Item 7. Management’s Discussion and Analysis
Item 7. 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.
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, 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. Our reportable segments are comprised of the following business activities:
• Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco and Northwest Pipeline, 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 our Northeast JV (a consolidated VIE) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated VIE) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 50 percent equity-method investment in Blue Racer, and Appalachia Midstream Investments.
• 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.
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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 included in Part II, Item 8 of this report.
Dividends
In December 2022, we paid a regular quarterly dividend of $0.425 per share. On January 31, 2023, our board of directors approved a regular quarterly dividend of $0.4475 per share payable on March 27, 2023.
Overview of the Results of Operations
Net income (loss) attributable to The Williams Companies, Inc. for the year ended December 31, 2022, increased by $532 million over the prior year. 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 Pipelines Holding Company (MountainWest) which includes FERC-regulated interstate natural gas pipeline systems and natural gas storage capacity, for $1.08 billion of cash and assumption of $430 million outstanding principal amount of long-term debt, subject to working capital and post-closing adjustments. 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 establishes 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.
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 $424 million.
Trace Acquisition
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 Midstream for $972 million. 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.
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.
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In 2023, our operating results are expected to benefit from the MountainWest Acquisition, volume growth in the Haynesville and Northeast G&P areas, and annual inflation-based rate increases across our gathering and processing business. We also anticipate increases resulting from the development of our upstream oil and gas properties and 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 $1.40 billion to $1.70 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 this report.
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.
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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.
Regional Energy Access
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 the full 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 May 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 Virginia and North Carolina to delivery points in North Carolina. We plan to place the project into service as early as the 2024/2025 winter heating season 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 first quarter of 2025, 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.
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.
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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 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.
Critical Accounting Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.
Pension and Postretirement Obligations
We have pension and other postretirement benefit plans that require the use of assumptions and estimates to determine the benefit obligations and costs. These estimates and assumptions involve significant judgement and actual results will likely be different than anticipated. Estimates and assumptions utilized include the expected long-term rates of return on plan assets, discount rates, cash balance interest crediting rate, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed. The assumptions utilized to compute the benefit obligations and costs are shown in Note 7 – Employee Benefit Plans of Notes to Consolidated Financial Statements.
The following table presents the estimated increase (decrease) in net periodic benefit cost and obligations resulting from a one-percentage-point change in the specific assumption.
Benefit Cost Benefit Obligation
One-
Percentage-
Point
Increase One-
Percentage-
Point
Decrease One-
Percentage-
Point
Increase One-
Percentage-
Point
Decrease
(Millions)
Pension benefits:
Discount rate
$ (21) $ (1) $ (69) $ 80
Expected long-term rate of return on plan assets
(11) 11 — —
Cash balance interest crediting rate
5 (25) 50 (43)
Other postretirement benefits:
Discount rate
(3) 2 (14) 16
Expected long-term rate of return on plan assets
(2) 2 — —
Our expected long-term rates of return on plan assets, as determined at the beginning of each fiscal year, are based on historical returns, forward-looking capital market expectations of at least 10 years from our third-party independent investment advisor, as well as the investment strategy and relative weightings of the asset classes within the investment portfolio. Our expected long-term rate of return on plan assets used for our pension plans was 3.81 percent in 2022. The 2022 actual return on plan assets for our pension plans was a loss of approximately 9.7 percent. The 10-year average rate of return on pension plan assets through December 2022 was approximately 6.8 percent. The expected rates of return on plan assets are long-term in nature and are not significantly impacted by short-term market performance.
The discount rates for our pension and other postretirement benefit plans are determined separately based on an approach specific to our plans, which considers a yield curve of high-quality corporate bonds and the duration of the expected benefit cash flows of each plan.
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The cash balance interest crediting rate assumption represents the average long-term rate by which the pension plans’ cash balance accounts are expected to grow. Interest on the cash balance accounts is based on the 30-year U.S. Treasury securities rate.
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Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2022. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
Year Ended December 31,
2022 $ Change
from
2021* % Change
from
2021* 2021 $ Change
from
2020* % Change
from
2020* 2020
(Millions)
Revenues:
Service revenues
$ 6,536 +535 +9 % $ 6,001 +77 +1 % $ 5,924
Service revenues – commodity consideration
260 +22 +9 % 238 +109 +84 % 129
Product sales
4,556 +20 — % 4,536 +2,865 +171 % 1,671
Net gain (loss) on commodity derivatives (387) -239 -161 % (148) -143 NM (5)
Total revenues
10,965 10,627 7,719
Costs and expenses:
Product costs
3,369 +562 +14 % 3,931 -2,386 -154 % 1,545
Net processing commodity expenses 88 +13 +13 % 101 -33 -49 % 68
Operating and maintenance expenses
1,817 -269 -17 % 1,548 -222 -17 % 1,326
Depreciation and amortization expenses
2,009 -167 -9 % 1,842 -121 -7 % 1,721
Selling, general, and administrative expenses
636 -78 -14 % 558 -92 -20 % 466
Impairment of certain assets — +2 +100 % 2 +180 +99 % 182
Impairment of goodwill — — — % — +187 +100 % 187
Other (income) expense – net
28 -14 -100 % 14 +8 +36 % 22
Total costs and expenses
7,947 7,996 5,517
Operating income (loss) 3,018 2,631 2,202
Equity earnings (losses) 637 +29 +5 % 608 +280 +85 % 328
Impairment of equity-method investments — — — % — +1,046 +100 % (1,046)
Other investing income (loss) – net 16 +9 +129 % 7 -1 -13 % 8
Interest expense (1,147) +32 +3 % (1,179) -7 -1 % (1,172)
Other income (expense) – net 18 +12 +200 % 6 +49 NM (43)
Income (loss) before income taxes 2,542 2,073 277
Less: Provision (benefit) for income taxes 425 +86 +17 % 511 -432 NM 79
Net income (loss)
2,117 1,562 198
Less: Net income (loss) attributable to noncontrolling interests
68 -23 -51 % 45 -58 NM (13)
Net income (loss) attributable to The Williams Companies, Inc.
$ 2,049 +532 +35 % $ 1,517 +1,306 NM $ 211
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* + = 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.
2022 vs. 2021
Service revenues increased primarily due to higher gathering and processing rates driven by favorable commodity prices and annual contractual rate escalations for certain of our West and Northeast G&P operations, higher volumes including from the Trace Acquisition and NorTex Asset Purchase, higher transportation fee revenues associated with the Leidy South expansion project placed fully in service at Transco in December 2021,
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and higher reimbursable electric power costs and storage rates which are substantially offset in Operating and maintenance expenses .
Service revenues – commodity consideration increased primarily due to higher NGL prices, partially offset by lower NGL 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 increased primarily due to higher marketing sales prices and volumes, including increased volumes associated with the Sequent Acquisition in third-quarter 2021 and the Trace Acquisition in second-quarter 2022. Product sales also increased due to higher sales volumes and prices associated with our upstream operations and system management gas sales, as well as higher prices and lower volumes related to our equity NGL sales activities. These increases were partially offset by an unfavorable change in natural gas marketing sales primarily due to the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs (see Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements). 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, including significant 2022 lower of cost or net realizable value adjustments to our natural gas inventory.
The unfavorable change in Net gain (loss) on commodity derivatives primarily reflects higher net unrealized losses in our Gas & NGL Marketing Services segment, and higher net realized losses related to derivative contracts in our Other segment. Lower net realized losses at our West segment and a net unrealized gain at our Other segment in 2022 partially offset these impacts. 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 the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs. This decrease was partially offset by higher prices and volumes associated with our NGL marketing activities, including the increase in volumes associated with the Trace Acquisition in second-quarter 2022, as well as significant 2022 lower of cost or net realizable value adjustments to our NGL inventory. Product costs also increased due to higher system management gas purchases and higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production activities.
Net processing commodity expenses decreased primarily due to the impact of a 2022 net unrealized gain on derivatives for processing plant shrink gas purchases and lower volumes for natural gas purchases associated with our equity NGL production activities, partially offset by higher net realized prices.
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— Year-Over-Year 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 and maintenance costs, including $63 million of higher reimbursable electric power and storage costs which are substantially offset in Service revenues. The increase was also a result of higher expenses associated with our upstream operations, increased costs associated with Transco's Leidy South expansion project placed in service in December 2021, higher employee-related expenses, and higher expenses associated with the 2022 Trace Acquisition and NorTex Asset Purchase.
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Depreciation and amortization expenses increased primarily due to amortization of intangibles acquired in the Sequent and Trace Acquisitions and an increase in depreciation at Transco related to ARO revisions (offset in Other (income) expense – net within Operating income (loss) resulting in no net impact on our results of operations), partially offset by the absence of 2021 depreciation on certain decommissioned facilities in our West segment.
Selling, general, and administrative expenses increased primarily due to higher employee-related expenses driven by the Sequent Acquisition in July 2021 and higher expenses for various corporate costs, including technology costs to support efforts to track and quantify emissions associated with natural gas procurement, transmission, and delivery.
Other (income) expense – net within Operating income (loss) changed unfavorably primarily due to charges related to Eminence storage cavern abandonments and monitoring, as well as regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate, offset by the deferral of ARO depreciation (offset in Depreciation and amortization expenses resulting in no net impact on our results of operations).
Equity earnings (losses) changed favorably primarily due to increases at investments across our West segment, including RMM, and at Laurel Mountain, partially offset by a decrease at Appalachia Midstream Investments.
Provision (benefit) for income taxes changed favorably primarily due to a benefit associated with a decrease in our estimate of the state deferred income tax rate, a benefit related to the release of a valuation allowance, and federal settlements, partially offset by higher pre-tax income. See Note 6 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to higher results at the Northeast JV.
2021 vs. 2020
Service revenues increased primarily due to higher transportation fee revenues associated with expansion projects placed in service at Transco in 2020 and 2021, higher revenue associated with reimbursable electricity expenses, and higher processing and fractionation revenues in our Northeast G&P segment. This increase was partially offset by lower volume deficiency fee revenues, lower gathering volumes, and lower deferred revenue amortization.
Service revenues – commodity consideration increased primarily due to higher NGL prices. These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided. Most of these NGL volumes are sold during the month processed and therefore are offset within Product costs below.
Product sales increased primarily due to higher prices and volumes associated with our natural gas and NGL marketing activities, as well as the inclusion of our recently acquired upstream operations. This increase also includes higher prices related to our equity NGL sales activities. These increases were partially offset by negative product marketing sales from operations acquired in the Sequent Acquisition in 2021 (which does not reflect commodity derivative net realized gains discussed below).
Net gain (loss) on commodity derivatives includes realized and unrealized gains and losses from derivative instruments. The unfavorable change primarily reflects net unrealized losses in our Gas & NGL Marketing Services segment, and net realized losses related to derivative contracts in our West and Other segments. Net realized gains at our Gas & NGL Marketing Services segment partially offset these impacts.
Product costs increased primarily due to higher prices and volumes associated with our natural gas and NGL marketing activities, as well as higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production activities.
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Net processing commodity expenses increased primarily due to higher prices for natural gas purchases associated with our equity NGL production activities, partially offset by lower volumes.
Operating and maintenance expenses increased primarily due to the inclusion of our recently acquired upstream operations and higher employee-related expenses, which reflect the absence of a 2020 favorable impact of a change in an employee benefit policy and increased incentive compensation costs associated with improved company performance, as well as higher reimbursable electricity expenses.
Depreciation and amortization expenses increased primarily due to the inclusion of our recently acquired upstream operations, reduced estimated useful lives for certain facilities in our West segment decommissioned during 2021, new assets placed in-service at Transco, and the amortization of intangible assets resulting from the Sequent Acquisition.
Selling, general, and administrative expenses increased primarily due to higher employee-related expenses, which reflect increased incentive compensation costs associated with improved company performance, Sequent Acquisition employee-related costs, and the absence of a 2020 favorable impact of a change in an employee benefit policy, partially offset by lower expenses for various corporate costs.
Impairment of certain assets reflects the 2020 impairment of our Northeast Supply Enhancement development project and certain gathering assets in the Marcellus Shale region (see Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
Impairment of goodwill reflects the goodwill impairment charge at the Northeast reporting unit in 2020 (see Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
Equity earnings (losses) changed favorably primarily due to the absence of the 2020 impairment of goodwill at RMM, increases at Appalachia Midstream Investments, Laurel Mountain, Blue Racer, Aux Sable, and Discovery, partially offset by a decrease at OPPL.
Impairment of equity-method investments reflects the absence of 2020 impairments to various equity-method investments (see Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
The favorable change in Other income (expense) – net below Operating income (loss) reflects the absence of a 2020 charge for a legal settlement associated with former olefins operations and the absence of 2020 write-offs of certain regulatory assets related to cancelled projects, partially offset by the unfavorable impact of a 2021 accrual for a loss contingency.
Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income. See Note 6 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to the absence of our partner’s share of the 2020 goodwill impairment at the Northeast reporting unit.
Year-Over-Year Operating Results – Segments
We evaluate segment operating performance based upon Modified EBITDA . Note 18 – 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.
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Transmission & Gulf of Mexico
Year Ended December 31,
2022 2021 2020
(Millions)
Service revenues $ 3,579 $ 3,385 $ 3,257
Service revenues – commodity consideration (1) 64 52 21
Product sales (1) 404 349 191
Segment revenues 4,047 3,786 3,469
Product costs (1) (399) (349) (193)
Net processing commodity expenses (1) (26) (17) (7)
Other segment costs and expenses (1,141) (980) (886)
Impairment of certain assets — (2) (170)
Proportional Modified EBITDA of equity-method investments 193 183 166
Transmission & Gulf of Mexico Modified EBITDA $ 2,674 $ 2,621 $ 2,379
Commodity margins $ 43 $ 35 $ 12
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(1) Included as a component of Commodity margins .
2022 vs. 2021
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 $163 million increase in Transco’s service revenues primarily associated with the Leidy South expansion project placed fully in service in December 2021, park and loan services, short-term firm transportation, overall demand, and commodity fee revenues. Additionally, 2022 benefited from higher reimbursable electric power costs and storage rates effective since the second quarter of 2022, partially offset by lower cash out surcharges, all of which are offset by similar changes in electricity, storage and cash out charges reflected in Other segment costs and expenses;
• A $21 million increase in the Eastern Gulf Coast region primarily due to higher production handling and gathering volumes from the absence of temporary shut-ins due to producer operational issues and weather-related events in 2021, partially offset by a decrease at Gulfstar One for the Tubular Bells field primarily due to lower production handling, gathering and transportation volumes from natural decline;
• A $16 million increase primarily related to storage and transportation revenues due to the acquisition of NorTex in August 2022; partially offset by
• A $13 million decrease in the Western Gulf Coast region primarily at Perdido due to lower transportation and gathering volumes from temporary downtime from producer operational issues in 2022.
Commodity margins associated with our equity NGLs increased $5 million primarily driven by favorable NGL sales prices, partially offset by higher prices for natural gas purchases associated with our equity NGL production activities.
Other segment costs and expenses increased primarily due to higher operating costs including higher reimbursable electric power costs and storage costs, partially offset by favorable cash out charges, all of which are offset by similar changes in electricity reimbursements, cash out charges, and storage revenues reflected in Service revenues. Additionally, 2022 was impacted by higher costs associated with the Leidy South expansion project;
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maintenance costs primarily related to general maintenance at Transco, Gulf Coast region, and Northwest Pipeline; charges related to Eminence storage cavern abandonments and monitoring; and regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate, higher employee-related costs, corporate allocations, and operations acquired in the NorTex Asset Purchase. These increases are partially offset by a favorable change in the deferral of ARO related depreciation at Transco.
2021 vs. 2020
Transmission & Gulf of Mexico Modified EBITDA increased primarily due to favorable changes to Impairment of certain assets and Service revenues, partially offset by higher Other segment costs and expenses.
Service revenues increased primarily due to:
• A $135 million increase in Transco’s and Northwest Pipeline’s natural gas transportation and storage revenues primarily associated with expansion projects placed in service in 2020 and 2021, higher reimbursable electric power costs and a cash out surcharge, which are offset by similar changes in electricity and cash out charges, reflected in Other segment costs and expenses ;
• A $21 million increase from the Norphlet pipeline associated primarily with higher deferred revenue amortization and higher volumes;
• An $18 million increase at Perdido primarily driven by higher volumes due to the absence of temporary shut-ins in 2020 related to scheduled maintenance and fewer Western Gulf of Mexico weather-related events; partially offset by
• A $25 million decrease at Gulfstar One for the Tubular Bells field primarily associated with lower deferred revenue amortization from lower contractually determined maximum daily quantities;
• A $17 million decrease due to lower volumes at Gulfstar One in the Gunflint field due to ongoing producer operational issues, partially offset by the lower temporary shut-ins related to pricing in 2020.
Commodity margins associated with our equity NGLs increased $21 million primarily driven by favorable NGL sales prices.
Other segment costs and expenses increased primarily due to higher incentive and benefit employee-related costs as previously discussed; higher operating costs, including higher reimbursable electric power costs; and a cash out surcharge reserve, which are offset by similar changes in electricity and cash out reimbursements, reflected in Service revenues; and higher operating taxes, partially offset by a favorable change associated with the deferral of asset retirement obligation-related depreciation at Transco.
Impairment of certain assets reflects the absence of the impairment of our Northeast Supply Enhancement development project in 2020 (see Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
Proportional Modified EBITDA of equity-method investments increased at Discovery driven by higher NGL sales prices and higher volumes due to the absence of prior year scheduled maintenance.
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Northeast G&P
Year Ended December 31,
2022 2021 2020
(Millions)
Service revenues $ 1,654 $ 1,528 $ 1,465
Service revenues – commodity consideration (1) 14 7 7
Product sales (1) 134 99 57
Segment revenues 1,802 1,634 1,529
Product costs (1) (135) (99) (57)
Net processing commodity expenses (1) (3) (2) (3)
Other segment costs and expenses (522) (503) (441)
Impairment of certain assets — — (12)
Proportional Modified EBITDA of equity-method investments 654 682 473
Northeast G&P Modified EBITDA $ 1,796 $ 1,712 $ 1,489
Commodity margins $ 10 $ 5 $ 4
(1) Included as a component of Commodity margins .
2022 vs. 2021
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 $64 million increase in revenues at the Northeast JV primarily related to higher gathering, processing, and fractionation volumes as well as higher processing rates;
• A $43 million increase in revenues in the Utica Shale region primarily related to higher gathering rates resulting from annual cost of service contract redeterminations, as well as proceeds from the release of an acreage dedication;
• A $14 million increase in revenues associated with reimbursable expenses, which is offset by similar changes in the charges reflected in Other segment costs and expenses;
• No change in revenues at Susquehanna Supply Hub primarily related to higher gathering rates, offset by lower gathering volumes.
Other segment costs and expenses increased primarily due to higher operating expenses, including higher electricity and fuel, which is partially offset in Service revenues .
Proportional Modified EBITDA of equity-method investments decreased at Appalachia Midstream Investments primarily driven by lower gathering rates resulting from annual cost of service contract redeterminations as well as lower volumes. Additionally, there was a decrease at Blue Racer primarily due to lower volumes. The decrease was partially offset by an increase at Laurel Mountain primarily due to higher commodity-based gathering rates.
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2021 vs. 2020
Northeast G&P Modified EBITDA increased primarily due to increased Proportional Modified EBITDA of equity-method investments and higher Service revenues , partially offset by increased Other segment costs and expenses .
Service revenues increased primarily due to:
• A $27 million increase in revenues associated with reimbursable electricity expenses, which is offset by similar changes in electricity charges, reflected in Other segment costs and expenses;
• A $23 million increase in revenues at the Northeast JV primarily related to higher processing and fractionation volumes, partially offset by lower gathering volumes;
• A $6 million increase in revenues at Susquehanna Supply Hub primarily related to higher gathering rates, partially offset by lower gathering volumes.
Other segment costs and expenses increased primarily due to higher maintenance and operating expenses, including higher electricity charges, as well as higher incentive and benefit employee-related costs as previously discussed.
Impairment of certain assets reflects a $12 million impairment of certain gathering assets in the Marcellus Shale region in 2020 (see Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments primarily driven by higher volumes as well as the absence of our $26 million share of an impairment of certain assets in 2020 that were subsequently sold. Additionally, there was an increase at Blue Racer primarily due to the favorable impact of increased ownership as well as the absence of our $10 million share of an impairment of certain assets in 2020. There was also an increase at Laurel Mountain due to higher commodity-based gathering rates as well as the absence of our $11 million share of an impairment of certain assets in 2020 that were subsequently sold and higher MVC revenue, partially offset by lower volumes, and an increase at Aux Sable.
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West
Year Ended December 31,
2022 2021 2020
(Millions)
Service revenues $ 1,542 $ 1,248 $ 1,272
Service revenues – commodity consideration (1)
182 179 101
Product sales (1) 841 643 152
Net realized gain (loss) on commodity derivatives – service revenues
(1) (15) —
Net realized gain (loss) on commodity derivatives – product sales (1)
(3) (29) (2)
Net realized gain (loss) on commodity derivatives (4) (44) (2)
Segment revenues 2,561 2,026 1,523
Product costs (1) (813) (608) (154)
Net processing commodity expenses (1) (105) (85) (58)
Other segment costs and expenses (564) (477) (474)
Proportional Modified EBITDA of equity-method investments 132 105 110
West Modified EBITDA $ 1,211 $ 961 $ 947
Commodity margins $ 102 $ 100 $ 39
________________
(1) Included as a component of Commodity margins .
2022 vs. 2021
West Modified EBITDA increased primarily due to higher Service revenues and a favorable change in Net realized gain (loss) on commodity derivatives, partially offset by higher Other segment costs and expenses.
Service revenues increased primarily due to:
• A $186 million increase in the Haynesville Shale region primarily due to higher gathering volumes including volumes from the Trace Acquisition as well as higher gathering rates driven by favorable commodity pricing;
• A $96 million increase in the Barnett Shale region primarily due to higher gathering rates driven by favorable commodity pricing;
• A $14 million increase associated with higher fractionation fees primarily due to higher fractionation volumes from a new contract;
• A $4 million increase in the Eagle Ford region primarily due to higher MVC revenues, escalated gathering rates, and higher deferred revenue amortization, substantially offset by lower volumes due to decreased producer activity; partially offset by
• A $10 million decrease in the Wamsutter region primarily due to lower MVC revenue.
Net realized gain (loss) on commodity derivatives – service revenues changed favorably due to a change in settled commodity prices relative to our hedge positions.
Product margins from our equity NGLs increased $6 million primarily due to higher net realized NGL sales prices, partially offset by higher net realized prices for natural gas purchases associated with our equity NGL production activities. Additionally, volumes of equity NGL sold and natural gas purchased associated with our
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equity NGL production activities were lower primarily due to a customer contract change. Margins from other sales activities increased $16 million primarily due to higher condensate sales and favorable pricing. Marketing margins decreased $20 million primarily due to the absence of the favorable impact of Winter Storm Uri in the first quarter of 2021.
Other segment costs and expenses increased primarily due to higher operating expenses related to timing and scope of activities including from operations acquired in the Trace Acquisition, the absence of gains on asset sales in 2021, higher corporate allocations, acquisition-related costs associated with the Trace Acquisition in 2022, and an unfavorable change in our net imbalance liability due to changes in pricing.
Proportional Modified EBITDA of equity-method investments increased primarily due to higher volumes at OPPL and higher commodity prices and volumes at RMM.
2021 vs. 2020
West Modified EBITDA increased primarily due to higher Commodity margins, partially offset by lower Service revenues .
Service revenues decreased primarily due to:
• A $63 million decrease associated with lower volumes, primarily due to production declines in the Eagle Ford Shale region which impact is substantially offset by recognition of higher MVC revenue (see below);
• A $22 million decrease driven by lower deferred revenue amortization, primary in the Barnett Shale region; partially offset by
• A $37 million increase associated with higher MVC revenue primarily in the Eagle Ford Shale region, partially offset by lower MVC revenue in the Wamsutter region;
• A $17 million increase in revenues associated primarily with reimbursable compressor power and fuel purchases due to higher prices related to the impact of Winter Storm Uri in the first quarter of 2021, which are offset by similar changes in Other segment costs and expenses;
• A $10 million increase associated with higher net realized gathering and processing rates, primarily in the Barnett Shale and Piceance regions due to higher commodity pricing, along with escalated gathering rates in the Eagle Ford Shale region, partially offset by a decrease in gathering rates in the Haynesville Shale region due to a customer contract change.
Marketing margins increased by $36 million primarily due to favorable changes in net realized natural gas and NGL prices, including the impact of Winter Storm Uri in the first quarter of 2021. Product margins from our equity NGLs increased by $13 million, primarily due to favorable net realized commodity price changes, partially offset by lower sales volumes. Margins on other sales of products increased $12 million primarily due to higher commodity prices.
Other segment costs and expenses increased primarily due to higher incentive and benefit employee-related expenses as previously discussed, higher reimbursable compressor power and fuel purchases which are offset in Service revenues, and higher compressor and plant fuel expenses which are not reimbursable, partially offset by gains on asset sales in 2021, lower leased compressor expenses, favorable changes in system gains and losses, lower legal and consulting expenses, and favorable settlements.
Proportional Modified EBITDA of equity-method investments decreased primarily due to lower volumes at OPPL, partially offset by higher volumes and commodity prices at Brazos Permian II.
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Gas & NGL Marketing Services
Year Ended December 31,
2022 2021 2020
(Millions)
Service revenues $ 3 $ 3 $ 32
Product sales (1) 3,534 4,292 1,602
Net realized gain (loss) from derivative instruments (1) 17 25 (3)
Net unrealized gain (loss) from derivative instruments (321) (109) —
Net gain (loss) on commodity derivatives (304) (84) (3)
Segment revenues 3,233 4,211 1,631
Net unrealized gain (loss) from derivative instruments within Net processing commodity expenses 47 — —
Product costs (1) (3,228) (4,152) (1,569)
Other segment costs and expenses (92) (37) (11)
Gas & NGL Marketing Services Modified EBITDA $ (40) $ 22 $ 51
Commodity margins $ 323 $ 165 $ 30
________________
(1) Included as a component of Commodity margins .
2022 vs. 2021
Gas & NGL Marketing Services Modified EBITDA decreased primarily due to higher net unrealized loss from derivative instruments and higher Other segment costs and expenses , partially offset by higher Commodity margins .
Commodity margins increased $158 million primarily due to:
• A $188 million increase in natural gas marketing margins which included the following:
◦ A $301 million increase in natural gas transportation capacity marketing margins primarily resulting from the Sequent Acquisition in the third quarter of 2021 and an increase in favorable pricing spreads in 2022 compared to 2021; partially offset by
◦ A $58 million decrease associated with our legacy natural gas marketing operations primarily due to the absence of the favorable impact of Winter Storm Uri in the first quarter of 2021;
◦ A $55 million decrease in natural gas storage marketing margins due primarily to an increase in lower of cost or net realizable value inventory adjustments of $115 million and higher storage fees, partially offset by higher storage withdrawals in 2022 compared to 2021.
• A $30 million decrease in our NGL marketing margins primarily due to lower of cost or net realizable value inventory adjustments in 2022.
Net unrealized gain (loss) from derivative instruments changed primarily due to the Sequent Acquisition in July 2021, and a change in forward commodity prices relative to our hedge positions in 2022 compared to 2021.
Other segment costs and expenses increased primarily due to higher employee-related costs related to the Sequent Acquisition and higher corporate allocations.
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2021 vs. 2020
Gas & NGL Marketing Services Modified EBITDA decreased primarily due to higher net unrealized losses from derivative instruments, lower Service revenues , and higher segment costs and expenses, partially offset by higher Commodity margins.
Service revenues decreased due to the absence of a temporary volume deficiency fee associated with reduced volumes from a shipper on OPPL in 2020.
Commodity margins increased $135 million primarily due to:
• A $112 million increase associated with our legacy natural gas and NGL marketing operations primarily due to favorable changes in net realized natural gas prices, including the impact of Winter Storm Uri in the first quarter of 2021;
• A $23 million increase associated with the operations acquired in the Sequent Acquisition in 2021 including $35 million primarily related to favorable pricing spreads on transportation capacity reflecting losses on physical transaction settlements more than offset by net realized gains on derivatives. The transportation related margin was partially offset by a $12 million unfavorable margin related to storage activity. The unfavorable storage margin reflects gains on physical transaction settlements offset by an $18 million charge related to the partial recognition of a purchase accounting inventory fair value adjustment which increased the weighted-average cost of inventory and $13 million related to a lower of cost or net realizable value inventory adjustment.
The Net unrealized gain (loss) from derivative instruments changed primarily due to the Sequent Acquisition in July 2021, and a change in forward commodity prices relative to our hedge positions.
Other segment costs and expenses increased primarily due to employee-related costs associated with the operations acquired in the Sequent Acquisition in 2021.
Other
Year Ended December 31,
2022 2021 2020
(Millions)
Service revenues $ 24 $ 32 $ 34
Product sales (1) 706 333 —
Net realized gain (loss) from derivative instruments (1) (104) (20) —
Net unrealized gain (loss) from derivative instruments 25 — —
Net gain (loss) on commodity derivatives (79) (20) —
Segment revenues 651 345 34
Other segment costs and expenses (217) (167) (49)
Other Modified EBITDA $ 434 $ 178 $ (15)
Net realized product sales $ 602 $ 313 $ —
________________
(1) Included as a component of Net realized product sales .
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2022 vs. 2021
Other Modified EBITDA increased primarily due to $248 million higher results from our upstream operations which included the following:
• A $289 million increase in Net realized product sales primarily due to higher commodity prices in 2022, partially offset by the absence of the favorable impact of Winter Storm Uri in 2021 and an unfavorable change in Net realized gain (loss) from derivative instruments due to an increase in commodity prices relative to our hedge positions and an increase in the volume of production hedged in 2022 compared to 2021. Net realized product sales also increased due to higher production from new wells and higher volumes associated with acquisitions of additional ownership interests in 2021;
• A $25 million favorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity prices relative to our hedge positions and an increase in the volume of production hedged in 2022 compared to 2021; partially offset by
• A $66 million increase in Other segment costs and expenses primarily due to the increased scale of our upstream operations and higher associated production taxes which were also impacted by higher commodity prices and higher volumes as well as higher tax rates.
Other segment costs and expenses also includes an $11 million charge related to an accrual for loss contingency in 2022, substantially offset by the absence of a $10 million charge related to an accrual for loss contingency in 2021.
2021 vs. 2020
Other Modified EBITDA increased primarily due to:
• A $168 million increase related to our upstream operations, including the favorable commodity price impact of Winter Storm Uri in the first quarter of 2021;
• A $24 million increase due to the absence of a 2020 charge related to a legal settlement associated with our former olefins operations;
• A $15 million increase due to the absence of 2020 charges related to write-offs of certain regulatory assets associated with cancelled projects; partially offset by
• A $10 million decrease associated with a 2021 charge related to a legal settlement.
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Management’s Discussion and Analysis of Financial Condition and Liquidity
Overview
We have continued to focus on earnings and cash flow growth, while continuing to improve leverage metrics and operating costs metrics. During 2022, we issued approximately $1.75 billion of new long-term debt primarily to fund current or near-term maturities. In April 2022, we completed the Trace Acquisition; and in August 2022, we completed the NorTex Asset Purchase, both of which were funded with available sources of short-term liquidity (see Note 3 – Acquisitions of Notes to Consolidated Financial Statements). See also the section titled Sources (Uses) of Cash .
Outlook
Our growth capital and investment expenditures in 2023 are currently expected to be in a range from $1.40 billion to $1.70 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, 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 assumption of $430 million outstanding principal amount of long-term debt, subject to working capital and post-closing adjustments. The acquisition was funded with available sources of short-term liquidity.
As of December 31, 2022, we have approximately $627 million 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.
Liquidity
Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 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
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At December 31, 2022, we have approximately $21.927 billion of long-term debt due after one year. See Note 12 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements for the aggregate maturities over the next five years. 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 .
At December 31, 2022, we had a working capital deficit of $1.093 billion, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:
Available Liquidity December 31, 2022
(Millions)
Cash and cash equivalents $ 152
Capacity available under our $3.75 billion credit facility, less amounts outstanding under our $3.5 billion commercial paper program (1) 3,400
$ 3,552
__________
(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 $350 million of commercial paper outstanding at December 31, 2022. The highest amount outstanding under our commercial paper program and credit facility during 2022 was $1.219 billion. At December 31, 2022, we were in compliance with the financial covenants associated with our credit facility. See Note 12 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements for additional information on our credit facility and commercial paper program.
Dividends
We increased our regular quarterly cash dividend to common stockholders by approximately 3.7 percent from the $0.41 per share paid in each quarter of 2021, to $0.425 per share paid in each quarter of 2022.
Registrations
In February 2021, we filed a shelf registration statement as a well-known seasoned issuer.
Distributions from Equity-Method Investees
The organizational documents of entities in which we have an equity-method investment generally require periodic distributions of their available cash to their members. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses. See Note 8 – Investing Activities of Notes to Consolidated Financial Statements for our more significant equity-method investees.
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
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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.
Sources (Uses) of Cash
The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented (see Notes to Consolidated Financial Statements for the Notes referenced in the table):
Cash Flow Year Ended December 31,
Category 2022 2021 2020
(Millions)
Sources of cash and cash equivalents:
Operating activities – net Operating $ 4,889 $ 3,945 $ 3,496
Proceeds from long-term debt (see Note 12)
Financing 1,755 2,155 2,199
Proceeds from credit-facility borrowings Financing — — 1,700
Proceeds from commercial paper - net Financing 345 — —
Contributions in aid of construction Investing 12 52 37
Uses of cash and cash equivalents:
Payments of long-term debt (see Note 12)
Financing (2,876) (894) (2,141)
Common dividends paid Financing (2,071) (1,992) (1,941)
Payments on credit-facility borrowings Financing — — (1,700)
Capital expenditures Investing (2,253) (1,239) (1,239)
Purchases of businesses, net of cash acquired (see Note 3)
Investing (933) (151) —
Dividends and distributions paid to noncontrolling interests Financing (204) (187) (185)
Purchases of and contributions to equity-method investments (see Note 8)
Investing (166) (115) (325)
Other sources / (uses) – net Financing and Investing (26) (36) (48)
Increase (decrease) in cash and cash equivalents $ (1,528) $ 1,538 $ (147)
Operating activities
The factors that determine operating activities are largely the same as those that affect Net income (loss) , with the exception of noncash items such as Depreciation and amortization , Provision (benefit) for deferred income taxes , Equity (earnings) losses , Impairment of goodwill , Impairment of equity-method investments , Impairment of certain assets , Net unrealized (gain) loss from derivative instruments , and Inventory write-downs.
Our Net cash provided (used) by operating activities in 2022 increased from 2021 primarily due to higher operating income (excluding noncash items as previously discussed), favorable changes in margin requirements, and higher Distributions from equity-method investees , partially offset by net unfavorable changes in net operating working capital.
Our Net cash provided (used) by operating activities in 2021 increased from 2020 primarily due to higher operating income (excluding noncash items as previously discussed), favorable changes in net operating working capital reflecting the absence in 2021 of the Transco rate refund payment made in 2020, and higher distributions from unconsolidated affiliates in 2021, partially offset by unfavorable changes in current and noncurrent derivative assets and liabilities.
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Environmental
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 (see Note 17 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements). We are monitoring these sites in a coordinated effort with other potentially responsible parties, the 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. Current estimates of the most likely costs of such activities are approximately $40 million, all of which are included in Accrued and other current liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet at December 31, 2022. We will seek to recover approximately $4 million of accrued costs related to remediation activities by our interstate gas pipelines through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2022, we paid approximately $5 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $11 million in 2023 for these activities. 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 December 31, 2022, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.
The EPA and various state regulatory agencies routinely propose and promulgate new rules and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine and combustion turbine maximum achievable control technology, reviews and updates to the National Ambient Air Quality Standards, and rules for new and existing source performance standards for volatile organic compounds 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 the 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 these regulatory impacts at this time.
We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates for our interstate natural gas transmission pipelines. Historically, with limited exceptions, we have been permitted recovery of these environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings.
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