QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2022
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
1
future operations, business prospects, outcomes of regulatory proceedings, market conditions, and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.
All statements, other than statements of historical facts, included in this report that address activities, events, or developments that we expect, believe, or anticipate will exist or may occur in the future are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “guidance,” “outlook,” “in-service date,” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:
•Levels of dividends to Williams stockholders;
•Future credit ratings of Williams and its affiliates;
•Amounts and nature of future capital expenditures;
•Expansion and growth of our business and operations;
•Expected in-service dates for capital projects;
•Financial condition and liquidity;
•Business strategy;
•Cash flow from operations or results of operations;
•Seasonality of certain business components;
•Natural gas, natural gas liquids, and crude oil prices, supply, and demand;
•Demand for our services;
•The impact of the coronavirus (COVID-19) pandemic.
Forward-looking statements are based on numerous assumptions, uncertainties, and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:
•Availability of supplies, market demand, and volatility of prices;
•Development and rate of adoption of alternative energy sources;
•The impact of existing and future laws and regulations, the regulatory environment, environmental matters, and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate proceeding outcomes;
•Our exposure to the credit risk of our customers and counterparties;
•Our ability to acquire new businesses and assets and successfully integrate those operations and assets into existing businesses as well as successfully expand our facilities, and to consummate asset sales on acceptable terms;
•Whether we are able to successfully identify, evaluate, and timely execute our capital projects and investment opportunities;
•The strength and financial resources of our competitors and the effects of competition;
2
•The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;
•Whether we will be able to effectively execute our financing plan;
•Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social, and governance practices;
•The physical and financial risks associated with climate change;
•The impacts of operational and developmental hazards and unforeseen interruptions;
•The risks resulting from outbreaks or other public health crises, including COVID-19;
•Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities;
•Acts of terrorism, cybersecurity incidents, and related disruptions;
•Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;
•Changes in maintenance and construction costs, as well as our ability to obtain sufficient construction-related inputs, including skilled labor;
•Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on customers and suppliers);
•Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally recognized credit rating agencies, and the availability and cost of capital;
•The ability of the members of the Organization of Petroleum Exporting Countries (OPEC) and other oil exporting nations to agree to and maintain oil price and production controls and the impact on domestic production;
•Changes in the current geopolitical situation, including the Russian invasion of Ukraine;
•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, 2021, as supplemented by the disclosure in Part II, Item 1A. Risk Factors in this Quarterly Report on Form 10-Q.
The following is a listing of certain abbreviations, acronyms, and other industry terminology that may be used throughout this Form 10-Q.
Measurements:
Barrel: One barrel of petroleum products that equals 42 U.S. gallons
Mbbls/d: One thousand barrels per day
Bcf: One billion cubic feet of natural gas
Bcf/d: One billion cubic feet of natural gas per day
MMcf/d: One million cubic feet per day
British Thermal Unit (Btu): A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit
MMbtu: One million British thermal units
Tbtu: One trillion British thermal units
Dekatherms (Dth): A unit of energy equal to one million British thermal units
Mdth/d: One thousand dekatherms per day
MMdth: One million dekatherms or approximately one trillion British thermal units
MMdth/d: One million dekatherms per day
Consolidated Entities:
BRMH: Blue Racer Midstream Holdings, LLC
Cardinal: Cardinal Gas Services, L.L.C.
Gulfstar One: Gulfstar One LLC
Northeast JV: Ohio Valley Midstream LLC
Northwest Pipeline: Northwest Pipeline LLC
Transco: Transcontinental Gas Pipe Line Company, LLC
Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of March 31, 2022, we account for as equity-method investments, including principally the following:
Exchange Act, the: Securities and Exchange Act of 1934, as amended
FERC: Federal Energy Regulatory Commission
IRS: Internal Revenue Service
SEC: Securities and Exchange Commission
Other:
EBITDA: Earnings before interest, taxes, depreciation, and amortization
Fractionation: The process by which a mixed stream of natural gas liquids is separated into constituent products, such as ethane, propane, and butane
GAAP: U.S. generally accepted accounting principles
LNG: Liquefied natural gas; natural gas which has been liquefied at cryogenic temperatures
MVC: Minimum volume commitments
NGLs: Natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are used as petrochemical feedstocks, heating fuels, and gasoline additives, among other applications
NGL margins:NGL revenues less any applicable Btu replacement cost, plant fuel, transportation, and fractionation
Sequent Acquisition: The July 1, 2021, acquisition of 100 percent of Sequent Energy Management, L.P. and Sequent Energy Canada, Corp.
Consolidated Statement of Comprehensive Income (Loss)
(Unaudited)
Three Months Ended March 31,
2022
2021
(Millions)
Net income (loss)
$
392
$
435
Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of ($1) in 2022 and $2 in 2021
3
(9)
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $— in 2022 and $— in 2021
—
2
Pension and other postretirement benefits:
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($1) in 2022 and ($1) in 2021
2
3
Other comprehensive income (loss)
5
(4)
Comprehensive income (loss)
397
431
Less: Comprehensive income (loss) attributable to noncontrolling interests
12
9
Comprehensive income (loss) attributable to The Williams Companies, Inc.
Intangible assets – net of accumulated amortization
7,278
7,402
Regulatory assets, deferred charges, and other
1,324
1,276
Total assets
$
46,049
$
47,612
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable
$
1,584
$
1,746
Accrued liabilities
1,099
1,201
Long-term debt due within one year
1,625
2,025
Total current liabilities
4,308
4,972
Long-term debt
20,801
21,650
Deferred income tax liabilities
2,570
2,453
Regulatory liabilities, deferred income, and other
4,399
4,436
Contingent liabilities and commitments (Note 12)
Equity:
Stockholders’ equity:
Preferred stock
35
35
Common stock ($1 par value; 1,470 million shares authorized at March 31, 2022 and December 31, 2021; 1,252 million shares issued at March 31, 2022 and 1,250 million shares issued at December 31, 2021)
1,252
1,250
Capital in excess of par value
24,476
24,449
Retained deficit
(13,378)
(13,237)
Accumulated other comprehensive income (loss)
(28)
(33)
Treasury stock, at cost (35 million shares of common stock)
(1,041)
(1,041)
Total stockholders’ equity
11,316
11,423
Noncontrolling interests in consolidated subsidiaries
Note 1 – General, Description of Business, and Basis of Presentation
General
Our accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with our consolidated financial statements and notes thereto for the year ended December 31, 2021, 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 our 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. Effective January 1, 2022, following an organizational realignment, our natural gas liquid (NGL) and natural gas marketing services, previously reported within the West segment, along with the former Sequent segment, are now all managed within the Gas & NGL Marketing Services segment. As a result, our operations are presented within the following reportable segments as of March 31, 2022: Transmission & Gulf of Mexico, Northeast G&P, West, and Gas & NGL Marketing Services, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. All remaining business activities, including our upstream operations, as well as corporate activities are included in Other. Prior period segment disclosures have been recast for the new segment presentation. Additionally, beginning in 2022 and concurrent with the integration of our legacy gas marketing operations and the marketing operations acquired in the Sequent Acquisition (see Note 3 – Acquisitions), all natural gas marketing revenues from Gas & NGL Marketing Services are presented net of the related costs of those activities in our Consolidated Statement of Income, as subsequent to the integration the entire natural gas marketing portfolio is considered held for trading purposes which requires net presentation.
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. (Gulfstream), 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), and Appalachia
Midstream Services, LLC, a wholly owned subsidiary that owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region (Appalachia Midstream Investments).
West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko and Permian basins. This segment also includes our NGL 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 (OPPL), 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).
Gas & NGL Marketing Services is comprised of our NGL and natural gas marketing and trading operations, which includes risk management and the storage and transportation of natural gas on strategically positioned assets, including our Transco system.
Basis of Presentation
Significant risks and uncertainties
We believe that the carrying value of certain of our property, plant, and equipment and 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 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 March 31, 2022, 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.
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. In accordance with the contract, future expansion activity is required to be funded with capital contributions from us and the other equity partner on a proportional basis.
The following table presents amounts included in our Consolidated Balance Sheet that are only for the use or obligation of our consolidated VIEs:
March 31, 2022
December 31, 2021
(Millions)
Assets (liabilities):
Cash and cash equivalents
$
116
$
78
Trade accounts and other receivables – net
104
132
Inventories
3
3
Other current assets and deferred charges
4
7
Property, plant, and equipment – net
5,237
5,295
Intangible assets – net of accumulated amortization
2,240
2,267
Regulatory assets, deferred charges, and other
23
20
Accounts payable
(50)
(61)
Accrued liabilities
(32)
(29)
Regulatory liabilities, deferred income, and other
(286)
(287)
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 March 31, 2022, the carrying value of our investment in Targa Train 7 was $47 million. Our maximum exposure to loss is limited to the carrying value of our investment.
Note 3 – Acquisitions
Sequent Acquisition
On July 1, 2021, we completed the acquisition of 100 percent of Sequent Energy Management, L.P. and Sequent Energy Canada, Corp (Sequent Acquisition). Total consideration for this acquisition was $159 million, which included $109 million related to working capital. The purpose of the Sequent Acquisition was to expand our natural gas marketing activities as well as optimize our pipeline and storage capabilities with expansions into new markets to reach incremental gas-fired power generation, liquified natural gas exports, and future renewable natural gas and other emerging opportunities.
The following unaudited pro forma Revenues and Net income (loss) attributable to The Williams Companies, Inc. for the three months ended March 31, 2021, are presented as if the Sequent Acquisition had been completed on January 1, 2020. These pro forma amounts are not necessarily indicative of what the actual results would have been if the Sequent Acquisition had in fact occurred on the date or for the periods indicated, nor do they purport to project Revenues or Net income (loss) attributable to The Williams Companies, Inc. for any future periods or as of any date. These amounts do not give effect to any potential cost savings, operating synergies, or revenue enhancements to result from the transaction or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements.
Net income (loss) attributable to The Williams Companies, Inc.
547
Seasonality can impact natural gas usage and operating results; thus, the results for the operations acquired in the Sequent Acquisition for interim periods are not necessarily indicative of annual results and can vary significantly from quarter to quarter. The results for the operations acquired in the Sequent Acquisition for the three months ended March 31, 2021, were favorably impacted by Winter Storm Uri.
During the period from the acquisition date of July 1, 2021 to December 31, 2021, results for the operations acquired in the Sequent Acquisition included net product sales of $(43) million (including $80 million of purchases from affiliates), net loss on commodity derivatives of $43 million, and unfavorable Modified EBITDA (as defined in Note 13 – Segment Disclosures) of $112 million. Both the Revenues and Modified EBITDA amounts reflect a net unrealized loss on commodity derivatives of $109 million for the period.
Costs related to the Sequent Acquisition for the period from the acquisition date of July 1, 2021 to December 31, 2021 were approximately $5 million and were included in Selling, general, and administrative expenses in our Consolidated Statement of Income for the year ended December 31, 2021.
The Sequent Acquisition was accounted for as a business combination, which requires, among other things, that identifiable assets acquired and liabilities assumed be recognized at their acquisition date fair values.
The following table presents the allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in the Gas & NGL Marketing Services segment, and liabilities assumed at July 1, 2021. The fair value of accounts receivable acquired equals contractual amounts receivable. The fair value of the intangible assets were measured using an income approach. The inventory acquired relates to natural gas in underground storage. The fair value of this inventory was based on the market price of the underlying commodity at the acquisition date. See Note 10 – Fair Value Measurements and Guarantees for the valuation techniques used to measure fair value of derivative assets and liabilities.
(Millions)
Cash and cash equivalents
$
8
Trade accounts and other receivables – net
498
Inventories
121
Other current assets and deferred charges
4
Commodity derivatives included in other current assets and deferred charges
57
Property, plant, and equipment – net
5
Intangible assets
306
Regulatory assets, deferred charges, and other
3
Commodity derivatives included in regulatory assets, deferred charges, and other
49
Total assets acquired
$
1,051
Accounts payable
$
514
Accrued liabilities
46
Commodity derivatives included in accrued liabilities
116
Regulatory liabilities, deferred income, and other
1
Commodity derivatives included in regulatory liabilities, deferred income, and other
Intangible assets are primarily related to transportation and storage capacity contracts. The basis for determining the value of these intangible assets was estimated future net cash flows to be derived from acquired transportation and storage capacity contracts that provide future economic benefits due to their market location, discounted using an industry weighted-average cost of capital. This intangible asset is being amortized based on the expected benefit period over which the underlying contracts are expected to contribute to our cash flows ranging from 1 year to 8 years. As a result, we expect a significant portion of the amortization to be recognized within the first few years of this range.
The following table presents our revenue disaggregated by major service line:
Transco
Northwest Pipeline
Gulf of Mexico Midstream
Northeast Midstream
West Midstream
Gas & NGL Marketing Services
Other
Eliminations
Total
(Millions)
Three Months Ended March 31, 2022
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage
$
665
$
113
$
—
$
—
$
—
$
—
$
—
$
(18)
$
760
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration
—
—
82
323
317
—
—
(30)
692
Commodity consideration
—
—
21
7
49
—
—
—
77
Other
2
—
6
51
12
1
—
(6)
66
Total service revenues
667
113
109
381
378
1
—
(54)
1,595
Product sales
16
—
87
36
187
2,470
104
(393)
2,507
Total revenues from contracts with customers
683
113
196
417
565
2,471
104
(447)
4,102
Other revenues (1)
3
1
2
6
(3)
1,615
(65)
(3)
1,556
Other adjustments (2)
—
—
—
—
—
(3,232)
—
98
(3,134)
Total revenues
$
686
$
114
$
198
$
423
$
562
$
854
$
39
$
(352)
$
2,524
Three Months Ended March 31, 2021
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage
$
625
$
113
$
—
$
—
$
—
$
—
$
—
$
(3)
$
735
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration
—
—
86
311
269
—
—
(28)
638
Commodity consideration
—
—
11
3
35
—
—
—
49
Other
3
—
3
41
19
1
—
(5)
62
Total service revenues
628
113
100
355
323
1
—
(36)
1,484
Product sales
14
—
53
32
150
1,088
56
(248)
1,145
Total revenues from contracts with customers
642
113
153
387
473
1,089
56
(284)
2,629
Other revenues (1)
2
—
2
6
3
(34)
7
(3)
(17)
Total revenues
$
644
$
113
$
155
$
393
$
476
$
1,055
$
63
$
(287)
$
2,612
______________________________
(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 our Consolidated Statement of Income, and realized and unrealized gains and losses associated with our derivative contracts, which are reported in Net gain (loss) on commodity derivativesin our Consolidated Statement of Income.
(2)Other adjustments reflect certain costs of Gas & NGL Marketing Services’ risk management activities. As we are acting as agent for natural gas marketing customers, the resulting revenues are presented net of the related costs of those activities in our Consolidated Statement of Income. In addition, the related derivatives qualify as held for trading purposes, which requires net presentation. (See Note 1 – General, Description of Business, and Basis of Presentation.)
Contract Assets
The following table presents a reconciliation of our contract assets:
Three Months Ended March 31,
2022
2021
(Millions)
Balance at beginning of period
$
22
$
12
Revenue recognized in excess of amounts invoiced
55
45
Minimum volume commitments invoiced
(41)
(32)
Balance at end of period
$
36
$
25
Contract Liabilities
The following table presents a reconciliation of our contract liabilities:
Three Months Ended March 31,
2022
2021
(Millions)
Balance at beginning of period
$
1,126
$
1,209
Payments received and deferred
29
13
Significant financing component
2
3
Recognized in revenue
(64)
(54)
Balance at end of period
$
1,093
$
1,171
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 (MVC) 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 March 31, 2022, 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 March 31, 2022, that will be recognized in future periods is also excluded from our remaining performance obligations and is instead reflected in contract liabilities.
The following table presents the amount of the contract liabilities balance expected to be recognized as revenue when performance obligations are satisfied and the transaction price allocated to the remaining performance obligations under certain contracts as of March 31, 2022.
Contract Liabilities
Remaining Performance Obligations
(Millions)
2022 (nine months)
$
98
$
2,683
2023 (one year)
120
3,386
2024 (one year)
119
3,152
2025 (one year)
114
2,623
2026 (one year)
110
2,395
Thereafter
532
17,027
Total
$
1,093
$
31,266
Accounts Receivable
The following is a summary of our Trade accounts and other receivables – net:
March 31, 2022
December 31, 2021
(Millions)
Accounts receivable related to revenues from contracts with customers
$
1,426
$
1,451
Receivables from derivatives
489
462
Other accounts receivable
58
65
Trade accounts and other receivables – net
$
1,973
$
1,978
Note 5 – Provision (Benefit) for Income Taxes
The Provision (benefit) for income taxes includes:
Three Months Ended March 31,
2022
2021
(Millions)
Current:
Federal
$
1
$
(2)
State
2
(1)
3
(3)
Deferred:
Federal
94
115
State
21
29
115
144
Provision (benefit) for income taxes
$
118
$
141
The effective income tax rates for the total provision (benefit) for both the three months ended March 31, 2022 and 2021 are greater than the federal statutory rate, primarily due to the effect of state income taxes.
It is reasonably possible that the total amount of unrecognized tax benefits will significantly decrease by the end of 2022 due to the resolution of audits related to U.S. federal tax positions.
(Dollars in millions, except per-share amounts; shares in thousands)
Net income (loss) available to common stockholders
$
379
$
425
Basic weighted-average shares
1,216,940
1,214,646
Effect of dilutive securities:
Nonvested restricted stock units
4,128
2,565
Stock options
211
—
Diluted weighted-average shares
1,221,279
1,217,211
Earnings (loss) per common share:
Basic
$
.31
$
.35
Diluted
$
.31
$
.35
Note 7 – Employee Benefit Plans
Net periodic benefit cost (credit) is as follows:
Pension Benefits
Three Months Ended March 31,
2022
2021
(Millions)
Components of net periodic benefit cost (credit):
Service cost
$
7
$
8
Interest cost
7
7
Expected return on plan assets
(11)
(11)
Amortization of net actuarial loss
3
4
Net periodic benefit cost (credit)
$
6
$
8
Other Postretirement Benefits
Three Months Ended March 31,
2022
2021
(Millions)
Components of net periodic benefit cost (credit):
Interest cost
$
1
$
1
Expected return on plan assets
(2)
(2)
Reclassification to regulatory liability
—
1
Net periodic benefit cost (credit)
$
(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 our Consolidated Statement of Income.
On January 18, 2022, we early retired $1.25 billion of 3.6 percent senior unsecured notes due March 15, 2022.
Commercial Paper Program
At March 31, 2022, no commercial paper was outstanding under our $3.5 billion commercial paper program.
Credit Facility
March 31, 2022
Stated Capacity
Outstanding
(Millions)
Long-term credit facility (1)
$
3,750
$
—
Letters of credit under certain bilateral bank agreements
16
(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
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, 2021
$
(2)
$
(1)
$
(30)
$
(33)
Other comprehensive income (loss) before reclassifications
3
—
—
3
Amounts reclassified from accumulatedother comprehensive income (loss)
—
—
2
2
Other comprehensive income (loss)
3
—
2
5
Balance at March 31, 2022
$
1
$
(1)
$
(28)
$
(28)
Reclassifications out of AOCI are presented in the following table by component for the three months ended March 31, 2022:
Component
Reclassifications
Classification
(Millions)
Pension and other postretirement benefits:
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit)
$
3
Other income (expense) – net below Operating income (loss)
The following table presents, by level within the fair value hierarchy, certain of our significant financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.
Fair Value Measurements Using
Carrying Amount
Fair Value
Quoted Prices In Active Markets for Identical Assets (Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs (Level 3)
(Millions)
Assets (liabilities) at March 31, 2022:
Measured on a recurring basis:
ARO Trust investments
$
250
$
250
$
250
$
—
$
—
Commodity derivative assets (1)
81
81
33
47
1
Commodity derivative liabilities (1)
(600)
(600)
(127)
(461)
(12)
Additional disclosures:
Long-term debt, including current portion
(22,426)
(24,301)
—
(24,301)
—
Guarantees
(39)
(26)
—
(10)
(16)
Assets (liabilities) at December 31, 2021:
Measured on a recurring basis:
ARO Trust investments
$
260
$
260
$
260
$
—
$
—
Commodity derivative assets (2)
84
84
2
81
1
Commodity derivative liabilities (2)
(488)
(488)
(69)
(403)
(16)
Additional disclosures:
Long-term debt, including current portion
(23,675)
(27,768)
—
(27,768)
—
Guarantees
(39)
(26)
—
(10)
(16)
(1)Excludes approximately $187 million of net cash collateral in Level 1.
(2)Excludes approximately $296 million of net cash collateral in Level 1.
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 our Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.
Commodity derivatives: Commodity derivatives include exchange-traded contracts and over-the-counter (OTC) contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis.
We also have other derivatives related to asset management agreements and other contracts that require physical delivery. Derivatives classified as Level 1 are valued using New York Mercantile Exchange (NYMEX) futures prices. Derivatives classified as Level 2 are valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers. Derivatives classified as Level 3 are valued using a combination of observable and unobservable inputs. Beginning in the third quarter of 2021 the fair value amounts are presented on a net basis and reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements and cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Commodity derivative assets are reported in Other current assets and deferred charges and Regulatory assets, deferred charges, and other in our Consolidated Balance Sheet. Commodity derivative liabilities are reported in Accrued liabilities and Regulatory liabilities, deferred income, and other in our Consolidated Balance Sheet. See Note 11 – Derivatives for additional information on our derivatives.
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, Leidy South, and Atlantic Sunrise projects, which are included within long-term debt, were determined using an income approach.
Guarantees: Guarantees primarily consist of a guarantee we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on a lease performance obligation that extends through 2042. Guarantees also include an indemnification related to a disposed operation.
To estimate the fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying value of the WilTel guarantee is reported in Accrued liabilities in our Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately $25 millionat March 31, 2022. 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 our 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.
Note 11 – Derivatives
Commodity-Related Derivatives
We are exposed to commodity price risk. To manage this volatility, we use various contracts in our marketing and trading activities that generally meet the definition of derivatives. Derivative positions are monitored using techniques including, but not limited to value at risk. Derivative instruments are recognized at fair value in our Consolidated Balance Sheet as either assets or liabilities and are presented on a net basis by counterparty, net of margin deposits. See Note 10 – Fair Value Measurements and Guarantees for additional fair value information. In
our Consolidated Statement of Cash Flows, any cash impacts of settled commodity-related derivatives are recorded as operating activities.
We enter into commodity-related derivatives to economically hedge exposures to natural gas, NGLs, and crude oil and retain exposure to price changes that can, in a volatile energy market, be material and can adversely affect our results of operations.
At March 31, 2022, the notional volume of the net long (short) positions for our commodity derivative contracts were as follows:
Commodity
Unit of Measure
Net Long (Short) Position
Sequent Acquisition (1)
Natural Gas
MMBtu
661,224,762
Central Hub Risk - Mont Belvieu
Natural Gas Liquids
Barrels
(2,205,000)
Basis Risk
Natural Gas Liquids
Barrels
(17,504,000)
Central Hub Risk - Henry Hub
Natural Gas
MMBtu
49,036,730
Basis Risk
Natural Gas
MMBtu
43,098,730
Central Hub Risk - WTI
Crude Oil
Barrels
(459,000)
_______________
(1)Derivative instruments include both long and short natural gas positions. The volume represents the net of long natural gas positions of 3.7 billion MMBtu (million British thermal units) and short natural gas positions of 3.1 billion MMBtu.
Derivative Financial Statement Presentation
The fair value of commodity-related derivatives, which are not designated as hedging instruments for accounting purposes, was reflected in our Consolidated Balance Sheet as follows:
March 31, 2022
December 31, 2021
Derivative Category
Assets
(Liabilities)
Assets
(Liabilities)
(Millions)
Current
$
657
$
(954)
$
619
$
(760)
Noncurrent
204
(426)
166
(429)
Total derivatives
$
861
$
(1,380)
$
785
$
(1,189)
Gross amounts recognized
$
861
$
(1,380)
$
785
$
(1,189)
Counterparty and collateral netting offset
(716)
903
(476)
772
Amounts recognized in our Consolidated Balance Sheet
For the three months ended March 31, 2022 and 2021 the pre-tax effects of commodity-related derivatives instrumentsin Net gain (loss) on commodity derivatives in our Consolidated Statement of Income were as follows:
Gain (Loss)
Three Months Ended March 31,
2022
2021
(Millions)
Realized commodity-related derivatives designated as hedging instruments
$
—
$
(2)
Realized commodity-related derivatives not designated as hedging instruments
(69)
(34)
Unrealized commodity-related derivative instruments not designated as hedging instruments (1)
(125)
—
Net gain (loss) on commodity derivatives
$
(194)
$
(36)
_______________
(1)Amounts for the three months ended March 31, 2022 include $59 million related to our Gas & NGL Marketing Services segment and $66 million related to our Other segment.
Contingent Features
Generally, collateral may be provided by a parent guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are offset against fair value amounts recognized for derivatives executed with the same counterparty.
We have specific trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, we would need to post collateral to continue transacting business with these counterparties. As of March 31, 2022 the contractually required collateral in the event of a credit rating downgrade to non-investment grade status was $32 million.
We maintain accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, we may be required to deposit cash into these accounts. At March 31, 2022, net cash collateral held on deposit in broker margin accounts was $187 million.
Note 12 – Contingent Liabilities
Reporting of Natural Gas-Related Information to Trade Publications
Direct and indirect purchasers of natural gas in various states filed individual and putative class actions against us, our former affiliate WPX Energy, Inc. (WPX) and its subsidiaries, and others alleging the manipulation of published gas price indices in 2000 and 2002 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.
We reached an agreement to settle two of the class actions, and on August 5, 2019, the final judgment of dismissal with prejudice was entered. We also reached an agreement to settle the individual action and on January 18, 2022, it was dismissed.
Two putative class actions remain unresolved, and they have been remanded to their originally filed court, the Wisconsin federal district court where the plaintiffs have re-urged their motion for class certification. On March 30, 2017, the Nevada federal district 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 plaintiff’s 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, where the plaintiffs re-urged their motion for class certification.
Trial was scheduled to begin June 14, 2021, but the court struck the setting and has not reset it due to the pending motion for class certification.
Because of the uncertainty around the remaining unresolved issues, we cannot reasonably estimate a range of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of these actions and our related indemnification obligation could result in a potential loss that may be material to our results of operations. In connection with this indemnification, we have an accrued liability balance associated with this matter and have exposure to future developments.
Alaska Refinery Contamination Litigation
We are involved in litigation arising from our ownership and operation of the North Pole Refinery in North Pole, Alaska, from 1980 until 2004, through our wholly owned subsidiaries Williams Alaska Petroleum Inc. (WAPI) and MAPCO Inc. We sold the refinery to Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., in 2004. The litigation involves three cases, with filing dates ranging from 2010 to 2014. The actions primarily arise from sulfolane contamination allegedly emanating from the refinery. A putative class action lawsuit was filed by James West in 2010 naming us, WAPI, and FHRA as defendants. We and FHRA filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination. In 2011, we and FHRA settled the claim with James West. Certain claims by FHRA against us were resolved by the Alaska Supreme Court in our favor. FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-site sulfolane were remanded to the Alaska Superior Court. The State of Alaska filed its action in March 2014, seeking damages. The City of North Pole (North Pole) filed its lawsuit in November 2014, seeking past and future damages, as well as punitive damages. Both we and WAPI asserted counterclaims against the State of Alaska and North Pole, and cross-claims against FHRA. FHRA has also filed cross-claims against us.
The underlying factual basis and claims in the cases are similar and may duplicate exposure. As such, in February 2017, the three cases were consolidated into one action in state court containing the remaining claims from the James West case and those of the State of Alaska and North Pole. The State of Alaska later announced the discovery of additional contaminants per- and polyfluoralkyl (PFOS and PFOA) offsite of the refinery, and the court permitted the State of Alaska to amend its complaint to add a claim for offsite PFOS/PFOA contamination. The court subsequently remanded the offsite PFOS/PFOA claims to the Alaska Department of Environmental Conservation for investigation and stayed the claims pending their potential resolution at the administrative agency. Several trial dates encompassing all three cases have been scheduled and stricken. In the summer of 2019, the court deconsolidated the cases for purposes of trial. A bench trial on all claims except North Pole’s claims began in October 2019.
In January 2020, the Alaska Superior Court issued its Memorandum of Decision finding in favor of the State of Alaska and FHRA, with the total incurred and potential future damages estimated to be $86 million. The court found that FHRA is not entitled to contractual indemnification from us because FHRA contributed to the sulfolane contamination. On March 23, 2020, the court entered final judgment in the case. Filing deadlines were stayed until May 1, 2020. However, on April 21, 2020, we filed a Notice of Appeal. We also filed post-judgment motions including a Motion for New Trial and a Motion to Alter or Amend the Judgment. These post-trial motions were resolved with the court’s denial of the last motion on June 11, 2020. Our Statement of Points on Appeal was filed on July 13, 2020. On June 22, 2020, the court stayed the North Pole’s case pending resolution of the appeal in the State of Alaska and FHRA case. On December 23, 2020, we filed our opening brief on appeal. Oral argument was held on December 15, 2021. We have recorded an accrued liability in the amount of our estimate of the probable loss. It is reasonably possible that we may not be successful on appeal and could ultimately pay up to the amount of judgment.
Royalty Matters
Certain of our customers, including Chesapeake Energy Corporation (Chesapeake), have been named in various lawsuits alleging underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases filed in Pennsylvania based on allegations that we improperly participated with Chesapeake in causing the
alleged royalty underpayments. We believe that the claims asserted are subject to indemnity obligations owed to us by Chesapeake. Chesapeake has reached a settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement applies to both Chesapeake and us. The settlement does not require any contribution from us. On August 23, 2021, the court approved the settlement, but two objectors filed an appeal with the United States Court of Appeals for the Fifth Circuit.
Litigation Against Energy Transfer and Related Parties
On April 6, 2016, we filed suit in Delaware Chancery Court against Energy Transfer Equity, L.P. (Energy Transfer) and LE GP, LLC (the general partner for Energy Transfer) alleging willful and material breaches of the Agreement and Plan of Merger (ETE Merger Agreement) with Energy Transfer resulting from the private offering by Energy Transfer on March 8, 2016, of Series A Convertible Preferred Units (Special Offering) to certain Energy Transfer insiders and other accredited investors. The suit seeks, among other things, an injunction ordering the defendants to unwind the Special Offering and to specifically perform their obligations under the ETE Merger Agreement. On April 19, 2016, we filed an amended complaint seeking the same relief. On May 3, 2016, Energy Transfer and LE GP, LLC filed an answer and counterclaims.
On May 13, 2016, we filed a separate complaint in Delaware Chancery Court against Energy Transfer, LE GP, LLC and the other Energy Transfer affiliates that are parties to the ETE Merger Agreement, alleging material breaches of the ETE Merger Agreement for failing to cooperate and use necessary efforts to obtain a tax opinion required under the ETE Merger Agreement (Tax Opinion) and for otherwise failing to use necessary efforts to consummate the merger under the ETE Merger Agreement wherein we would be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger). The suit sought, among other things, a declaratory judgment and injunction preventing Energy Transfer from terminating or otherwise avoiding its obligations under the ETE Merger Agreement due to any failure to obtain the Tax Opinion.
The Court of Chancery coordinated the Special Offering and Tax Opinion suits. On May 20, 2016, the Energy Transfer defendants filed amended affirmative defenses and verified counterclaims in the Special Offering and Tax Opinion suits, alleging certain breaches of the ETE Merger Agreement by us and seeking, among other things, a declaration that we were not entitled to specific performance, that Energy Transfer could terminate the ETC Merger, and that Energy Transfer is entitled to a $1.48 billion termination fee. On June 24, 2016, following a two-day trial, the court issued a Memorandum Opinion and Order denying our requested relief in the Tax Opinion suit. The court did not rule on the substance of our claims related to the Special Offering or on the substance of Energy Transfer’s counterclaims. On June 27, 2016, we filed an appeal of the court’s decision with the Supreme Court of Delaware, seeking reversal and remand to pursue damages. On March 23, 2017, the Supreme Court of Delaware affirmed the Court of Chancery’s ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied on April 5, 2017.
On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the ETE Merger Agreement by defendants. On September 23, 2016, Energy Transfer filed a second amended and supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things, payment of the $1.48 billion termination fee due to our alleged breaches of the ETE Merger Agreement. On December 1, 2017, the court granted our motion to dismiss certain of Energy Transfer’s counterclaims, including its claim seeking payment of the $1.48 billion termination fee. On December 8, 2017, Energy Transfer filed a motion for reargument, which the Court of Chancery denied on April 16, 2018. The Court of Chancery originally scheduled trial for May 20 through May 24, 2019; the court struck that setting and reset trial to occur in 2020. All 2020 trial settings were struck due to COVID-19. Trial was held May 10 through May 17, 2021. Post-trial argument occurred September 16, 2021. On December 29, 2021, the court entered judgment in our favor in the amount of $410 million, plus interest at the contractual rate, and our reasonable attorneys’ fees and expenses. The judgment may be appealed to the Delaware Supreme Court.
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 March 31, 2022, we have accrued liabilities totaling $30 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 March 31, 2022, 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 propose and promulgate 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, reviews and updates to the National Ambient Air Quality Standards, and rules for new and existing source performance standards for volatile organic compound and methane. We continuously monitor these regulatory changes and how they may impact our operations. Implementation of new or modified regulations may result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in our Consolidated Balance Sheet for both new and existing facilities in affected areas; however, due to regulatory uncertainty on final rule content and applicability timeframes, we are unable to reasonably estimate the cost of these regulatory impacts at this time.
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 March 31, 2022, we have accrued liabilities of $4 million for these costs. We expect that these costs will be recoverable through rates.
We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At March 31, 2022, 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 March 31, 2022, we have accrued environmental liabilities of $18 million related to these matters.
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 March 31, 2022, 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 13 – Segment Disclosures
Our reportable segments are Transmission & Gulf of Mexico, Northeast G&P, West, and Gas & NGL Marketing Services. All remaining business activities are included in Other. (See Note 1 – General, Description of Business, and Basis of Presentation.)
Performance Measurement
We evaluate segment operating performance based upon Modified EBITDA. 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);
◦Other investing income (loss) – net;
◦Depreciation and amortization expenses;
◦Accretion expense associated with asset retirement obligations for nonregulated operations.
•This measure is further adjusted to include our proportionate share (based on ownership interest) of Modified EBITDA from our equity-method investments calculated consistently with the definition described above.
The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in our Consolidated Statement of Income.
Three Months Ended March 31,
2022
2021
(Millions)
Modified EBITDA by segment:
Transmission & Gulf of Mexico
$
697
$
660
Northeast G&P
418
402
West
260
222
Gas & NGL Marketing Services
13
93
Other
5
33
1,393
1,410
Accretion expense associated with asset retirement obligations for nonregulated operations
(11)
(10)
Depreciation and amortization expenses
(498)
(438)
Equity earnings (losses)
136
131
Other investing income (loss) – net
1
2
Proportional Modified EBITDA of equity-method investments
The following table reflects the reconciliation of Segment revenues to Total revenues as reported in our Consolidated Statement of Income and Total assets by reportable segment.
Transmission & Gulf of Mexico
Northeast G&P
West
Gas & NGL Marketing Services (1)
Other
Eliminations
Total
(Millions)
Three Months Ended March 31, 2022
Segment revenues:
Service revenues
External
$
845
$
370
$
316
$
1
$
5
$
—
$
1,537
Internal
29
10
15
—
4
(58)
—
Total service revenues
874
380
331
1
9
(58)
1,537
Total service revenues – commodity consideration
21
7
49
—
—
—
77
Product sales
External
51
5
11
1,015
22
—
1,104
Internal
49
31
176
(47)
82
(291)
—
Total product sales
100
36
187
968
104
(291)
1,104
Net gain (loss) on commodity derivatives (2)
—
—
(5)
(115)
(74)
—
(194)
Total revenues
$
995
$
423
$
562
$
854
$
39
$
(349)
$
2,524
Three Months Ended March 31, 2021
Segment revenues:
Service revenues
External
$
822
$
347
$
278
$
1
$
4
$
—
$
1,452
Internal
12
11
13
—
3
(39)
—
Total service revenues
834
358
291
1
7
(39)
1,452
Total service revenues – commodity consideration
11
3
35
—
—
—
49
Product sales
External
40
4
15
1,039
49
—
1,147
Internal
27
28
137
49
7
(248)
—
Total product sales
67
32
152
1,088
56
(248)
1,147
Net gain (loss) on commodity derivatives (2)
—
—
(2)
(34)
—
—
(36)
Total revenues
$
912
$
393
$
476
$
1,055
$
63
$
(287)
$
2,612
March 31, 2022
Total assets
$
20,698
$
15,145
$
10,479
$
2,258
$
2,009
$
(4,540)
$
46,049
December 31, 2021
Total assets
$
20,394
$
14,939
$
10,330
$
2,127
$
2,991
$
(3,169)
$
47,612
______________
(1) See Note 1 – General, Description of Business, and Basis of Presentation.
(2) We record transactions that qualify as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are presented on a net basis in revenue.
In April 2022, we completed the acquisition of 100 percent of Gemini Arklatex, LLC through which we acquired the gas gathering and related assets of Trace Midstream, located in the Haynesville Shale region (Trace Acquisition), for approximately $950 million funded with available sources of short-term liquidity, subject to working capital and post-closing adjustments. The purpose of the Trace Acquisition was to expand our footprint into the East Texas region of the Haynesville Shale region, increasing in-basin scale in one of the largest growth basins in the country, and to advance our clean energy strategy. The transaction closed on April 29, 2022. Due to the timing, the initial purchase price accounting for the transaction was not yet complete at the time of filing.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
We are an energy company committed to being the leader in providing infrastructure that safely delivers natural gas products to reliably fuel the clean energy economy. 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. The rates are established primarily through the FERC’s ratemaking process, but we also may negotiate rates with our customers pursuant to the terms of our tariffs and FERC policy. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.
The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers. These services include natural gas gathering, processing, treating, and compression, NGL fractionation and transportation, crude oil production handling and transportation, marketing services for NGL, crude oil and natural gas, as well as storage facilities.
Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are conducted, managed, and presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, West, and Gas & NGL Marketing Services. All remaining business 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, 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 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, LLC.
•Gas & NGL Marketing Services includes our NGL and natural gas marketing and trading operations previously reported within the West segment prior to January 1, 2022, as well as the operations acquired in the Sequent Acquisition in 2021. This segment includes risk management and the storage and transportation of natural gas on strategically positioned assets, including our Transco system.
In March 2022, we paid a regular quarterly dividend of $0.425 per share.
Overview of Three Months Ended March 31, 2022
Net income (loss) attributable to The Williams Companies, Inc., for the three months ended March 31, 2022, decreased $46 millioncompared to the three months ended March 31, 2021, reflecting the benefit of higher service revenues from commodity-based gathering and processing rates in the West and Transco’s Leidy South project placed in service during the second half of 2021, higher commodity margins, and higher results from our upstream operations associated with increased scale of operations, more than offset by a $123 million net unrealized loss on commodity derivatives, the absence of a $77 million favorable impact in 2021 from Winter Storm Uri, and increased intangible asset amortization and selling, general, and administrative expenses, primarily resulting from the Sequent Acquisition.
Our results include $123 million of net unrealized losses from commodity derivatives not designated as hedges for accounting purposes. We can experience significant earnings volatility from the fair value accounting required for the derivatives used to hedge a portion of the economic value of the underlying transportation and storage marketing portfolio as well as upstream related production. However, the unrealized fair value measurement gains and losses are generally offset by valuation changes in the economic value of the underlying production or contracts, which is not recognized until the underlying transaction occurs.
The following discussion and analysis of results of operations and financial condition and liquidity should be read in conjunction with our consolidated financial statements and notes thereto of this Form 10‑Q and our Annual Report on Form 10-K dated February 28, 2022.
Recent Developments
Trace Acquisition
In April 2022, we completed the acquisition of 100 percent of Gemini Arklatex, LLC through which we acquired the gas gathering and related assets of Trace Midstream, located in the Haynesville Shale region (Trace Acquisition), for approximately $950 million, subject to working capital and post-closing adjustments. The purpose of the Trace Acquisition was to expand our footprint into the East Texas region of the Haynesville Shale region, increasing in-basin scale in one of the largest growth basins in the country, and to advance our clean energy strategy. The transaction closed on April 29, 2022.
Company Outlook
Our strategy is to provide a large-scale, reliable, and clean 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 including seeking opportunities for renewable energy ventures, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe, reliable, clean energy services to our customers and an attractive return to our shareholders. Our business plan for 2022 includes a continued focus on earnings and cash flow growth.
In 2022, our operating results are expected to benefit from higher commodity prices and volume growth in our Haynesville, Ohio Valley Midstream, and Cardinal areas. We also anticipate increases resulting from recently completed Transco expansion projects, development of our upstream oil and gas properties, and our recently completed Trace Acquisition. These increases are partially offset by the absence of favorable results captured during Winter Storm Uri in 2021 by our Gas & NGL Marketing Services business and lower expected results in the Bradford Supply Hub primarily due to lower gathering rates resulting from annual cost of service contract redetermination.
We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of safe, clean, and reliable energy infrastructure assets that continue to serve key growth markets and supply basins in the United States. Our growth capital and investment expenditures in 2022 are expected to be in a range from $2.25 billion to $2.35 billion. Growth capital spending in 2022 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business, the Trace Acquisition, and an expansion in the Western Gulf area. We also expect to invest capital in the development of our upstream oil and gas properties. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.
Potential risks and obstacles that could impact the execution of our plan include:
•Continued negative impacts of COVID-19 driving a global recession, which could result in downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products;
•Opposition to, and 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 industry downturns, including increased inflation and 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, 2021, as filed with the SEC on February 28, 2022, as supplemented by the disclosure in Part II, Item 1A. Risk Factors in this Quarterly Report on Form 10-Q.
Expansion Projects
Our ongoing major expansion projects include the following:
Transmission & Gulf of Mexico
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 2024, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 829 Mdth/d.
The following table and discussion is a summary of our consolidated results of operations for the three months ended March 31, 2022, compared to the three months ended March 31, 2021. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
Three Months Ended March 31,
2022
2021
$ Change*
% Change*
(Millions)
Revenues:
Service revenues
$
1,537
$
1,452
+85
+6
%
Service revenues – commodity consideration
77
49
+28
+57
%
Product sales
1,104
1,147
-43
-4
%
Net gain (loss) on commodity derivatives
(194)
(36)
-158
NM
Total revenues
2,524
2,612
Costs and expenses:
Product costs
803
932
+129
+14
%
Processing commodity expenses
30
21
-9
-43
%
Operating and maintenance expenses
394
360
-34
-9
%
Depreciation and amortization expenses
498
438
-60
-14
%
Selling, general, and administrative expenses
154
123
-31
-25
%
Other (income) expense – net
(9)
(1)
+8
NM
Total costs and expenses
1,870
1,873
Operating income (loss)
654
739
Equity earnings (losses)
136
131
+5
+4
%
Other investing income (loss) – net
1
2
-1
-50
%
Interest expense
(286)
(294)
+8
+3
%
Other income (expense) – net
5
(2)
+7
NM
Income (loss) before income taxes
510
576
Less: Provision (benefit) for income taxes
118
141
+23
+16
%
Net income (loss)
392
435
Less: Net income (loss) attributable to noncontrolling interests
12
9
-3
-33
%
Net income (loss) attributable to The Williams Companies, Inc.
$
380
$
426
* + = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.
Three months ended March 31, 2022 vs. three months ended March 31, 2021
Service revenues increased primarily due to higher gathering and processing rates driven by favorable commodity prices and annual contractual rate escalations for certain of our West and Northeast operations as well as higher transportation fee revenues associated with the Leidy South expansion project placed in service at Transco in the second half of 2021.
Service revenues – commodity consideration increased primarily due to higher NGL prices. These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services
provided. Most of these NGL volumes are sold during the month processed and therefore are offset within Product costs below.
Product sales decreased primarily due to the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs (see Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements) and lower gas marketing sales prices related to the absence of severe winter weather in 2022 as compared to the first quarter of 2021. These decreases were partially offset by higher marketing sales volumes of NGLs and natural gas, including the increase associated with the Sequent Acquisition in third-quarter 2021, higher sales associated with our upstream operations presented in our Other segment, and higher sales prices related to our equity NGL sales activities. As we are acting as agent for natural gas marketing customers of our Gas & NGL Marketing Services segment, our natural gas marketing product sales are presented net of the related costs of those activities.
Net gain (loss) on commodity derivatives includes realized and unrealized gains and losses from derivative instruments. The unfavorable change primarily reflects net realized and unrealized losses in our Other and Gas & NGL Marketing Services segments.
Product costs decreased primarily due to the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs. These decreases were partially offset by higher prices and volumes for our NGL marketing activities, as well as higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production activities.
The net sum of Service revenues – commodity consideration, Product sales, Product costs,Processing commodity expenses, and net realized gains and losses on commodity derivatives related to sales of product comprise our commodity margins. However, Product sales at our Other segment reflect sales related to our upstream operations and are excluded from our commodity margins.
Operating and maintenance expenses increased primarily due to increased costs associated with Transco's Leidy South expansion project placed in service in 2021 and higher expenses associated with our upstream operations.
Depreciation and amortization expenses increased primarily due to amortization of intangibles acquired in the Sequent Acquisition and an increase in depreciation at Transco related to ARO revisions (offset in Other (income) expense – net within Operating income (loss) resulting in no net impact on our results of operations).
Selling, general, and administrative expenses increased primarily due to higher employee-related expenses associated with the Sequent Acquisition.
Other (income) expense – net within Operating income (loss) changed favorably primarily due to the deferral of ARO depreciation (offset in Depreciation and amortization expenses resulting in no net impact on our results of operations).
Provision (benefit) for income taxes changed favorably primarily due to lower 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.
Period-Over-Period Operating Results - Segments
We evaluate segment operating performance based upon Modified EBITDA. Note 13 – Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.
Proportional Modified EBITDA of equity-method investments
48
47
Transmission & Gulf of Mexico Modified EBITDA
$
697
$
660
Commodity margins
$
15
$
8
Three months ended March 31, 2022 vs. three months ended March 31, 2021
Transmission & Gulf of Mexico Modified EBITDA increased primarily due to a favorable change to Service revenues, partially offset by higher Other segment costs and expenses.
Service revenues increased primarily due to a $39 million increase in Transco’s natural gas transportation revenues primarily associated with the Leidy South expansion project placed in service in the second half of 2021, and higher reimbursable electric power costs, which is offset by a similar change in electricity charges, reflected in Other segment costs and expenses.
Other segment costs and expenses increased primarily due to higher operating costs, including higher costs associated with the Leidy South expansion project and higher reimbursable electric power costs, which is offset by a similar change in electricity reimbursements, reflected in Service revenues. These increases are partially offset by a favorable change in the deferral of ARO related depreciation at Transco.
Northeast G&P
Three Months Ended March 31,
2022
2021
(Millions)
Service revenues
$
380
$
358
Service revenues – commodity consideration
7
3
Product sales
36
32
Segment revenues
423
393
Product costs
(37)
(32)
Other segment costs and expenses
(118)
(112)
Proportional Modified EBITDA of equity-method investments
Three months ended March 31, 2022 vs. three months ended March 31, 2021
Northeast G&P Modified EBITDA increased primarily due to higher Service revenues.
Service revenues increased primarily due to:
•A $9 million increase in revenues at Susquehanna Supply Hub primarily related to higher gathering rates, partially offset by lower gathering volumes;
•A $7 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 $5 million increase in revenues at the Northeast JV primarily related to higher processing volumes, partially offset by lower gathering volumes.
Other segment costs and expenses increased primarily due to higher operating expenses, including higher electricity charges.
Proportional Modified EBITDA of equity-method investments decreased at Appalachia Midstream Investments primarily driven by lower gathering rates resulting from annual cost of service contract redetermination, partially offset by an increase at Laurel Mountain due to higher commodity-based gathering rates and higher MVC revenue.
West
Three Months Ended March 31,
2022
2021
(Millions)
Service revenues
$
331
$
291
Service revenues – commodity consideration
49
35
Product sales
187
152
Net gain (loss) on commodity derivatives
(5)
(2)
Segment revenues
562
476
Product costs
(182)
(137)
Processing commodity expenses
(26)
(17)
Other segment costs and expenses
(121)
(125)
Proportional Modified EBITDA of equity-method investments
27
25
West Modified EBITDA
$
260
$
222
Commodity margins
$
23
$
31
Three months ended March 31, 2022 vs. three months ended March 31, 2021
West Modified EBITDA increased primarily due to higher Service revenues, partially offset by lower Commodity margins.
Service revenues increased primarily due to:
•A $50 million increase primarily due to higher processing rates in the Piceance region and higher gathering rates in the Barnett Shale and Haynesville Shale regions, driven by favorable commodity pricing;
•A $1 million increase associated gathering volumes primarily due to a production increase in the Haynesville Shale region, substantially offset by a production decline in the Eagle Ford Shale region (the
impact of which is substantially offset by the recognition of higher MVC revenue described below); partially offset by
•A $7 million decrease in revenues associated with reimbursable compressor power and fuel purchases primarily due to lower prices related to the impact of the absence of severe winter weather in the first quarter of 2022 as compared to the first quarter of 2021, which are offset by similar changes in Other segment costs and expenses;
•A $3 million decrease associated with lower MVC revenue in the Wamsutter region, partially offset by higher MVC revenue in the Eagle Ford Shale region.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, Processing commodity expenses, andnet realized gains and losses on commodity derivativesrelated to sales of product comprise our Commodity margins. We further segregate our Commodity margins into product margins associated with our equity NGLs and marketing margins. Marketing margins decreased $12 million, primarily due to the absence of severe winter weather in the first quarter of 2022 as compared to the first quarter of 2021. Product margins from our equity NGLs increased $1 million, primarily due to higher net realized commodity sales prices, offset by lower non-ethane sales volumes and higher net realized prices for natural gas purchases associated with our equity NGL production activities.
Other segment costs and expenses changed favorably primarily due to lower reimbursable compressor power and fuel purchases which are offset in Service revenues.
Gas & NGL Marketing Services
Three Months Ended March 31,
2022
2021
(Millions)
Service revenues
$
1
$
1
Product sales
968
1,088
Net realized gain (loss) from derivative instruments
(56)
(34)
Net unrealized gain (loss) from derivative instruments
(59)
—
Net gain (loss) on commodity derivatives
(115)
(34)
Segment revenues
854
1,055
Product costs
(812)
(959)
Other segment costs and expenses
(29)
(3)
Gas & NGL Marketing Services Modified EBITDA
$
13
$
93
Commodity margins
$
100
$
95
Three months ended March 31, 2022 vs. three months ended March 31, 2021
Gas & NGL Marketing Services Modified EBITDA decreased primarily due to higher net unrealized loss from derivative instruments and higher Other segment costs and expenses, partially offset by higher Commodity margins.
The net sum of Product sales, Product costs, and Net realized gain (loss) from derivative instruments related to sales of product comprise our Commodity margins. Commodity margins increased $5 million primarily due to:
•A $63 million increase associated with the operations acquired in the Sequent Acquisition in the third quarter of 2021 primarily related to favorable pricing spreads on transportation capacity reflecting gains on physical transactions, partially offset by net realized losses on derivatives and a $15 million charge related
to the remaining recognition of a purchase accounting inventory fair value adjustment which increased the weighted-average cost of inventory. This increase was substantially offset by
•A $58 million decrease associated with our legacy natural gas marketing operations primarily due to lower net realized natural gas prices from the absence of severe winter weather in the first quarter of 2022 as compared to the first quarter of 2021.
Net unrealized gain (loss) from derivative instruments relates to derivative contracts that are not designated as hedges for accounting purposes. We can experience significant earnings volatility from the fair value accounting required for the derivatives used to hedge a portion of the economic value of the underlying transportation and storage portfolio. However, the unrealized fair value measurement gains and losses are offset by valuation changes in the economic value of the underlying transportation and storage portfolio, which is not accounted for on a fair value basis.
Other segment costs and expenses increased primarily due to higher employee-related costs related to the Sequent Acquisition.
Other
Three Months Ended March 31,
2022
2021
(Millions)
Service revenues
$
9
$
7
Product sales
104
56
Net realized gain (loss) from derivative instruments
(8)
—
Net unrealized gain (loss) from derivative instruments
(66)
—
Net gain (loss) on commodity derivatives
(74)
—
Segment revenues
39
63
Other segment costs and expenses
(34)
(30)
Other Modified EBITDA
$
5
$
33
Three months ended March 31, 2022 vs. three months ended March 31, 2021
Other Modified EBITDA decreased primarily due to $32 million lower results from our upstream operations which included the following:
•A $66 million net unrealized loss on commodity derivatives in the first quarter of 2022 related to hedges of future upstream production; partially offset by
•A $40 million increase in realized product sales primarily due to higher volumes associated with acquisitions of additional ownership interests in the second and third quarters of 2021. This volume increase was partially offset by lower average realized commodity prices due to the absence of severe winter weather in the first quarter of 2022 as compared to the first quarter of 2021.
Management’s Discussion and Analysis of Financial Condition and Liquidity
Outlook
Our growth capital and investment expenditures in 2022 are currently expected to be in a range from $2.25 billion to $2.35 billion. Growth capital spending in 2022 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business, the Trace Acquisition, and an expansion in the Western Gulf area. We also expect to invest capital in the development of our upstream oil and gas properties. 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 funded the Trace Acquisition with available sources of short-term liquidity and intend to fund substantially all additional planned 2022 capital spending with cash available after paying dividends. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities including the repurchase of our common stock.
During the first quarter of 2022, we early retired of $1.25 billion of 3.6 percent senior unsecured notes that were scheduled to mature in March 2022. As of March 31, 2022, we have approximately $1.6 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 or from our credit facility, as well as proceeds from asset monetizations. In May 2022, we expect to early retire our $750 million of 3.35 percent senior unsecured notes that are scheduled to mature in August 2022.
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 2022. Our potential material internal and external sources and uses of liquidity are as follows:
Sources:
Cash and cash equivalents on hand
Cash generated from operations
Distributions from our equity-method investees
Utilization of our credit facility and/or commercial paper program
Cash proceeds from issuance of debt and/or equity securities
Proceeds from asset monetizations
Uses:
Working capital requirements
Capital and investment expenditures
Product costs
Other operating costs including human capital expenses
Quarterly dividends to our shareholders
Debt service payments, including payments of long-term debt
Distributions to noncontrolling interests
Share repurchase program
As of March 31, 2022, we have approximately $20.8 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 or from our credit facility, as well as proceeds from asset monetizations.
Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook.
As of March 31, 2022, we had a working capital deficit of $1.154 billion, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:
Available Liquidity
March 31, 2022
(Millions)
Cash and cash equivalents
$
604
Capacity available under our $3.75 billion credit facility, less amounts outstanding under our $3.5 billion commercial paper program (1)
3,750
$
4,354
(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 March 31, 2022. Through March 31, 2022, there was no amount outstanding under our commercial paper program and credit facility. At March 31, 2022, 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 3.7 percent from the $0.41 per share paid in each quarter of 2021, to $0.425 per share paid in March 2022.
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
These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our securities, and each rating should be evaluated independently of any other rating. No assurance can be given that the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current criteria for investment-grade ratios. A downgrade of our credit ratings might increase our future cost of borrowing and, if ratings were to fall below investment-grade, could require us to provide additional collateral to third parties, negatively impacting our available liquidity.
The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented (see Notes to Consolidated Financial Statements for the Notes referenced in the table):
Cash Flow
Three Months Ended March 31,
Category
2022
2021
(Millions)
Sources of cash and cash equivalents:
Operating activities – net
Operating
$
1,082
$
915
Proceeds from long-term debt
Financing
3
897
Uses of cash and cash equivalents:
Payments of long-term debt
Financing
(1,256)
(5)
Common dividends paid
Financing
(518)
(498)
Capital expenditures
Investing
(291)
(260)
Dividends and distributions paid to noncontrolling interests
Financing
(37)
(54)
Purchases of and contributions to equity-method investments
Investing
(56)
(14)
Other sources / (uses) – net
Financing and Investing
(3)
3
Increase (decrease) in cash and cash equivalents
$
(1,076)
$
984
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, and Net unrealized (gain) loss from derivative instruments.
Our Net cash provided (used) by operating activities for the three months ended March 31, 2022, increased from the same period in 2021 primarily due to higher operating income (excluding noncash items as previously discussed), favorable changes in margin requirements, and higher distributions from unconsolidated affiliates.
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 three months of 2022.
Commodity Price Risk
We are exposed to commodity price risk primarily through the operations acquired in the Sequent Acquisition (Sequent), which routinely utilize various types of derivative instruments to economically hedge certain commodity price risks inherent in the natural gas marketing industry. These instruments include a variety of exchange-traded and OTC energy contracts such as forward contracts, futures contracts, and basis swaps, as well as physical transactions that qualify as derivatives. These economic hedging activities are not designated and do not qualify for hedge accounting treatment.
The maturities of Sequent’s derivative contracts at March 31, 2022 were as follows:
Total Fair Value
Maturity
Fair Value Measurements Using (1)
2022
2023 - 2024
2025 - 2026+
(Millions)
Level 1
$
(32)
$
15
$
(59)
$
12
Level 2
(408)
(52)
(195)
(161)
Level 3
(11)
4
(14)
(1)
Fair value of contracts outstanding at end of period (2)
$
(451)
$
(33)
$
(268)
$
(150)
_______________
(1)See Note 10 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements for discussion of valuation techniques by level within the fair value hierarchy. See Note 11 – Derivatives for the amount of change in fair value recognized in our Consolidated Statement of Income.
(2)Excludes cash collateral of $107 million in Level 1.
Sequent Value at Risk (VaR)
VaR is the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability. Sequent’s VaR may not be comparable to that of other companies due to differences in the factors used to calculate VaR. Sequent’s VaR is determined using a parametric model with a 95 percent confidence interval and a one-day holding period, which means that 95 percent of the time, the risk of loss in a day from a portfolio of positions is expected to be less than or equal to the amount of VaR calculated. Sequent’s open exposure is managed in accordance with established policies that limit market risk and require daily reporting of potential financial exposure to senior management. Because Sequent generally manages physical gas assets and economically protects its positions by hedging in the futures markets, Sequent’s open exposure is generally mitigated. Sequent employs daily risk testing, using both VaR and stress testing, to evaluate the risk of its positions.
Sequent actively monitors open commodity positions and the resulting VaR and maintains a relatively small risk exposure as total buy volume is close to sell volume, with minimal open natural gas price risk.
Sequent had the following VaRs for the period shown:
Three Months Ended March 31, 2022
(Millions)
Average
$
6.2
High
$
10.4
Low
$
4.1
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 first quarter of 2022 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, 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 12 – 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 12 – 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, 2021, includes risk factors that could materially affect our business, financial condition, or future results. Those Risk Factors have not materially changed, except that they are supplemented or modified by the following risk factors.
Prices for natural gas, NGLs, oil, and other commodities, are volatile and this volatility has and could continue to adversely affect our financial condition, results of operations, cash flows, access to capital, and ability to maintain or grow our businesses.
Our revenues, operating results, future rate of growth, and the value of certain components of our businesses depend primarily upon the prices of natural gas, NGLs, oil, or other commodities, and the differences between prices of these commodities and could be materially adversely affected by an extended period of low commodity prices, or a decline in commodity prices. Price volatility has and could continue to impact both the amount we receive for our products and services and the volume of products and services we sell. Prices affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Price volatility has had and could continue to have an adverse effect on our business, results of operations, financial condition, and cash flows.
The markets for natural gas, NGLs, oil, and other commodities are likely to continue to be volatile. Wide fluctuations in prices might result from one or more factors beyond our control, including:
•Imbalances in supply and demand whether rising from worldwide or domestic supplies of and demand for natural gas, NGLs, oil, and related commodities;
•Turmoil in the Middle East and other producing regions, including the Russian invasion of Ukraine;
•The activities of OPEC and other countries, whether acting independently of or informally aligned with OPEC, which have significant oil, natural gas or other commodity production capabilities, including Russia;
•The level of consumer demand;
•The price and availability of other types of fuels or feedstocks;
•Supply disruptions, including plant outages and transportation disruptions;
•The price and quantity of foreign imports and domestic exports of natural gas and oil;
•Domestic and foreign governmental regulations and taxes;
•The credit of participants in the markets where products are bought and sold.
A breach of our information technology infrastructure, including a breach caused by a cybersecurity attack on us or third parties with whom we are interconnected, may interfere with the safe operation of our assets, result in the disclosure of personal or proprietary information, and harm our reputation.
We rely on our information technology infrastructure to process, transmit, and store electronic information, including information we use to safely operate our assets. Our Board of Directors has oversight responsibility with regard to assessment of the major risks inherent in our business, including cybersecurity risks, and reviews management’s efforts to address and mitigate such risks, including the establishment and implementation of policies to address cybersecurity threats. We have invested, and expect to continue to invest, significant time, manpower and capital in our information technology infrastructure. However, the age, operating systems, or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cybersecurity threats. While we believe that we maintain appropriate information security policies, practices, and protocols, we regularly face cybersecurity and other security threats to our information technology infrastructure, which could include threats to our operational industrial control systems and safety systems that operate our pipelines, plants, and assets. We face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists,” or private individuals. We face the threat of theft and misuse of sensitive data and information, including customer and employee information. We also face attempts to gain access to information related to our assets through attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations or information. We also are subject to cybersecurity risks arising from the fact that our business operations are interconnected with third parties, including third-party pipelines, other facilities and our contractors and vendors. In addition, the breach of certain business systems could affect our ability to correctly record, process and report financial information. Breaches in our information technology infrastructure or physical facilities, or other disruptions including those arising from theft, vandalism, fraud, or unethical conduct, which may increase as a result of the Russian invasion of Ukraine, could result in damage to or destruction of our assets, unnecessary waste, safety incidents, damage to the environment, reputational damage, potential liability, the loss of contracts, the imposition of significant costs associated with remediation and litigation, heightened regulatory scrutiny, increased insurance costs, and have a material adverse effect on our operations, financial condition, results of operations, and cash flows.
Difficult conditions in the global financial markets and the economy in general could negatively affect our business and results of operations.
Our businesses may be negatively impacted by adverse economic conditions or future disruptions in the global financial markets. Included among these potential negative impacts are industrial or economic contraction, (including as a result of the COVID-19 pandemic) leading to reduced energy demand and lower prices for our products and services and increased difficulty in collecting amounts owed to us by our customers. The ongoing Russian invasion of Ukraine and the actions undertaken by western nations in response to Russia’s actions has had, and may continue to have, adverse impacts on global financial markets. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures. In addition, financial markets have periodically been affected by concerns over U.S. fiscal and monetary policies. These concerns, as well as actions taken by the U.S. federal government in response to these concerns, could significantly and adversely impact the global and U.S. economies and financial markets, which could negatively impact us in the manner described above.
Our business could be negatively impacted by acts of terrorism and related disruptions.
Given the volatile nature of the commodities we transport, process, store, and sell, our assets and the assets of our customers and others in our industry may be targets of terrorist activities. Uncertainty surrounding the Russian invasion of Ukraine, or other sustained military campaigns, may affect our operations in unpredictable ways, including the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terrorism. A terrorist attack could create significant price volatility, disrupt our business, limit our access to capital markets, or cause significant harm to our operations, such as full or partial disruption to our ability to produce, process, transport, or distribute natural gas, NGLs, or other commodities. Acts of terrorism, as well as events occurring in response to or in connection with acts of terrorism, could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Share Repurchase Program
In September 2021, our Board of Directors authorized a share repurchase program with a maximum dollar limit of $1.5 billion. Repurchases may be made from time to time in the open market, by block purchases, in privately negotiated transactions or in such other manner as determined by our management. Our management will also determine the timing and amount of any repurchases based on market conditions and other factors. The share repurchase program does not obligate us to acquire any particular amount of common stock, and it may be suspended or discontinued at any time. This share repurchase program does not have an expiration date. There were no repurchases under the program through March 31, 2022.
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* Filed herewith.
** Furnished herewith.
50
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/ Mary A. Hausman
Mary A. Hausman
Vice President, Chief Accounting Officer and Controller (Duly Authorized Officer and Principal Accounting Officer)
