 million. Transco and Northwest Pipeline are each able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers. At September 30, 2021, and as of October 8, 2021, the effective date of the amended and restated Credit Agreement, no letters of credit have been issued and no loans were outstanding under the credit facility.
The Credit Agreement contains the following terms and conditions:
•Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets in certain circumstances, make certain distributions during an event of default, and each borrower and each borrower’s respective material subsidiaries’ ability to enter into certain restrictive agreements.
•If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments for the respective borrowers and accelerate the maturity of the loans of the defaulting borrower under the credit facility and exercise other rights and remedies.
•Other than swing line loans, each time funds are borrowed, the applicable borrower may choose from two methods of calculating interest: a fluctuating base rate equal to an alternative base rate as defined in the Credit Agreement plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus an applicable margin. We are required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin is determined by reference to a pricing schedule based on the applicable borrower’s senior unsecured long-term debt ratings and the commitment fee is determined by reference to a pricing schedule based on Williams’ senior unsecured long-term debt ratings. The Credit Agreement also includes customary provisions to provide for replacement of LIBOR with an alternative benchmark rate when LIBOR ceases to be available.
Significant financial covenants under the Credit Agreement require the ratio of debt to EBITDA (earnings before interest, taxes, depreciation, and amortization), each as defined in the Credit Agreement, to be no greater than 5.0 to 1.0, except that for any fiscal quarter in which the funding of the purchase price for an acquisition (whether
effectuated as one or a series of related transactions) with an aggregate purchase price of $25 million or more has been effected, and the following two fiscal quarters (in each case subject to certain limitations), the ratio of debt to EBITDA is to be no greater than 5.5 to 1.
The ratio of debt to capitalization (defined as net worth plus debt), each as defined in the Credit Agreement, must be no greater than 65 percent for each of Transco and Northwest Pipeline.
At September 30, 2021, we are in compliance with these covenants.
Note 10 – Stockholders’ Equity
Share Repurchase Program
On September 3, 2021, our Board of Directors authorized a new share repurchase program with a maximum dollar limit of $1.5 billion. Repurchases may be made from time to time in the open market, by block purchases, in privately negotiated transactions or in such other manner as determined by our management. Our management will also determine the timing and amount of any repurchases based on market conditions and other factors. The share repurchase program does not obligate us to acquire any particular amount of common stock, and it may be suspended or discontinued at any time. This share repurchase program does not have an expiration date. There were no repurchases under the program through September 30, 2021.
Stockholder Rights Agreement
As disclosed in our Annual Report on Form 10-K filed February 24, 2021, a purported shareholder filed a putative class action lawsuit in the Delaware Court of Chancery challenging our stockholder rights agreement (Rights Agreement). On February 26, 2021, the Delaware Court of Chancery issued a decision which declared the Rights Agreement unenforceable and permanently enjoined the continued operation of the Rights Agreement, which otherwise would have expired on March 20, 2021.
AOCI
The following table presents the changes in AOCI by component, net of income taxes:
Cash Flow Hedges
Foreign Currency Translation
Pension and Other Postretirement Benefits
Total
(Millions)
Balance at December 31, 2020
$
(3)
$
(1)
$
(92)
$
(96)
Other comprehensive income (loss) before reclassifications
(43)
—
—
(43)
Amounts reclassified from accumulatedother comprehensive income (loss)
The following table presents, by level within the fair value hierarchy, certain of our significant financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, 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, 2021:
Measured on a recurring basis:
ARO Trust investments
$
248
$
248
$
248
$
—
$
—
Commodity derivative assets (1)
131
131
38
83
10
Commodity derivative liabilities (1)
(773)
(773)
(285)
(470)
(18)
Additional disclosures:
Long-term debt, including current portion
(22,362)
(26,614)
—
(26,614)
—
Guarantees
(40)
(26)
—
(10)
(16)
Assets (liabilities) at December 31, 2020:
Measured on a recurring basis:
ARO Trust investments
$
235
$
235
$
235
$
—
$
—
Commodity derivative assets
3
3
1
2
—
Commodity derivative liabilities
(6)
(6)
(3)
(1)
(2)
Additional disclosures:
Long-term debt, including current portion
(22,344)
(27,043)
—
(27,043)
—
Guarantees
(40)
(27)
—
(11)
(16)
(1)Excludes approximately $313 million of net cash collateral.
Fair Value Methods
We use the following methods and assumptions in estimating the fair value of our financial instruments:
Assets 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 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.
Commodity derivatives: Commodity derivatives include commodity-based exchange-traded contracts and OTC contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. We also have other derivatives related to asset management agreements and other contracts that require physical delivery. Derivatives classified as Level 1 are valued using NYMEX futures prices. Derivatives classified as Level 2
are valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers. Derivatives classified as Level 3 are valued using a combination of observable and unobservable inputs. Beginning in the third quarter of 2021 the fair value amounts are presented on a net basis and reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements and cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Commodity derivative assets are reported in Other current assets and deferred charges and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Commodity derivative liabilities are reported in Accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.
Additional fair value disclosures
Long-term debt, including current portion: The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair values of the financing obligations associated with our Dalton lateral and Atlantic Sunrise projects, which are included within long-term debt, were determined using an income approach.
Guarantees: Guarantees primarily consist of a guarantee we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on a lease performance obligation that extends through 2042. Guarantees also include an indemnification related to a disposed operation.
To estimate the fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying value of the WilTel guarantee is reported in Accrued liabilities in the Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately $26 millionat September 30, 2021. Our exposure declines systematically through the remaining term of WilTel’s obligation.
The fair value of the guarantee associated with the indemnification related to a disposed operation was estimated using an income approach that considered probability-weighted scenarios of potential levels of future performance. The terms of the indemnification do not limit the maximum potential future payments associated with the guarantee. The carrying value of this guarantee is reported in Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.
We are required by our revolving credit agreement to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.
Nonrecurring fair value measurements
During the first quarter of 2020, we observed a significant decline in the publicly traded price of our common stock (NYSE: WMB), which declined 40 percent during the quarter, including a 26 percent decline in the month of March. These changes were generally attributed to macroeconomic and geopolitical conditions, including significant declines in crude oil prices driven by both surplus supply and a decrease in demand caused by the coronavirus (COVID-19) pandemic. As a result of these conditions, we performed an interim assessment of the goodwill associated with our Northeast G&P reporting unit as of March 31, 2020.
The assessment considered the total fair value of the businesses within the Northeast G&P reporting unit, which was determined using income and market approaches. We utilized internally developed industry weighted-average discount rates and estimates of valuation multiples of comparable publicly traded gathering and processing
companies. In assessing the fair value as of the March 31, 2020 measurement date, we were required to consider recent publicly available indications of value, which included lower observed publicly traded EBITDA market multiples as compared with recent history and significantly higher industry weighted-average discount rates. The fair value of the reporting unit was further reconciled to our estimated total enterprise value as of March 31, 2020, which considered observable valuation multiples of comparable publicly traded companies applied to each distinct business including the Northeast G&P reporting unit. This assessment indicated that the estimated fair value of the Northeast G&P reporting unit was below its carrying value, including goodwill. As a result of this Level 3 measurement, we recognized a full impairment charge of $187 million as of March 31, 2020, in Impairment of goodwill in the Consolidated Statement of Income. Our partner’s $65 million share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in the Consolidated Statement of Income.
The following table presents impairments of equity-method investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy.
Impairments
Nine Months Ended September 30,
Segment
Date of Measurement
Fair Value
2021
2020
(Millions)
Impairment of equity-method investments:
RMM (1)
West
March 31, 2020
$
557
$
—
$
243
Brazos Permian II (1)
West
March 31, 2020
—
—
193
Caiman II (2)
Northeast G&P
March 31, 2020
191
—
229
Appalachia Midstream Investments (2)
Northeast G&P
March 31, 2020
2,700
—
127
Aux Sable (2)
Northeast G&P
March 31, 2020
7
—
39
Laurel Mountain (2)
Northeast G&P
March 31, 2020
236
—
10
Discovery (2)
Transmission & Gulf of Mexico
March 31, 2020
367
—
97
Impairment of equity-method investments
$
—
$
938
_______________
(1)Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The fair value was measured using an income approach. Both investees operate in primarily oil-driven basins where significant expected reductions in producer activities led to reduced estimates of expected future cash flows. Our fair value estimates also reflected discount rates of approximately 17 percent for these investments. We also considered any debt held at the investee level, and its impact to fair value. The industry weighted-average discount rates utilized were significantly influenced by the market declines previously discussed.
(2)Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The impairments within our Northeast G&P segment are primarily associated with operations in wet-gas areas where producer drilling activities are influenced by NGL prices which historically trend with crude oil prices. The fair values of our investments in Caiman II and Aux Sable Liquid Products LP (Aux Sable) were estimated using a market approach, reflecting valuation multiples ranging from 5.0x to 6.2x EBITDA (weighted-average 6.0x). The fair values of the other investments, including gathering systems that are part of Appalachia Midstream Investments, were estimated using an income approach, with discount rates ranging from 9.7 percent to 13.5 percent (weighted-average 12.6 percent). We also considered any debt held at the investee level, and its impact to fair value. The assumed valuation multiples and industry weighted-average discount rates utilized were both significantly influenced by the market declines previously discussed.
We are exposed to commodity price risk. To manage this volatility we use various contracts in our marketing and trading activities that generally meet the definition of derivatives. Derivative positions are monitored using techniques including, but not limited to value at risk. Derivative instruments are recognized at fair value in the Consolidated Balance Sheet as either assets or liabilities and are presented on a net basis by counterparty, net of margin deposits. See Note 11 – Fair Value Measurements and Guarantees for additional fair value information. In the Consolidated Statement of Cash Flows, any cash impacts of settled commodity-related derivatives are recorded as operating activities.
We enter into commodity-related derivatives to hedge exposures to natural gas, NGLs, and crude oil and retain exposure to price changes that can, in a volatile energy market, be material and can adversely affect our results of operations.
Our commodity-related derivative contracts are primarily not designated as hedging instruments. Realized and unrealized gains and losses on these non-designated commodity-related derivative contracts are recognized in Net gain (loss) on commodity derivatives in the Consolidated Statement of Income as incurred. Unrealized gains and losses on commodity-related derivative contracts that are designated as hedging instruments are initially reported in AOCI in the Consolidated Balance Sheet and later reclassified as realized gains and losses into Net gain (loss) on commodity derivatives in the Consolidated Statement of Income in the period in which the hedged item affects earnings.
Some commodity-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the natural gas marketing operations. When a commodity-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item in the Consolidated Statement of Income representing the actual price of the underlying goods being delivered.
At September 30, 2021, the notional volume of the net long (short) positions for our commodity derivative contracts were as follows:
Segment
Commodity
Unit of Measure
Net Long (Short) Position
Designated as Hedging Instruments
West - Central Hub Risk
Natural Gas Liquids
Barrels
(261,000)
West - Central Hub Risk
Natural Gas
MMBtu
(7,217,500)
West - Basis Risk
Natural Gas
MMBtu
(3,542,000)
Not Designated as Hedging Instruments
Sequent (1)
Natural Gas
MMBtu
591,732,203
West - Central Hub Risk
Natural Gas Liquids
Barrels
(515,000)
West - Basis Risk
Natural Gas Liquids
Barrels
(22,449,000)
West - Central Hub Risk
Natural Gas
MMBtu
(25,281,500)
West - Basis Risk
Natural Gas
MMBtu
(51,362,500)
West - Central Hub Risk
Crude Oil
Barrels
(96,000)
_______________
(1)Derivative instruments include both long and short natural gas positions. The volume represents the net of long natural gas positions of 4.3 billion MMBtu (million British thermal units) and short natural gas positions of 3.7 billion MMBtu.
The fair value of commodity-related derivatives was reflected in the Consolidated Balance Sheet as follows:
September 30, 2021
December 31, 2020
Derivative Category
Assets
(Liabilities)
Assets
(Liabilities)
(Millions)
Derivatives designated as hedging instruments
Current
$
1
$
(31)
$
1
$
(2)
Noncurrent
—
—
—
—
Total derivatives designated as hedging instruments
$
1
$
(31)
$
1
$
(2)
Derivatives not designated as hedging instruments
Current
$
1,832
$
(2,203)
$
2
$
(3)
Noncurrent
240
(481)
—
(1)
Total derivatives not designated as hedging instruments
$
2,072
$
(2,684)
$
2
$
(4)
Gross amounts recognized
$
2,073
$
(2,715)
$
3
$
(6)
Counterparty and collateral netting offset
(1,939)
2,252
—
—
Amounts recognized in the Consolidated Balance Sheet
$
134
$
(463)
$
3
$
(6)
For the three and nine months ended September 30, 2021 and 2020 the pre-tax effects of commodity-related derivatives instruments in the Consolidated Statement of Income were as follows:
Gain (Loss)
Three Months Ended September 30,
Nine Months Ended September 30,
Income Statement Location
2021
2020
2021
2020
(Millions)
Realized commodity-related derivatives designated as hedging instruments
Net gain (loss) on
commodity derivatives
$
(20)
$
(1)
$
(28)
$
(1)
Realized commodity-related derivatives not designated as hedging instruments
Net gain (loss) on
commodity derivatives
(57)
—
(96)
(1)
Unrealized commodity-related derivatives not designated as hedging instruments
Net gain (loss) on
commodity derivatives
(314)
(3)
(317)
(2)
Total
Net gain (loss) on
commodity derivatives
$
(391)
$
(4)
$
(441)
$
(4)
Contingent Features
Generally, collateral may be provided by a parent guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are offset against fair value amounts recognized for derivatives executed with the same counterparty.
We have trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, we would need to post collateral to continue transacting business with some of our counterparties. As of September 30, 2021 the required collateral in the event of a credit rating downgrade to non-investment grade status was $33 million.
We maintain accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, we may be required to deposit cash into these accounts. At September 30, 2021, net cash collateral held on deposit in broker margin accounts was $313 million.
Note 13 – Contingent Liabilities and Commitments
Reporting of Natural Gas-Related Information to Trade Publications
Direct and indirect purchasers of natural gas in various states filed individual and class actions against us, our former affiliate WPX Energy, Inc. (WPX) and its subsidiaries, and others alleging the manipulation of published gas price indices and seeking unspecified amounts of damages. Such actions were transferred to the Nevada federal district court for consolidation of discovery and pre-trial issues. We have agreed to indemnify WPX and its subsidiaries related to this matter.
In the individual action, filed by Farmland Industries Inc. (Farmland), the court issued an order on May 24, 2016, granting one of our co-defendant’s motion for summary judgment as to Farmland’s claims. On January 5, 2017, the court extended such ruling to us, entering final judgment in our favor. Farmland appealed. On March 27, 2018, the appellate court reversed the district court’s grant of summary judgment, and on April 10, 2018, the defendants filed a petition for rehearing with the appellate court, which was denied on May 9, 2018. The case was remanded to the Nevada federal district court and subsequently remanded to its originally filed court, the Kansas federal district court where we re-urged our motion for summary judgment. The district court denied the motion but granted our request to seek permission for an immediate appeal to the appellate court. Oral argument occurred before the appellate court on January 19, 2021. On June 22, 2021, the appellate court ruled that we are not entitled to summary judgment and remanded the case to the Kansas federal district court. The court has scheduled trial to begin May 9, 2022.
In the putative class actions, on March 30, 2017, the court issued an order denying the plaintiffs’ motions for class certification. On June 13, 2017, the United States Court of Appeals for the Ninth Circuit granted the plaintiffs’ petition for permission to appeal the order. On August 6, 2018, the Ninth Circuit reversed the order denying class certification and remanded the case to the Nevada federal district court.
We reached an agreement to settle two of the actions, and on April 22, 2019, the Nevada federal district court preliminarily approved the settlements, which are on behalf of Kansas and Missouri class members. The final fairness hearing on the settlement occurred August 5, 2019, and a final judgment of dismissal with prejudice was entered the same day.
Two putative class actions remain unresolved, and they have been remanded to their originally filed court, the Wisconsin federal district court where the plaintiffs have re-urged their motion for class certification. Trial was scheduled to begin June 14, 2021, but the court struck the setting and has not reset it.
Because of the uncertainty around the remaining unresolved issues, we cannot reasonably estimate a range of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of these actions and our related indemnification obligation could result in a potential loss that may be material to our results of operations. In connection with this indemnification, we have an accrued liability balance associated with this matter and have exposure to future developments.
Alaska Refinery Contamination Litigation
We are involved in litigation arising from our ownership and operation of the North Pole Refinery in North Pole, Alaska, from 1980 until 2004, through our wholly owned subsidiaries Williams Alaska Petroleum Inc. (WAPI) and MAPCO Inc. We sold the refinery to Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., in 2004. The litigation involves three cases, with filing dates ranging from 2010 to 2014. The actions primarily arise from sulfolane contamination allegedly emanating from the refinery. A putative class action lawsuit was filed by James West in 2010 naming us, WAPI, and FHRA as defendants. We and FHRA filed claims against
each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination. In 2011, we and FHRA settled the claim with James West. Certain claims by FHRA against us were resolved by the Alaska Supreme Court in our favor. FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-site sulfolane were remanded to the Alaska Superior Court. The State of Alaska filed its action in March 2014, seeking damages. The City of North Pole (North Pole) filed its lawsuit in November 2014, seeking past and future damages, as well as punitive damages. Both we and WAPI asserted counterclaims against the State of Alaska and North Pole, and cross-claims against FHRA. FHRA has also filed cross-claims against us.
The underlying factual basis and claims in the cases are similar and may duplicate exposure. As such, in February 2017, the three cases were consolidated into one action in state court containing the remaining claims from the James West case and those of the State of Alaska and North Pole. The State of Alaska later announced the discovery of additional contaminants per- and polyfluoralkyl (PFOS and PFOA) offsite of the refinery, and the court permitted the State of Alaska to amend its complaint to add a claim for offsite PFOS/PFOA contamination. The court subsequently remanded the offsite PFOS/PFOA claims to the Alaska Department of Environmental Conservation for investigation and stayed the claims pending their potential resolution at the administrative agency. Several trial dates encompassing all three cases have been scheduled and stricken. In the summer of 2019, the court deconsolidated the cases for purposes of trial. A bench trial on all claims except North Pole’s claims began in October 2019.
In January 2020, the Alaska Superior Court issued its Memorandum of Decision finding in favor of the State of Alaska and FHRA, with the total incurred and potential future damages estimated to be $86 million. The court found that FHRA is not entitled to contractual indemnification from us because FHRA contributed to the sulfolane contamination. On March 23, 2020, the court entered final judgment in the case. Filing deadlines were stayed until May 1, 2020. However, on April 21, 2020, we filed a Notice of Appeal. We also filed post-judgment motions including a Motion for New Trial and a Motion to Alter or Amend the Judgment. These post-trial motions were resolved with the court’s denial of the last motion on June 11, 2020. Our Statement of Points on Appeal was filed on July 13, 2020. On June 22, 2020, the court stayed the North Pole’s case pending resolution of the appeal in the State of Alaska and FHRA case. On December 23, 2020, we filed our opening brief on appeal. The court set oral argument for December 15, 2021. We have recorded an accrued liability in the amount of our estimate of the probable loss. It is reasonably possible that we may not be successful on appeal and could ultimately pay up to the amount of judgment.
Royalty Matters
Certain of our customers, including Chesapeake Energy Corporation (Chesapeake), have been named in various lawsuits alleging underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases filed in Pennsylvania based on allegations that we improperly participated with Chesapeake in causing the alleged royalty underpayments. We believe that the claims asserted are subject to indemnity obligations owed to us by Chesapeake. Chesapeake has reached a settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement applies to both Chesapeake and us. The settlement does not require any contribution from us. On August 23, 2021, the court approved the settlement, but two objectors filed an appeal with the United States Court of Appeals for the Fifth Circuit.
Litigation Against Energy Transfer and Related Parties
On April 6, 2016, we filed suit in Delaware Chancery Court against Energy Transfer Equity, L.P. (Energy Transfer) and LE GP, LLC (the general partner for Energy Transfer) alleging willful and material breaches of the Agreement and Plan of Merger (ETE Merger Agreement) with Energy Transfer resulting from the private offering by Energy Transfer on March 8, 2016, of Series A Convertible Preferred Units (Special Offering) to certain Energy Transfer insiders and other accredited investors. The suit seeks, among other things, an injunction ordering the defendants to unwind the Special Offering and to specifically perform their obligations under the ETE Merger Agreement. On April 19, 2016, we filed an amended complaint seeking the same relief. On May 3, 2016, Energy Transfer and LE GP, LLC filed an answer and counterclaims.
On May 13, 2016, we filed a separate complaint in Delaware Chancery Court against Energy Transfer, LE GP, LLC and the other Energy Transfer affiliates that are parties to the ETE Merger Agreement, alleging material breaches of the ETE Merger Agreement for failing to cooperate and use necessary efforts to obtain a tax opinion required under the ETE Merger Agreement (Tax Opinion) and for otherwise failing to use necessary efforts to consummate the merger under the ETE Merger Agreement wherein we would be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger). The suit sought, among other things, a declaratory judgment and injunction preventing Energy Transfer from terminating or otherwise avoiding its obligations under the ETE Merger Agreement due to any failure to obtain the Tax Opinion.
The Court of Chancery coordinated the Special Offering and Tax Opinion suits. On May 20, 2016, the Energy Transfer defendants filed amended affirmative defenses and verified counterclaims in the Special Offering and Tax Opinion suits, alleging certain breaches of the ETE Merger Agreement by us and seeking, among other things, a declaration that we were not entitled to specific performance, that Energy Transfer could terminate the ETC Merger, and that Energy Transfer is entitled to a $1.48 billion termination fee. On June 24, 2016, following a two-day trial, the court issued a Memorandum Opinion and Order denying our requested relief in the Tax Opinion suit. The court did not rule on the substance of our claims related to the Special Offering or on the substance of Energy Transfer’s counterclaims. On June 27, 2016, we filed an appeal of the court’s decision with the Supreme Court of Delaware, seeking reversal and remand to pursue damages. On March 23, 2017, the Supreme Court of Delaware affirmed the Court of Chancery’s ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied on April 5, 2017.
On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the ETE Merger Agreement by defendants. On September 23, 2016, Energy Transfer filed a second amended and supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things, payment of the $1.48 billion termination fee due to our alleged breaches of the ETE Merger Agreement. On December 1, 2017, the court granted our motion to dismiss certain of Energy Transfer’s counterclaims, including its claim seeking payment of the $1.48 billion termination fee. On December 8, 2017, Energy Transfer filed a motion for reargument, which the Court of Chancery denied on April 16, 2018. The Court of Chancery originally scheduled trial for May 20 through May 24, 2019; the court struck that setting and reset trial to occur in 2020. All 2020 trial settings were struck due to COVID-19. Trial was held May 10 through May 17, 2021. Post-trial argument occurred September 16, 2021.
Environmental Matters
We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of September 30, 2021, we have accrued liabilities totaling $32 million for these matters, as discussed below. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At September 30, 2021, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.
The EPA and various state regulatory agencies routinely promulgate and propose new rules and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine and combustion turbine maximum achievable control technology, air quality standards for one-hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. The EPA previously issued its rule regarding National Ambient Air Quality Standards for ground-level ozone. We are monitoring the rule’s
implementation as it will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.
Continuing operations
Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At September 30, 2021, we have accrued liabilities of $4 million for these costs. We expect that these costs will be recoverable through rates.
We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At September 30, 2021, we have accrued liabilities totaling $8 million for these costs.
Former operations
We have potential obligations in connection with assets and businesses we no longer operate. These potential obligations include remediation activities at the direction of federal and state environmental authorities and the indemnification of the purchasers of certain of these assets and businesses for environmental and other liabilities existing at the time the sale was consummated. Our responsibilities relate to the operations of the assets and businesses described below.
•Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations;
•Former petroleum products and natural gas pipelines;
•Former petroleum refining facilities;
•Former exploration and production and mining operations;
•Former electricity and natural gas marketing and trading operations.
At September 30, 2021, we have accrued environmental liabilities of $20 million related to these matters.
Other Divestiture Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers 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, 2021, other than as previously disclosed, we are not aware of any material claims against us involving the above-described 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 that are incidental to our operations, none of which are expected to be material to our expected future annual results of operations, liquidity, and financial position.
We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity, and financial position. These calculations have been made without consideration of any potential recovery from third parties.
Commitments
Commitments for Sequent pipeline transportation capacity, storage capacity, and gas supply are approximately $424 million at September 30, 2021.
Note 14 – Segment Disclosures
Our reportable segments are Transmission & Gulf of Mexico, Northeast G&P, West, and Sequent. 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. This measure represents the basis of our internal financial reporting and is the primary performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments. Intersegment Service revenues primarily represent transportation services provided to our marketing business and gathering services provided to our oil and gas properties. Intersegment Product sales primarily represent the sale of NGLs from our natural gas processing plants and our oil and gas properties to our marketing business.
We define Modified EBITDA as follows:
•Net income (loss) before:
◦Provision (benefit) for income taxes;
◦Interest incurred, net of interest capitalized;
◦Equity earnings (losses);
◦Impairment of equity-method investments;
◦Other investing income (loss) – net;
◦Impairment of goodwill;
◦Depreciation and amortization expenses;
◦Accretion expense associated with asset retirement obligations for nonregulated operations.
•This measure is further adjusted to include our proportionate share (based on ownership interest) of Modified EBITDA from our equity-method investments calculated consistently with the definition described above.
The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Income and Total assets by reportable segment.
(1) Sequent nets revenues from marketing and trading activities with the associated costs. Sequent records transactions that qualify as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are presented on a net basis in revenue.
(2) The increase at our Other segment is primarily due to the acquisitions of oil and gas properties in 2021. In February 2021, we acquired properties in the Wamsutter field in Wyoming from a supermajor oil and gas
company for approximately $79 million, a portion of which was paid in the prior year. We recorded $290 million of property, plant, and equipment and $207 million of ARO related to this transaction. In June 2021, we acquired additional properties also in the Wamsutter field in Wyoming from an oil and gas company for approximately $86 million in cash, which is net of approximately $48 million reflecting the full settlement of outstanding receivables. We recorded $257 million of property, plant, and equipment and $125 million of ARO related to this transaction. Our oil and gas exploration and production activities are accounted for under the successful efforts method.
The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in the Consolidated Statement of Income.
Three Months Ended September 30,
Nine Months Ended September 30,
2021
2020
2021
2020
(Millions)
Modified EBITDA by segment:
Transmission & Gulf of Mexico
$
630
$
616
$
1,936
$
1,893
Northeast G&P
442
387
1,253
1,126
West
276
247
822
715
Sequent
(281)
—
(281)
—
Other
38
(7)
91
8
1,105
1,243
3,821
3,742
Accretion expense associated with asset retirement obligations for nonregulated operations
(12)
(10)
(33)
(27)
Depreciation and amortization expenses
(487)
(426)
(1,388)
(1,285)
Impairment of goodwill
—
—
—
(187)
Equity earnings (losses)
157
106
423
236
Impairment of equity-method investments
—
—
—
(938)
Other investing income (loss) – net
2
2
6
6
Proportional Modified EBITDA of equity-method investments
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 and NGLs through our gas pipeline and midstream business. Our operations are located in the United States.
Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets. Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. Rates are established in accordance with the FERC’s ratemaking process. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.
The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers. These services include natural gas gathering, processing, treating, and compression, NGL fractionation and transportation, crude oil production handling and transportation, marketing services for NGL, crude oil and natural gas, as well as storage facilities.
Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are conducted, managed, and presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, West, and Sequent. All remaining business activities, including our recently acquired upstream operations, as well as corporate activities are included in Other. Our reportable segments are comprised of the following businesses:
•Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco and Northwest Pipeline, as well as natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated VIE), which is a proprietary floating production system, a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery.
•Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in our Northeast JV (a consolidated VIE) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated VIE) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 50 percent equity-method investment in Blue Racer (we previously effectively owned a 29 percent indirect interest in Blue Racer through our 58 percent equity-method investment in Caiman II until acquiring a controlling interest of Caiman II in November 2020 and the remaining interest in September 2021), and Appalachia Midstream Investments, a wholly owned subsidiary that owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region.
•West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko and Permian basins. This segment also includes our NGL and natural gas marketing business (excluding the activities within the Sequent segment described below), storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in OPPL, a 50 percent equity-method investment in RMM, a 20 percent equity-method investment in Targa Train 7, and a 15 percent interest in Brazos Permian II.
•Sequent includes the operations of Sequent Energy Management, L.P. and Sequent Energy Canada, Corp. (collectively, Sequent) acquired on July 1, 2021. Sequent focuses on risk management and the marketing, trading, storage, and transportation of natural gas for a diverse set of natural gas utilities, municipalities, power generators, and producers, and moves gas to markets through transportation and storage agreements on strategically positioned assets, including along our Transco system.
Dividends
In September 2021, we paid a regular quarterly dividend of $0.41 per share.
Overview of Nine Months Ended September 30, 2021
Net income (loss) attributable to The Williams Companies, Inc., for the nine months ended September 30, 2021, increased $800 millioncompared to the nine months ended September 30, 2020, reflecting:
•The absence of $938 million of Impairment of equity-method investments in the first quarter of 2020;
•A $190 million favorable change in our commodity margins primarily due to increases in net realized sales prices and volumes. Our commodity margins are comprised of the net sum of Service revenues – commodity consideration, Product sales, net realized gains and losses on our commodity derivatives, Product costs, and Processing commodity expenses; however, Product sales at our Other segment reflect sales related to our recently acquired upstream operations and are excluded from our commodity margins;
•A $210 million increase in Product sales net of realized losses on our commodity derivatives at our Other segment reflecting net realized sales related to our recently acquired upstream operations;
•The absence of $187 million of Impairment of goodwill in 2020, of which $65 million was attributable to noncontrolling interests;
•A $187 million increase in equity earnings, primarily due to the absence of our $78 million share of an impairment of goodwill recorded by an equity-method investee in 2020 and higher volumes from certain of our Northeast G&P investments.
These favorable changes were partially offset by:
•$315 million change in net unrealized losses on commodity derivatives discussed below;
•A $289 million unfavorable change in provision for income taxes, driven by higher pre-tax earnings;
•$155 million of higher Operating and maintenance expensesprimarily due to the inclusion of our recently acquired upstream operations at our Other segment and higher employee-related expenses;
•A $103 million unfavorable change in Depreciation and amortization expenses.
The net unrealized losses on commodity derivatives include $277 million related to derivative contracts within the Sequent segment that are not designated as hedges for accounting purposes. Sequent can experience significant earnings volatility from the fair value accounting required for the derivatives used to hedge a portion of the economic value of the underlying transportation and storage portfolio. However, the unrealized fair value measurement gains and losses are offset by valuation changes in the economic value of the underlying transportation and storage portfolio, which is not accounted for on a fair value basis.
The net unrealized losses on commodity derivatives also includes the impact from derivative contracts from certain of our other businesses that are not designated as hedges for accounting purposes.
The following discussion and analysis of results of operations and financial condition and liquidity 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 24, 2021.
In September 2021, our Board of Directors authorized a new share repurchase program with a maximum dollar limit of $1.5 billion. Repurchases may be made from time to time in the open market, by block purchases, in privately negotiated transactions or in such other manner as determined by our management. Our management will also determine the timing and amount of any repurchases based on market conditions and other factors. The share repurchase program does not obligate us to acquire any particular amount of common stock, and it may be suspended or discontinued at any time. This stock repurchase program does not have an expiration date. There were no repurchases under the program through September 30, 2021.
Sequent Acquisition
In July 2021, we completed the acquisition of 100 percent of Sequent Energy Management, L.P. and Sequent Energy Canada, Corp. (collectively, Sequent). Total consideration for this acquisition was $159 million, which included $109 million related to working capital. Of the total consideration, $134 million of cash was paid in the third quarter of 2021 and $25 million was accrued in the same period for post-closing working capital adjustments. Sequent focuses on risk management and the marketing, trading, storage, and transportation of natural gas for a diverse set of natural gas utilities, municipalities, power generators, and producers, and moves gas to markets through transportation and storage agreements on strategically positioned assets, including along our Transco system. The addition of Sequent complements the current geographic footprint of our core pipeline transportation and storage business and is expected to enhance our gas marketing capabilities and expand the suite of services we can provide to our existing midstream customers.
Upstream Joint Ventures
In the third quarter of 2021, we cross-conveyed certain of our oil and gas properties in the Wamsutter field (see Note 14 – Segment Disclosures of Notes to Consolidated Financial Statements) to a venture along with certain oil and gas properties cross-conveyed by a third-party operator in the region. The combined properties consist of over 1.2 million net acres and an interest in over 3,500 wells. Under the terms of the agreement, our partner owns a 25 percent undivided interest in each well’s working interest percentage, and we own a 75 percent undivided interest in each well’s working interest percentage.
In August 2021, we agreed to sell 50 percent of certain of our existing wells and wellbore rights in the South Mansfield area of the Haynesville Shale region to a third party (see Note 14 – Segment Disclosures of Notes to Consolidated Financial Statements), in a strategic effort to develop the acreage, thereby enhancing the value of our midstream natural gas infrastructure. Under the agreement, the third party will operate the upstream position and develop the undeveloped acreage, and we will continue to operate and retain full ownership of our midstream assets. We will additionally retain ownership in the undeveloped acreage until certain acreage earning and carried interest hurdles are met, at which time remaining undeveloped acreage will be conveyed to the third party resulting in their 75 percent and our 25 percent ownership.
Expansion Project Update
Transmission & Gulf of Mexico
Southeastern Trail
In October 2019, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the Pleasant Valley interconnect with Dominion’s Cove Point Pipeline in Virginia to the Station 65 pooling point in Louisiana. We placed 230 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and the project was fully in service on January 1, 2021. In total, the project increased capacity by 296 Mdth/d.
The outbreak of COVID-19 has severely impacted global economic activity and caused significant volatility and negative pressure in financial markets. We continue to monitor the COVID-19 pandemic and have taken steps intended to protect the safety of our customers, employees, and communities, and to support the continued delivery of safe and reliable service to our customers and the communities we serve. Our financial condition, results of operations, and liquidity have not been materially impacted by direct effects of COVID-19.
Company Outlook
Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States. We accomplish this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins. We continue to maintain a strong commitment to safety, environmental stewardship, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe and reliable service to our customers and an attractive return to our shareholders. Our business plan for 2021 includes a continued focus on earnings and cash flow growth, while continuing to improve leverage metrics and control operating costs.
In 2021, our operating results are expected to benefit from growth in our Northeast G&P gathering and processing volumes. We also anticipate increases from recently completed Transco expansion projects and higher Gulf of Mexico results despite recent hurricane related shut-ins. Our results also benefited from the overall net favorable impact of unusually high natural gas prices in the first quarter associated with Winter Storm Uri and more recently a strong commodity price environment, including contributions from our upstream properties. These increases will be partially offset by decreases in the West, including a reduction in NGL transportation volumes on OPPL and certain fee reductions in the Haynesville area in exchange for future value in upstream natural gas properties. We also expect an increase in expenses, including higher incentive compensation costs and operating taxes.
Our growth capital and investment expenditures in 2021 are expected to be in a range from $1.0 billion to $1.2 billion. Growth capital spending in 2021 includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business, midstream opportunities in the Haynesville area in the West segment, and the recent acquisitions of certain upstream operations and Sequent. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.
Potential risks and obstacles that could impact the execution of our plan include:
•Continued negative impacts of COVID-19 driving a global recession, which could result in further downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products;
•Opposition to, and legal regulations affecting, our infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects;
•Counterparty credit and performance risk;
•Unexpected significant increases in capital expenditures or delays in capital project execution;
•Unexpected changes in customer drilling and production activities, which could negatively impact gathering and processing volumes;
•Lower than anticipated demand for natural gas and natural gas products which could result in lower than expected volumes, energy commodity prices, and margins;
•General economic, financial markets, or further industry downturns, including increased interest rates;
•Physical damages to facilities, including damage to offshore facilities by weather-related events;
•Other risks set forth under Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2020, as filed with the SEC on February 24, 2021, as supplemented by the disclosures in Part II, Item 1A. of this Quarterly Report on Form 10-Q for the quarter ended September 30, 2021.
We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of energy infrastructure assets that continue to serve key growth markets and supply basins in the United States.
Expansion Projects
Our ongoing major expansion projects include the following:
Transmission & Gulf of Mexico
Leidy South
In July 2020, we received approval from the FERC for the project to expand Transco’s existing natural gas transmission system and also extend its system through a capacity lease with National Fuel Gas Supply Corporation that will enable us to provide incremental firm transportation from Clermont, Pennsylvania and from the Zick interconnection on Transco’s Leidy Line to the River Road regulating station in Lancaster County, Pennsylvania. We placed 125 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and in September and October of 2021, we placed approximately 382 Mdth/d of additional capacity into service. We plan to place the remainder of the project into service by year-end 2021. The project is expected to increase capacity by 582 Mdth/d.
Regional Energy Access
In March 2021, we filed an application with the FERC for the project to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in northeastern Pennsylvania to multiple delivery points in Pennsylvania, New Jersey, and Maryland. We plan to place the project into service as early as the fourth quarter of 2023, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 829 Mdth/d.
The following table and discussion is a summary of our consolidated results of operations for the three and nine months ended September 30, 2021, compared to the three and nine months ended September 30, 2020. 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,
2021
2020
$ Change*
% Change*
2021
2020
$ Change*
% Change*
(Millions)
(Millions)
Revenues:
Service revenues
$
1,506
$
1,479
+27
+2
%
$
4,418
$
4,399
+19
—
%
Service revenues – commodity consideration
64
40
+24
+60
%
164
93
+71
+76
%
Product sales
1,296
418
+878
NM
3,229
1,139
+2,090
+183
%
Net gain (loss) on commodity derivatives
(391)
(4)
-387
NM
(441)
(4)
-437
NM
Total revenues
2,475
1,933
7,370
5,627
Costs and expenses:
Product costs
1,043
380
-663
-174
%
2,672
1,047
-1,625
-155
%
Processing commodity expenses
28
21
-7
-33
%
67
49
-18
-37
%
Operating and maintenance expenses
409
336
-73
-22
%
1,148
993
-155
-16
%
Depreciation and amortization expenses
487
426
-61
-14
%
1,388
1,285
-103
-8
%
Selling, general, and administrative expenses
152
114
-38
-33
%
389
354
-35
-10
%
Impairment of goodwill
—
—
—
—
%
—
187
+187
+100
%
Other (income) expense – net
1
15
+14
+93
%
12
28
+16
+57
%
Total costs and expenses
2,120
1,292
5,676
3,943
Operating income (loss)
355
641
1,694
1,684
Equity earnings (losses)
157
106
+51
+48
%
423
236
+187
+79
%
Impairment of equity-method investments
—
—
—
—
%
—
(938)
+938
+100
%
Other investing income (loss) – net
2
2
—
—
%
6
6
—
—
%
Interest expense
(292)
(292)
—
—
%
(884)
(882)
-2
—
%
Other income (expense) – net
4
(23)
+27
NM
4
(14)
+18
NM
Income (loss) before income taxes
226
434
1,243
92
Less: Provision (benefit) for income taxes
53
111
+58
+52
%
313
24
-289
NM
Net income (loss)
173
323
930
68
Less: Net income (loss) attributable to noncontrolling interests
8
14
+6
+43
%
35
(27)
-62
NM
Net income (loss) attributable to The Williams Companies, Inc.
$
165
$
309
$
895
$
95
* + = 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.
Three months ended September 30, 2021 vs. three months ended September 30, 2020
Service revenues increased primarily due to higher transportation fee revenues associated with expansion projects placed in service at Transco in 2020 and 2021.
Service revenues – commodity consideration increased primarily due to higher NGL prices. These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided. Most of these NGL volumes are sold during the month processed and therefore are offset within Product costs below.
Product sales increased primarily due to higher prices and volumes associated with our marketing activities, and higher prices partially offset by lower volumes related to our equity NGL sales activities. This increase also includes our recently acquired upstream operations, as well as our Sequent segment. Marketing sales for Sequent are netted with its product costs within Product sales.
Net gain (loss) on commodity derivatives includes realized and unrealized gains and losses from derivative instruments. The unfavorable change primarily reflects unrealized losses in our Sequent segment, as well as the impact from derivative contracts from certain of our other businesses.
Product costs increased primarily due to higher prices and volumes for our marketing activities, as well as higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production activities.
The net sum of Service revenues – commodity consideration, Product sales, Product costs,Processing commodity expenses, and net realized gains and losses on commodity derivatives comprise our commodity margins. However, Product sales at our Other segment reflect sales related to our oil and gas producing properties and are excluded from our commodity margins.
Operating and maintenance expenses increased primarily due to the inclusion of our recently acquired upstream operations, and higher employee-related expenses, which include increased incentive compensation costs and the absence of a 2020 favorable impact of a change in an employee benefit policy.
Depreciation and amortization expenses increased primarily due to the amortization of intangible assets resulting from Sequent business combination accounting, the inclusion of our recently acquired upstream operations, as well as reduced estimated useful lives for certain facilities in our West segment expected to be decommissioned during 2021.
Selling, general, and administrative expenses increased primarily due to higher employee-related expenses, which include increased incentive compensation costs and expenses associated with the Sequent acquisition, as well as higher expenses for various corporate costs.
Equity earnings (losses) changed favorably primarily due to increases at Appalachia Midstream Investments, Laurel Mountain, and Aux Sable.
The favorable change in Other income (expense) – net below Operating income (loss) includes higher allowance for equity funds used during construction (equity AFUDC) and the absence of a 2020 write-off of a regulatory asset related to a cancelled project.
Provision (benefit) for income taxes changed favorably primarily due to lower pre-tax income. See Note 6 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
Nine months ended September 30, 2021 vs. nine months ended September 30, 2020
Service revenues increased primarily due to higher transportation fee revenues associated with expansion projects placed in service at Transco in 2020 and 2021, higher revenue associated with reimbursable electricity expenses, higher processing and fractionation revenues in our Northeast G&P segment, and an increase associated
with Norphlet. This increase was partially offset by lower volumes driven by production declines, the impact of which is substantially offset by higher MVC revenue, and lower deferred revenue amortization, as well as the absence of a temporary volume deficiency fee from a customer in our West segment. Additional offsets include lower deferred revenue amortization and lower volumes primarily from producer operational issues, both in the Transmission & Gulf of Mexico segment.
Service revenues – commodity consideration increased primarily due to higher NGL prices. These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided. Most of these NGL volumes are sold during the month processed and therefore are offset within Product costs below.
Product sales increased primarily due to higher prices and volumes associated with our marketing activities, and the inclusion of our recently acquired upstream operations, as well as our Sequent segment. This increase also includes higher prices related to our equity NGL sales activities. Marketing sales for Sequent are netted with its product costs within Product sales.
Net gain (loss) on commodity derivatives includes realized and unrealized gains and losses from derivative instruments. The unfavorable change primarily reflects unrealized losses in our Sequent segment, as well as the impact from derivative contracts from certain of our other businesses.
Product costs increased primarily due to higher prices and volumes associated with our marketing activities, as well as higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production activities.
Processing commodity expenses increased primarily due to higher prices for natural gas purchases associated with our equity NGL production activities, partially offset by lower volumes.
Operating and maintenance expenses increased primarily due to the inclusion of our recently acquired upstream operations and higher employee-related expenses, which include increased incentive compensation costs and the absence of a 2020 favorable impact of a change in an employee benefit policy, as well as higher reimbursable electricity expenses.
Depreciation and amortization expenses increased primarily due to the inclusion of our recently acquired upstream operations, reduced estimated useful lives for certain facilities in our West segment expected to be decommissioned during 2021, the amortization of intangible assets resulting from Sequent business combination accounting, and new assets placed in-service at Transco.
Selling, general, and administrative expenses increased primarily due to higher employee-related expenses, which include increased incentive compensation costs and expenses at Sequent and the absence of 2020 favorable impact of a change in an employee benefit policy, and were partially offset by lower expenses for various corporate costs.
Impairment of goodwill reflects the 2020 charge at the Northeast reporting unit (see Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).
The favorable change in Other (income) expense – net within Operating income (loss) was due to the gains on the sales of certain assets in our West segment, offset by a Transco cashout surcharge.
Equity earnings (losses) changed favorably primarily due to the absence of the 2020 impairment of goodwill at RMM, increases at Appalachia Midstream Investments, Discovery, Aux Sable and Laurel Mountain, partially offset by a decrease at OPPL.
The change in Impairment of equity-method investments reflects the absence of 2020 impairments to various equity-method investments (see Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).
The favorable change in Other income (expense) – net below Operating income (loss) includes higher equity AFUDC and the write-off of a regulatory asset related to a 2020 cancelled project, offset by the unfavorable impact of a 2021 accrual for a loss contingency.
Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income. See Note 6 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to the absence of our partner’s share of the 2020 goodwill impairment at the Northeast reporting unit.
Period-Over-Period Operating Results - Segments
We evaluate segment operating performance based upon Modified EBITDA. Note 14 – 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.
Transmission & Gulf of Mexico
Three Months Ended September 30,
Nine Months Ended September 30,
2021
2020
2021
2020
(Millions)
Service revenues
$
836
$
807
$
2,493
$
2,431
Service revenues – commodity consideration
13
6
34
14
Product sales
88
46
222
134
Segment revenues
937
859
2,749
2,579
Product costs
(89)
(47)
(223)
(136)
Processing commodity expenses
(4)
(1)
(10)
(4)
Other segment costs and expenses
(259)
(233)
(718)
(670)
Proportional Modified EBITDA of equity-method investments
45
38
138
124
Transmission & Gulf of Mexico Modified EBITDA
$
630
$
616
$
1,936
$
1,893
Commodity margins
$
8
$
4
$
23
$
8
Three months ended September 30, 2021 vs. three months ended September 30, 2020
Transmission & Gulf of Mexico Modified EBITDA increased primarily due to favorable changes to Service revenues and Proportional Modified EBITDA of equity-method investments, partially offset by higher Other segment costs and expenses.
Service revenues increased primarily due to:
•A $43 million increase in Transco’s natural gas transportation revenues primarily associated with expansion projects placed in service in 2020 and 2021, higher reimbursable electric power costs and a cash out surcharge, which are offset by similar changes in electricity and cash out charges, reflected in Other segment costs and expenses; partially offset by
•A $20 million decrease in the Eastern Gulf Coast region primarily due to lower volumes associated with temporary shut-ins due to ongoing producer operational issues and weather-related events and lower deferred revenue recognition.
Other segment costs and expenses increased primarily due to higher incentive and benefit employee-related costs, higher operating costs, including higher reimbursable electric power costs, and a cash out surcharge, which are offset by similar changes in electricity and cash out reimbursements, reflected in Service revenues. These increases are partially offset by a favorable change in allowance for equity funds used during construction.
Proportional Modified EBITDA of equity-method investments increased at Discovery driven by higher volumes due to the absence of prior year scheduled maintenance and NGL sales prices.
Nine months ended September 30, 2021 vs. nine months ended September 30, 2020
Transmission & Gulf of Mexico Modified EBITDA increased primarily due to favorable changes to Service revenues,Commodity margins and Proportional Modified EBITDA of equity-method investments, partially offset by higher Other segment costs and expenses.
Service revenues increased primarily due to:
•A $78 million increase in Transco’s natural gas transportation revenues primarily associated with expansion projects placed in service in 2020 and 2021, higher reimbursable electric power costs and a cash out surcharge, which are offset by similar changes in electricity and cash out charges, reflected in Other segment costs and expenses; partially offset by one less billing day;
•A $13 million increase in the Western Gulf Coast region primarily driven by higher volumes due to the absence of temporary shut-ins in 2020 related to scheduled maintenance; partially offset by
•A decrease in the Eastern Gulf Coast region operations primarily due to:
◦A $23 million decrease due to lower volumes primarily from certain operations due to ongoing producer operational issues, partially offset by the absence of temporary shut-ins related to pricing in 2020;
◦A $19 million decrease at Gulfstar One for the Tubular Bells field primarily due to lower deferred revenue amortization; partially offset by
◦A $17 million increase associated with the Norphlet pipeline.
Commodity margins associated with our equity NGLs increased $14 million primarily driven by favorable NGL sales prices.
Other segment costs and expenses increased primarily due to higher incentive and benefit employee-related costs, higher operating costs, including higher reimbursable electric power costs, and a cash out surcharge, which are offset by similar changes in electricity and cash out reimbursements, reflected in Service revenues, and higher operating taxes.
Proportional Modified EBITDA of equity-method investments increased at Discovery driven by higher NGL sales prices and higher volumes due to the absence of prior year scheduled maintenance.
Proportional Modified EBITDA of equity-method investments
175
121
490
367
Northeast G&P Modified EBITDA
$
442
$
387
$
1,253
$
1,126
Commodity margins
$
(2)
$
1
$
1
$
3
Three months ended September 30, 2021 vs. three months ended September 30, 2020
Northeast G&P Modified EBITDA increased primarily due to increased Proportional Modified EBITDA of equity-method investments and higher Service revenues, partially offset by increased Other segment costs and expenses.
Service revenues increased primarily due to:
•A $10 million increase in revenues at the Northeast JV primarily related to higher processing and fractionation volumes;
•A $6 million increase in revenues associated with reimbursable electricity expenses, which is offset by similar changes in electricity charges, reflected in Other segment costs and expenses.
Other segment costs and expenses increased primarily due to higher operating expenses, including higher electricity charges, and higher incentive and benefit employee-related costs.
Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments primarily driven by higher volumes. There was also an increase at Laurel Mountain due to higher commodity-based gathering rates as well as the absence of our $11 million share of an impairment of certain assets in the third quarter of 2020 that were subsequently sold. Additionally, there was an increase at Blue Racer/Caiman II due to the favorable impact of increased ownership, and an increase at Aux Sable.
Nine months ended September 30, 2021 vs. nine months ended September 30, 2020
Northeast G&P Modified EBITDA increased primarily due to increased Proportional Modified EBITDA of equity-method investments and higher Service revenues, partially offset by increased Other segment costs and expenses.
Service revenues increased primarily due to:
•A $19 million increase in revenues at the Northeast JV primarily related to higher processing and fractionation volumes, partially offset by lower gathering volumes;
•A $17 million increase in revenues associated with reimbursable electricity expenses, which is offset by similar changes in electricity charges, reflected in Other segment costs and expenses; partially offset by
•A $6 million decrease in revenues at Susquehanna Supply Hub primarily related to lower gathering volumes, partially offset by higher gathering rates.
Other segment costs and expenses increased primarily due to higher maintenance and operating expenses, including higher electricity charges, as well as higher incentive and benefit employee-related costs.
Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments primarily driven by higher volumes. Additionally, there was an increase at Blue Racer/Caiman II primarily due to the favorable impact of increased ownership, partially offset by the absence of a gain on early debt retirement at Blue Racer in the second quarter of 2020. There was also an increase at Laurel Mountain due to higher commodity-based gathering rates as well as the absence of our $11 million share of an impairment of certain assets in the third quarter of 2020 that were subsequently sold, and an increase at Aux Sable.
Total Northeast G&P gathering volumes, including our operated equity-method investments, increased 8 percent over the prior year.
West
Three Months Ended September 30,
Nine Months Ended September 30,
2021
2020
2021
2020
(Millions)
Service revenues
$
312
$
311
$
887
$
938
Service revenues – commodity consideration
52
32
126
74
Product sales
1,170
395
2,983
1,057
Net gain (loss) on commodity derivatives
(48)
(4)
(93)
(4)
Segment revenues
1,486
734
3,903
2,065
Product costs
(1,108)
(377)
(2,748)
(1,026)
Processing commodity expenses
(24)
(18)
(57)
(41)
Other segment costs and expenses
(105)
(122)
(350)
(365)
Proportional Modified EBITDA of equity-method investments
27
30
74
82
West Modified EBITDA
$
276
$
247
$
822
$
715
Commodity margins
$
63
$
30
$
235
$
62
Net unrealized gain (loss) from derivative instruments
(17)
(2)
(20)
(2)
Three months ended September 30, 2021 vs. three months ended September 30, 2020
West Modified EBITDA increased primarily due to higher Commodity margins and lower Other segment costs and expenses, partially offset by an unfavorable change in Net unrealized gain (loss) from derivative instruments.
Service revenues increased primarily due to:
•A $16 million increase related to higher MVC revenue primarily in the Eagle Ford Shale region;
•An $11 million increase primarily due to higher gathering rates in the Barnett Shale region and higher processing rates in the Piceance region, both driven by favorable commodity pricing, were partially offset by lower gathering rates in the Haynesville Shale region due to a customer contract change; partially offset by
•A $15 million decrease associated with lower volumes, primarily in the Eagle Ford Shale region which impact is substantially offset by the recognition of higher MVC revenue (see above);
•An $11 million decrease due to the absence of a temporary volume deficiency fee from a customer in 2020.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, Processing commodity expenses, andnet realized gains and losses on commodity derivativescomprise our Commodity margins. We further segregate our commodity margins into product margins associated with our equity NGLs and marketing margins. The change in product margins from our equity NGLs was zero, primarily due to favorable net realized commodity price changes, offset by lower sales volumes. Marketing margins increased $30 million, primarily due to higher net realized NGL and natural gas prices. The higher net realized prices were partially offset by an unfavorable change in net unrealized losses from derivatives associated with our marketing activities.
Other segment costs and expenses changed favorably primarily due to a gain on an asset sale in 2021.
Nine months ended September 30, 2021 vs. nine months ended September 30, 2020
West Modified EBITDA increased primarily due to higher Commodity margins, partially offset by lower Service revenues.
Service revenues decreased primarily due to:
•A $64 million decrease associated with lower volumes, primarily due to production declines in the Eagle Ford Shale region which impact is substantially offset by the recognition of higher MVC revenue (see below). Additionally, lower volumes in the Haynesville Shale region were impacted by production declines;
•A $23 million decrease related to lower deferred revenue amortization primarily in the Barnett Shale region;
•A $20 million decrease due to the absence of a temporary volume deficiency fee from a customer in 2020;
•A $9 million decrease associated with lower gathering rates, primarily in the Haynesville Shale region due to a customer contract change, partially offset by an increase in gathering rates in the Barnett Shale region associated with favorable commodity pricing and escalated rates in the Eagle Ford Shale region; partially offset by
•A $52 million increase associated with higher MVC revenue, primarily in the Eagle Ford Shale region;
•A $14 million increase in revenues associated primarily with reimbursable compressor power and fuel purchases due to higher prices related to the impact of severe winter weather, which are offset by similar changes in Other segment costs and expenses.
Product margins from our equity NGLs increased by $10 million, primarily due to favorable net realized commodity price changes, partially offset by lower sales volumes. Marketing margins increased by $155 million primarily due to favorable changes in net realized natural gas and NGL prices, including the impact of severe winter weather in the first quarter of 2021. The higher net realized prices were partially offset by an unfavorable change in net unrealized losses from derivatives associated with our marketing activities.
Other segment costs and expenses decreased primarily due to gains on asset sales in 2021 and lower leased compressor expenses, partially offset by higher reimbursable compressor power and fuel purchases which are offset in Service revenues, and higher incentive and benefit employee-related expenses.
Proportional Modified EBITDA of equity-method investments decreased primarily due to lower volumes at OPPL, partially offset by higher volumes and commodity prices at Brazos Permian II.
Net unrealized gain (loss) from derivative instruments
(277)
—
(277)
—
Three and nine months ended September 30, 2021 vs. three and nine months ended September 30, 2020
Commodity margins were primarily due to storage withdrawals driven by strong pricing.
The net unrealized loss on commodity derivatives relates to derivative contracts within the Sequent segment that are not designated as hedges for accounting purposes. Sequent can experience significant earnings volatility from the fair value accounting required for the derivatives used to hedge a portion of the economic value of the underlying transportation and storage portfolio. However, the unrealized fair value measurement gains and losses are offset by valuation changes in the economic value of the underlying transportation and storage portfolio, which is not accounted for on a fair value basis.
Other segment costs and expenses primarily include employee-related costs.
Other
Three Months Ended September 30,
Nine Months Ended September 30,
2021
2020
2021
2020
(Millions)
Other Modified EBITDA
$
38
$
(7)
$
91
$
8
Three and nine months ended September 30, 2021 vs. three and nine months ended September 30, 2020
Other Modified EBITDA increased primarily due to our recently acquired upstream operations, including the favorable commodity price impact of severe winter weather in the first quarter of 2021. See Note 14 – Segment Disclosures of Notes to Consolidated Financial Statements. The year-to-date comparative period also includes the impact of a $10 million accrual for a loss contingency in 2021 and the absence of a third-quarter 2020 charge of $8 million for the write-off of a regulatory asset associated with a cancelled project.
Management’s Discussion and Analysis of Financial Condition and Liquidity
Outlook
As previously discussed in Company Outlook, our growth capital and investment expenditures in 2021 are currently expected to be in a range from $1.0 billion to $1.2 billion. Growth capital spending in 2021 includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business, midstream opportunities in the Haynesville area in the West segment, and the recent acquisitions of certain upstream operations and Sequent. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments. We intend to fund substantially all of our planned 2021 capital spending with cash available after paying dividends. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities including the repurchase of our common stock as previously discussed in Recent Developments.
In the first half of 2021, we acquired various oil and gas properties in the Wamsutter field in Wyoming, funding the $165 million paid with cash on hand (see Note 14 – Segment Disclosures of Notes to Consolidated Financial Statements). In July 2021, we acquired Sequent, funding the $134 million paid with cash on hand (see Note 3 – Acquisitions of Notes to Consolidated Financial Statements).
During the first quarter of 2021, we issued $900 million of new long-term debt to fund the third quarter 2021 repayment of $500 million of 4.0 percent senior unsecured notes that were scheduled to mature in November 2021 as well as $371 million of 7.875 percent senior unsecured notes that were due September 2021, and for general corporate purposes. In October 2021, we issued an additional $1.25 billion of new long-term debt to fund the repayment of debt maturing in 2022 and for general corporate purposes. As of September 30, 2021, we have approximately $2.0 billion of long-term debt due within one year. Our potential sources of liquidity available to address these maturities include cash on hand, proceeds from refinancing at attractive long-term rates or from our credit facility, as well as proceeds from asset monetizations.
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 2021. Our potential material internal and external sources and uses of liquidity are as follows:
Sources:
Cash and cash equivalents on hand
Cash generated from operations
Distributions from our equity-method investees
Utilization of our credit facility and/or commercial paper program
Cash proceeds from issuance of debt and/or equity securities
Proceeds from asset monetizations
Uses:
Working capital requirements
Capital and investment expenditures
Product costs
Other operating costs including human capital expenses
Quarterly dividends to our shareholders
Debt service payments, including payments of long-term debt
Distributions to noncontrolling interests
Share repurchase program
As of September 30, 2021, we have approximately $20.3 billion of long-term debt due after one year. Our potential sources of liquidity available to address these maturities include cash generated from operations, proceeds from refinancing at attractive long-term rates or from our credit facility, as well as proceeds from asset monetizations.
Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook.
As of September 30, 2021, we had a working capital deficit of $2.055 billion, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:
Available Liquidity
September 30, 2021
(Millions)
Cash and cash equivalents
$
214
Capacity available under our $4.5 billion credit facility, less amounts outstanding under our $4 billion commercial paper program (1)
4,500
$
4,714
(1)In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. We had no commercial paper outstanding as of September 30, 2021. Through September 30, there was no amount outstanding under our commercial paper program and credit facility during 2021. At September 30, 2021, we were in compliance with the financial covenants associated with our credit facility. Effective October 8, 2021, we entered into a new credit agreement whereby we have $3.75 billion available under our credit facility and we reduced the size of our commercial paper program to $3.5 billion. As of October 28, 2021, we have $3.75 billion available under our new credit facility.
We increased our regular quarterly cash dividend to common stockholders by approximately 2.5 percent from the $0.40 per share paid in each quarter of 2020, to $0.41 per share paid in March, June, and September 2021.
Registrations
In February 2021, we filed a shelf registration statement as a well-known seasoned issuer.
Distributions from Equity-Method Investees
The organizational documents of entities in which we have an equity-method investment generally require periodic distributions of their available cash to their members. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses.
Credit Ratings
The interest rates at which we are able to borrow money are impacted by our credit ratings. The current ratings are as follows:
Rating Agency
Outlook
Senior Unsecured Debt Rating
S&P Global Ratings
Stable
BBB
Moody’s Investors Service
Stable
Baa2
Fitch Ratings
Stable
BBB
In June 2021, Moody’s upgraded our credit rating from Baa3 to Baa2.
These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our securities, and each rating should be evaluated independently of any other rating. No assurance can be given that the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current criteria for investment-grade ratios. A downgrade of our credit ratings might increase our future cost of borrowing and, if ratings were to fall below investment-grade, could require us to provide additional collateral to third parties, negatively impacting our available liquidity.
The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented (see Notes to Consolidated Financial Statements for the Notes referenced in the table):
Cash Flow
Nine Months Ended September 30,
Category
2021
2020
(Millions)
Sources of cash and cash equivalents:
Operating activities – net
Operating
$
2,806
$
2,382
Proceeds from long-term debt (see Note 9)
Financing
898
2,198
Proceeds from credit-facility borrowings
Financing
—
1,700
Proceeds from commercial paper – net
Financing
—
40
Uses of cash and cash equivalents:
Common dividends paid
Financing
(1,494)
(1,456)
Capital expenditures
Investing
(957)
(938)
Payments of long-term debt
Financing
(887)
(2,136)
Payments on credit-facility borrowings
Financing
—
(1,700)
Purchases of businesses, net of cash acquired (see Note 3)
Investing
(126)
—
Dividends and distributions paid to noncontrolling interests
Financing
(135)
(147)
Purchases of and contributions to equity-method investments
Investing
(79)
(150)
Other sources / (uses) – net
Financing and Investing
46
(12)
Increase (decrease) in cash and cash equivalents
$
72
$
(219)
Operating activities
The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash items such as Depreciation and amortization, Provision (benefit) for deferred income taxes, Equity (earnings) losses, Impairment of goodwill, Impairment of equity-method investments, and Net unrealized (gain) loss from derivative instruments. Our Net cash provided (used) by operating activities for the nine months ended September 30, 2021, increased from the same period in 2020 primarily due to higher operating income (excluding noncash items as previously discussed) and favorable changes in net operating working capital in 2021, partially offset by unfavorable changes in current and noncurrent derivative assets and liabilities.
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 2021.
Commodity Price Risk
We are exposed to commodity price risk primarily through Sequent. Sequent routinely utilizes various types of derivative instruments to economically hedge certain commodity price risks inherent in the natural gas marketing industry. These instruments include a variety of exchange-traded and OTC energy contracts such as forward contracts, futures contracts, and basis swaps, as well as physical transactions that qualify as derivatives. These economic hedging activities are not designated and do not qualify for hedge accounting treatment.
The maturities of Sequent’s derivative contracts at September 30, 2021 were as follows:
Fair Value Measurements Using (1)
Total Fair Value
Maturity
2021
2022 - 2023
2024 - 2025+
(Millions)
Level 1
$
(195)
$
(51)
$
(160)
$
16
Level 2
(373)
(18)
(195)
(160)
Level 3
(2)
(3)
(14)
15
Fair value of contracts outstanding at end of period (2)
$
(570)
$
(72)
$
(369)
$
(129)
_______________
(1)See Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements for discussion of valuation techniques by level.
(2)Excludes cash collateral of $247 million.
Sequent Value at Risk (VaR)
VaR is the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability. Sequent’s VaR may not be comparable to that of other companies due to differences in the factors used to calculate VaR. Sequent’s VaR is determined on a 95 percent confidence interval and a one-day holding period, which means that 95 percent of the time, the risk of loss in a day from a portfolio of positions is expected to be less than or equal to the amount of VaR calculated. The open exposure of Sequent is managed in accordance with established policies that limit market risk and require daily reporting of potential financial exposure to senior management. Because Sequent generally manages physical gas assets and economically protects its positions by hedging in the futures markets, Sequent’s open exposure is generally mitigated. Sequent employs daily risk testing, using both VaR and stress testing, to evaluate the risk of its positions.
Sequent actively monitors open commodity positions and the resulting VaR and maintains a relatively small risk exposure as total buy volume is close to sell volume, with minimal open natural gas price risk.
Sequent had the following VaRs for the period shown:
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 of 1934, as amended) (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.
As disclosed in Note 3 – Acquisitions of Notes to Consolidated Financial Statements, we acquired Sequent on July 1, 2021, and its total revenues constituted approximately (10.8) percent of total revenues as shown on our consolidated financial statements for the three months ended September 30, 2021 (Sequent’s total revenues, excluding net gain (loss) on commodity derivatives, constituted approximately 1.9 percent of total revenues, excluding net gain (loss) on commodity derivatives during that period). Sequent’s total assets constituted approximately 3.0 percent of total assets as shown on our consolidated financial statements as of September 30, 2021. We excluded Sequent’s disclosure controls and procedures that are subsumed by its internal control over financial reporting from the scope of management’s assessment of the effectiveness of our disclosure controls and procedures. This exclusion is in accordance with the guidance issued by the Staff of the Securities and Exchange Commission that an assessment of recent business combinations may be omitted from management’s assessment of internal control over financial reporting for one year following the acquisition.
Changes in Internal Control Over Financial Reporting
On July 1, 2021, we implemented a new enterprise resource planning (ERP) system on a company-wide basis.We will continue to evaluate and test control changes in order to provide certification on the effectiveness, in all material respects, of our internal controls over financial reporting for the year ending December 31, 2021. Also, as noted above, we acquired Sequent on July 1, 2021. We are currently integrating Sequent into our operations and internal control processes. The scope of our assessment of our internal control over financial reporting as of December 31, 2021, will exclude Sequent’s internal control over financial reporting.
Other than as set forth above, there have been no changes during the third quarter of 2021 that have materially affected, or are reasonably likely to materially affect, our Internal Control over Financial Reporting.
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 that 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. Our threshold for disclosing material environmental legal proceedings involving a governmental authority where potential monetary sanctions are involved is $1 million.
On January 19, 2016, we received a Notice of Noncompliance with certain Leak Detection and Repair (LDAR) regulations under the Clean Air Act at our Moundsville Fractionator Facility from the EPA, Region 3. Subsequently, the EPA alleged similar violations of certain LDAR regulations at our Oak Grove Gas Plant. On March 19, 2018, we received a Notice of Violation of certain LDAR regulations at our former Ignacio Gas Plant from the EPA, Region 8, following an on-site inspection of the facility. On March 20, 2018, we also received a Notice of Violation of certain LDAR regulations at our Parachute Creek Gas Plant from the EPA, Region 8. All such notices were subsequently referred to a common attorney at the Department of Justice (DOJ). We are exploring global resolution of the claims at these facilities, as well as alleged violations at certain other facilities, with the DOJ. Global resolution would include both payment of a civil penalty and an injunctive relief component. We continue to work with the DOJ and the other agencies to resolve these claims, whether individually or globally, and negotiations are ongoing.
Other environmental matters called for by this Item are described under the caption “Environmental Matters” in Note 13 – Contingent Liabilities and Commitments of 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.
Other litigation
The additional information called for by this Item is provided in Note 10 – Stockholders’ Equity and Note 13 – Contingent Liabilities and Commitments of 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.
Item 1A. Risk Factors
Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2020, includes risk factors that could materially affect our business, financial condition, or future results. Those Risk Factors have not materially changed, except that they are supplemented or modified by the following risk factor.
Hedging Activities
Our hedging activities might not be effective and could increase the volatility of our results. In an effort to manage our financial exposure related to commodity price and market fluctuations, we have entered, and may in the future enter into contracts to hedge certain risks associated with our assets and operations. In these hedging activities, we have used, and may in the future use, fixed-price, forward, physical purchase, and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. Nevertheless, no single hedging arrangement can adequately address all risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist. While we attempt to manage counterparty credit risk within guidelines established by our credit policy, we may not be able to successfully manage all credit risk and as such, future cash flows and results of operations could be impacted by counterparty default.
In addition, our recently acquired Sequent segment utilizes derivative instruments, which may not qualify or be designated as hedges for accounting purposes. The difference in accounting treatment for the underlying position and the financial instrument used to hedge the value of the contract can cause volatility in our reported net income while the positions are open due to mark-to-market accounting.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Share Repurchase Program
On September 3, 2021, our Board of Directors authorized a new share repurchase program with a maximum dollar limit of $1.5 billion. Repurchases may be made from time to time in the open market, by block purchases, in privately negotiated transactions or in such other manner as determined by our management. Our management will also determine the timing and amount of any repurchases based on market conditions and other factors. The share repurchase program does not obligate us to acquire any particular amount of common stock, and it may be suspended or discontinued at any time. This share repurchase program does not have an expiration date. There were no repurchases under the program through September 30, 2021.
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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.
THE WILLIAMS COMPANIES, INC.
(Registrant)
/s/ John D. Porter
John D. Porter
Vice President, Controller, and Chief Accounting Officer (Duly Authorized Officer and Principal Accounting Officer)
