QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2023
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: 800-945-5426 (800-WILLIAMS)
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 and Section 21E of the Exchange Act. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcomes of regulatory proceedings, market conditions, and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.
All statements, other than statements of historical facts, included in this report that address activities, events, or developments that we expect, believe, or anticipate will exist or may occur in the future are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,”
1
“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.
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 consummate asset sales on acceptable terms;
•Whether we are able to successfully identify, evaluate, and timely execute our capital projects and investment opportunities;
•The strength and financial resources of our competitors and the effects of competition;
•The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;
•Whether we will be able to effectively execute our financing plan;
•Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social, and governance practices;
•The physical and financial risks associated with climate change;
•The impacts of operational and developmental hazards and unforeseen interruptions;
2
•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 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, 2022, as filed with the SEC on February 27, 2023, as may be supplemented by disclosures in Part II, Item 1A. Risk Factors in subsequent Quarterly Reports 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 or Bbl: 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
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: Entities in which we either own 100 percent ownership interest or for which we do not own 100 percent ownership interest but which we control and therefore consolidate, including the following:
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
Nonconsolidated Entities: Entities in which we do not own a 100 percent ownership interest and which, as of June 30, 2023, 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
Securities Act, the: Securities Act of 1933, as amended
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
Appalachia Midstream Investments: Our equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region
Sequent Acquisition: The July 1, 2021, acquisition of 100 percent of Sequent Energy Management, L.P. and Sequent Energy Canada, Corp.
Trace Acquisition: The April 29, 2022, acquisition of 100 percent of Gemini Arklatex, LLC, through which we acquired the Haynesville Shale region gas gathering and related assets of Trace Midstream (Trace)
NorTex Asset Purchase: The August 31, 2022, purchase of a group of assets in north Texas, primarily natural gas storage facilities and pipelines, from NorTex Midstream Holdings, LLC
MountainWest Acquisition: The February 14, 2023, acquisition of 100 percent of MountainWest Pipelines Holding Company (MountainWest), which includes FERC-regulated interstate natural gas pipeline systems and natural gas storage capacity
Net unrealized gain (loss) from derivative instruments, net of taxes of $(4) and $(11) in 2023 and $(1) and $(2) in 2022
16
2
36
5
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $— and $— in 2023 and $— and $— in 2022
(1)
—
(1)
—
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) and $(1) in 2023 and $— and ($1) in 2022
—
3
1
5
Other comprehensive income (loss)
15
5
36
10
Comprehensive income (loss)
509
412
1,487
809
Less: Comprehensive income (loss) attributable to noncontrolling interests
34
7
64
19
Comprehensive income (loss) attributable to The Williams Companies, Inc.
Trade accounts and other receivables (net of allowance of $6 at June 30, 2023 and December 31, 2022)
1,362
2,723
Inventories
259
320
Derivative assets
233
323
Other current assets and deferred charges
234
279
Total current assets
2,639
3,797
Investments
5,046
5,065
Property, plant, and equipment
50,240
47,057
Accumulated depreciation and amortization
(17,894)
(16,168)
Property, plant, and equipment – net
32,346
30,889
Intangible assets – net of accumulated amortization
7,573
7,363
Regulatory assets, deferred charges, and other
1,421
1,319
Total assets
$
49,025
$
48,433
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable
$
1,146
$
2,327
Derivative liabilities
143
316
Accrued and other current liabilities
1,218
1,270
Commercial paper
—
350
Long-term debt due within one year
2,877
627
Total current liabilities
5,384
4,890
Long-term debt
21,532
21,927
Deferred income tax liabilities
3,325
2,887
Regulatory liabilities, deferred income, and other
4,575
4,684
Contingent liabilities and commitments (Note 9)
Equity:
Stockholders’ equity:
Preferred stock ($1 par value; 30 million shares authorized at June 30, 2023 and December 31, 2022; 35,000 shares issued at June 30, 2023 and December 31, 2022)
35
35
Common stock ($1 par value; 1,470 million shares authorized at June 30, 2023 and December 31, 2022; 1,256 million shares issued at June 30, 2023 and 1,253 million shares issued at December 31, 2022)
1,256
1,253
Capital in excess of par value
24,538
24,542
Retained deficit
(12,982)
(13,271)
Accumulated other comprehensive income (loss)
12
(24)
Treasury stock, at cost (39 million shares at June 30, 2023 and 35 million shares at December 31, 2022 of common stock)
(1,180)
(1,050)
Total stockholders’ equity
11,679
11,485
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, 2022, 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.
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. During 2023, there have been $130 million in repurchases under the program which are included in our Consolidated Statement of Changes in Equity. Cumulative repurchases to date under the program total $139 million.
Description of Business
We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located in the United States and are presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, West, and 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 and corporate activities, are included in Other.
Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco, Northwest Pipeline, and MountainWest (see Note 3 – Acquisitions), and their related natural gas storage facilities, 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 variable interest entity, or VIE), a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery. Transmission & Gulf of Mexico also includes natural gas storage facilities and pipelines providing services in north Texas.
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 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.
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 east Texas and 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 (a nonconsolidated VIE), and a 15 percent equity-method investment in Brazos Permian II (a nonconsolidated VIE).
Gas & NGL Marketing Services is comprised of our NGL and natural gas marketing and trading operations, which includes risk management and transactions related to the storage and transportation of natural gas and NGLs on strategically positioned assets.
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 June 30, 2023, we consolidate the following VIEs:
Northeast JV
We own a 65 percent interest in the Northeast JV, a subsidiary that is a VIE due to certain of our voting rights being disproportionate to our obligation to absorb losses and substantially all of the Northeast JV’s activities being performed on our behalf. We are the primary beneficiary because we have the power to direct the activities that most significantly impact the Northeast JV’s economic performance. The Northeast JV provides midstream services for producers in the Marcellus Shale and Utica Shale regions. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner on a proportional basis.
Gulfstar One
We own a 51 percent interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. Gulfstar One includes a proprietary floating production system, Gulfstar FPS, and associated pipelines that provide production handling and gathering services in the eastern deepwater Gulf of Mexico. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance.
Cardinal
We own a66 percent interest in Cardinal, a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Cardinal’s economic performance. In order to meet
contractual gas gathering commitments, we may fund more than our proportional share of future expansion activity, which could ultimately impact relative ownership.
The following table presents amounts included in our Consolidated Balance Sheet that are only for the use or obligation of our consolidated VIEs:
June 30, 2023
December 31, 2022
(Millions)
Assets (liabilities):
Cash and cash equivalents
$
61
$
49
Trade accounts and other receivables – net
183
136
Inventories
2
4
Other current assets and deferred charges
2
7
Property, plant, and equipment – net
5,099
5,154
Intangible assets – net of accumulated amortization
2,104
2,158
Regulatory assets, deferred charges, and other
29
29
Accounts payable
(77)
(76)
Accrued and other current liabilities
(35)
(34)
Regulatory liabilities, deferred income, and other
(273)
(275)
Nonconsolidated VIEs
Targa Train 7
We own a 20 percent interest in Targa Train 7, which provides fractionation services at Mont Belvieu, Texas, and is a VIE due primarily to our limited participating rights as the minority equity holder. At June 30, 2023, the carrying value of our investment in Targa Train 7 was $45 million. Our maximum exposure to loss is limited to the carrying value of our investment.
Brazos Permian II
We own a 15 percent interest in Brazos Permian II, which provides gathering and processing services in the Delaware basin and is a VIE due primarily to our limited participating rights as the minority equity holder. At June 30, 2023, the carrying value of our investment in Brazos Permian II was $18 million. Our maximum exposure to loss is limited to the carrying value of our investment.
Note 3 – Acquisitions
MountainWest Acquisition
On February 14, 2023, we closed on the acquisition of 100 percent of MountainWest, which includes FERC-regulated interstate natural gas pipeline systems and natural gas storage capacity, for $1.08 billion of cash, funded with available sources of short-term liquidity, and retaining $430 million outstanding principal amount of MountainWest long-term debt. Associated with the acquisition, we recorded a $28 million receivable from the seller related to an indemnified regulatory matter. The purpose of the MountainWest Acquisition was to expand our existing transmission and storage infrastructure footprint into major markets in Utah, Wyoming, and Colorado.
During the period from the acquisition date of February 14, 2023 to June 30, 2023, the operations acquired in the MountainWest Acquisition contributed Revenues of $94 million and Modified EBITDA (as defined in Note 10 – Segment Disclosures) of $45 million, which includes $18 million of transition-related costs.
Acquisition-related costs for the MountainWest Acquisition of $13 million are reported within our Transmission & Gulf of Mexico segment and included in Selling, general, and administrative expenses in our Consolidated Statement of Income during 2023.
We accounted for the MountainWest Acquisition 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 valuation techniques used consisted of depreciated replacement costs for non-regulated property, plant, and equipment, as well as the market approach for the assumed long-term debt consistent with the valuation technique discussed in Note 7 – Fair Value Measurements and Guarantees. MountainWest’s regulated operations are accounted for pursuant to Accounting Standards Codification 980, Regulated Operations. The fair value of assets and liabilities subject to rate making and cost recovery provisions were determined utilizing the income approach. MountainWest’s expected return on rate base is consistent with expected returns of similarly situated assets, resulting in carryover basis of these assets and liabilities equaling their fair value.
The following table presents the preliminary allocation of the acquisition date fair value of the major classes of the assets acquired, which are included in our Transmission & Gulf of Mexico segment, and liabilities assumed at February 14, 2023. The allocation is considered preliminary because the valuation work has not been completed due to the ongoing review of the valuation results and validation of significant inputs and assumptions. Preliminary fair value measurements were made for certain acquired assets and liabilities, primarily property, plant, and equipment and long-term debt; however, adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date, as new information related to facts and circumstances as of the acquisition date may be identified. The fair value of accounts receivable acquired equals contractual amounts receivable. After the March 31, 2023, financial statements were issued, we identified adjustments to the preliminary purchase price allocation, primarily resulting in an increase of $19 million in trade accounts and other receivables and decreases of $75 million in property, plant, and equipment and $60 million in other noncurrent liabilities.
(Millions)
Cash and cash equivalents
$
23
Trade accounts and other receivables
33
Other current assets
26
Investments
22
Property, plant, and equipment – net
1,017
Other noncurrent assets
32
Total identifiable assets acquired
$
1,153
Current liabilities
$
(47)
Long-term debt (see Note 6)
(365)
Other noncurrent liabilities
(95)
Total liabilities assumed
$
(507)
Net identifiable assets acquired
$
646
Goodwill included in Intangible assets – net of accumulated amortization
401
Net assets acquired
$
1,047
Goodwill recognized in the MountainWest Acquisition relates primarily to enhancing and diversifying our basin positions and the long-term value associated with rate regulated businesses and is reported within our Transmission & Gulf of Mexico segment. Substantially all of the goodwill is deductible for tax purposes. Goodwill is included within Intangible assets – net of accumulated amortization in our Consolidated Balance Sheet and represents the excess of the consideration over the fair value of the net assets acquired. It is not subject to amortization but is evaluated annually as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more likely than not that the fair value of the reporting unit is less than its carrying amount. As part of the evaluation, we compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, an impairment charge is recorded for the difference (not to exceed the carrying value of goodwill). Judgments and assumptions are inherent in our management’s estimates of fair value.
On April 29, 2022, we closed on the acquisition of 100 percent of Gemini Arklatex, LLC through which we acquired the Haynesville Shale region gas gathering and related assets of Trace for $972 million of cash funded with cash on hand and proceeds from issuance of commercial paper. The purpose of the Trace Acquisition was to expand our footprint into the east Texas area of the Haynesville Shale region, increasing in-basin scale in one of the largest growth basins in the country.
During the period from the acquisition date of April 29, 2022 to December 31, 2022, the operations acquired in the Trace Acquisition contributed Revenues of $148 million and Modified EBITDA of $73 million.
Acquisition-related costs for the Trace Acquisition of $8 million are reported within our West segment and were included in Selling, general, and administrative expenses in our Consolidated Statement of Income during 2022.
We accounted for the Trace Acquisition as a business combination. The following table presents the allocation of the acquisition date fair value of the major classes of the assets acquired, which are included in our West segment, and liabilities assumed at April 29, 2022. The fair value of accounts receivable acquired equals contractual amounts receivable. The valuation techniques used consisted of the income approach (excess earnings method) for valuation of intangible assets and depreciated replacement costs for property, plant, and equipment.
(Millions)
Cash and cash equivalents
$
39
Trade accounts and other receivables
18
Property, plant, and equipment – net
448
Intangible assets – net of accumulated amortization
472
Other noncurrent assets
20
Total assets acquired
$
997
Accounts payable
$
(12)
Accrued and other current liabilities
(5)
Other noncurrent liabilities
(8)
Total liabilities assumed
$
(25)
Net assets acquired
$
972
Other intangible assets
Other intangible assets recognized in the Trace Acquisition are related to contractual customer relationships from gas gathering agreements with our customers. The basis for determining the value of these intangible assets is estimated future net cash flows to be derived from acquired contractual customer relationships discounted using a risk-adjusted discount rate. These intangible assets are being amortized on a straight-line basis over an initial period of 20 years which represents the term over which the contractual customer relationships are expected to contribute to our cash flows. Approximately 2 percent of the expected future revenues from these contractual customer relationships are impacted by our ability and intent to renew or renegotiate existing customer contracts. We expense costs incurred to renew or extend the terms of our gas gathering contracts with customers. Based on the estimated future revenues during the current contract periods (as estimated at the time of the acquisition), the weighted-average period prior to the next renewal or extension of the existing contractual customer relationships is approximately 19 years.
Supplemental Pro Forma
The following pro forma Revenues and Net income (loss) attributable to The Williams Companies, Inc. for the three months ended June 30, 2022, and six months ended June 30, 2023 and 2022, are presented as if the MountainWest Acquisition had been completed on January 1, 2022, and the Trace Acquisition had been completed on January 1, 2021. These pro forma amounts are not necessarily indicative of what the actual results would have
been if the MountainWest Acquisition and Trace Acquisition had in fact occurred on the dates 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.
Three Months Ended June 30, 2022
As Reported
Pro Forma MountainWest
Pro Forma Trace (1)
Pro Forma Combined
(Millions)
Revenues
$
2,490
$
62
$
10
$
2,562
Net income (loss) attributable to The Williams Companies, Inc.
400
14
4
418
Six Months Ended June 30, 2023
As Reported
Pro Forma MountainWest (2)
Pro Forma Combined
(Millions)
Revenues
$
5,564
$
35
$
5,599
Net income (loss) attributable to The Williams Companies, Inc.
1,387
6
1,393
Six Months Ended June 30, 2022
As Reported
Pro Forma MountainWest
Pro Forma Trace (1)
Pro Forma Combined
(Millions)
Revenues
$
5,014
$
129
$
45
$
5,188
Net income (loss) attributable to The Williams Companies, Inc.
780
31
18
829
(1)Excludes results from operations acquired in the Trace Acquisition for the period beginning on the acquisition date of April 29, 2022, as these results are included in the amounts as reported.
(2)Excludes results from operations acquired in the MountainWest Acquisition for the period beginning on the acquisition date of February 14, 2023, as these results are included in the amounts as reported.
NorTex Asset Purchase
On August 31, 2022, we purchased a group of assets in north Texas, primarily natural gas storage facilities and pipelines, from NorTex Midstream Holdings, LLC for approximately $424 million. These assets are included in our Transmission & Gulf of Mexico segment.
Regulated interstate natural gas transportation and storage
$
1,639
$
—
$
—
$
—
$
—
$
—
$
(23)
$
1,616
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration
—
213
884
702
—
—
(89)
1,710
Commodity consideration
—
18
3
42
—
—
—
63
Other
9
8
45
6
1
—
(8)
61
Total service revenues
1,648
239
932
750
1
—
(120)
3,450
Product sales
79
60
77
175
2,330
185
(442)
2,464
Total revenues from contracts with customers
1,727
299
1,009
925
2,331
185
(562)
5,914
Other revenues (1)
21
7
14
78
2,543
23
—
2,686
Other adjustments (2)
—
—
—
—
(3,238)
—
202
(3,036)
Total revenues
$
1,748
$
306
$
1,023
$
1,003
$
1,636
$
208
$
(360)
$
5,564
Six Months Ended June 30, 2022
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage
$
1,549
$
—
$
—
$
—
$
—
$
—
$
(36)
$
1,513
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration (3)
—
173
736
702
—
—
(66)
1,545
Commodity consideration
—
43
10
110
—
—
—
163
Other (3)
5
5
42
6
1
—
(9)
50
Total service revenues
1,554
221
788
818
1
—
(111)
3,271
Product sales
59
164
70
439
5,313
284
(919)
5,410
Total revenues from contracts with customers
1,613
385
858
1,257
5,314
284
(1,030)
8,681
Other revenues (1)
5
4
13
(8)
3,231
(49)
(9)
3,187
Other adjustments (2)
—
—
—
—
(7,132)
—
278
(6,854)
Total revenues
$
1,618
$
389
$
871
$
1,249
$
1,413
$
235
$
(761)
$
5,014
______________________________
(1)Revenues not derived from contracts with customers primarily consist of physical product sales related to derivative contracts, realized and unrealized gains and losses associated with our derivative contracts, which are reported in Net gain (loss) on commodity derivativesin the Consolidated Statement of Income, management fees that we receive for certain services we provide to operated equity-method investments, and leasing revenues associated with our headquarters building.
(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 or engage in energy trading activities, the resulting revenues are presented net of the related costs of those activities in our Consolidated Statement of Income.
(3)Certain contractual reimbursements of operating and maintenance costs previously included in Other are now presented in Monetary consideration as they were received in exchange for providing gas gathering and processing services.
The following table presents a reconciliation of our contract assets:
Three Months Ended June 30,
Six Months Ended June 30,
2023
2022
2023
2022
(Millions)
Balance at beginning of period
$
42
$
36
$
29
$
22
Revenue recognized in excess of amounts invoiced
45
49
88
104
Minimum volume commitments invoiced
(31)
(37)
(61)
(78)
Balance at end of period
$
56
$
48
$
56
$
48
Contract Liabilities
The following table presents a reconciliation of our contract liabilities:
Three Months Ended June 30,
Six Months Ended June 30,
2023
2022
2023
2022
(Millions)
Balance at beginning of period
$
1,010
$
1,093
$
1,043
$
1,126
Payments received and deferred
95
81
124
110
Significant financing component
2
3
4
5
Contract liability acquired
—
—
5
—
Recognized in revenue
(68)
(62)
(137)
(126)
Balance at end of period
$
1,039
$
1,115
$
1,039
$
1,115
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 FERC tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes are not currently known.
Our remaining performance obligations exclude variable consideration, including contracts with variable consideration for which we have elected the practical expedient for consideration recognized in revenue as billed. Certain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term of the contract. The remaining performance obligation amounts as of June 30, 2023, do not consider potential future performance obligations for which the renewal has not been exercised and exclude contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service. Consideration received prior to June 30, 2023, 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 June 30, 2023.
Contract Liabilities
Remaining Performance Obligations
(Millions)
2023 (six months)
$
98
$
1,900
2024 (one year)
140
3,706
2025 (one year)
123
3,409
2026 (one year)
112
2,987
2027 (one year)
105
2,580
Thereafter
461
15,267
Total
$
1,039
$
29,849
Accounts Receivable
The following is a summary of our Trade accounts and other receivables – net:
June 30, 2023
December 31, 2022
(Millions)
Accounts receivable related to revenues from contracts with customers
$
1,113
$
1,771
Receivables from derivatives
185
889
Other accounts receivable
64
63
Trade accounts and other receivables – net
$
1,362
$
2,723
Note 5 – Provision (Benefit) for Income Taxes
The Provision (benefit) for income taxes from continuing operations includes:
Three Months Ended June 30,
Six Months Ended June 30,
2023
2022
2023
2022
(Millions)
Current:
Federal
$
(1)
$
(28)
$
—
$
(27)
State
4
8
4
10
3
(20)
4
(17)
Deferred:
Federal
149
(10)
386
84
State
23
(15)
69
6
172
(25)
455
90
Provision (benefit) for income taxes
$
175
$
(45)
$
459
$
73
The effective income tax rates for the total provision (benefit) for the three and six months ended June 30, 2023, are greater than the federal statutory rate primarily due to the effect of state income taxes.
The effective income tax rates for the total provision (benefit) for the three and six months ended June 30, 2022, are less than the federal statutory rate primarily due to the release of valuation allowances and federal settlements, partially offset by the effect of state income taxes.
We have a valuation allowance on certain deferred income tax assets that serves to reduce those assets to amounts that will, more likely than not, be realized. We must evaluate whether we will ultimately realize these tax benefits considering all available positive and negative evidence, which incorporates management’s assessment of available tax planning strategies, future reversals of existing taxable temporary differences, and the availability and
character of future taxable income. In the second quarter of 2022, we released $88 million of valuation allowance upon determining we expect to utilize an additional $70 million of foreign tax credits and $18 million related to various state net operating loss carryforwards and state credits.
During the second quarter of 2022, we finalized settlements for 2011 through 2014 on certain contested matters with the Internal Revenue Service (IRS). This settlement resulted in decreasing our uncertain tax positions of approximately $46 million, which favorably impacted the Provision (benefit) for income taxes.
Note 6 – Debt and Banking Arrangements
Long-Term Debt
Issuances and retirements
On March 2, 2023, we issued $750 million of 5.40 percent senior unsecured notes due March 2, 2026, and $750 million of 5.65 percent senior unsecured notes due March 15, 2033.
As a result of the MountainWest Acquisition on February 14, 2023, our Consolidated Balance Sheet now includes $100 million of 3.53 percent senior unsecured notes due January 31, 2028, $150 million of 3.91 percent senior unsecured notes due January 31, 2038, and $180 million of 4.875 percent senior unsecured notes due December 1, 2041. The acquisition date fair value reflects a $65 million reduction to the aggregate principal amount. (See Note 3 – Acquisitions.)
Commercial Paper Program
At June 30, 2023, no commercial paper was outstanding under our $3.5 billion commercial paper program.
Credit Facility
In the second quarter of 2023, the maturity date of our October 2021 amended and restated credit agreement (Credit Agreement) was extended one year and now expires October 8, 2027. One participating lender, Credit Suisse AG, New York Branch, with a commitment of approximately $194 million did not extend their commitment beyond October 8, 2026. The amended Credit Agreement allows the co-borrowers to request up to two extensions of the maturity date each for an additional one-year period to allow a maturity date as late as October 8, 2029, under certain circumstances. Additionally, the amended Credit Agreement replaces the London Interbank Offered Rate with the Term Secured Overnight Financing Rate as the benchmark interest rate index.
June 30, 2023
Stated Capacity
Outstanding
(Millions)
Long-term credit facility (1)
$
3,750
$
—
Letters of credit under certain bilateral bank agreements
17
(1)In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program.
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, accounts payable, and commercial paper approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.
Fair Value Measurements Using
Carrying Amount
Fair Value
Quoted Prices In Active Markets for Identical Assets (Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs (Level 3)
(Millions)
Assets (liabilities) at June 30, 2023:
Measured on a recurring basis:
ARO Trust investments
$
254
$
254
$
254
$
—
$
—
Commodity derivative assets (1)
174
174
80
88
6
Commodity derivative liabilities (1)
(402)
(402)
—
(374)
(28)
Other financial assets (liabilities) – net
7
7
—
7
—
Additional disclosures:
Long-term debt, including current portion
(24,409)
(23,580)
—
(23,580)
—
Guarantees
(38)
(27)
—
(11)
(16)
Assets (liabilities) at December 31, 2022:
Measured on a recurring basis:
ARO Trust investments
$
230
$
230
$
230
$
—
$
—
Commodity derivative assets (2)
166
166
20
132
14
Commodity derivative liabilities (2)
(810)
(810)
(22)
(718)
(70)
Other financial assets (liabilities) – net
(5)
(5)
—
(5)
—
Additional disclosures:
Long-term debt, including current portion
(22,554)
(21,569)
—
(21,569)
—
Guarantees
(38)
(25)
—
(9)
(16)
(1)Net commodity derivative assets and liabilities exclude $83 million of net cash collateral in Level 1.
(2)Net commodity derivative assets and liabilities exclude $202 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. 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 Derivative assets and Regulatory assets, deferred charges, and other in our Consolidated Balance Sheet. Commodity derivative liabilities are reported in Derivative liabilities and Regulatory liabilities, deferred income, and other in our Consolidated Balance Sheet. Changes in the fair value of our derivative assets and liabilities are recorded in Net gain (loss) on commodity derivatives and Net processing commodity expenses in our Consolidated Statement of Income. See Note 8 – 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, Inc., (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 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 and other current liabilities in our Consolidated Balance Sheet. The maximum potential undiscounted liquidity exposure is approximately $24 millionat June 30, 2023. 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.
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 7 – 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 June 30, 2023, the notional volume of the net long (short) positions for our commodity-related derivative contracts were as follows:
Commodity
Unit of Measure
Net Long (Short) Position
Index Risk
Natural Gas
MMBtu
829,561,223
Central Hub Risk - Henry Hub
Natural Gas
MMBtu
(65,156,751)
Basis Risk
Natural Gas
MMBtu
(25,966,126)
Central Hub Risk - Mont Belvieu
Natural Gas Liquids
Barrels
(1,263,112)
Basis Risk
Natural Gas Liquids
Barrels
(1,438,000)
Central Hub Risk - WTI
Crude Oil
Barrels
172,300
Derivative Financial Statement Presentation
The fair value of commodity-related derivatives, which are not designated as hedging instruments for accounting purposes, was reflected as follows:
June 30, 2023
December 31, 2022
Derivative Category
Assets
(Liabilities)
Assets
(Liabilities)
(Millions)
Current
$
486
$
(661)
$
1,099
$
(1,278)
Noncurrent
256
(309)
269
(734)
Total derivatives
$
742
$
(970)
$
1,368
$
(2,012)
Counterparty and collateral netting offset
(484)
567
(1,034)
1,236
Amounts recognized in our Consolidated Balance Sheet
The pre-tax effects of commodity-related derivative instrumentsin Net gain (loss) on commodity derivatives reflected within Total revenues and Net processing commodity expenses in our Consolidated Statement of Income were as follows:
Gain (Loss)
Three Months Ended June 30,
Six Months Ended June 30,
2023
2022
2023
2022
(Millions)
Realized commodity-related derivatives not designated as hedging instruments
$
3
$
(63)
$
177
$
(132)
Unrealized commodity-related derivatives not designated as hedging instruments
112
(250)
444
(375)
Net gain (loss) on commodity derivatives
$
115
$
(313)
$
621
$
(507)
Realized commodity-related derivatives not designated as hedging instruments in Net processing commodity expenses
$
1
$
5
$
(3)
$
6
Unrealized commodity-related derivatives not designated as hedging instruments in Net processing commodity expenses
$
(29)
$
9
$
(34)
$
11
Contingent Features
Generally, collateral may be provided in the form of 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. At June 30, 2023, the contractually required collateral in the event of a credit rating downgrade to non-investment grade status was $6 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 June 30, 2023, net cash collateral held on deposit in broker margin accounts was $83 million.
Note 9 – Contingent Liabilities
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, plus fees and interest. 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. On May 26, 2023, the Alaska Supreme Court issued its Opinion substantially affirming the Superior Court’s decision. On June 26, 2023, we filed a motion to stay the effect of the Alaska Supreme Court’s Opinion because we intend to file a petition for writ of certiorari in the United States Supreme Court. On July 18, 2023, the Superior Court granted our stay of execution of the monetary judgment portions of the judgment while we seek review before the United States Supreme Court. During the second quarter of 2023, as a result of the Alaska Supreme Court’s Opinion, we recorded a pre-tax charge of $115 million to Income (loss) from discontinued operations to fully accrue for the judgment, plus the related fees and interest.
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, which obligations survived Chesapeake’s bankruptcy proceedings. Prior to its bankruptcy, Chesapeake reached a settlement to resolve substantially all Pennsylvania royalty cases pending. During the pendency of the bankruptcy, that settlement was renegotiated. The settlement applies to both Chesapeake and us and does not require any contribution from us. On August 23, 2021, after referral to the United States District Court for the Southern District of Texas by the bankruptcy court, the court approved the settlement. Two objectors filed an appeal with the United States Court of Appeals for the Fifth Circuit. On June 8, 2023, the Court of Appeals vacated the settlement approval and remanded to the United States District Court for the Southern District of Texas with instructions to dismiss the settlement proceedings for lack of jurisdiction. Certain plaintiffs have indicated in a status report filing with the United States District Court for the Middle District of Pennsylvania that they are pursuing their claims against us, which we continue to believe are subject to indemnity obligations owed to us by Chesapeake.
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. Trial was held May 10 through May 17, 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. On September 21, 2022, the court entered a final order and judgment awarding us the termination fee, attorney’s fees, expenses, and interest in the amount of $602 million plus additional interest starting September 17, 2022. Energy Transfer has appealed to the Delaware Supreme Court. The Delaware Supreme Court held oral argument en banc on July 12, 2023, and we await a ruling.
Environmental Matters
We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of June 30, 2023, we have accrued liabilities totaling $52 million for these matters, as discussed below. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At June 30, 2023, 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 and monitoring activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At June 30, 2023, we have accrued liabilities of $13 million for these costs and expect to recover approximately $4 million through rates.
We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At June 30, 2023, we have accrued liabilities totaling $10 million for these costs.
Former operations
We have potential obligations in connection with assets and businesses we no longer operate. These potential obligations include remediation activities at the direction of federal and state environmental authorities and the indemnification of the purchasers of certain of these assets and businesses for environmental and other liabilities existing at the time the sale was consummated. Our responsibilities relate to the operations of the assets and businesses described below.
•Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations;
•Former petroleum products and natural gas pipelines;
•Former petroleum refining facilities;
•Former exploration and production and mining operations;
•Former electricity and natural gas marketing and trading operations.
At June 30, 2023, we have accrued environmental liabilities of $29 million related to these matters.
Other Divestiture Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way, and other representations that we have provided.
At June 30, 2023, 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 10 – 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 natural gas and 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:
◦Income (loss) from discontinued operations;
◦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 June 30,
Six Months Ended June 30,
2023
2022
2023
2022
(Millions)
Modified EBITDA by segment:
Transmission & Gulf of Mexico
$
731
$
652
$
1,446
$
1,349
Northeast G&P
515
450
985
868
West
312
288
616
548
Gas & NGL Marketing Services (1)
68
(282)
635
(269)
Other
41
139
115
144
1,667
1,247
3,797
2,640
Accretion expense associated with asset retirement obligations for nonregulated operations
(14)
(13)
(29)
(24)
Depreciation and amortization expenses
(515)
(506)
(1,021)
(1,004)
Equity earnings (losses)
160
163
307
299
Other investing income (loss) – net
13
2
21
3
Proportional Modified EBITDA of equity-method investments
(249)
(250)
(478)
(475)
Interest expense
(306)
(281)
(600)
(567)
(Provision) benefit for income taxes
(175)
45
(459)
(73)
Income (loss) from discontinued operations
(87)
—
(87)
—
Net income (loss)
$
494
$
407
$
1,451
$
799
_____________
(1) Modified EBITDA for the three and six months ended June 30, 2023 and 2022, includes charges of $5 million and $23 million, and $12 million and $12 million, respectively, associated with lower of cost or net realizable value adjustments to our inventory. These charges are reflected in Product sales and Product costs in our Consolidated Statement of Income. Net unrealized commodity-related derivative gains (losses) of $(29) million and $(34) million, and $9 million and $11 million for the three and six months ended June 30, 2023 and 2022, respectively, are reflected in Net processing commodity expenses.
Total net gain (loss) on commodity derivatives (2)
1
—
72
533
15
—
621
Total revenues
$
2,049
$
1,023
$
1,003
$
1,636
$
208
$
(355)
$
5,564
Six Months Ended June 30, 2022
Segment revenues:
Service revenues
External
$
1,683
$
770
$
680
$
1
$
9
$
—
$
3,143
Internal
58
21
34
—
7
(120)
—
Total service revenues
1,741
791
714
1
16
(120)
3,143
Total service revenues – commodity consideration
43
10
110
—
—
—
163
Product sales
External
109
13
50
1,994
49
—
2,215
Internal
104
57
389
(154)
235
(631)
—
Total product sales
213
70
439
1,840
284
(631)
2,215
Net gain (loss) on commodity derivatives
Realized
—
—
(14)
(72)
(46)
—
(132)
Unrealized
—
—
—
(356)
(19)
—
(375)
Total net gain (loss) on commodity derivatives (2)
—
—
(14)
(428)
(65)
—
(507)
Total revenues
$
1,997
$
871
$
1,249
$
1,413
$
235
$
(751)
$
5,014
_____________
(1) As we are acting as agent for natural gas marketing customers or engage in energy trading activities, the resulting revenues are presented net of the related costs of those activities.
(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.
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, compression, and storage, NGL fractionation, transportation and storage, crude oil production handling and transportation, as well as marketing services for NGL, crude oil, and natural gas.
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, including our upstream operations and corporate activities, are included in Other. Our reportable segments are comprised of the following business activities:
•Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco, Northwest Pipeline, and MountainWest, and their related natural gas storage facilities, 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 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery. Transmission & Gulf of Mexico also includes natural gas storage facilities and pipelines providing services in north Texas.
•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 which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal 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.
•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 east Texas and 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 equity-method investment in Brazos Permian II.
•Gas & NGL Marketing Services is comprised of our NGL and natural gas marketing and trading operations which includes risk management and transactions related to the storage and transportation of natural gas and NGLs on strategically positioned assets.
Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2022 dated February 27, 2023.
Dividends
In June 2023, we paid a regular quarterly dividend of $0.4475 per share.
Overview of Six Months Ended June 30, 2023
Net income (loss) attributable to The Williams Companies, Inc., for the six months ended June 30, 2023, increased $607 millioncompared to the six months ended June 30, 2022. Further discussion of our results is found in this report in the Results of Operations.
Recent Developments
MountainWest Acquisition
On February 14, 2023, we closed on the acquisition of 100 percent of MountainWest, which includes FERC-regulated interstate natural gas pipeline systems and natural gas storage capacity, for $1.08 billion of cash, funded with available sources of short-term liquidity, and retaining $430 million outstanding principal amount of MountainWest long-term debt. The MountainWest Acquisition expands our existing transmission and storage infrastructure footprint into major markets in Utah, Wyoming, and Colorado.
Northwest Pipeline FERC Rate Case Settlement
On November 15, 2022, Northwest Pipeline received approval from the FERC for a stipulation and settlement agreement which generally reduces rates effective January 1, 2023, resolves other rate issues, establishes a Modernization and Emission Reduction Program, and satisfies its rate case filing obligation. Provisions were included in the settlement that establish a moratorium on any proceedings that would seek to place new rates in effect any earlier than January 1, 2026, and that a general rate case filing will be made for rates to become effective not later than April 1, 2028, unless we have entered into a pre-filing settlement prior to that date.
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 2023 includes a continued focus on earnings and cash flow growth.
In 2023, our operating results are expected to benefit from the MountainWest Acquisition, volume growth in the Haynesville and Northeast G&P areas, annual inflation-based rate increases across our gathering and processing business, and partial in-service of the Regional Energy Access project. We also anticipate increases resulting from a full year of contribution from recently acquired Trace and NorTex assets. These increases are partially offset by a lower expected commodity price environment.
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 2023 are expected to be in a range from $1.6 billion to $1.9 billion, excluding the MountainWest Acquisition. Growth capital spending in 2023 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business and projects supporting growth in the Haynesville basin, including the Louisiana Energy
Gateway project. 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 reduce emissions, and meet legal, regulatory, and/or contractual commitments.
Potential risks and obstacles that could impact the execution of our plan include:
•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, including increases from inflation or delays caused by supply chain disruptions;
•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, 2022, as filed with the SEC on February 27, 2023.
Expansion Projects
Our ongoing major expansion projects include the following:
Transmission & Gulf of Mexico
Deepwater Shenandoah Project
In June 2021, we reached an agreement with two third-parties to provide offshore natural gas gathering and transportation services as well as onshore natural gas processing services. The project expands our existing Gulf of Mexico offshore infrastructure via a 5-mile offshore lateral pipeline from the Shenandoah platform to Discovery’s existing Keathley Canyon Connector pipeline, adds onshore processing facilities at Larose, Louisiana to handle the expected rich Shenandoah production, and the natural gas liquids will be fractionated and marketed at Discovery’s Paradis plant in Louisiana. We plan to place the project into service in the fourth quarter of 2024.
Deepwater Whale Project
In August 2021, we reached an agreement with two third-parties to provide offshore natural gas gathering and crude oil transportation services as well as onshore natural gas processing services. The project expands our existing Western Gulf of Mexico offshore infrastructure via a 26-mile gas lateral pipeline from the Whale platform to the existing Perdido gas pipeline and adds a new 125-mile oil pipeline from the Whale platform to our existing junction platform. We plan to place the project into service in the fourth quarter of 2024.
In January 2023, we received approval from 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 a portion of the project into service as early as the fourth quarter of 2023, and the remainder of 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.
Southside Reliability Enhancement
In July 2023, we received approval from the FERC for the project, which is an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Virginia and North Carolina to delivery points in North Carolina. 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 423 Mdth/d.
Texas to Louisiana Energy Pathway
In August 2022, we filed an application with the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide firm transportation capacity from receipt points in south Texas to delivery points in Texas and Louisiana. We plan to place the project into service as early as the first quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to provide 364 Mdth/d of new firm transportation service through a combination of increasing capacity, converting interruptible capacity to firm, and utilizing existing capacity.
Southeast Energy Connector
In August 2022, we filed an application with the FERC for the project, which is an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Mississippi and Alabama to a delivery point in Alabama. We plan to place the project into service in the fourth quarter of 2024, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 150 Mdth/d.
Commonwealth Energy Connector
In August 2022, we filed an application with the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity in Virginia. We plan to place the project into service as early as the fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 105 Mdth/d.
Alabama Georgia Connector
In April 2023, we filed an application with the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from our Station 85 pooling point in Alabama to customers in Georgia. We plan to place the project into service as early as the fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by approximately 64 Mdth/d.
West
Louisiana Energy Gateway
In June 2022, we announced our intention to construct new natural gas gathering assets which are expected to gather 1.8 Bcf/d of natural gas produced in the Haynesville Shale basin for delivery to premium markets,
including Transco, industrial markets, and growing LNG export demand along the Gulf Coast. This project is expected to go into service in the fourth quarter of 2024.
Haynesville Gathering Expansion
In February 2023, we announced our agreement with a third party to facilitate natural gas production growth in the Haynesville basin. We plan to construct a greenfield gathering system in support of the third party’s 26,000-acre dedication. The system, once constructed, will provide natural gas gathering services to the third party. The third party has also agreed to a long-term capacity commitment on our Louisiana Energy Gateway project.
Northeast G&P
Susquehanna Supply Hub Gathering Expansion
We have an agreement in place with a third party to facilitate natural gas production growth in the Susquehanna region. We plan to construct approximately 22 miles of gathering pipeline and associated incremental compression. The system, once constructed, will add incremental capacity of 320 MMcf/d and will provide natural gas gathering services to the third party. The project is expected to go into service in the fourth quarter of 2023.
Utica Shale Gathering Expansion
We have an agreement in place with a third party to facilitate natural gas production growth in the Utica region on our Cardinal gathering system. We are constructing approximately 30 miles of gathering pipeline and associated incremental compression. The system, once constructed, will add incremental capacity of 125 MMcf/d and will provide natural gas gathering services to the third party. The project is expected to go into service in the second half of 2023.
The following table and discussion is a summary of our consolidated results of operations for the three and six months ended June 30, 2023, compared to the three and six months ended June 30, 2022. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
Three Months Ended June 30,
Six Months Ended June 30,
2023
2022
$ Change*
% Change*
2023
2022
$ Change*
% Change*
(Millions)
(Millions)
Revenues:
Service revenues
$
1,748
$
1,606
+142
+9
%
$
3,442
$
3,143
+299
+10
%
Service revenues – commodity consideration
27
86
-59
-69
%
63
163
-100
-61
%
Product sales
593
1,111
-518
-47
%
1,438
2,215
-777
-35
%
Net gain (loss) on commodity derivatives
115
(313)
+428
NM
621
(507)
+1,128
NM
Total revenues
2,483
2,490
5,564
5,014
Costs and expenses:
Product costs
421
857
+436
+51
%
974
1,660
+686
+41
%
Net processing commodity expenses
44
40
-4
-10
%
98
70
-28
-40
%
Operating and maintenance expenses
481
465
-16
-3
%
944
859
-85
-10
%
Depreciation and amortization expenses
515
506
-9
-2
%
1,021
1,004
-17
-2
%
Selling, general, and administrative expenses
161
160
-1
-1
%
337
314
-23
-7
%
Other (income) expense – net
(9)
(10)
-1
-10
%
(40)
(19)
+21
+111
%
Total costs and expenses
1,613
2,018
3,334
3,888
Operating income (loss)
870
472
2,230
1,126
Equity earnings (losses)
160
163
-3
-2
%
307
299
+8
+3
%
Other investing income (loss) – net
13
2
+11
NM
21
3
+18
NM
Interest expense
(306)
(281)
-25
-9
%
(600)
(567)
-33
-6
%
Other income (expense) – net
19
6
+13
NM
39
11
+28
NM
Income (loss) before income taxes
756
362
1,997
872
Less: Provision (benefit) for income taxes
175
(45)
-220
NM
459
73
-386
NM
Income (loss) from continuing operations
581
407
1,538
799
Income (loss) from discontinued operations
(87)
—
-87
NM
(87)
—
-87
NM
Net income (loss)
494
407
1,451
799
Less: Net income (loss) attributable to noncontrolling interests
34
7
-27
NM
64
19
-45
NM
Net income (loss) attributable to The Williams Companies, Inc.
$
460
$
400
+60
+15
%
$
1,387
$
780
+607
+78
%
* + = 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 June 30, 2023 vs. three months ended June 30, 2022
Service revenues increased primarily due to higher volumes from the MountainWest and Trace Acquisitions, and the NorTex Asset Purchase, and higher gathering and processing volumes as well as higher rates due to rate escalations and annual cost of service rate redetermination for certain of our Northeast G&P operations, partially offset by lower rates driven by unfavorable commodity pricing at our West operations.
Service revenues – commodity consideration decreased primarily due to lower NGL prices and volumes. 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 lower natural gas and NGL marketing prices and volumes. These decreases were substantially offset by lower prices and volumes for natural gas marketing associated purchases. 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. Product sales from our upstream operations decreased primarily due to lower commodity prices and lower NGL production volumes, offset by higher natural gas production volumes. Product sales also decreased due to lower prices and volumes related to our equity NGL sales.
Net gain (loss) on commodity derivatives includes realized and unrealized gains and losses from derivative instruments reflected within Total revenues in our Gas & NGL Marketing Services, West, and Other segments. We 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 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 transportation and storage contracts, which is not recognized until the underlying transaction occurs.
Product costs decreased primarily due to lower prices and volumes associated with our NGL marketing activities, and lower prices and volumes associated with NGLs acquired as commodity consideration related to our equity NGL production activities.
Net processing commodity expenses increased primarily due to the impact of net unrealized and realized losses on derivatives for processing plant shrink gas purchases, partially offset by lower prices and volumes for natural gas purchases associated with our equity NGL production activities.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, net realized gains and losses on commodity derivatives related to sales of product, and net realized processing commodity expenses comprise our Commodity margins. However, Product sales and net realized gains and losses on commodity derivatives at our Other segment reflecting sales related to our oil and gas producing properties comprise Net realized product sales and are excluded from our Commodity margins. See Results of Operations— Period-Over-Period Operating Results - Segments for additional discussion of Commodity margins and Net realized product sales on a segment basis.
Operating and maintenance expenses increased primarily due to higher operating costs, including increased costs associated with the 2023 MountainWest Acquisition, the 2022 Trace Acquisition, and the NorTex Asset Purchase, partially offset by a favorable change due to the timing and scope of maintenance activities.
Depreciation and amortization expenses increased primarily related to our upstream assets, and assets acquired in the 2023 MountainWest Acquisition, the 2022 Trace Acquisition, and the NorTex Asset Purchase. The increase is partially offset by lower amortization of intangibles related to our 2021 Sequent Acquisition.
The change in Equity earnings (losses) resulted from a decrease at Laurel Mountain, partially offset by an increase at RMM.
Interest expense changed unfavorably primarily due to our March 2023 debt issuance and MountainWest’s long-term debt (see Note 6 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements).
Provision (benefit) for income taxes changed unfavorably primarily due to the absence of a benefit associated with the release of valuation allowances on deferred income tax assets and federal income tax settlements both recorded in the prior year, and higher pre-tax income. See Note 5 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
Income (loss) from discontinued operations in 2023 includes a pre-tax charge of $115 million to increase the related accrued liability associated with our Alaska refinery contamination litigation, partially offset by the related income tax effect. See Note 9 – Contingent Liabilities of Notes to Consolidated Financials Statements for further discussion.
The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to higher results at Cardinal.
Six months ended June 30, 2023 vs. six months ended June 30, 2022
Service revenues increased primarily due to higher volumes from the MountainWest and Trace Acquisitions, and the NorTex Asset Purchase, as well as higher gathering, processing, and transportation volumes, and higher rates due to rate escalations and annual cost of service rate redetermination for certain Northeast G&P operations, partially offset by lower rates driven by unfavorable commodity pricing at our West operations.
Service revenues – commodity consideration decreased primarily due to lower NGL prices and volumes. 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 lower natural gas and NGL marketing prices and volumes. These decreases were substantially offset by lower prices and volumes for natural gas marketing associated purchases. 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. Product sales from our upstream operations decreased due to lower commodity prices and lower NGL and crude oil production volumes, offset by higher natural gas production volumes. Product sales also decreased due to lower prices and volumes related to our equity NGL sales.
Net gain (loss) on commodity derivatives includes realized and unrealized gains and losses from derivative instruments reflected within Total revenues in our Gas & NGL Marketing Services, West, and Other segments.
Product costs decreased primarily due to lower prices and volumes associated with our NGL marketing activities, and lower volumes and prices associated with NGLs acquired as commodity consideration related to our equity NGL production activities.
Net processing commodity expenses increased primarily due to the impact of net unrealized and realized losses on derivatives for processing plant shrink gas purchases, partially offset by lower volumes and prices for natural gas purchases associated with our equity NGL production activities.
Operating and maintenance expenses increased primarily due to higher operating costs, including increased costs associated with the 2023 MountainWest Acquisition, the 2022 Trace Acquisition, and the NorTex Asset Purchase, as well as the increased production volumes from our upstream operations and increased scope and timing of activities.
Depreciation and amortization expenses increased primarily related to our upstream assets, and assets acquired in the 2023 MountainWest Acquisition, the 2022 Trace Acquisition, and the NorTex Asset Purchase. The increase is partially offset by lower amortization of intangibles related to our 2021 Sequent Acquisition and a decrease in ARO-
related depreciation at Transco (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 acquisition and transition-related costs associated with the MountainWest Acquisition.
Other (income) expense – net within Operating income (loss) changed favorably primarily due to a gain related to a contract settlement in 2023, and a favorable change associated with regulatory liabilities established for the impacts of deferred income taxes at Northwest Pipeline, partially offset by a decrease in the deferral of ARO-related depreciation (offset in Depreciation and amortization expenses, resulting in no net impact on our results of operations).
The change in Equity earnings (losses) resulted from an increase at RMM and OPPL, partially offset by a decrease at Laurel Mountain.
Interest expense changed unfavorable primarily due to our March 2023 debt issuance and MountainWest's long-term debt (see Note 6 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements).
The favorable change in Other income (expense) – net below Operating income (loss) reflects an increase in allowance for equity funds used during construction (equity AFUDC).
Provision (benefit) for income taxes changed unfavorably primarily due to the absence of a benefit associated with the release of valuation allowances on deferred income tax assets and federal income tax settlements both recorded in the prior year, and higher pre-tax income. See Note 5 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
Income (loss) from discontinued operations in 2023 includes a pre-tax charge of $115 million to increase the related accrued liability associated with our Alaska refinery contamination litigation, partially offset by the related income tax effect.
The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to higher results at the Northeast JV and Cardinal.
Period-Over-Period Operating Results - Segments
We evaluate segment operating performance based upon Modified EBITDA. Note 10 – 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.
Net realized gain (loss) on commodity derivatives - product sales (1)
1
—
1
—
Segment revenues
1,042
1,002
2,049
1,997
Product costs (1)
(76)
(109)
(129)
(209)
Net processing commodity expenses (1)
(2)
(15)
(6)
(21)
Other segment costs and expenses
(281)
(271)
(569)
(511)
Proportional Modified EBITDA of equity-method investments
48
45
101
93
Transmission & Gulf of Mexico Modified EBITDA
$
731
$
652
$
1,446
$
1,349
Commodity margins
$
8
$
11
$
18
$
26
(1)Included as a component of Commodity margins.
Three months ended June 30, 2023 vs. three months ended June 30, 2022
Transmission & Gulf of Mexico Modified EBITDA increased primarily due to higher Service revenues, partially offset by higher Other segment costs and expenses.
Service revenues increased primarily due to:
•A $60 million increase due to the acquisition of MountainWest in February 2023 primarily in transportation and storage revenues;
•A $15 million increase due to the NorTex Asset Purchase in August 2022 primarily in storage and transportation revenues;
•A $15 million increase in the Eastern Gulf Coast region primarily due to higher production handling volumes from new wells at Devils Tower;
•A $7 million increase in Transco’s and Northwest Pipeline’s revenues associated with park and loan services; partially offset by
•A $5 million decrease due to lower rates from the FERC rate case settlement effective January 1, 2023, at Northwest Pipeline.
Other segment costs and expenses increased primarily due to higher operating and administrative costs including higher operating, acquisition, and transition costs related to our MountainWest Acquisition and NorTex Asset Purchase. This increase is partially offset by favorable changes associated with employee-related costs and lower costs related to timing and scope of general maintenance activities at Transco; regulatory liabilities established for the impacts of deferred income taxes at Northwest Pipeline and allowance for equity funds used during construction as a result of increased capital expenditures at Transco.
Six months ended June 30, 2023 vs. six months ended June 30, 2022
Transmission & Gulf of Mexico Modified EBITDA increased primarily due to higher Service revenues, partially offset by higher Other segment costs and expenses.
Service revenues increased primarily due to:
•A $93 million increase due to the acquisition of MountainWest in February 2023 primarily in transportation and storage revenues;
•A $28 million increase due to the NorTex Asset Purchase in August 2022 primarily in storage and transportation revenues;
•A $20 million increase in the Eastern Gulf Coast region primarily due to higher production handling volumes from new wells at Devils Tower;
•A $17 million increase in Transco’s and Northwest Pipeline’s revenues associated with park and loan services; partially offset by
•A $9 million decrease due to lower rates from the FERC rate case settlement effective January 1, 2023, at Northwest Pipeline.
Other segment costs and expenses increased primarily due to higher operating and administrative costs including higher operating, acquisition, and transition costs related to our MountainWest Acquisition and NorTex Asset Purchase and an unfavorable change in the deferral of ARO-related depreciation at Transco. These increases are partially offset by favorable changes associated with regulatory liabilities established for the impacts of deferred income taxes at Northwest Pipeline and allowance for equity funds used during construction as a result of increased capital expenditures at Transco.
Northeast G&P
Three Months Ended June 30,
Six Months Ended June 30,
2023
2022
2023
2022
(Millions)
Service revenues
$
489
$
411
$
943
$
791
Service revenues – commodity consideration (1)
(3)
3
3
10
Product sales (1)
28
34
77
70
Segment revenues
514
448
1,023
871
Product costs (1)
(25)
(34)
(77)
(71)
Net processing commodity expenses (1)
(1)
(2)
1
(2)
Other segment costs and expenses
(132)
(136)
(264)
(254)
Proportional Modified EBITDA of equity-method investments
159
174
302
324
Northeast G&P Modified EBITDA
$
515
$
450
$
985
$
868
Commodity margins
$
(1)
$
1
$
4
$
7
(1)Included as a component of Commodity margins.
Three months ended June 30, 2023 vs. three months ended June 30, 2022
Northeast G&P Modified EBITDA increased primarily due to higher Service revenues, partially offset by lower Proportional Modified EBITDA of equity-method investments.
•A $38 million increase in gathering revenues in the Utica Shale region primarily related to higher rates resulting from annual cost of service rate redetermination as well as higher volumes;
•A $22 million increase in revenues at the Northeast JV primarily related to higher gathering, processing, transportation, and fractionation volumes as well as higher processing rates;
•A $20 million increase in gathering revenues at Susquehanna Supply Hub primarily related to escalated rates as well as higher volumes.
Proportional Modified EBITDA of equity-method investments decreased at Laurel Mountain primarily due to lower commodity-based rates and MVC. The decrease was partially offset by an increase at Blue Racer primarily driven by higher volumes.
Six months ended June 30, 2023 vs. six months ended June 30, 2022
Northeast G&P Modified EBITDA increased primarily due to higher Service revenues, partially offset by lower Proportional Modified EBITDA of equity-method investments and higher Other segment costs and expenses.
Service revenues increased primarily due to:
•A $70 million increase in revenues at the Northeast JV primarily related to higher processing, gathering, transportation, and fractionation volumes as well as higher processing rates;
•A $59 million increase in gathering revenues in the Utica Shale region primarily related to higher rates resulting from annual cost of service rate redetermination as well as higher volumes;
•A $23 million increase in gathering revenues at Susquehanna Supply Hub primarily related to escalated rates as well as higher volumes.
Other segment costs and expenses increased primarily due to higher operating expenses related to the scope and timing of activities.
Proportional Modified EBITDA of equity-method investments decreased at Laurel Mountain primarily due to lower commodity-based rates and MVC, and a decrease at Aux Sable Liquid Products LP. The decrease was partially offset by an increase at Blue Racer primarily driven by higher volumes, as well as an increase at Appalachia Midstream Investments primarily driven by higher volumes offset by lower gathering rates resulting from annual cost of service rate redetermination.
Net realized gain (loss) on commodity derivatives – service revenues
29
(5)
68
(5)
Net realized gain (loss) on commodity derivatives – product sales (1)
4
(4)
4
(9)
Net realized gain (loss) on commodity derivatives
33
(9)
72
(14)
Segment revenues
500
687
1,003
1,249
Product costs (1)
(84)
(247)
(169)
(429)
Net processing commodity expenses (1)
(11)
(37)
(58)
(63)
Other segment costs and expenses
(136)
(146)
(236)
(267)
Proportional Modified EBITDA of equity-method investments
43
31
76
58
West Modified EBITDA
$
312
$
288
$
616
$
548
Commodity margins
$
18
$
25
$
(6)
$
48
_________
(1) Included as a component of Commodity margins.
Three months ended June 30, 2023 vs. three months ended June 30, 2022
West Modified EBITDA increased primarily due to favorable Net realized gain (loss) on commodity derivatives – service revenues, higher Proportional Modified EBITDA of equity-method investments, and lower Other segment costs and expenses, partially offset by lower Service revenues.
Service revenues decreased primarily due to:
•A $38 million decrease in the Barnett Shale region primarily due to lower gathering rates driven by unfavorable commodity pricing; partially offset by
•A $17 million increase in the Haynesville Shale region primarily associated with higher gathering volumes including from the Trace Acquisition in April 2022 and increased producer activity, partially offset by lower rates driven by unfavorable commodity pricing.
Net realized gain (loss) on commodity derivatives – service revenues reflects a favorable change in settled commodity prices relative to our natural gas hedge positions.
Other segment costs and expenses decreased primarily due to lower operating costs and the absence of acquisition-related costs associated with the Trace Acquisition in 2022.
Proportional Modified EBITDA of equity-method investments increased primarily due to higher volumes at RMM and higher volumes at OPPL.
Six months ended June 30, 2023vs.six months ended June 30, 2022
West Modified EBITDA increased primarily due to favorable Net realized gain (loss) on commodity derivatives – service revenues, lower Other segment costs and expenses, higher Proportional Modified EBITDA of equity-method investments, partially offset by lower Commodity margins.
Service revenues were unchanged primarily due to:
•A $64 million increase in the Haynesville Shale region primarily associated with higher gathering volumes including from the Trace Acquisition in April 2022 and increased producer activity, partially offset by lower rates driven by unfavorable commodity pricing; partially offset by
•A $45 million decrease in the Barnett Shale region primarily due to lower gathering rates driven by unfavorable commodity pricing, partially offset by higher gathering volumes from increased producer activity;
•A $9 million decrease in the Piceance region primarily due to lower gathering and processing volumes driven by natural production rate declines;
•An $8 million decrease in the Wamsutter region primarily due to lower volumes associated with weather-related events in first-quarter 2023.
Net realized gain (loss) on commodity derivatives – service revenues reflects a favorable change in settled commodity prices relative to our natural gas hedge positions.
Commodity margins decreased primarily due to a $44 million decrease from our equity NGLs, driven by unfavorable net realized pricing for equity NGL sales and shrink gas purchases, as well as lower volumes processed under commodity-consideration contracts.
Other segment costs and expenses decreased primarily due to favorable contract settlements in first-quarter 2023, a favorable change in our net imbalance liability due to changes in pricing, the absence of acquisition-related costs associated with the Trace Acquisition in 2022, partially offset by higher operating expenses related to operations acquired in the Trace Acquisition.
Proportional Modified EBITDA of equity-method investments increased primarily due to higher volumes at RMM and higher volumes at OPPL.
Net realized gain (loss) from derivative instruments (1)
(45)
(16)
72
(72)
Net unrealized gain (loss) from derivative instruments
123
(297)
461
(356)
Net gain (loss) on commodity derivatives
78
(313)
533
(428)
Segment revenues
505
559
1,636
1,413
Net unrealized gain (loss) from derivative instruments within Net processing commodity expenses
(29)
9
(34)
11
Product costs (1)
(384)
(833)
(911)
(1,645)
Other segment costs and expenses
(24)
(17)
(56)
(48)
Gas & NGL Marketing Services Modified EBITDA
$
68
$
(282)
$
635
$
(269)
Commodity margins
$
(2)
$
23
$
263
$
123
________________
(1) Included as a component of Commodity margins.
Three months ended June 30, 2023 vs. three months ended June 30, 2022
Gas & NGL Marketing Services Modified EBITDA increased primarily due to a favorable change in Net unrealized gain (loss) from derivative instruments within Segment revenues and Net processing commodity expenses, partially offset by lower Commodity margins.
Commodity margins decreased $25 million primarily due to:
•A $27 million decrease in our NGL marketing margins including losses on sale of inventory in 2023 compared to gains in 2022 driven by an unfavorable change in NGL prices; partially offset by
•A $2 million increase from our natural gas marketing operations including $7 million of higher natural gas transportation capacity marketing margins due to favorable net realized pricing spreads. The increase is partially offset by a decrease of $14 million lower natural gas storage marketing margins primarily due to realized derivative losses, partially reduced by $9 million benefit due to the absence of a lower of cost or net realizable value adjustment in 2022.
Net unrealized gain (loss) from derivative instruments within Segment revenues and Net processing commodity expenses relates to derivative contracts that are not designated as hedges for accounting purposes. The change from 2022 is primarily due to a change in forward commodity prices relative to our hedge positions in 2023 compared to 2022.
Six months ended June 30, 2023 vs. six months ended June 30, 2022
Gas & NGL Marketing Services Modified EBITDA increased primarily due to a favorable change in Net unrealized gain (loss) from derivative instruments within Segment revenues and Net processing commodity expensesand higher Commodity margins.
Commodity margins increased $140 million primarily due to:
•A $182 million increase from our natural gas marketing operations including $92 million of higher natural gas transportation capacity marketing margins due to favorable net realized pricing spreads and $90 million of higher natural gas storage marketing margins primarily driven by lower cost of storage inventory in the first quarter of 2023 resulting from a fourth-quarter 2022 lower of cost or net realizable value inventory adjustment. The increase in our natural gas storage marketing margins also includes the absence of a $15 million charge related to the remaining recognition of a purchase accounting inventory fair value adjustment in 2022, partially offset by an unfavorable change of $6 million lower of cost or net realizable value adjustment; partially offset by
•A $42 million decrease in our NGL marketing margins including losses on sale of inventory in 2023 compared to gains in 2022 driven by an unfavorable change in NGL prices.
Net unrealized gain (loss) from derivative instruments within Segment revenues and Net processing commodity expenses relates to derivative contracts that are not designated as hedges for accounting purposes. The change from 2022 is primarily due to a change in forward commodity prices relative to our hedge positions in 2023 compared to 2022.
Other
Three Months Ended June 30,
Six Months Ended June 30,
2023
2022
2023
2022
(Millions)
Service revenues
$
5
$
7
$
8
$
16
Product sales (1)
83
180
185
284
Net realized gain (loss) from derivative instruments (1)
14
(38)
32
(46)
Net unrealized gain (loss) from derivative instruments
(11)
47
(17)
(19)
Net gain (loss) on commodity derivatives
3
9
15
(65)
Segment revenues
91
196
208
235
Other segment costs and expenses
(49)
(57)
(92)
(91)
Proportional Modified EBITDA of equity-method investments
(1)
—
(1)
—
Other Modified EBITDA
$
41
$
139
$
115
$
144
Net realized product sales
$
97
$
142
$
217
$
238
________________
(1) Included as a component of Net realized product sales.
Three months ended June 30, 2023 vs. three months ended June 30, 2022
Other Modified EBITDA decreased primarily due to lower results from our upstream operations which included the following:
•A $58 million unfavorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity prices relative to our hedge positions in 2023 compared to 2022;
•A $45 million decrease in Net realized product sales primarily due to lower net realized commodity prices, partially offset by higher sales associated with increased production volumes. Higher natural gas production
volumes from new wells in our Haynesville Shale region were partially offset by lower natural gas and NGL production volumes in our Wamsutter region driven by the impact of severe winter weather in 2023.
Six months ended June 30, 2023vs.six months ended June 30, 2022
Other Modified EBITDA decreased primarily due to lower results from our upstream operations which included the following:
•A $21 million decrease in Net realized product sales primarily due to lower net realized commodity prices, partially offset by higher sales associated with increased production volumes. Higher natural gas production volumes from new wells in our Haynesville Shale region were partially offset by lower natural gas, NGL, and crude oil production volumes in our Wamsutter region driven by the impact of severe winter weather in 2023;
•An increase in Other segment costs and expenses primarily due to the increased production volumes from our upstream operations.
Management’s Discussion and Analysis of Financial Condition and Liquidity
Outlook
Our growth capital and investment expenditures in 2023 are currently expected to be in a range from $1.6 billion to $1.9 billion, excluding the MountainWest Acquisition discussed below. Growth capital spending in 2023 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business and projects supporting growth in the Haynesville basin, including the Louisiana Energy Gateway project. 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 reduce emissions, and meet legal, regulatory, and/or contractual commitments. We intend to fund substantially all planned 2023 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.
On February 14, 2023, we acquired 100 percent of MountainWest which includes FERC-regulated interstate natural gas pipeline systems and natural gas storage capacity, for $1.08 billion of cash and retaining $430 million outstanding principal amount of MountainWest’s long-term debt. The acquisition was funded with available sources of short-term liquidity.
During the first quarter of 2023, we issued $1.5 billion of long-term debt, a portion of which we used to pay down our commercial paper outstanding. As of June 30, 2023, we have approximately $2.88 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, our credit facility, or our commercial paper program, as well as proceeds from asset monetizations.
Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2023. 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
Gas & NGL Marketing Services payments for transportation and storage capacity and gas supply
Other operating costs including human capital expenses
Quarterly dividends to our shareholders
Repayments of borrowings under our credit facility and/or commercial paper program
Debt service payments, including payments of long-term debt
Distributions to noncontrolling interests
Share repurchase program
As of June 30, 2023, we have $21.5 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, our credit facility, or our commercial paper program, 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 June 30, 2023, we had a working capital deficit of $2.7 billion, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:
Available Liquidity
June 30, 2023
(Millions)
Cash and cash equivalents
$
551
Capacity available under our $3.75 billion credit facility, less amounts outstanding under our $3.5 billion commercial paper program (1)
3,750
$
4,301
(1)In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. We had no commercial paper outstanding as of June 30, 2023. Through June 30, 2023, the highest amount outstanding under our commercial paper program and credit facility during 2023 was $730 million. At June 30, 2023, we were in compliance with the financial covenants associated with our credit facility.
We increased our regular quarterly cash dividend to common stockholders by approximately 5.3 percent from the $0.425 per share paid in each quarter of 2022, to $0.4475 per share paid in March and June 2023.
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 in the Consolidated Statement of Cash Flows (see Notes to Consolidated Financial Statements for the Notes referenced in the table):
Cash Flow
Six Months Ended June 30,
Category
2023
2022
(Millions)
Sources of cash and cash equivalents:
Net cash provided (used) by operating activities
Operating
$
2,891
$
2,180
Proceeds from long-term debt
Financing
1,503
5
Proceeds from (payments of) commercial paper - net
Financing
—
1,037
Uses of cash and cash equivalents:
Capital expenditures
Investing
(1,155)
(606)
Common dividends paid
Financing
(1,091)
(1,035)
Purchases of businesses, net of cash acquired (see Note 3)
Investing
(1,053)
(933)
Proceeds from (payments of) commercial paper - net
Financing
(352)
—
Purchases of treasury stock
Financing
(130)
—
Dividends and distributions paid to noncontrolling interests
Financing
(112)
(95)
Purchases of and contributions to equity-method investments
Investing
(69)
(100)
Payments of long-term debt
Financing
(14)
(2,012)
Other sources / (uses) – net
Financing and Investing
(19)
12
Increase (decrease) in cash and cash equivalents
$
399
$
(1,547)
Operating activities
The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash items such as Depreciation and amortization, Provision (benefit) for deferred income taxes, Equity (earnings) losses,Net unrealized (gain) loss from derivative instruments, Inventory write-downs, and Amortization of stock-based awards.
Our Net cash provided (used) by operating activities for the six months ended June 30, 2023 increased from the same period in 2022 primarily due to higher operating income (excluding noncash items as previously discussed), net favorable changes in operating working capital, and improved derivative margin requirements.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
Our current interest rate risk exposure is related primarily to our debt portfolio and has not materially changed during the first six months of 2023. We may utilize interest rate derivative instruments to hedge interest rate risk associated with future debt issuances.
Commodity Price Risk
We are exposed to commodity price risk through our natural gas and NGL marketing activities, including contracts to purchase, sell, transport, and store product. We routinely manage this risk with a variety of exchange-traded and OTC energy contracts such as forward contracts, futures contracts, and basis swaps, as well as physical transactions. Although many of the contracts used to manage commodity exposure are derivative instruments, these economic hedges are not designated or do not qualify for hedge accounting treatment.
We are also exposed to commodity prices through our upstream business and certain gathering and processing contracts. We use derivative instruments to lock in forward sales prices on a portion of our expected future production. These economic hedges are not designated for hedge accounting treatment.
The maturities of our commodity derivative contracts at June 30, 2023 were as follows:
Total Fair Value
Maturity
Fair Value Measurements of Assets (Liabilities) Using (1)
2023
2024 - 2025
2026 - 2027+
(Millions)
Level 1 (2)
$
80
$
37
$
47
$
(4)
Level 2
(286)
(10)
(108)
(168)
Level 3
(22)
(2)
8
(28)
Fair value of contracts outstanding at end of period
$
(228)
$
25
$
(53)
$
(200)
_______________
(1)See Note 7 – 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 8 – Derivatives of Notes to Consolidated Financial Statements for the amount of change in fair value recognized in our Consolidated Statement of Income.
(2)Net commodity derivative assets and liabilities exclude $83 million of net cash collateral in Level 1.
Value at Risk (VaR)
VaR is the maximum predicted loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability. Our VaR may not be comparable to that of other companies due to differences in the factors used to calculate VaR. Our VaR is determined using parametric models with 95 percent confidence intervals and one-day holding periods, 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. Our open exposure is managed in accordance with established policies that limit market risk and require daily reporting of predicted financial loss to management. Because we generally manage physical gas assets and economically protect our positions by hedging in the futures markets, our open exposure is generally mitigated. We employ daily risk testing, using both VaR and stress testing, to evaluate the risk of our positions.
We actively monitor open commodity marketing positions and the resulting VaR and maintain a relatively small risk exposure as total buy volume is close to sell volume, with minimal open natural gas price risk.
The VaR associated with our integrated natural gas trading operations activity was $6 million at June 30, 2023 and was $10 million at December 31, 2022. We had the following VaRs for the period shown:
Six Months Ended June 30, 2023
(Millions)
Average
$
8
High
$
13
Low
$
4
Our non-trading portfolio primarily consists of derivatives that hedge our upstream business and certain gathering and processing contracts. The VaR associated with these derivatives was $5 million at June 30, 2023 and $8 million at December 31, 2022. We had the following VaRs for the period shown:
Six Months Ended June 30, 2023
(Millions)
Average
$
4
High
$
8
Low
$
2
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 Exchange Act) (Disclosure Controls) or our internal control over financial reporting (Internal Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and Internal Controls will be modified as systems change and conditions warrant.
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.
As disclosed in Note 3 – Acquisitions of Notes to Consolidated Financial Statements, we acquired MountainWest on February 14, 2023, and its total revenues constituted approximately 2 percent of total revenues as shown on our consolidated financial statements for the six months ended June 30, 2023. MountainWest’s total assets constituted approximately 3 percent of total assets as shown on our consolidated financial statements as of June 30, 2023. We excluded MountainWest’s disclosure controls and procedures that are subsumed by its internal control over financial reporting from the scope of management’s assessment of the effectiveness of our disclosure controls
and procedures. This exclusion is in accordance with the guidance issued by the Staff of the Securities and Exchange Commission that an assessment of recent business combinations may be omitted from management’s assessment of internal control over financial reporting for one year following the acquisition.
Changes in Internal Control Over Financial Reporting
As noted above, we acquired MountainWest on February 14, 2023. We are currently integrating MountainWest into our operations and internal control processes. The scope of our assessment of our internal control over financial reporting as of December 31, 2023, will exclude MountainWest’s internal control over financial reporting.
Other than as set forth above, there have been no changes during the second quarter of 2023 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 have executed a consent decree with the DOJ and other agencies resolving the claims at these facilities, as well as alleged violations at certain other facilities. The consent decree which will become effective upon final entry by the United States District Court for the District of Colorado, requires both payment of a civil penalty in the amount of $3.75 million and injunctive relief.
Other environmental matters called for by this Item are described under the caption “Environmental Matters” in Note 9 – 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 – 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, 2022, as filed with the SEC on February 27, 2023, includes risk factors that could materially affect our business, financial condition, or future results. Those Risk Factors have not materially changed.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
ISSUER PURCHASES OF EQUITY SECURITIES
Period
Total Number of Shares Purchased
Average Price Paid Per Share
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1)
Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
April 1 - April 30, 2023
—
$
—
—
$
1,416,749,645
May 1 - May 31, 2023
1,842,276
$
28.77
1,842,276
$
1,363,755,349
June 1 - June 30, 2023
97,994
$
28.75
97,994
$
1,360,938,325
Total
1,940,270
1,940,270
(1)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.
Item 5. Other Information
During the three months ended June 30, 2023, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.
XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
Cover Page Interactive Data File. The cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document (contained in Exhibit 101).
* Filed herewith.
** Furnished herewith.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
THE WILLIAMS COMPANIES, INC.
(Registrant)
/s/ Mary A. Hausman
Mary A. Hausman
Vice President, Chief Accounting Officer and Controller (Duly Authorized Officer and Principal Accounting Officer)
