QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 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 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;
1
•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;
•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;
2
•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 filed with the SEC on February 24, 2021.
3
DEFINITIONS
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
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 consolidated entity following our November 2020 acquisition of an additional ownership interest
Cardinal: Cardinal Gas Services, L.L.C.
Gulfstar One: Gulfstar One LLC
Northwest Pipeline: Northwest Pipeline LLC
Transco: Transcontinental Gas Pipe Line Company, LLC
Northeast JV: Ohio Valley Midstream LLC
Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of June 30, 2021, we account for as equity-method investments, including principally the following:
Aux Sable: Aux Sable Liquid Products LP
Blue Racer: Blue Racer Midstream LLC
Discovery: Discovery Producer Services LLC
Gulfstream: Gulfstream Natural Gas System, L.L.C.
Laurel Mountain: Laurel Mountain Midstream, LLC
OPPL: Overland Pass Pipeline Company LLC
RMM: Rocky Mountain Midstream Holdings LLC
Targa Train 7: Targa Train 7 LLC
4
Government and Regulatory:
EPA: Environmental Protection Agency
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
5
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
The Williams Companies, Inc.
Consolidated Statement of Operations
(Unaudited)
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(Millions, except per-share amounts)
Revenues:
Service revenues
$
1,460
$
1,446
$
2,912
$
2,920
Service revenues – commodity consideration
51
25
100
53
Product sales
772
310
1,883
721
Total revenues
2,283
1,781
4,895
3,694
Costs and expenses:
Product costs
697
271
1,629
667
Processing commodity expenses
18
15
39
28
Operating and maintenance expenses
379
320
739
657
Depreciation and amortization expenses
463
430
901
859
Selling, general, and administrative expenses
114
127
237
240
Impairment of goodwill (Note 10)
—
—
—
187
Other (income) expense – net
12
6
11
13
Total costs and expenses
1,683
1,169
3,556
2,651
Operating income (loss)
600
612
1,339
1,043
Equity earnings (losses) (Note 4)
135
108
266
130
Impairment of equity-method investments (Note 10)
—
—
—
(938)
Other investing income (loss) – net
2
1
4
4
Interest incurred
(301)
(299)
(597)
(600)
Interest capitalized
3
5
5
10
Other income (expense) – net
2
5
—
9
Income (loss) before income taxes
441
432
1,017
(342)
Less: Provision (benefit) for income taxes
119
117
260
(87)
Net income (loss)
322
315
757
(255)
Less: Net income (loss) attributable to noncontrolling interests
18
12
27
(41)
Net income (loss) attributable to The Williams Companies, Inc.
304
303
730
(214)
Less: Preferred stock dividends
—
—
1
1
Net income (loss) available to common stockholders
$
304
$
303
$
729
$
(215)
Basic earnings (loss) per common share:
Net income (loss)
$
.25
$
.25
$
.60
$
(.18)
Weighted-average shares (thousands)
1,215,250
1,213,601
1,214,950
1,213,310
Diluted earnings (loss) per common share:
Net income (loss)
$
.25
$
.25
$
.60
$
(.18)
Weighted-average shares (thousands)
1,217,476
1,214,581
1,217,344
1,213,310
See accompanying notes.
6
The Williams Companies, Inc.
Consolidated Statement of Comprehensive Income (Loss)
(Unaudited)
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(Millions)
Net income (loss)
$
322
$
315
$
757
$
(255)
Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $7 and $9 in 2021 and $— and $— in 2020
(17)
—
(26)
—
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of ($2) and ($2) in 2021 and $— and $— in 2020
4
—
6
—
Pension and other postretirement benefits:
Net actuarial gain (loss) arising during the year, net of taxes of $— and $— in 2021 and ($7) and ($3) in 2020
—
23
—
9
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($1) and ($2) in 2021 and ($3) and ($5) in 2020
3
6
6
14
Other comprehensive income (loss)
(10)
29
(14)
23
Comprehensive income (loss)
312
344
743
(232)
Less: Comprehensive income (loss) attributable to noncontrolling interests
18
12
27
(41)
Comprehensive income (loss) attributable to The Williams Companies, Inc.
$
294
$
332
$
716
$
(191)
See accompanying notes.
7
The Williams Companies, Inc.
Consolidated Balance Sheet
(Unaudited)
June 30, 2021
December 31, 2020
(Millions, except per-share amounts)
ASSETS
Current assets:
Cash and cash equivalents
$
1,201
$
142
Trade accounts and other receivables
1,000
1,000
Allowance for doubtful accounts
(1)
(1)
Trade accounts and other receivables – net
999
999
Inventories
194
136
Other current assets and deferred charges
231
152
Total current assets
2,625
1,429
Investments
5,124
5,159
Property, plant, and equipment
43,543
42,489
Accumulated depreciation and amortization
(14,244)
(13,560)
Property, plant, and equipment – net
29,299
28,929
Intangible assets – net of accumulated amortization
7,277
7,444
Regulatory assets, deferred charges, and other
1,182
1,204
Total assets
$
45,507
$
44,165
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable
$
611
$
482
Accrued liabilities
1,005
944
Long-term debt due within one year
2,143
893
Total current liabilities
3,759
2,319
Long-term debt
21,091
21,451
Deferred income tax liabilities
2,179
1,923
Regulatory liabilities, deferred income, and other
4,213
3,889
Contingent liabilities (Note 11)
Equity:
Stockholders’ equity:
Preferred stock
35
35
Common stock ($1 par value; 1,470 million shares authorized at June 30, 2021 and December 31, 2020; 1,249 million shares issued at June 30, 2021 and 1,248 million shares issued at December 31, 2020)
1,249
1,248
Capital in excess of par value
24,401
24,371
Retained deficit
(13,022)
(12,748)
Accumulated other comprehensive income (loss)
(110)
(96)
Treasury stock, at cost (35 million shares of common stock)
(1,041)
(1,041)
Total stockholders’ equity
11,512
11,769
Noncontrolling interests in consolidated subsidiaries
2,753
2,814
Total equity
14,265
14,583
Total liabilities and equity
$
45,507
$
44,165
See accompanying notes.
8
The Williams Companies, Inc.
Consolidated Statement of Changes in Equity
(Unaudited)
The Williams Companies, Inc. Stockholders
Preferred Stock
Common Stock
Capital in Excess of Par Value
Retained Deficit
AOCI*
Treasury Stock
Total Stockholders’ Equity
Noncontrolling Interests
Total Equity
(Millions)
Balance – March 31, 2021
$
35
$
1,249
$
24,384
$
(12,825)
$
(100)
$
(1,041)
$
11,702
$
2,771
$
14,473
Net income (loss)
—
—
—
304
—
—
304
18
322
Other comprehensive income (loss)
—
—
—
—
(10)
—
(10)
—
(10)
Cash dividends – common stock ($0.41 per share)
—
—
—
(498)
—
—
(498)
—
(498)
Dividends and distributions to noncontrolling interests
—
—
—
—
—
—
—
(41)
(41)
Stock-based compensation and related common stock issuances, net of tax
—
—
20
—
—
—
20
—
20
Contributions from noncontrolling interests
—
—
—
—
—
—
—
4
4
Other
—
—
(3)
(3)
—
—
(6)
1
(5)
Net increase (decrease) in equity
—
—
17
(197)
(10)
—
(190)
(18)
(208)
Balance – June 30, 2021
$
35
$
1,249
$
24,401
$
(13,022)
$
(110)
$
(1,041)
$
11,512
$
2,753
$
14,265
Balance – March 31, 2020
$
35
$
1,248
$
24,330
$
(12,013)
$
(205)
$
(1,041)
$
12,354
$
2,905
$
15,259
Net income (loss)
—
—
—
303
—
—
303
12
315
Other comprehensive income (loss)
—
—
—
—
29
—
29
—
29
Cash dividends – common stock ($0.40 per share)
—
—
—
(486)
—
—
(486)
—
(486)
Dividends and distributions to noncontrolling interests
—
—
—
—
—
—
—
(54)
(54)
Stock-based compensation and related common stock issuances, net of tax
—
—
13
—
—
—
13
—
13
Contributions from noncontrolling interests
—
—
—
—
—
—
—
2
2
Other
—
—
—
(1)
—
—
(1)
3
2
Net increase (decrease) in equity
—
—
13
(184)
29
—
(142)
(37)
(179)
Balance – June 30, 2020
$
35
$
1,248
$
24,343
$
(12,197)
$
(176)
$
(1,041)
$
12,212
$
2,868
$
15,080
*Accumulated Other Comprehensive Income (Loss)
See accompanying notes.
9
The Williams Companies, Inc.
Consolidated Statement of Changes in Equity (Continued)
(Unaudited)
The Williams Companies, Inc. Stockholders
Preferred Stock
Common Stock
Capital in Excess of Par Value
Retained Deficit
AOCI*
Treasury Stock
Total Stockholders’ Equity
Noncontrolling Interests
Total Equity
(Millions)
Balance – December 31, 2020
$
35
$
1,248
$
24,371
$
(12,748)
$
(96)
$
(1,041)
$
11,769
$
2,814
$
14,583
Net income (loss)
—
—
—
730
—
—
730
27
757
Other comprehensive income (loss)
—
—
—
—
(14)
—
(14)
—
(14)
Cash dividends – common stock ($0.82 per share)
—
—
—
(996)
—
—
(996)
—
(996)
Dividends and distributions to noncontrolling interests
—
—
—
—
—
—
—
(95)
(95)
Stock-based compensation and related common stock issuances, net of tax
—
1
30
—
—
—
31
—
31
Contributions from noncontrolling interests
—
—
—
—
—
—
—
6
6
Other
—
—
—
(8)
—
—
(8)
1
(7)
Net increase (decrease) in equity
—
1
30
(274)
(14)
—
(257)
(61)
(318)
Balance – June 30, 2021
$
35
$
1,249
$
24,401
$
(13,022)
$
(110)
$
(1,041)
$
11,512
$
2,753
$
14,265
Balance – December 31, 2019
$
35
$
1,247
$
24,323
$
(11,002)
$
(199)
$
(1,041)
$
13,363
$
3,001
$
16,364
Net income (loss)
—
—
—
(214)
—
—
(214)
(41)
(255)
Other comprehensive income (loss)
—
—
—
—
23
—
23
—
23
Cash dividends – common stock ($0.80 per share)
—
—
—
(971)
—
—
(971)
—
(971)
Dividends and distributions to noncontrolling interests
—
—
—
—
—
—
—
(98)
(98)
Stock-based compensation and related common stock issuances, net of tax
—
1
20
—
—
—
21
—
21
Contributions from noncontrolling interests
—
—
—
—
—
—
—
4
4
Other
—
—
—
(10)
—
—
(10)
2
(8)
Net increase (decrease) in equity
—
1
20
(1,195)
23
—
(1,151)
(133)
(1,284)
Balance – June 30, 2020
$
35
$
1,248
$
24,343
$
(12,197)
$
(176)
$
(1,041)
$
12,212
$
2,868
$
15,080
*Accumulated Other Comprehensive Income (Loss)
See accompanying notes.
10
The Williams Companies, Inc.
Consolidated Statement of Cash Flows
(Unaudited)
Six Months Ended June 30,
2021
2020
(Millions)
OPERATING ACTIVITIES:
Net income (loss)
$
757
$
(255)
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization
901
859
Provision (benefit) for deferred income taxes
262
(59)
Equity (earnings) losses
(266)
(130)
Distributions from unconsolidated affiliates
345
323
Impairment of goodwill (Note 10)
—
187
Impairment of equity-method investments (Note 10)
—
938
Amortization of stock-based awards
39
24
Cash provided (used) by changes in current assets and liabilities:
Accounts receivable
(50)
85
Inventories
(58)
(9)
Other current assets and deferred charges
(56)
(13)
Accounts payable
94
236
Accrued liabilities
14
(236)
Other, including changes in noncurrent assets and liabilities
(10)
(20)
Net cash provided (used) by operating activities
1,972
1,930
FINANCING ACTIVITIES:
Proceeds from long-term debt
898
3,896
Payments of long-term debt
(11)
(3,226)
Proceeds from issuance of common stock
3
6
Common dividends paid
(996)
(971)
Dividends and distributions paid to noncontrolling interests
(95)
(98)
Contributions from noncontrolling interests
6
4
Payments for debt issuance costs
(6)
(17)
Other – net
(12)
(10)
Net cash provided (used) by financing activities
(213)
(416)
INVESTING ACTIVITIES:
Property, plant, and equipment:
Capital expenditures (1)
(685)
(613)
Dispositions – net
(5)
(16)
Contributions in aid of construction
36
19
Proceeds from dispositions of equity-method investments
1
—
Purchases of and contributions to equity-method investments
(44)
(66)
Other – net
(3)
6
Net cash provided (used) by investing activities
(700)
(670)
Increase (decrease) in cash and cash equivalents
1,059
844
Cash and cash equivalents at beginning of year
142
289
Cash and cash equivalents at end of period
$
1,201
$
1,133
_____________
(1) Increases to property, plant, and equipment
$
(693)
$
(581)
Changes in related accounts payable and accrued liabilities
8
(32)
Capital expenditures
$
(685)
$
(613)
See accompanying notes.
11
The Williams Companies, Inc.
Notes to Consolidated Financial Statements
(Unaudited)
Note 1 – General, Description of Business, and Basis of Presentation
General
Our accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 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, and West, 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 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
12
Notes (Continued)
Anadarko and Permian basins. This segment also includes our natural gas liquid (NGL) and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in Overland Pass Pipeline Company LLC, 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).
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 June 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.
13
Notes (Continued)
The following table presents amounts included in the Consolidated Balance Sheet that are only for the use or obligation of our consolidated VIEs:
June 30, 2021
December 31, 2020
(Millions)
Assets (liabilities):
Cash and cash equivalents
$
81
$
107
Trade accounts and other receivables – net
151
148
Other current assets and deferred charges
9
7
Property, plant, and equipment – net
5,406
5,514
Intangible assets – net of accumulated amortization
2,322
2,376
Regulatory assets, deferred charges, and other
15
15
Accounts payable
(55)
(42)
Accrued liabilities
(39)
(34)
Regulatory liabilities, deferred income, and other
(286)
(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 June 30, 2021, the carrying value of our investment in Targa Train 7 was $49 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.
14
Notes (Continued)
Note 3 – Revenue Recognition
Revenue by Category
The following table presents our revenue disaggregated by major service line:
Transco
Northwest Pipeline
Gulf of Mexico Midstream
Northeast Midstream
West Midstream
Other
Eliminations
Total
(Millions)
Three Months Ended June 30, 2021
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage
$
613
$
108
$
—
$
—
$
—
$
—
$
(2)
$
719
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration
—
—
90
315
278
—
(26)
657
Commodity consideration
—
—
10
2
39
—
—
51
Other
2
—
7
52
10
—
(4)
67
Total service revenues
615
108
107
369
327
—
(32)
1,494
Product sales
16
—
53
24
726
44
(87)
776
Total revenues from contracts with customers
631
108
160
393
1,053
44
(119)
2,270
Other revenues (1)
—
—
3
6
(1)
8
(3)
13
Total revenues
$
631
$
108
$
163
$
399
$
1,052
$
52
$
(122)
$
2,283
Three Months Ended June 30, 2020
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage
$
592
$
110
$
—
$
—
$
—
$
—
$
(1)
$
701
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration
—
—
78
308
297
—
(19)
664
Commodity consideration
—
—
3
1
21
—
—
25
Other
2
—
10
41
17
—
(4)
66
Total service revenues
594
110
91
350
335
—
(24)
1,456
Product sales
20
—
17
1
303
—
(31)
310
Total revenues from contracts with customers
614
110
108
351
638
—
(55)
1,766
Other revenues (1)
2
—
1
5
2
9
(4)
15
Total revenues
$
616
$
110
$
109
$
356
$
640
$
9
$
(59)
$
1,781
15
Notes (Continued)
Transco
Northwest Pipeline
Gulf of Mexico Midstream
Northeast Midstream
West Midstream
Other
Eliminations
Total
(Millions)
Six Months Ended June 30, 2021
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage
$
1,238
$
221
$
—
$
—
$
—
$
—
$
(5)
$
1,454
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration
—
—
176
626
540
—
(47)
1,295
Commodity consideration
—
—
21
5
74
—
—
100
Other
5
—
10
93
29
—
(8)
129
Total service revenues
1,243
221
207
724
643
—
(60)
2,978
Product sales
30
—
106
56
1,806
100
(177)
1,921
Total revenues from contracts with customers
1,273
221
313
780
2,449
100
(237)
4,899
Other revenues (1)
2
—
5
12
(32)
15
(6)
(4)
Total revenues
$
1,275
$
221
$
318
$
792
$
2,417
$
115
$
(243)
$
4,895
Six Months Ended June 30, 2020
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage
$
1,196
$
225
$
—
$
—
$
—
$
—
$
(3)
$
1,418
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration
—
—
177
620
596
—
(41)
1,352
Commodity consideration
—
—
8
3
42
—
—
53
Other
5
—
16
82
26
—
(9)
120
Total service revenues
1,201
225
201
705
664
—
(53)
2,943
Product sales
40
—
49
30
662
—
(60)
721
Total revenues from contracts with customers
1,241
225
250
735
1,326
—
(113)
3,664
Other revenues (1)
2
—
3
10
5
17
(7)
30
Total revenues
$
1,243
$
225
$
253
$
745
$
1,331
$
17
$
(120)
$
3,694
______________________________
(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 Operations, and amounts associated with our derivative contracts, which are reported in Product sales in the Consolidated Statement of Operations.
16
Notes (Continued)
Contract Assets
The following table presents a reconciliation of our contract assets:
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(Millions)
Balance at beginning of period
$
25
$
18
$
12
$
8
Revenue recognized in excess of amounts invoiced
38
46
83
69
Minimum volume commitments invoiced
(25)
(34)
(57)
(47)
Balance at end of period
$
38
$
30
$
38
$
30
Contract Liabilities
The following table presents a reconciliation of our contract liabilities:
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(Millions)
Balance at beginning of period
$
1,171
$
1,189
$
1,209
$
1,215
Payments received and deferred
72
74
85
102
Significant financing component
2
2
5
5
Recognized in revenue
(52)
(62)
(106)
(119)
Balance at end of period
$
1,193
$
1,203
$
1,193
$
1,203
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 June 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 June 30, 2021, that will be recognized in future periods is also excluded from our remaining performance obligations and is instead reflected in contract liabilities.
17
Notes (Continued)
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 June 30, 2021.
Contract Liabilities
Remaining Performance Obligations
(Millions)
2021 (six months)
$
83
$
1,724
2022 (one year)
130
3,409
2023 (one year)
111
3,137
2024 (one year)
106
2,723
2025 (one year)
101
2,330
Thereafter
662
18,055
Total
$
1,193
$
31,378
Accounts Receivable
The following is a summary of our Trade accounts and other receivables – net:
June 30, 2021
December 31, 2020
(Millions)
Accounts receivable related to revenues from contracts with customers
$
928
$
892
Other accounts receivable
71
107
Trade accounts and other receivables – net
$
999
$
999
Note 4 – Investing Activities
Equity Earnings (Losses)
Equity earnings (losses) for the six months ended June 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 six months ended June 30, 2020, includes $938 million associated with the first-quarter 2020 impairment of certain equity-method investments (see Note 10 – Fair Value Measurements and Guarantees).
18
Notes (Continued)
Note 5 – Provision (Benefit) for Income Taxes
The Provision (benefit) for income taxes includes:
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(Millions)
Current:
Federal
$
—
$
—
$
(2)
$
(28)
State
1
(1)
—
—
1
(1)
(2)
(28)
Deferred:
Federal
85
93
200
(41)
State
33
25
62
(18)
118
118
262
(59)
Provision (benefit) for income taxes
$
119
$
117
$
260
$
(87)
The effective income tax rates for the total provision (benefit) for both the three and six months ended June 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 6 – Earnings (Loss) Per Common Share
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(Dollars in millions, except per-share amounts; shares in thousands)
Net income (loss) available to common stockholders
$
304
$
303
$
729
$
(215)
Basic weighted-average shares
1,215,250
1,213,601
1,214,950
1,213,310
Effect of dilutive securities:
Nonvested restricted stock units
2,208
980
2,385
—
Stock options
18
—
9
—
Diluted weighted-average shares (1)
1,217,476
1,214,581
1,217,344
1,213,310
Earnings (loss) per common share:
Basic
$
.25
$
.25
$
.60
$
(.18)
Diluted
$
.25
$
.25
$
.60
$
(.18)
______________________________
(1)For the six months ended June 30, 2020, 1.1 million weighted-average nonvested restricted stock units have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to our loss available to common stockholders.
19
Notes (Continued)
Note 7 – Employee Benefit Plans
Net periodic benefit cost (credit) is as follows:
Pension Benefits
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(Millions)
Components of net periodic benefit cost (credit):
Service cost
$
7
$
7
$
15
$
15
Interest cost
7
9
14
19
Expected return on plan assets
(11)
(14)
(22)
(27)
Amortization of net actuarial loss
3
7
7
11
Net actuarial loss from settlements
1
2
1
8
Net periodic benefit cost (credit)
$
7
$
11
$
15
$
26
Other Postretirement Benefits
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(Millions)
Components of net periodic benefit cost (credit):
Interest cost
$
2
$
1
$
3
$
3
Expected return on plan assets
(3)
(2)
(5)
(5)
Reclassification to regulatory liability
—
—
1
1
Net periodic benefit cost (credit)
$
(1)
$
(1)
$
(1)
$
(1)
The components of Net periodic benefit cost (credit) other than the Service cost component are included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations.
During the six months ended June 30, 2021, we contributed $3 million to our pension plans and $3 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $1 million to our pension plans and approximately $2 million to our other postretirement benefit plans in the remainder of 2021.
Note 8 – Debt and Banking Arrangements
Long-Term Debt
Issuances and retirements
On March 2, 2021, we completed a public offering of $900 million of 2.6 percent senior unsecured notes due 2031.
Commercial Paper Program
At June 30, 2021, noCommercial paper was outstanding under our $4 billion commercial paper program.
20
Notes (Continued)
Credit Facilities
June 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.
Note 9 – Stockholders’ Equity
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
(26)
—
—
(26)
Amounts reclassified from accumulatedother comprehensive income (loss)
6
—
6
12
Other comprehensive income (loss)
(20)
—
6
(14)
Balance at June 30, 2021
$
(23)
$
(1)
$
(86)
$
(110)
Reclassifications out of AOCI are presented in the following table by component for the six months ended June 30, 2021:
Component
Reclassifications
Classification
(Millions)
Cash flow hedges:
Energy commodity contracts
$
8
Product sales
Pension and other postretirement benefits:
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit)
8
Other income (expense) – net below Operating income (loss)
Income tax benefit
(4)
Provision (benefit) for income taxes
Reclassifications during the period
$
12
21
Notes (Continued)
Note 10 – Fair Value Measurements and Guarantees
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, margin deposits, and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.
Fair Value Measurements Using
Carrying Amount
Fair Value
Quoted Prices In Active Markets for Identical Assets (Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs (Level 3)
(Millions)
Assets (liabilities) at June 30, 2021:
Measured on a recurring basis:
ARO Trust investments
$
257
$
257
$
257
$
—
$
—
Additional disclosures:
Long-term debt, including current portion
(23,234)
(27,643)
—
(27,643)
—
Guarantees
(40)
(26)
—
(10)
(16)
Assets (liabilities) at December 31, 2020:
Measured on a recurring basis:
ARO Trust investments
$
235
$
235
$
235
$
—
$
—
Additional disclosures:
Long-term debt, including current portion
(22,344)
(27,043)
—
(27,043)
—
Guarantees
(40)
(27)
—
(11)
(16)
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.
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.
22
Notes (Continued)
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 June 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 (earnings before interest, taxes, depreciation, and amortization) 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 Operations. Our partner’s $65 million share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in the Consolidated Statement of Operations.
23
Notes (Continued)
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
Six Months Ended June 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.
Note 11 – Contingent Liabilities
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.
24
Notes (Continued)
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. 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
25
Notes (Continued)
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. 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 and is awaiting court approval.
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
26
Notes (Continued)
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 is scheduled for 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 June 30, 2021, we have accrued liabilities totaling $31 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 June 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 June 30, 2021, we have accrued liabilities of $4 million for these costs. We expect that these costs will be recoverable through rates.
27
Notes (Continued)
We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At June 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 June 30, 2021, we have accrued environmental liabilities of $19 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 June 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.
Summary
We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity, and financial position. These calculations have been made without consideration of any potential recovery from third parties.
Note 12 – Segment Disclosures
Our reportable segments are Transmission & Gulf of Mexico, Northeast G&P, and West. All remaining business activities are included in Other. (See Note 1 – General, Description of Business, and Basis of Presentation.)
28
Notes (Continued)
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.
29
Notes (Continued)
The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Operations and Total assets by reportable segment.
Transmission & Gulf of Mexico
Northeast G&P
West
Other
Eliminations
Total
(Millions)
Three Months Ended June 30, 2021
Segment revenues:
Service revenues
External
$
811
$
364
$
280
$
5
$
—
$
1,460
Internal
12
9
11
3
(35)
—
Total service revenues
823
373
291
8
(35)
1,460
Total service revenues – commodity consideration
10
2
39
—
—
51
Product sales
External
47
8
696
21
—
772
Internal
20
16
26
23
(85)
—
Total product sales
67
24
722
44
(85)
772
Total revenues
$
900
$
399
$
1,052
$
52
$
(120)
$
2,283
Three Months Ended June 30, 2020
Segment revenues:
Service revenues
External
$
783
$
342
$
316
$
5
$
—
$
1,446
Internal
12
12
—
4
(28)
—
Total service revenues
795
354
316
9
(28)
1,446
Total service revenues – commodity consideration
3
1
21
—
—
25
Product sales
External
29
(8)
289
—
—
310
Internal
7
9
14
—
(30)
—
Total product sales
36
1
303
—
(30)
310
Total revenues
$
834
$
356
$
640
$
9
$
(58)
$
1,781
Six Months Ended June 30, 2021
Segment revenues:
Service revenues
External
$
1,633
$
711
$
559
$
9
$
—
$
2,912
Internal
24
20
16
6
(66)
—
Total service revenues
1,657
731
575
15
(66)
2,912
Total service revenues – commodity consideration
21
5
74
—
—
100
Product sales
External
87
12
1,714
70
—
1,883
Internal
47
44
54
30
(175)
—
Total product sales
134
56
1,768
100
(175)
1,883
Total revenues
$
1,812
$
792
$
2,417
$
115
$
(241)
$
4,895
30
Notes (Continued)
Transmission & Gulf of Mexico
Northeast G&P
West
Other
Eliminations
Total
(Millions)
Six Months Ended June 30, 2020
Segment revenues:
Service revenues
External
$
1,597
$
686
$
627
$
10
$
—
$
2,920
Internal
27
26
—
7
(60)
—
Total service revenues
1,624
712
627
17
(60)
2,920
Total service revenues – commodity consideration
8
3
42
—
—
53
Product sales
External
70
15
636
—
—
721
Internal
18
15
26
—
(59)
—
Total product sales
88
30
662
—
(59)
721
Total revenues
$
1,720
$
745
$
1,331
$
17
$
(119)
$
3,694
June 30, 2021
Total assets (1)
$
19,575
$
14,470
$
10,448
$
2,570
$
(1,556)
$
45,507
December 31, 2020
Total assets
$
19,110
$
14,569
$
10,558
$
927
$
(999)
$
44,165
______________
(1) The increase at our Other segment is primarily due to increased cash balance and 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.
31
Notes (Continued)
The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in the Consolidated Statement of Operations.
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(Millions)
Modified EBITDA by segment:
Transmission & Gulf of Mexico
$
646
$
615
$
1,306
$
1,277
Northeast G&P
409
370
811
739
West
231
253
546
468
Other
20
8
53
15
1,306
1,246
2,716
2,499
Accretion expense associated with asset retirement obligations for nonregulated operations
(11)
(7)
(21)
(17)
Depreciation and amortization expenses
(463)
(430)
(901)
(859)
Impairment of goodwill
—
—
—
(187)
Equity earnings (losses)
135
108
266
130
Impairment of equity-method investments
—
—
—
(938)
Other investing income (loss) – net
2
1
4
4
Proportional Modified EBITDA of equity-method investments
(230)
(192)
(455)
(384)
Interest expense
(298)
(294)
(592)
(590)
(Provision) benefit for income taxes
(119)
(117)
(260)
87
Net income (loss)
$
322
$
315
$
757
$
(255)
Note 13 – Subsequent Event
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 paid was $134 million, which includes $84 million of working capital acquired, and is subject to post-closing adjustment. Sequent focuses on asset management and the wholesale 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. Due to the recent closing of this acquisition, we have not provided all required disclosures as the information necessary is still under development. We plan to provide these disclosures in future filings.
32
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, and West. 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 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, 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.
33
Management’s Discussion and Analysis (Continued)
Dividends
In June 2021, we paid a regular quarterly dividend of $0.41 per share.
Overview of Six Months Ended June 30, 2021
Net income (loss) attributable to The Williams Companies, Inc., for the six months ended June 30, 2021, increased $944 millioncompared to the six months ended June 30, 2020, reflecting:
•The absence of $938 million of Impairment of equity-method investments in the first quarter of 2020;
•The absence of $187 million of Impairment of goodwill in 2020, of which $65 million was attributable to noncontrolling interests;
•A $136 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, 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 $136 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;
•A $100 million increase in Product sales at our Other segment reflecting sales related to our recently acquired upstream operations.
These favorable changes were partially offset by:
•A $347 million unfavorable change in provision for income taxes, driven by higher pre-tax earnings;
•$82 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 $42 million unfavorable change in Depreciation and amortization expenses.
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.
Recent Developments
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 paid was $134 million, which includes $84 million of working capital acquired, and is subject to post-closing adjustment. Sequent focuses on asset management and the wholesale 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 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.
Wamsutter Upstream Joint Venture
During the second quarter of 2021, we agreed to cross-convey certain of our oil and gas properties in the Wamsutter field (see Note 12 - Segment Disclosures of Notes to Consolidated Financial Statements) to a venture
34
Management’s Discussion and Analysis (Continued)
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 which became effective during the third quarter of 2021, 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.
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.
COVID-19
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 primarily due to lower planned hurricane impacts. Our results also benefited from the overall net favorable impact of unusually high natural gas prices in the first quarter, including contributions from certain of our recently acquired upstream properties. These increases will be partially offset by a decrease in West results, 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 a modest increase in expenses, including higher 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.
35
Management’s Discussion and Analysis (Continued)
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.
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 we plan to place the remainder of the project into service as early as the fourth quarter of 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.
36
Management’s Discussion and Analysis (Continued)
Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for the three and six months ended June 30, 2021, compared to the three and six months ended June 30, 2020. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
$ Change*
% Change*
2021
2020
$ Change*
% Change*
(Millions)
(Millions)
Revenues:
Service revenues
$
1,460
$
1,446
+14
+1
%
$
2,912
$
2,920
-8
—
%
Service revenues – commodity consideration
51
25
+26
+104
%
100
53
+47
+89
%
Product sales
772
310
+462
+149
%
1,883
721
+1,162
+161
%
Total revenues
2,283
1,781
4,895
3,694
Costs and expenses:
Product costs
697
271
-426
-157
%
1,629
667
-962
-144
%
Processing commodity expenses
18
15
-3
-20
%
39
28
-11
-39
%
Operating and maintenance expenses
379
320
-59
-18
%
739
657
-82
-12
%
Depreciation and amortization expenses
463
430
-33
-8
%
901
859
-42
-5
%
Selling, general, and administrative expenses
114
127
+13
+10
%
237
240
+3
+1
%
Impairment of goodwill
—
—
—
—
%
—
187
+187
+100
%
Other (income) expense – net
12
6
-6
-100
%
11
13
+2
+15
%
Total costs and expenses
1,683
1,169
3,556
2,651
Operating income (loss)
600
612
1,339
1,043
Equity earnings (losses)
135
108
+27
+25
%
266
130
+136
+105
%
Impairment of equity-method investments
—
—
—
—
%
—
(938)
+938
+100
%
Other investing income (loss) – net
2
1
+1
+100
%
4
4
—
—
%
Interest expense
(298)
(294)
-4
-1
%
(592)
(590)
-2
—
%
Other income (expense) – net
2
5
-3
-60
%
—
9
-9
-100
%
Income (loss) before income taxes
441
432
1,017
(342)
Less: Provision (benefit) for income taxes
119
117
-2
-2
%
260
(87)
-347
NM
Net income (loss)
322
315
757
(255)
Less: Net income (loss) attributable to noncontrolling interests
18
12
-6
-50
%
27
(41)
-68
NM
Net income (loss) attributable to The Williams Companies, Inc.
$
304
$
303
$
730
$
(214)
* + = 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.
37
Management’s Discussion and Analysis (Continued)
Three months ended June 30, 2021 vs. three months ended June 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, the absence of certain 2020 Gulf of Mexico maintenance shut-ins, and an increase in reimbursable electricity expenses which is offset in Operating and maintenance expenses in our Northeast G&P segment. These increases were partially offset by lower volumes driven by production declines, lower deferred revenue amortization, and the absence of a temporary volume deficiency fee from a customer, in our West 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 net realized NGL and natural gas prices and higher natural gas volumes associated with our marketing activities, and higher net realized prices related to our equity NGL sales activities. This increase also includes our recently acquired upstream operations (see Note 12 – Segment Disclosures of Notes to Consolidated Financial Statements). Marketing sales are offset within Product costs.
Product costs increased primarily due to higher NGL and natural gas prices and higher natural gas 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, and Processing commodity expenses 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, as well as higher maintenance and reimbursable electricity expenses, and higher employee-related expenses.
Depreciation and amortization expenses increased primarily due to reduced estimated useful lives for certain facilities in our West segment expected to be decommissioned during 2021, as well as the inclusion of our recently acquired upstream operations.
Selling, general, and administrative expenses decreased primarily due to lower expenses for various corporate costs, partially offset by higher employee-related expenses.
Equity earnings (losses) changed favorably primarily due to an increase at Appalachia Midstream Investments.
Six months ended June 30, 2021 vs. six months ended June 30, 2020
Service revenues decreased primarily due to lower volumes driven by production declines, lower gathering and processing rates, lower deferred revenue amortization, and the absence of a temporary volume deficiency fee from a customer, in our West segment. This decrease was partially offset by higher transportation fee revenues associated with expansion projects placed in service at Transco in 2020 and 2021, higher MVC revenue in our West segment, higher revenue associated with reimbursable electricity expenses, and an increase associated with Norphlet.
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 net realized natural gas and NGL prices and higher natural gas volumes associated with our marketing activities, and the inclusion of our recently acquired upstream operations
38
Management’s Discussion and Analysis (Continued)
(see Note 12 – Segment Disclosures of Notes to Consolidated Financial Statements). This increase also includes higher prices related to our equity NGL sales activities. Marketing sales are partially offset within Product costs.
Product costs increased primarily due to higher natural gas and NGL prices and higher natural gas 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.
Processing commodity expenses increased primarily due to higher prices for natural gas purchases associated with our equity NGL production activities.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses 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, as well as higher maintenance and reimbursable electricity expenses, and higher employee-related expenses.
Depreciation and amortization expenses increased primarily due to reduced estimated useful lives for certain facilities in our West segment expected to be decommissioned during 2021, the inclusion of our recently acquired upstream operations, as well as new assets placed in-service at Transco.
Selling, general, and administrative expenses decreased primarily due to lower expenses for various corporate costs, partially offset by higher employee-related expenses.
Impairment of goodwill reflects the 2020 charge at the Northeast reporting unit (see Note 10 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).
Equity earnings (losses) changed favorably primarily due to the absence of the 2020 impairment of goodwill at RMM, increases at Appalachia Midstream Investments and Discovery, 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 10 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).
Other income (expense) – net includes the unfavorable impact of an accrual for a loss contingency in 2021.
Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income. See Note 5 – 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 12 – 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.
39
Management’s Discussion and Analysis (Continued)
Transmission & Gulf of Mexico
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(Millions)
Service revenues
$
823
$
795
$
1,657
$
1,624
Service revenues – commodity consideration
10
3
21
8
Product sales
67
36
134
88
Segment revenues
900
834
1,812
1,720
Product costs
(68)
(37)
(134)
(89)
Processing commodity expenses
(2)
(1)
(6)
(3)
Other segment costs and expenses
(230)
(223)
(459)
(437)
Proportional Modified EBITDA of equity-method investments
46
42
93
86
Transmission & Gulf of Mexico Modified EBITDA
$
646
$
615
$
1,306
$
1,277
Commodity margins
$
7
$
1
$
15
$
4
Three months ended June 30, 2021 vs. three months ended June 30, 2020
Transmission & Gulf of Mexico Modified EBITDA increased primarily due to favorable changes to Service revenues and Commodity margins, partially offset by higher Other segment costs and expenses.
Service revenues increased primarily due to:
•A $19 million increase in Transco’s natural gas transportation revenues primarily associated with expansion projects placed in service in 2020 and 2021;
•A $12 million increase in the Western Gulf Coast region primarily due to the absence of temporary shut-ins in 2020 related to scheduled maintenance.
The increase in Product sales includes an increase in commodity marketing sales primarily due to higher NGL prices. Marketing sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA. Our commodity margins associated with our equity NGLs increased $5 million primarily driven by favorable NGL sales prices.
Other segment costs and expenses increased primarily due to higher employee-related costs.
Six months ended June 30, 2021 vs. six months ended June 30, 2020
Transmission & Gulf of Mexico Modified EBITDA increased primarily due to favorable changes to Service revenues and Commodity margins, partially offset by higher Other segment costs and expenses.
Service revenues increased primarily due to:
•A $36 million increase in Transco’s natural gas transportation revenues primarily associated with expansion projects placed in service in 2020 and 2021, partially offset by one less billing day;
•A $16 million increase associated with Norphlet;
•An $11 million increase in the Western Gulf Coast region primarily due to the absence of temporary shut-ins in 2020 related to scheduled maintenance; partially offset by
•A $16 million decrease due to lower volumes primarily from certain Eastern Gulf Coast region operations due to producer operational issues;
40
Management’s Discussion and Analysis (Continued)
•An $8 million decrease at Gulfstar One for the Tubular Bells field primarily due to lower deferred revenue amortization.
The increase in Product sales includes an increase in commodity marketing sales primarily due to higher NGL prices. Marketing sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA. Our commodity margins associated with our equity NGLs increased $9 million primarily driven by favorable NGL sales prices.
Other segment costs and expenses increased primarily due to higher employee-related costs and an unfavorable 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 absence of prior year scheduled maintenance and temporary shut-ins related to Gulf of Mexico weather-related events and pricing.
Northeast G&P
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(Millions)
Service revenues
$
373
$
354
$
731
$
712
Service revenues – commodity consideration
2
1
5
3
Product sales
24
1
56
30
Segment revenues
399
356
792
745
Product costs
(26)
—
(58)
(29)
Processing commodity expenses
—
(1)
—
(2)
Other segment costs and expenses
(126)
(111)
(238)
(221)
Proportional Modified EBITDA of equity-method investments
162
126
315
246
Northeast G&P Modified EBITDA
$
409
$
370
$
811
$
739
Commodity margins
$
—
$
1
$
3
$
2
Three months ended June 30, 2021 vs. three months ended June 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 associated with reimbursable electricity expenses, which is offset by similar changes in electricity charges, reflected in Other segment costs and expenses;
•A $7 million increase in revenues at the Northeast JV primarily related to higher processing and fractionation volumes.
Product sales increased primarily due to higher sales prices of NGLs associated with our marketing activities. Marketing sales are offset by similar changes in marketing purchases, reflected above as Product costs, and therefore have little impact to Modified EBITDA.
Other segment costs and expenses increased primarily due to higher maintenance and operating expenses, including higher electricity charges.
41
Management’s Discussion and Analysis (Continued)
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 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.
Six months ended June 30, 2021 vs. six months ended June 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 $12 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;
•A $9 million increase in revenues at the Northeast JV primarily related to higher processing and fractionation volumes; partially offset by
•An $8 million decrease associated with lower gathering volumes at Susquehanna Supply Hub.
Product sales increased primarily due to higher sales prices of NGLs associated with our marketing activities, which were partially offset by lower sales volumes. Marketing sales are offset by similar changes in marketing purchases, reflected above as Product costs, and therefore have little impact to Modified EBITDA.
Other segment costs and expenses increased primarily due to higher maintenance and operating expenses, including higher electricity charges.
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.
West
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(Millions)
Service revenues
$
291
$
316
$
575
$
627
Service revenues – commodity consideration
39
21
74
42
Product sales
722
303
1,768
662
Segment revenues
1,052
640
2,417
1,331
Product costs
(704)
(281)
(1,640)
(649)
Processing commodity expenses
(16)
(13)
(33)
(23)
Other segment costs and expenses
(123)
(117)
(245)
(243)
Proportional Modified EBITDA of equity-method investments
22
24
47
52
West Modified EBITDA
$
231
$
253
$
546
$
468
Commodity margins
$
41
$
30
$
169
$
32
42
Management’s Discussion and Analysis (Continued)
Three months ended June 30, 2021 vs. three months ended June 30, 2020
West Modified EBITDA decreased primarily due to lower Service revenues and higher Other segment costs and expenses, partially offset by higher Commodity margins.
Service revenues decreased primarily due to:
•A $10 million decrease associated with lower volumes, primarily due to production declines in the Haynesville Shale region;
•A $9 million decrease related to lower deferred revenue amortization primarily in the Barnett Shale region;
•A $9 million decrease due to the absence of a temporary volume deficiency fee from a customer in 2020.
•Higher gathering rates in the Barnett Shale region and higher processing rates in the Piceance region, both driven by favorable commodity pricing, were substantially offset by lower gathering rates in the Haynesville Shale region due to a customer contract change.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity margins, which we further segregate into product margins associated with our equity NGLs and marketing margins. Product margins from our equity NGLs increased $7 million, primarily due to higher net realized sales prices, partially offset by lower sales volumes and an increase in natural gas purchases associated with our equity NGLs. Commodity marketing sales increased primarily due to higher net realized NGL and natural gas prices. Marketing sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA.
Six months ended June 30, 2021 vs. six months ended June 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 $47 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 $25 million decrease associated with lower gathering rates in the Haynesville Shale region due to a customer contract change and lower processing rates in the Piceance region driven primarily by unfavorable commodity pricing. These decreases are partially offset by an increase in gathering rates in the Barnett Shale region primarily due to favorable commodity pricing;
•An $18 million decrease related to lower deferred revenue amortization primarily in the Barnett Shale region;
•A $9 million decrease due to the absence of a temporary volume deficiency fee from a customer in 2020; partially offset by
•A $36 million increase associated with higher MVC revenue, primarily in the Eagle Ford Shale and Wamsutter regions;
•An $11 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.
43
Management’s Discussion and Analysis (Continued)
Marketing margins increased by $122 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. Product margins from our equity NGLs increased $11 million, primarily due to higher net realized sales prices, partially offset by an increase in natural gas purchases associated with our equity NGLs and lower sales volumes.
Other segment costs and expenses increased primarily due to higher maintenance expenses including costs associated with the timing and scope of activities as well as higher reimbursable compressor power and fuel purchases which are offset in Service revenues. These increases are partially offset by lower operating expenses including costs related to fewer leased compressors.
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.
Other
Three Months Ended June 30,
Six Months Ended June 30,
2021
2020
2021
2020
(Millions)
Other Modified EBITDA
$
20
$
8
$
53
$
15
Three and six months ended June 30, 2021 vs. three and six months ended June 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 12 – Segment Disclosures of Notes to Consolidated Financial Statements. The year-to-date comparative period also includes the unfavorable impact of an accrual for a loss contingency in 2021.
44
Management’s Discussion and Analysis (Continued)
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.
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 12 – 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 13 – Subsequent Event of Notes to Consolidated Financial Statements).
During the first quarter of 2021, we issued $900 million of new long-term debt to fund the repayment of long-term debt maturing in 2021 and for general corporate purposes. As of June 30, 2021, we have approximately $2.1 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. In August 2021, we expect to early retire our $500 million of 4 percent senior unsecured notes that are scheduled to mature in November 2021.
Liquidity
Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 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
As of June 30, 2021, we have approximately $21.1 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.
45
Management’s Discussion and Analysis (Continued)
Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook.
As of June 30, 2021, we had a working capital deficit of $1.134 billion, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:
Available Liquidity
June 30, 2021
(Millions)
Cash and cash equivalents
$
1,201
Capacity available under our $4.5 billion credit facility, less amounts outstanding under our $4 billion commercial paper program (1)
4,500
$
5,701
(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 June 30, 2021. Through June 30, there was no amount outstanding under our commercial paper program and credit facility during 2021. At June 30, 2021, we were in compliance with the financial covenants associated with our credit facility.
Dividends
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 and June 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, and changed our Outlook from Positive to Stable.
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.
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Management’s Discussion and Analysis (Continued)
Sources (Uses) of Cash
The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented (see Notes to Consolidated Financial Statements for the Notes referenced in the table):
Cash Flow
Six Months Ended June 30,
Category
2021
2020
(Millions)
Sources of cash and cash equivalents:
Operating activities – net
Operating
$
1,972
$
1,930
Proceeds from long-term debt (see Note 8)
Financing
898
2,196
Proceeds from credit-facility borrowings
Financing
—
1,700
Uses of cash and cash equivalents:
Common dividends paid
Financing
(996)
(971)
Capital expenditures
Investing
(685)
(613)
Dividends and distributions paid to noncontrolling interests
Financing
(95)
(98)
Purchases of and contributions to equity-method investments
Investing
(44)
(66)
Payments of long-term debt
Financing
(11)
(1,526)
Payments on credit-facility borrowings
Financing
—
(1,700)
Other sources / (uses) – net
Financing and Investing
20
(8)
Increase (decrease) in cash and cash equivalents
$
1,059
$
844
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, and Impairment of equity-method investments. Our Net cash provided (used) by operating activities for the six months ended June 30, 2021, increased from the same period in 2020 primarily due to higher operating income (excluding noncash items as previously discussed) in 2021, partially offset by the net unfavorable changes in net operating working capital in 2021.
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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 six months of 2021.
Item 4. Controls and Procedures
Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Securities Exchange Act 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.
Changes in Internal Control Over Financial Reporting
There have been no changes during the second quarter of 2021 that have materially affected, or are reasonably likely to materially affect, our Internal Control over Financial Reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Environmental
Certain reportable legal proceedings involving governmental authorities under federal, state, and local laws regulating the discharge of materials into the environment are described below. While it is not possible for us to predict the final outcome of the proceedings 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,
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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 11 – Contingent Liabilities 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 9 – Stockholders’ Equity and Note 11 – Contingent Liabilities 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.
Item 5. Other Information
On July 28, 2021, our Board of Directors (the “Board”) approved amendments to the By-laws of The Williams Companies, Inc. (the “By-laws”), effective immediately. In addition to certain technical and conforming amendments, the amended By-laws, among other things:
Notice and Record Date Provisions
•Reflect certain changes in the General Corporation Law of the State of Delaware (the “DGCL”) to (i) allow the Board to set a record date for determining the stockholders entitled to vote at a stockholder meeting that is different than the record date for determining the stockholders entitled to notice of a stockholder meeting; (ii) provide for a record date for the stockholders entitled to vote at a stockholder meeting if the Board fails to establish one; (iii) provide for the record date for an adjourned stockholder meeting or allow the Board to reset the record date for an adjourned stockholder meeting; (iv) allow the Board to fix a record date for purpose of allowing us to determine the stockholders entitled to consent to a corporation action without a meeting; and (v) allow the Board to set a record date to allow us to determine the stockholders entitled to receive payment of any dividend or other distribution or allotment of any rights or the stockholders entitled to exercise any rights in respect of any change, conversion or exchange of stock or for the purpose of any other lawful action (Article V, Section 5);
•Update the notices required to be sent prior to a special or general stockholder meeting to provide that the notices shall include the record date for determining the stockholders entitled to vote at the meeting if that record date is different from the record date for determining stockholders entitled to notice (Article II, Sections 2);
•Clarify that our secretary shall send the notice of any special meetings (Article II, Section 3);
•Provide that for an adjourned annual or special meeting of stockholders, if adjournment is for more than 30 calendar days, or if after the adjournment a new record date for stockholders entitled to vote is fixed for the
49
adjourned meeting, a notice of the adjournment shall be given to stockholders entitled to vote at the adjourned meeting as of the record date fixed for the notice of the adjourned meeting (Article II, Section 5);
•Provide that if the record date for determining the stockholders entitled to vote is less than 10 days before the meeting date, the list of stockholders entitled to vote shall reflect the stockholders entitled to vote as of the tenth day before the meeting (Article II, Section 8);
•Specify the information the notice of any special Board meeting shall contain and to specify the delivery and timing requirements for the notice of any special Board meeting (Article III, Section 6);
•Reflect (i) certain definitional changes to the DGCL related to the transmission of notices; and (ii) provide for the delivery of notices to stockholders by electronic mail and facsimile under certain circumstances (Article VI, Section 1 and Article VII, Section 5).
Miscellaneous Updates
•Provide, among other things, the Board has the sole right to determine the time, date and place of a special meeting, including whether to allow the meeting by remote communication, and our secretary shall send a notice of the special meeting (Article II, Section 3);
•Clarify that to determine whether a quorum is present at a stockholder meeting, the standard is the majority of the voting power of the outstanding shares of capital stock entitled to vote at the annual or special stockholder meeting, except as otherwise provided by law or by the Certificate of Incorporation (Article II, Section 4);
•Clarify, among other things, that adjournment of a meeting by stockholders requires a majority of the voting power of our outstanding shares of capital stock that are present in person or represented by proxy at the meeting and entitled to vote (even though less than a quorum) (Article II, Section 5);
•Provide that a stockholder entitled to vote at any meeting of stockholders or to express consent or dissent to corporate action without a meeting may authorize up to three people to act for such stockholder as a proxy in accordance with Section 212 of the DGCL (Article II, Section 6);
•Delete duplicative provisions already contained in the Certificate of Incorporation pertaining to votes by a class of stockholders and one share equating to one vote (Article II, Section 6);
•Provide that the chair of the Board may designate someone to preside at a stockholder meeting (Article II, Section 7);
•Provide that a series of preferred stock may have a different voting standard for the election of a director (Article III, Section 1);
•Clarify that a majority of the directors of the Board may create a new directorship without a vacancy left by an existing director subject to the provisions of the Certificate of Incorporation (Article III, Section 2);
•Allow for the record of Board actions or consents to be in any format permitted by the DGCL, and provide that the record of actions as well as consents be filed with the minutes of the proceedings of the Board (Article III, Section 8);
•Clarify that a committee established by the Board may approve or recommend to the stockholders the election or removal of directors (Article III, Section 11).
The foregoing is only a summary of the changes made to the By-laws and is qualified in its entirety by reference to the full text of the By-laws, which is filed as Exhibit 3.4 to this Quarterly Report on Form 10-Q and is incorporated herein by reference.
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Exhibit No.
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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)
