WILLIAMS COMPANIES 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
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 theFERC 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 theFERC's ratemaking process, but we also may negotiate rates with our customers pursuant to the terms of our tariffs andFERC policy. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates. The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers. These services include natural gas gathering, processing, treating, and compression, NGL fractionation and transportation, crude oil production handling and transportation, marketing services for NGL, crude oil and natural gas, as well as storage facilities. Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are conducted, managed, and presented within the following reportable segments: Transmission &Gulf of Mexico , Northeast G&P, West, and Sequent. All remaining business activities are included in Other. As ofDecember 31, 2021 , our reportable segments are comprised of the following businesses: •Transmission &Gulf of Mexico is comprised of our interstate natural gas pipelines,Transco and Northwest Pipeline, as well as natural gas gathering and processing and crude oil production handling and transportation assets in theGulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated variable interest entity), which is a proprietary floating production system, a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery. •Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in theMarcellus Shale region primarily inPennsylvania andNew York , and theUtica Shale region of easternOhio , as well as a 65 percent interest in our Northeast JV (a consolidated variable interest entity) which operates in WestVirginia, Ohio , andPennsylvania , a 66 percent interest in Cardinal (a consolidated variable interest entity) which operates inOhio , a 69 percent equity-method investment inLaurel Mountain , a 50 percent equity-method investment in Blue Racer (we previously effectively owned a 29 percent indirect interest in Blue Racer through our 58 percent equity-method investment in BRMH until acquiring a controlling interest of BRMH inNovember 2020 and the remaining interest inSeptember 2021 ), and Appalachia Midstream Investments, a wholly owned subsidiary that owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in theMarcellus Shale region. •West is comprised of our gas gathering, processing, and treating operations in theRocky Mountain region ofColorado andWyoming , theBarnett Shale region of north-centralTexas , theEagle Ford Shale region of southTexas , theHaynesville Shale region of northwestLouisiana , and the Mid-Continent region which includes theAnadarko and Permian basins. This segment also includes NGL and natural gas marketing business (excluding the activities within the Sequent segment described below), storage facilities, an undivided 50 percent interest in an NGL fractionator nearConway, Kansas , a 50 percent equity-method investment in OPPL, a 50 percent equity-method investment in RMM, a 20 percent equity-method investment inTarga Train 7, and a 15 percent interest inBrazos Permian II, LLC (Brazos Permian II). •Sequent includes the operations ofSequent Energy Management, L.P. and Sequent Energy Canada, Corp. acquired onJuly 1, 2021 (Sequent Acquisition). Sequent focuses on risk management and the marketing, 43 -------------------------------------------------------------------------------- trading, storage, and transportation of natural gas for a diverse set of natural gas utilities, municipalities, power generators, and producers, and moves gas to markets through transportation and storage agreements on strategically positioned assets, including ourTransco system.
•Other includes our upstream operations and minor business activities that are not reportable segments, as well as corporate operations.
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
InDecember 2021 , we paid a regular quarterly dividend of$0.41 per share. OnFebruary 1, 2022 , our board of directors approved a regular quarterly dividend of$0.425 per share payable onMarch 28, 2022 .
Overview
Net income (loss) attributable toThe Williams Companies, Inc. for the year endedDecember 31, 2021 , increased by$1.3 billion over the prior year, reflecting$223 million of higher net realized commodity margins,$280 million of increased earnings from equity-method investments, primarily due to the absence of our$78 million share of a 2020 impairment of goodwill at West and higher volumes within Northeast G&P, as well as net realized product sales from upstream operations of$313 million and$106 million of higher transportation fee revenues associated with expansion projects placed in service atTransco in 2020 and 2021. The improvement over last year was partially offset by$314 million of higher operating and administrative costs,$121 million of higher depreciation and amortization expense, and a$109 million unfavorable impact of 2021 net unrealized losses from commodity derivative instruments at Sequent. The improvement over last year also reflects the absence of$1.4 billion in pre-tax charges in 2020 related to impairments of equity-method investments, goodwill, and certain assets, of which$65 million was attributable to noncontrolling interests. The provision for income taxes changed unfavorably by$432 million primarily due to higher pre-tax income. The Sequent segment includes$109 million of net unrealized losses from commodity derivatives not designated as hedges for accounting purposes. Sequent can experience significant earnings volatility from the fair value accounting required for the derivatives used to hedge a portion of the economic value of the underlying transportation and storage portfolio. However, the unrealized fair value measurement gains and losses are generally offset by valuation changes in the economic value of the underlying transportation and storage portfolio, which is not recognized until the underlying transportation and storage transaction occurs. Recent Developments Share Repurchase Program InSeptember 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 stock repurchase program does not have an expiration date. There were no repurchases under the program as ofDecember 31, 2021 .
Sequent Acquisition
InJuly 2021 , we completed the acquisition of 100 percent of Sequent. Total consideration for this acquisition was$159 million , which included$109 million related to working capital. Sequent focuses on risk management and the marketing, trading, storage, and transportation of natural gas for a diverse set of natural gas utilities, municipalities, power generators, and producers, and moves gas to markets through transportation and storage agreements on strategically positioned assets, including ourTransco system. The addition of Sequent complements 44 --------------------------------------------------------------------------------
the geographic footprint of our core pipeline transportation and storage business, enhances our gas marketing capabilities, and expands the suite of services we provide to our existing midstream customers.
In the third quarter of 2021, we conveyed certain oil and gas properties in theWamsutter field, which we acquired in 2021, to a venture along with certain oil and gas properties conveyed by a third-party operator in the region. Under the terms of the agreement, the third party owns a 25 percent and we own a 75 percent undivided interest in each well's working interest. We will retain ownership in the undeveloped acreage until certain acreage earning hurdles are met, at which time the remaining undeveloped acreage will be conveyed to the third party resulting in the third party owning 50 percent and us owning 50 percent. The combined properties consist of over 1.2 million net acres and an interest in over 3,500 wells. In the third quarter of 2021, we sold 50 percent of certain existing wells and wellbore rights in theSouth Mansfield area of theHaynesville Shale region to a third party operator, in a strategic effort to develop the acreage, thereby enhancing the value of our midstream natural gas infrastructure. Under the agreement, the third party will operate the upstream position and develop the undeveloped acreage. We will retain ownership in the undeveloped acreage until certain acreage earning and carried interest hurdles are met, at which time remaining undeveloped acreage will be conveyed to the third party resulting in the third party owning 75 percent and us owning 25 percent. Expansion Project Update Transmission &Gulf of Mexico Leidy South InJuly 2020 , we received approval from theFERC for the project to expandTransco's existing natural gas transmission system and also extend its system through a capacity lease withNational Fuel Gas Supply Corporation that will enable us to provide incremental firm transportation fromClermont, Pennsylvania and from the Zick interconnection onTransco's Leidy Line to theRiver Road regulating station inLancaster County, Pennsylvania . We placed 125 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and in September and October of 2021, we placed approximately 382 Mdth/d of additional capacity into service. We placed the remainder of the project into service inDecember 2021 . The project increased capacity by 582 Mdth/d.
InOctober 2019 , we received approval from theFERC to expandTransco's existing natural gas transmission system to provide incremental firm transportation capacity from thePleasant Valley interconnect with Dominion'sCove Point Pipeline inVirginia to the Station 65 pooling point inLouisiana . We placed 230 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and the project was fully in service onJanuary 1, 2021 . In total, the project increased capacity by 296 Mdth/d.
COVID-19
The outbreak of COVID-19 severely impacted global economic activity and caused significant volatility and negative pressure in financial markets. We continue to monitor the COVID-19 pandemic and have taken steps intended to protect the safety of our customers, employees, and communities, and to support the continued delivery of safe and reliable service to our customers and the communities we serve. Our financial condition, results of operations, and liquidity have not been materially impacted by effects of COVID-19.
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 inthe 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, 45 -------------------------------------------------------------------------------- environmental stewardship including seeking opportunities for renewable energy ventures, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe, reliable, clean energy services to our customers and an attractive return to our shareholders. Our business plan for 2022 includes a continued focus on earnings and cash flow growth. In 2022, our operating results are expected to benefit from growth in ourOhio Valley Midstream, Cardinal,Susquehanna , andHaynesville areas. We also anticipate increases resulting from recently completedTransco expansion projects and development of our upstream oil and gas properties. These increases are partially offset by the absence of favorable results captured during Winter Storm Uri in 2021 by our commodity marketing business and lower expected results in the Bradford Supply Hub primarily due to lower gathering rates resulting from annual cost of service contract redetermination. We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of safe, clean, and reliable energy infrastructure assets that continue to serve key growth markets and supply basins inthe United States . Our growth capital and investment expenditures in 2022 are expected to be in a range from$1.25 billion to$1.35 billion . Growth capital spending in 2022 primarily includesTransco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business, opportunities in theHaynesville area, and an expansion in the Western Gulf area. We also expect to invest capital in the development of our upstream oil and gas properties. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.
Potential risks and obstacles that could impact the execution of our plan include:
•Continued negative impacts of COVID-19 driving a global recession, which could result in downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products;
•Opposition to, and regulations affecting, our infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects;
•Counterparty credit and performance risk;
•Unexpected significant increases in capital expenditures or delays in capital project execution;
•Unexpected changes in customer drilling and production activities, which could negatively impact gathering and processing volumes;
•Lower than anticipated demand for natural gas and natural gas products which could result in lower than expected volumes, energy commodity prices, and margins;
•General economic, financial markets, or industry downturns, including increased inflation and interest rates;
•Physical damages to facilities, including damage to offshore facilities by weather-related events;
•Other risks set forth under Part I, Item 1A. Risk Factors in this report.
Expansion Projects
Our ongoing major expansion projects include the following:
Transmission &
Regional Energy Access
InMarch 2021 , we filed an application with theFERC for the project to expandTransco's existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in northeasternPennsylvania to multiple delivery points inPennsylvania ,New Jersey , andMaryland . We plan to place the project into service as early as the fourth quarter of 2024, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 829 Mdth/d. 46 --------------------------------------------------------------------------------
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 8 - 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- One- One- One-
Percentage- Percentage- Percentage- Percentage-
Point Point Point Point
Increase Decrease Increase Decrease
(Millions)
Pension benefits:
Discount rate $ 2
$ -
(12) 12 - -
Cash balance interest crediting rate 6 (4) 66 (56)
Other postretirement benefits:
Discount rate (4) (1) (22) 27
Expected long-term rate of return on plan assets (3) 3 - -
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 3.69
percent in 2021. The 2021 actual return on plan assets for our pension plans was
approximately 4.9 percent. The 10-year average rate of return on pension plan
assets through December 2021 was approximately 9.2 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.
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
47
--------------------------------------------------------------------------------Results of Operations Consolidated Overview
The following table and discussion is a summary of our consolidated results of
operations for the three years ended
Year Ended December 31,
$ Change % Change $ Change % Change
from from from from
2021 2020* 2020* 2020 2019* 2019* 2019
(Millions)
Revenues:
Service revenues $ 6,001 +77 +1 % $ 5,924 -9 - % $ 5,933
Service revenues - commodity
consideration 238 +109 +84 % 129 -74 -36 % 203
Product sales 4,536 +2,865 +171 % 1,671 -392 -19 % 2,063
Net gain (loss) on commodity derivatives (148) -143 NM (5) -7 NM 2
Total revenues 10,627 7,719 8,201
Costs and expenses:
Product costs 3,931 -2,386 -154 % 1,545 +416 +21 % 1,961
Processing commodity expenses 101 -33 -49 % 68 +37 +35 % 105
Operating and maintenance expenses 1,548 -222 -17 % 1,326 +142 +10 %
1,468
Depreciation and amortization expenses 1,842 -121 -7 % 1,721 -7 - %
1,714
Selling, general, and administrative expenses 558 -92 -20 % 466 +92 +16 %
558
Impairment of certain assets 2 +180 +99 % 182 +282 +61 % 464 Impairment of goodwill - +187 +100 % 187 -187 NM - Other (income) expense - net 14 +8 +36 % 22 -12 -120 % 10 Total costs and expenses 7,996 5,517
6,280
Operating income (loss) 2,631 2,202
1,921
Equity earnings (losses) 608 +280 +85 % 328 -47 -13 %
375
Impairment of equity-method investments - +1,046 +100 % (1,046) -860 NM
(186)
Other investing income (loss) - net 7 -1 -13 % 8 -99 -93 % 107 Interest expense (1,179) -7 -1 % (1,172) +14 +1 % (1,186) Other income (expense) - net 6 +49 NM (43) -76 NM 33 Income (loss) from continuing operations before income taxes 2,073 277
1,064
Less: Provision (benefit) for income taxes 511 -432 NM 79 +256 +76 %
335
Income (loss) from continuing operations 1,562 198
729
Income (loss) from discontinued operations - - - % - +15 +100 % (15) Net income (loss) 1,562 198 714 Less: Net income (loss) attributable to noncontrolling interests 45 -58 NM (13) -123 -90 %
(136)
Net income (loss) attributable to The Williams Companies, Inc.$ 1,517 $ 211 $ 850 _______
* + = 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.
48
--------------------------------------------------------------------------------2021 vs. 2020
Service revenues increased primarily due to higher transportation fee revenues associated with expansion projects placed in service atTransco 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 in our West segment. Service revenues - commodity consideration increased primarily due to higher NGL prices. These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided. Most of these NGL volumes are sold during the month processed and therefore are offset within Product costs below. Product sales increased primarily due to higher 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 Sequent (which does not reflect Sequent's commodity derivative net realized gains discussed below). As we are acting as agent for our Sequent natural gas marketing customers, our natural gas marketing product sales are presented net of the related product costs of those activities. Net gain (loss) on commodity derivatives includes realized and unrealized gains and losses from derivative instruments. The unfavorable change primarily reflects net unrealized losses in our Sequent segment, and net realized losses related to derivative contracts in our West and Other segments. Net realized gains at our Sequent 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.
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.
The net sum of Service revenues - commodity consideration, Product sales, Product costs, Processing commodity expenses, and net realized gains and losses on commodity derivatives related to sales of product comprise our commodity margins. However, Product sales at our Other segment reflect sales related to our oil and gas producing properties and are excluded from our commodity margins. Operating and maintenance expenses increased primarily due to the inclusion of our recently acquired upstream operations and higher employee-related expenses, which reflect the absence of a 2020 favorable impact of a change in an employee benefit policy (see Note 5 - Other Income and Expenses of Notes to Consolidated Financial Statements) 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 atTransco , 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 employee-related costs, and the absence of a 2020 favorable impact of a change in an employee benefit policy (see Note 5 - Other Income and Expenses of Notes to Consolidated Financial Statements), partially offset by lower expenses for various corporate costs. 49 --------------------------------------------------------------------------------
Impairment of certain assets reflects the 2020 impairment of our Northeast
Supply Enhancement development project and certain gathering assets in the
Impairment of goodwill reflects the goodwill impairment charge at the Northeast reporting unit in 2020 (see Note 17 - 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 17 - 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.
2020 vs. 2019
Service revenues decreased primarily due to lower volumes in our West segment, lower deferred revenue amortization at Gulfstar One, the expiration of an MVC agreement in theBarnett Shale region, and temporary shut-ins at certain offshoreGulf of Mexico operations. This decrease was partially offset by higher Northeast G&P revenues driven by higher volumes and theMarch 2019 consolidation of UEOM (see Note 3 - Acquisitions of Notes to Consolidated Financial Statements), higher MVC revenue in our West segment, as well as higher transportation fee revenues atTransco and Northwest Pipeline associated with expansion projects placed in service in 2019 and 2020, increased volumes in the Eastern Gulf region, and higher deficiency fee revenue associated with lower volumes at OPPL. Service revenues - commodity consideration decreased due to lower commodity prices, as well as lower equity NGL processing volumes due to less producer drilling activity. 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 within the month processed and therefore are offset within Product costs below. Product sales decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL sales activities, as well as lower volumes associated with our equity NGL sales activities, partially offset by higher marketing volumes. This decrease also includes lower system management gas sales. Marketing sales and system management gas sales are substantially offset within Product costs. Product costs decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL production activities. This decrease also includes lower volumes acquired as commodity consideration for NGL processing services and lower system management gas purchases, partially offset by higher volumes for marketing activities.
Processing commodity expenses decreased primarily due to lower natural gas purchases associated with equity NGL production primarily due to lower natural gas prices and lower volumes.
50
--------------------------------------------------------------------------------
Operating and maintenance expenses decreased primarily due to lower
employee-related expenses, including the absence of 2019 severance and related
costs and the associated reduced costs in 2020, as well as the favorable impact
of a 2020 change in an employee benefit policy (see Note 5 - Other Income and
Expenses of Notes to Consolidated Financial Statements), and lower maintenance
and operating costs primarily due to timing and scope of activities. These
decreases are partially offset by higher expenses related to the consolidation
of UEOM.
Depreciation and amortization expenses increased primarily due to new assets
placed in service and the March 2019 consolidation of UEOM, partially offset by
lower expense related to assets that became fully depreciated in the fourth
quarter of 2019.
Selling, general, and administrative expenses decreased primarily due to lower
employee-related expenses, including the absence of 2019 severance and related
costs and the associated reduced costs in 2020, as well as the favorable impact
of a 2020 change in an employee benefit policy (see Note 5 - Other Income and
Expenses of Notes to Consolidated Financial Statements), and the absence of
transaction costs associated with our 2019 acquisition of UEOM and the formation
of the Northeast JV.
Impairment of certain assets includes the 2019 impairments of our Constitution
development project, certain Eagle Ford Shale gathering assets, and certain idle
gathering assets. The asset impairments in 2020 included our Northeast Supply
Enhancement development project and certain gathering assets in the Marcellus
Shale region (see Note 17 - 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 17 - Fair Value Measurements, Guarantees, and
Concentration of Credit Risk of Notes to Consolidated Financial Statements).
Equity earnings (losses) changed unfavorably primarily due to our share of 2020
impairments at equity-method investments (see Note 9 - Investing Activities of
Notes to Consolidated Financial Statements), and lower volumes at OPPL and
Discovery. These decreases were partially offset by favorable amortization of
basis differences related to impairments of several of our equity-method
investments which were recognized in first quarter 2020, as well as higher
volumes at Appalachia Midstream Investments, increased results at Blue Racer
driven by higher volumes and a higher ownership interest, and the absence of
2019 losses at Brazos Permian II.
Impairment of equity-method investments includes impairments to various equity-method investments in 2019 and 2020 (see Note 17 - Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).
The unfavorable change in Other investing income (loss) - net is primarily due to the absence of a 2019 gain on the sale of our equity-method investment in Jackalope, partially offset by the absence of a 2019 loss on the deconsolidation ofConstitution (see Note 9 - Investing Activities of Notes to Consolidated Financial Statements). The unfavorable change in Other income (expense) - net below Operating income (loss) includes a charge in the fourth quarter 2020 for a legal settlement associated with former olefins operations, lower equity allowance for funds used during construction (AFUDC), and 2020 write-offs of certain regulatory assets related to cancelled projects. Provision (benefit) for income taxes changed favorably primarily due to lower pre-tax income. See Note 6 - Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
The unfavorable change in Net income (loss) attributable to noncontrolling
interests is primarily due to the absence of the 2019 impairment of our
51
--------------------------------------------------------------------------------Year-Over-Year Operating Results - Segments
We evaluate segment operating performance based upon Modified EBITDA. Note 20 - Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP. Transmission &Gulf of Mexico Year Ended December 31, 2021 2020 2019 (Millions) Service revenues$ 3,385 $ 3,257 $ 3,311 Service revenues - commodity consideration 52 21 41 Product sales 349 191 288 Segment revenues 3,786 3,469 3,640 Product costs (349) (193) (288) Processing commodity expenses (17) (7) (16) Other segment costs and expenses (980) (886) (984) Impairment of certain assets (2) (170) (354)
Proportional Modified EBITDA of equity-method investments 183
166 177
Transmission & Gulf of Mexico Modified EBITDA $ 2,621 $ 2,379 $ 2,175
Commodity margins $ 35 $ 12 $ 25
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 inTransco'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
•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 WesternGulf 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. 52 --------------------------------------------------------------------------------
The net sum of Service revenues - commodity consideration, Product sales,
Product costs, Processing commodity expenses, comprise our Commodity margins.
Commodity margins associated with our equity NGLs increased
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 atTransco . Impairment of certain assets reflects the absence of the impairment of our Northeast Supply Enhancement development project in 2020 (see Note 17 - 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. 2020 vs. 2019 Transmission & Gulf of Mexico Modified EBITDA increased primarily due to lower Impairment of certain assets and favorable changes to Other segment costs and expenses, partially offset by decreased Service revenues.
Service revenues decreased primarily due to:
•A$115 million decrease due to lower deferred revenue amortization associated with the end of the exclusive use period at Gulfstar One for the Tubular Bells field;
•A
•A
•A
•A
•A
Commodity margins associated with our equity NGLs decreased
Other segment costs and expenses decreased primarily due to lower employee-related expenses, including the absence of 2019 severance and related costs and the associated reduced costs in 2020, as well as the favorable impact of a 2020 change in an employee benefit policy (see Note 5 - Other Income and Expenses of Notes to Consolidated Financial Statements), lower maintenance costs primarily due to a decrease in contracted services related to general maintenance and other testing atTransco , the absence of a 2019 charge for reversal of costs capitalized in previous periods. The 2020 period also benefited from net favorable changes to charges and credits associated with a regulatory asset related toTransco's asset retirement obligations, partially offset by lower equity AFUDC and higher operating taxes. Impairment of certain assets includes the absence of the impairment of ourConstitution development project in 2019, partially offset by the impairment of our Northeast Supply Enhancement development project in 2020 (see Note 17 - Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements). 53 --------------------------------------------------------------------------------
Proportional Modified EBITDA of equity-method investments decreased at Discovery
driven by lower volumes due to scheduled maintenance and temporary shut-ins
related to
Northeast G&P
Year Ended December 31,
2021 2020 2019
(Millions)
Service revenues $ 1,528 $ 1,465 $ 1,338
Service revenues - commodity consideration 7 7 12
Product sales 99 57 150
Segment revenues 1,634 1,529 1,500
Product costs (99) (57) (152)
Processing commodity expenses (2) (3) (8)
Other segment costs and expenses (503) (441) (470)
Impairment of certain assets - (12) (10)
Proportional Modified EBITDA of equity-method investments 682
473 454
Northeast G&P Modified EBITDA $ 1,712 $ 1,489 $ 1,314
Commodity margins $ 5 $ 4 $ 2
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
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
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 atLaurel 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. 54 --------------------------------------------------------------------------------
2020 vs. 2019
Northeast G&P Modified EBITDA increased primarily due to higher Service revenues, lower Other segment costs and expenses, and increased Proportional Modified EBITDA of equity-method investments, in addition to the favorable impact of acquiring the additional interest in UEOM, which is a consolidated entity after the remaining ownership interest was purchased inMarch 2019 .
Service revenues increased primarily due to:
•A$94 million increase at the Northeast JV, including$62 million higher processing, fractionation, transportation, and gathering revenues primarily due to higher volumes and a$32 million increase associated with the consolidation of UEOM, as previously discussed;
•A
•A$13 million increase in revenues associated with reimbursable electricity expenses, which is offset by similar changes in electricity charges, reflected in Other segment costs and expenses. Other segment costs and expenses decreased due to lower employee-related expenses, including the absence of 2019 severance and related costs and the associated reduced costs in 2020, as well as the favorable impact of a 2020 change in an employee benefit policy (see Note 5 - Other Income and Expenses of Notes to Consolidated Financial Statements), and lower maintenance and operating expenses primarily due to timing and scope of activities. Additionally, expenses changed favorably due to the absence of transaction costs associated with our 2019 acquisition of UEOM and the formation of the Northeast JV. These decreases were partially offset by higher reimbursable electricity expenses, increased expenses associated with the consolidation of UEOM, and the absence of a favorable customer settlement in 2019.
Impairment of certain assets reflects a
Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments driven by higher volumes, partially offset by a$26 million decrease for our share of an impairment of certain assets. Additionally, there was an increase at Blue Racer primarily due to higher volumes and the favorable impact of increased ownership, partially offset by a$10 million decrease for our share of an impairment of certain assets. These increases were partially offset by a$16 million decrease as a result of the consolidation of UEOM in 2019, as previously discussed, as well as a decrease atLaurel Mountain primarily due to$11 million for our share of an impairment of certain assets that were subsequently sold, partially offset by higher volumes, and a decrease at Aux Sable. 55 --------------------------------------------------------------------------------
West
Year Ended December 31,
2021 2020 2019
(Millions)
Service revenues $ 1,221 $ 1,280 $ 1,364
Service revenues - commodity consideration 179 101 150
Product sales 4,330 1,567 1,795
Net gain (loss) on commodity derivatives (85) (5) 2
Segment revenues 5,645 2,943 3,311
Product costs (4,099) (1,520) (1,774)
Processing commodity expenses (85) (58) (79)
Other segment costs and expenses (471) (477) (521)
Impairment of certain assets - - (100)
Proportional Modified EBITDA of equity-method investments 105
110 115
West Modified EBITDA $ 1,095 $ 998 $ 952
Commodity margins $ 255 $ 85 $ 91
Net unrealized gain (loss) from derivative instruments - - 3
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
•A
•A
•A$37 million increase associated with higher MVC revenue primarily in theEagle Ford Shale region, partially offset by lower MVC revenue in theWamsutter 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 severe winter weather, 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 theBarnett Shale and Piceance regions due to higher commodity pricing, along with escalated gathering rates in theEagle Ford Shale region, partially offset by a decrease in gathering rates in theHaynesville Shale region due to a customer contract change. The net sum of Service revenues - commodity consideration, Product sales, Product costs, Processing commodity expenses, and net realized gains and losses on commodity derivatives related to sales of product comprise our Commodity margins. We further segregate our Commodity margins into product margins associated with our equity NGLs and marketing margins. Marketing margins increased by$145 million primarily due to favorable changes in net realized natural gas and NGL prices, including the impact of severe winter weather in the first quarter of 2021. Product margins from our equity NGLs increased by$13 million , primarily due to favorable 56 -------------------------------------------------------------------------------- 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 decreased primarily due to 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, partially offset by higher reimbursable compressor power and fuel purchases which are offset in Service revenues and higher incentive and benefit employee-related expenses as previously discussed. 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.
2020 vs. 2019
West Modified EBITDA increased primarily due to the absence of Impairment of certain assets and lower Other segment costs and expenses, partially offset by lower Service revenues.
Service revenues decreased primarily due to:
•An
•A$72 million decrease driven by lower deferred revenue amortization and MVC deficiency fee revenues associated with the second-quarter 2019 expiration of the MVC agreement in theBarnett Shale region; •A$47 million decrease associated with lower rates, excluding theEagle Ford Shale region, driven by lower commodity pricing in theBarnett Shale region and the expiration of a cost-of-service period on a contract in the Mid-Continent region;
•An
•An
•A$91 million increase in theEagle Ford Shale region due to higher MVC revenue and higher rates, partially offset by lower volumes primarily due to decreased producer activity, including temporary shut-ins on certain gathering systems;
•A
•A
Product margins from our equity NGLs decreased
•A
•A
•A
Additionally, marketing margins increased by$26 million primarily due to higher net realized NGL and natural gas prices. The decrease in Product sales includes a$168 million decrease in marketing sales, which is due to lower sales prices, partially offset by higher marketing sales volumes. An$18 million decrease in other product sales also contributed to the overall decrease. These decreases are substantially offset in Product costs.
Other segment costs and expenses decreased primarily due to lower employee-related expenses driven by the absence of 2019 severance and related costs and the associated reduced costs in 2020, and the favorable impact of a
57
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2020 change in an employee benefit policy (see Note 5 - Other Income and
Expenses of Notes to Consolidated Financial Statements), as well as lower
operating costs due to fewer leased compressors and lower maintenance costs
primarily due to timing and scope of activities. These favorable changes are
partially offset by the absence of
Impairment of certain assets reflects a$79 million impairment of certainEagle Ford Shale gathering assets and a$12 million impairment of certain idle gathering assets in 2019 (see Note 17 - Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements). Proportional Modified EBITDA of equity-method investments decreased primarily due to lower volumes at OPPL and the absence of the Jackalope equity-method investment sold inApril 2019 , partially offset by growth at the RMM, Brazos Permian II, andTarga Train 7 equity-method investments.
Sequent
We closed the Sequent Acquisition onJuly 1, 2021 . See the Sequent Acquisition section of Recent Developments above for additional information related to Sequent. Year Ended December 31, 2021 (Millions) Product sales $ (43) Net realized gain (loss) from derivative instruments
66
Net unrealized gain (loss) from derivative instruments
(109)
Net gain (loss) on commodity derivatives (43) Segment revenues (86) Other segment costs and expenses (26) Sequent Modified EBITDA $ (112) Commodity margins $ 23 2021
Sequent Modified EBITDA reflects Commodity margins more than offset by net unrealized losses from derivative instruments and segment costs and expenses.
The net sum of Product sales and net realized gains and losses on commodity derivatives related to sales of product comprise our Commodity margins. Commodity margins include$35 million primarily related to favorable pricing spreads on Sequent's 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 relates to derivative contracts within the Sequent segment that are not designated as hedges for accounting purposes. Sequent can experience significant earnings volatility from the fair value accounting required for the derivatives used to hedge a portion of the economic value of the underlying transportation and storage portfolio. However, the unrealized fair value measurement gains and losses are generally offset by valuation changes in the economic value of the underlying transportation and storage portfolio, which is not recognized until the underlying transportation and storage transaction occurs.
Other segment costs and expenses primarily include employee-related costs.
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Other
Year Ended December 31,
2021 2020 2019
(Millions)
Other Modified EBITDA $ 178 $ (15) $ 6
2021 vs. 2020
Other Modified EBITDA increased primarily due to:
•A$168 million increase due to our recently acquired upstream operations, including the favorable commodity price impact of severe winter weather in the first quarter of 2021;
•A
•A
•A
2020 vs. 2019
Other Modified EBITDA decreased primarily due to:
•A
•A charge of
•The absence of a 2019$12 million unfavorable adjustment to a regulatory asset associated with an increase inTransco's estimated deferred state income tax rate following the merger transaction wherein we acquired all of the outstanding common units held by others of our former publicly traded master limited partnership. 59 --------------------------------------------------------------------------------
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 control operating costs. During 2021, we issued approximately$2.15 billion of new long-term debt primarily to fund current or near-term retirements. In the first half of 2021, we acquired various oil and gas properties in theWamsutter field inWyoming , funding the$165 million paid with cash on hand. InJuly 2021 , we acquired Sequent, funding the final purchase price of$159 million paid with cash on hand (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 2022 are currently expected to be in a range from$1.25 billion to$1.35 billion . Growth capital spending in 2022 primarily includesTransco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business, opportunities in theHaynesville area, and an expansion in the Western Gulf area. We also expect to invest capital in the development of our upstream oil and gas properties. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments. We intend to fund substantially all of our planned 2022 capital spending with cash available after paying dividends. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities including the repurchase of our common stock as previously discussed in Recent Developments. As ofDecember 31, 2021 , we have approximately$2.025 billion of long-term debt due within one year. Our potential sources of liquidity available to address these maturities include cash on hand, proceeds from refinancing at attractive long-term rates or from our credit facility, as well as proceeds from asset monetizations. InJanuary 2022 , we retired our$1.25 billion of 3.6 percent senior unsecured notes that were scheduled to mature inMarch 2022 with cash on hand. Liquidity Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2022. Our potential material internal and external sources and uses of liquidity are as follows: Sources: Cash and cash equivalents on hand Cash generated from operations Distributions from our equity-method investees Utilization of our credit facility and/or commercial paper program Cash proceeds from issuance of debt and/or equity securities Proceeds from asset monetizations Uses: Working capital requirements Capital and investment expenditures Product costs Other operating costs including human capital expenses Quarterly dividends to our shareholders Debt service payments, including payments of long-term debt Distributions to noncontrolling interests Share repurchase program
As of
60
--------------------------------------------------------------------------------maturities over the next five years. Our potential sources of liquidity available to address these maturities include cash generated from operations, proceeds from refinancing at attractive long-term rates or from our credit facility, as well as proceeds from asset monetizations.
Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook.
As of
Available Liquidity December 31, 2021
(Millions)
Cash and cash equivalents $ 1,680
Capacity available under our $3.75 billion credit facility, less
amounts outstanding under our $3.5 billion commercial paper program
(1) 3,750
$ 5,430
__________
(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 December 31, 2021 . The highest amount outstanding under
our commercial paper program and credit facility during 2021 was $15 million . At
December 31, 2021 , we were in compliance with the financial covenants associated
with our credit facility. See Note 13 - 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 2.5 percent from the
Registrations
In
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 9 - 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:
Senior Unsecured
Rating Agency Outlook 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
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--------------------------------------------------------------------------------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 2021 2020 2019
(Millions)
Sources of cash and cash equivalents:
Operating activities - net Operating
Financing 2,155 2,199 67
Proceeds from credit-facility borrowings Financing - 1,700 700
Contributions in aid of construction Investing 52 37 52
Proceeds from sale of partial interest in consolidated subsidiary (see Note 3)
Financing - - 1,334
Proceeds from dispositions of equity-method investments (see Note 9)
Investing 1 - 485
Uses of cash and cash equivalents:
Payments of long-term debt (see Note 13) Financing (894) (2,141) (49)
Common dividends paid Financing (1,992) (1,941) (1,842)
Payments on credit-facility borrowings Financing - (1,700) (860)
Capital expenditures Investing (1,239) (1,239) (2,109)
Purchases of and contributions to equity-method
investments (see Note 9) Investing (115) (325) (453)
Dividends and distributions paid to noncontrolling interests
Financing (187) (185) (124)
Purchases of businesses, net of cash acquired (see Note
3) Investing (151) - (728)
Financing and
Other sources / (uses) - net Investing (37) (48) (45)
Increase (decrease) in cash and cash equivalents $ 1,538 $ (147) $ 121
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, Gain on disposition of equity-method investments,
(Gain) loss on deconsolidation of businesses, Impairment of goodwill, Impairment
of equity-method investments, Impairment of certain assets, and Net unrealized
(gain) loss from derivative instruments.
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.
Our Net cash provided (used) by operating activities in 2020 decreased from 2019
primarily due to the net unfavorable changes in net operating working capital in
2020, including the payment of Transco's rate refunds in 2020 and the decrease
in the income tax refund that was received in 2020 compared to that received in
2019, partially offset by higher operating income (excluding noncash items as
previously discussed) in 2020.
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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 19 - 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$31 million , all of which are included in Accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet atDecember 31, 2021 . We will seek recovery of the accrued costs related to remediation activities by our interstate gas pipelines totaling approximately$4 million through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2021, we paid approximately$5 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately$9 million in 2022 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. AtDecember 31, 2021 , certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors. The EPA and various state regulatory agencies routinely 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 pipelines. To date, 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. 63
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