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, compression, and storage, NGL fractionation, transportation and storage, crude oil production handling and transportation, as well as marketing services for NGL, crude oil and natural gas. Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are conducted, managed, and presented within the following reportable segments: Transmission &Gulf of Mexico , Northeast G&P, West, and Gas & NGL Marketing Services. All remaining business activities, including our upstream operations and corporate activities, are included in Other. Our reportable segments are comprised of the following businesses: •Transmission &Gulf of Mexico is comprised of our interstate natural gas pipelines and complimentary natural gas storage facilities withinTransco 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 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 northTexas . •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 VIE) which operates in WestVirginia, Ohio , andPennsylvania , a 66 percent interest in Cardinal (a consolidated VIE) which operates inOhio , a 69 percent equity-method investment inLaurel Mountain , a 50 percent equity-method investment in Blue Racer, and Appalachia Midstream Investments, a wholly owned subsidiary that owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in 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 eastTexas and northwestLouisiana , and the Mid-Continent region which includes theAnadarko and Permian basins. This segment also includes our NGL 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 equity-method investment inBrazos Permian II, LLC . 35 --------------------------------------------------------------------------------
Management's Discussion and Analysis (Continued) Table of Contents
•Gas & NGL Marketing Services includes our NGL and natural gas marketing and trading operations previously reported within the West segment prior toJanuary 1, 2022 , as well as the operations acquired in the Sequent Acquisition in 2021. This segment includes risk management and the storage and transportation of natural gas on strategically positioned assets, including ourTransco system.
Dividends
In
Overview of Nine Months Ended
Net income (loss) attributable toThe Williams Companies, Inc. , for the nine months endedSeptember 30, 2022 , increased$485 million compared to the nine months endedSeptember 30, 2021 , reflecting the benefit of higher service revenues from commodity-based gathering and processing rates and higher gathering volumes, including from the Trace Acquisition in the West, as well asTransco's Leidy South project placed in service inDecember 2021 , higher results from our upstream operations associated with higher prices and increased scale of operations, higher commodity margins, higher equity earnings, and favorable interest expense due to debt retirements. These favorable impacts were partially offset by a$12 million unfavorable change in net unrealized loss on commodity derivatives, increased intangible asset amortization, the absence of a$77 million favorable impact in 2021 from Winter Storm Uri, higher operating and maintenance expenses, and higher selling, general, and administrative expenses, primarily resulting from the Sequent Acquisition. The tax provision benefited from the release of valuation allowances on deferred income tax assets and federal income tax settlements, as well as from a decrease in our estimated deferred state income tax rate. Our results include a$12 million unfavorable change in net unrealized losses from commodity derivatives not designated as hedges for accounting purposes. We can experience significant earnings volatility from the fair value accounting required for the derivatives used to hedge a portion of the economic value of the underlying transportation and storage marketing portfolio as well as upstream related production. However, the unrealized fair value measurement gains and losses are generally offset by valuation changes in the economic value of the underlying production or contracts, which is not recognized until the underlying transaction occurs. The following discussion and analysis of results of operations and financial condition and liquidity should be read in conjunction with our consolidated financial statements and notes thereto of this Form 10Q and in Exhibit 99.1 of our Form 8-K datedMay 2, 2022 .
Recent Developments
Trace Acquisition
OnApril 29, 2022 , we closed on the acquisition of 100 percent ofGemini Arklatex, LLC through which we acquired theHaynesville Shale region gas gathering and related assets of Trace Midstream for$972 million , subject to post-closing adjustments. The purpose of the Trace Acquisition was to expand our footprint into the eastTexas area of theHaynesville Shale region, increasing in-basin scale in one of the largest growth basins in the country.
Purchase of North Texas Assets
OnAugust 31, 2022 , we purchased a group of assets in northTexas , primarily natural gas storage facilities and pipelines, fromNorTex Midstream Holdings, LLC for approximately$424 million . These assets are included in the Transmission &Gulf of Mexico segment.
Northwest Pipeline FERC Rate Case Settlement Filing
On
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obligation. Provisions were included in the settlement that a new rate case can be filed to be effective afterJanuary 1, 2026 , and that a general rate case filing must be made for rates to become effective no later thanApril 1, 2028 .
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, environmental stewardship including seeking opportunities for renewable energy ventures, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe, reliable, clean energy services to our customers and an attractive return to our shareholders. Our business plan for 2022 includes a continued focus on earnings and cash flow growth. In 2022, our operating results are expected to benefit from higher commodity prices and volume growth in ourHaynesville and Ohio Valley Midstream areas. We also anticipate increases resulting fromTransco expansion projects, development of our upstream oil and gas properties, and our recently completed Trace Acquisition. These increases are partially offset by the absence of favorable results captured during Winter Storm Uri in 2021 by our Gas & NGL Marketing Services business and lower expected results in the Bradford Supply Hub primarily due to lower gathering rates resulting from annual cost of service contract redeterminations. 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 , which excludes approximately$1.5 billion in total acquisitions and follow-on expenditures for the Trace Acquisition and NorTex Asset Purchase. Growth capital spending in 2022, excluding the Trace Acquisition and NorTex Asset Purchase, primarily includesTransco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business, 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, including 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;
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•Physical damages to facilities, including damage to offshore facilities by weather-related events;
•Other risks set forth under Part I, Item 1A. Risk Factors in our Annual Report
on Form 10-K for the year ended
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.
Southside Reliability Enhancement
InMay 2022 , we filed an application with theFERC for the project, which is an incremental expansion ofTransco's existing natural gas transmission system to provide firm transportation capacity from receipt points inVirginia andNorth Carolina to delivery points inNorth 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.
InAugust 2022 , we filed an application with theFERC for the project, which involves an expansion ofTransco's existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in southTexas to delivery points inTexas andLouisiana . 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 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
InAugust 2022 , we filed an application with theFERC for the project, which is an expansion ofTransco's existing natural gas transmission system to provide incremental firm transportation capacity from receipt points inMississippi andAlabama to a delivery point inAlabama . We plan to place the project into service in the fourth 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
InAugust 2022 , we filed an application with theFERC for the project, which involves an expansion ofTransco's existing natural gas transmission system to provide incremental firm transportation capacity inVirginia . 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. 38 --------------------------------------------------------------------------------
Management's Discussion and Analysis (Continued) Table of Contents
West Louisiana Energy Gateway InJune 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 theHaynesville Shale basin for delivery to premium markets, includingTransco , industrial markets, and growing LNG export demand along theGulf Coast . This project is expected to go into service in late 2024. 39 --------------------------------------------------------------------------------
Management's Discussion and Analysis (Continued) Table of Contents
Results of Operations Consolidated Overview The following table and discussion is a summary of our consolidated results of operations for the three and nine months endedSeptember 30, 2022 , compared to the three and nine months endedSeptember 30, 2021 . The results of operations by segment are discussed in further detail following this consolidated overview discussion. Three Months Ended Nine Months Ended September 30, September 30, 2022 2021 $ Change* % Change* 2022 2021 $ Change* % Change* (Millions) (Millions) Revenues: Service revenues$ 1,685 $ 1,506 +179 +12 %$ 4,828 $ 4,418 +410 +9 % Service revenues - commodity consideration 60 64 -4 -6 % 223 164 +59 +36 % Product sales 1,260 1,296 -36 -3 % 3,475 3,229 +246 +8 % Net gain (loss) on commodity derivatives 16 (391) +407 NM (491) (441) -50 -11 % Total revenues 3,021 2,475 8,035 7,370 Costs and expenses: Product costs 990 1,043 +53 +5 % 2,650 2,672 +22 +1 % Net processing commodity expenses 29 28 -1 -4 % 99 67 -32 -48 % Operating and maintenance expenses 486 409 -77 -19 % 1,345 1,148 -197 -17 % Depreciation and amortization expenses 500 487 -13 -3 % 1,504 1,388 -116 -8 % Selling, general, and administrative expenses 163 152 -11 -7 % 477 389 -88 -23 % Other (income) expense - net 33 1 -32 NM 14 12 -2 -17 % Total costs and expenses 2,201 2,120 6,089 5,676 Operating income (loss) 820 355 1,946 1,694 Equity earnings (losses) 193 157 +36 +23 % 492 423 +69 +16 % Other investing income (loss) - net 1 2 -1 -50 % 4 6 -2 -33 % Interest expense (291) (292) +1 - % (858) (884) +26 +3 % Other income (expense) - net (6) 4 -10 NM 5 4 +1 +25 % Income (loss) before income taxes 717 226 1,589 1,243 Less: Provision (benefit) for income taxes 96 53 -43 -81 % 169 313 +144 +46 % Net income (loss) 621 173 1,420 930 Less: Net income (loss) attributable to noncontrolling interests 21 8 -13 -163 % 40 35 -5 -14 % Net income (loss) attributable to The Williams Companies, Inc.$ 600 $ 165 $ 1,380 $ 895
* + = 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.
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Three months ended
Service revenues increased primarily due to higher gathering rates driven by favorable commodity prices and annual contractual rate escalations for certain of our West and Northeast G&P operations, higher gathering volumes including from the Trace Acquisition, higher transportation fee revenues associated with the Leidy South expansion project placed fully in service atTransco inDecember 2021 , and higher reimbursable electric power and storage costs, which are substantially offset in Operating and maintenance expenses. Product sales decreased primarily due to the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs (see Note 1 - General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements). 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 a 2022 lower of cost or net realizable value adjustment to our gas marketing storage inventory. Additional unfavorable impacts include lower marketing and equity NGL sales volumes. These decreases were substantially offset by higher marketing sales prices, higher sales prices and volumes associated with our upstream operations presented in our Other segment, higher sales prices related to our equity NGL sales, and higher other product sales. Net gain (loss) on commodity derivatives includes realized and unrealized gains and losses from derivative instruments reflected within Total revenues. The favorable change primarily reflects a net gain related to derivative contracts in our Gas & NGL Marketing Services segment. 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, volumes, and lower of cost or net realizable value inventory adjustments in 2022 associated with our NGL marketing activities, higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production activities, and higher other product costs. 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, Net realized product sales at our Other segment reflect sales of our upstream related production net of the associated realized gains and losses and are excluded from our Commodity Margins. Operating and maintenance expenses increased primarily due to higher operating costs including higher reimbursable electric power and storage costs, which are substantially offset in Service revenues, higher expenses associated with our upstream operations, and increased costs associated withTransco's Leidy South expansion project placed in service inDecember 2021 . Depreciation and amortization expenses increased primarily due to amortization of intangibles acquired in the Sequent and Trace Acquisitions, 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.
Other (income) expense - net within Operating income (loss) changed unfavorably primarily due to losses related to Eminence storage cavern abandonments and regulatory charges associated with a decrease inTransco's estimated deferred state income tax rate.
Equity earnings (losses) changed favorably primarily due to an increase at
Provision (benefit) for income taxes changed unfavorably primarily due to higher
pre-tax income, partially offset by a benefit related to a decrease in our
estimate of the state deferred income tax rate. See Note 5 - Provision (Benefit)
for Income Taxes of Notes to Consolidated Financial Statements for a discussion
of the effective tax rate compared to the federal statutory rate for both
periods.
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Nine months ended
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 gathering volumes including from the Trace Acquisition, higher transportation fee revenues associated with the Leidy South expansion project placed fully in service atTransco inDecember 2021 , and higher reimbursable electric power and storage costs, which are substantially offset in Operating and maintenance expenses. 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 marketing sales prices and volumes, including the increase associated with the Sequent Acquisition in third-quarter 2021, higher sales prices and volumes associated with our upstream operations presented in our Other segment, higher sales prices related to our equity NGL sales activities, and higher other product sales. These increases were substantially offset by the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs, including a 2022 lower of cost or net realizable value adjustment to our gas marketing storage inventory (see Note 1 - General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements) as well as lower gas marketing sales prices related to the absence of a 2021 favorable impact from Winter Storm Uri severe winter weather. The unfavorable change in Net gain (loss) on commodity derivatives primarily reflects a higher net realized loss, offset by a favorable change in net unrealized gains and losses related to derivative contracts in our Other segment. The change also reflects a lower net realized loss, offset by a higher net unrealized loss related to derivative contracts in our Gas & NGL Marketing Services segment. 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, volumes, and lower of cost or net realizable value inventory adjustments in 2022 associated with our NGL marketing activities, higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production activities, and higher other product costs. Net processing commodity expenses increased primarily due to higher net realized prices for natural gas purchases associated with our equity NGL production activities, partially offset by favorable change in net unrealized gains from commodity derivatives related to these purchases. These net gains from commodity derivatives include realized gains in our West segment and unrealized gains in our Gas & NGL Marketing segment. Operating and maintenance expenses increased primarily due to higher operating costs including higher reimbursable electric power and storage costs which are substantially offset in Service revenues, higher expenses associated with our upstream operations, increased costs associated withTransco's Leidy South expansion project placed in service in 2021, and higher employee-related expenses. Depreciation and amortization expenses increased primarily due to amortization of intangibles acquired in the Sequent and Trace Acquisitions and an increase in depreciation atTransco 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 and other general expenses, primarily resulting from the Sequent Acquisition, as well as Trace Acquisition costs.
Other (income) expense - net within Operating income (loss) changed unfavorably primarily due to losses related to Eminence storage cavern abandonments and regulatory charges associated with a decrease inTransco'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). 42 --------------------------------------------------------------------------------
Management's Discussion and Analysis (Continued) Table of Contents
Equity earnings (losses) changed favorably primarily due to increases at
Interest expense changed favorably primarily due to the early retirement of notes (see Note 8 - Debt and Banking Arrangements of Notes to Consolidated Financial Statements).
Provision (benefit) for income taxes changed favorably primarily due to a benefit related to the release of a valuation allowance, a benefit associated with a decrease in our estimate of the state deferred income tax rate, and federal settlements, partially offset by higher pre-tax income. See Note 5 - Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
Period-Over-Period Operating Results - Segments
We evaluate segment operating performance based upon Modified EBITDA. Note 12 - Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.
Transmission &
Three Months Ended Nine Months Ended
September 30, September 30,
2022 2021 2022 2021
(Millions)
Service revenues $ 910 $ 836 $ 2,651 $ 2,493
Service revenues - commodity consideration 11 13 54 34
Product sales 121 88 334 222
Net unrealized gain (loss) from derivative
instruments 1 - 1 -
Segment revenues 1,043 937 3,040 2,749
Product costs (120) (89) (329) (223)
Net processing commodity expenses (2) (4) (23) (10)
Other segment costs and expenses (333) (259) (844) (718)
Proportional Modified EBITDA of equity-method
investments 50 45 143 138
Transmission & Gulf of Mexico Modified EBITDA $ 638 $ 630 $ 1,987 $ 1,936
Commodity margins $ 10 $ 8 $ 36 $ 23 Three months ended
Transmission & Gulf of Mexico Modified EBITDA increased primarily due to a favorable change to Service revenues, substantially offset by higher Other segment costs and expenses.
Service revenues increased primarily due to:
•A$43 million increase inTransco's natural gas transportation and storage revenues primarily associated with the Leidy South expansion project placed fully in service inDecember 2021 and higher storage rates effective since the second quarter of 2022 as well as benefited from higher reimbursable electric power costs, which is offset by a similar change in electricity charges reflected in Other segment costs and expenses.
•A
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Other segment costs and expenses increased primarily due to higher operating costs including higher reimbursable electric power costs and storage costs, which are offset by a similar change in electricity reimbursements and storage revenues reflected in Service revenues; losses related to Eminence storage cavern abandonments; higher maintenance costs primarily related to general maintenance atTransco ; regulatory charges associated with a decrease inTransco's estimated deferred state income tax rate; and costs associated with the Leidy South expansion project.
Nine months ended
Transmission & Gulf of Mexico Modified EBITDA increased primarily due to favorable changes to Service revenues and Commodity margins, partially offset by higher Other segment costs and expenses.
Service revenues increased primarily due to:
•A$134 million increase inTransco's natural gas transportation and storage revenues primarily associated with the Leidy South expansion project placed fully in service inDecember 2021 and higher storage rates effective since the second quarter of 2022 as well as benefited from higher reimbursable electric power costs, which is offset by a similar change in electricity charges reflected in Other segment costs and expenses and higher short-term firm transportation, overall demand and commodity revenues. •A$19 million increase in theEastern Gulf Coast region primarily due to higher 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 volumes from natural decline.
Commodity margins associated with our equity NGLs increased
Other segment costs and expenses increased primarily due to higher operating costs including higher reimbursable electric power costs and storage costs, which are offset by a similar change in electricity reimbursements and storage revenues reflected in Service revenues; costs associated with the Leidy South expansion project; higher maintenance costs primarily related to general maintenance atTransco andGulf Coast region; higher employee-related costs; losses related to Eminence storage cavern abandonments; and regulatory charges associated with a decrease inTransco's estimated deferred state income tax rate. These increases are partially offset by a favorable change in the deferral of ARO related depreciation atTransco . 44 --------------------------------------------------------------------------------
Management's Discussion and Analysis (Continued) Table of Contents
Northeast G&P
Three Months Ended Nine Months Ended
September 30, September 30,
2022 2021 2022 2021
(Millions)
Service revenues $ 417 $ 399 $ 1,208 $ 1,130
Service revenues - commodity consideration 2 (1) 12 4
Product sales 40 19 110 75
Segment revenues 459 417 1,330 1,209
Product costs (39) (19) (110) (77)
Net processing commodity expenses - (1) (2) (1)
Other segment costs and expenses (138) (130) (392) (368)
Proportional Modified EBITDA of equity-method
investments 182 175 506 490
Northeast G&P Modified EBITDA $ 464 $ 442 $ 1,332 $ 1,253
Commodity margins $ 3 $ (2) $ 10 $ 1 Three months ended
Northeast G&P Modified EBITDA increased primarily due to higher Service revenues and higher Proportional Modified EBITDA of equity-method investments, partially offset by higher Other segment costs and expenses. Service revenues increased primarily due to a$16 million increase in revenues at the Northeast JV primarily related to higher gathering and processing volumes as well as higher processing rates. Higher escalated rates at Susquehanna Supply Hub and higher cost of service rates in theUtica Shale region were substantially offset by lower volumes. Other segment costs and expenses increased primarily due to higher operating expenses, including higher electricity and fuel, which is partially offset by reimbursable revenue. Proportional Modified EBITDA of equity-method investments increased atLaurel Mountain due to higher commodity-based gathering rates and higher MVC revenue, partially offset by a decrease at Appalachia Midstream Investments primarily driven by lower gathering rates resulting from annual cost of service contract redetermination.
Nine months ended
Northeast G&P Modified EBITDA increased primarily due to higher Service revenues and higher Proportional Modified EBITDA of equity-method investments, partially offset by higher Other segment costs and expenses.
Service revenues increased primarily due to:
•A
•A
•A
•A$12 million increase in revenues associated with reimbursable expenses, which is offset by similar changes in the charges reflected in Other segment costs and expenses. 45 --------------------------------------------------------------------------------
Management's Discussion and Analysis (Continued) Table of Contents
Other segment costs and expenses increased primarily due to higher operating expenses, including higher electricity and fuel, which is partially offset by reimbursable revenue. Proportional Modified EBITDA of equity-method investments increased atLaurel Mountain due to higher commodity-based gathering rates and higher MVC revenue, partially offset by a decrease at Appalachia Midstream Investments primarily driven by lower gathering rates resulting from annual cost of service contract redetermination. West Three Months Ended Nine Months Ended September 30, September 30, 2022 2021 2022 2021 (Millions) Service revenues$ 425 $ 320 $ 1,139 $ 908 Service revenues - commodity consideration 47 52 157 126 Product sales 245 177 684 441 Net realized gain (loss) on commodity derivatives - service revenues (10) (4) (15) (4) Net realized gain (loss) on commodity derivatives - product sales 1 (14) (8) (21) Net realized gain (loss) on commodity derivatives (9) (18) (23) (25) Segment revenues 708 531 1,957 1,450 Product costs (238) (170) (667) (411) Net processing commodity expenses (28) (24) (91) (57) Other segment costs and expenses (146) (107) (413) (354) Proportional Modified EBITDA of equity-method investments 41 27 99 74 West Modified EBITDA$ 337 $ 257 $ 885 $ 702 Commodity margins$ 27 21$ 75 $ 78
Three months ended
West Modified EBITDA increased primarily due to higher Service revenues and Proportional Modified EBITDA of equity-method investments, partially offset by higher Other segment costs and expenses.
Service revenues increased primarily due to:
•A$59 million increase in theHaynesville Shale region primarily associated with higher gathering volumes including from the Trace Acquisition (see Note 3 - Acquisitions of Notes to Consolidated Financial Statements) inApril 2022 as well as higher gathering rates driven by favorable commodity pricing;
•A
Product margins from our equity NGLs increased$5 million , primarily due to higher net realized commodity sales prices, partially offset by higher net realized prices for natural gas purchases associated with our equity NGLs production activities and lower non-ethane sales volumes. Other product margins increased$6 million primarily due to the Trace Acquisition. Marketing margins decreased$5 million . 46 --------------------------------------------------------------------------------
Management's Discussion and Analysis (Continued) Table of Contents
Other segment costs and expenses increased primarily due to higher operating expenses related to the Trace Acquisition as well as higher compressor electricity and fuel costs, and the absence of a gain on an asset sale in 2021.
Proportional Modified EBITDA of equity-method investments increased primarily due to higher commodity prices and volumes at RMM as well as higher volumes at OPPL.
Nine months ended
West Modified EBITDA increased primarily due to higher Service revenues and Proportional Modified EBITDA of equity-method investments, partially offset by higher Other segment costs and expenses.
Service revenues increased primarily due to:
•A
•An
•A
•A
•An
Marketing margins decreased$21 million , primarily due to the absence of the favorable impact of Winter Storm Uri in the first quarter of 2021. Other product margins increased$13 million primarily due to higher condensate sales and the Trace Acquisition in 2022. Product margins from our equity NGLs increased$5 million primarily due to higher net realized commodity sales prices, partially offset by higher net realized prices for natural gas purchases associated with our equity NGLs production activities and lower sales volumes primarily due to a customer contract change. Other segment costs and expenses increased primarily due to higher operating expenses related to higher electricity and compressor fuel costs, the absence of gains on asset sales in 2021, higher corporate allocations, and expenses associated with the Trace Acquisition in 2022.
Proportional Modified EBITDA of equity-method investments increased primarily due to higher volumes and commodity prices at RMM and higher volumes at OPPL.
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Gas & NGL Marketing Services
Nine Months Ended September
Three Months Ended September 30, 30,
2022 2021 2022 2021
(Millions)
Service revenues $ 1 $ - $ 2 $ 2
Product sales 884 1,234 2,724 3,049
Net realized gain (loss) from derivative instruments 54 (58) (18) (93)
Net unrealized gain (loss) from derivative
instruments (1) (294) (357) (297)
Net gain (loss) on commodity derivatives 53 (352) (375) (390)
Segment revenues 938 882 2,351 2,661
Net unrealized gain (loss) from derivative
instruments within Net processing commodity expenses 6 - 17 -
Product costs (899) (1,130) (2,544) (2,802)
Other segment costs and expenses (25) (14) (73) (20)
Gas & NGL Marketing Services Modified EBITDA $ 20 $ (262) $ (249) $ (161)
Commodity margins $ 39 $ 46 $ 162 $ 154 Three months ended
Gas & NGL Marketing Services Modified EBITDA increased primarily due to the absence of a 2021 net unrealized loss from derivative instruments, partially offset by higher Other segment costs and expenses and lower Commodity margins.
Commodity margins decreased
•A
•A
•A
•A
•A$48 million increase from our natural gas marketing operations including$83 million of higher natural gas transportation capacity marketing margins due to favorable pricing spreads, partially offset by$35 million lower natural gas storage marketing margins primarily due to a third-quarter 2022 charge related to a lower of cost or net realizable value inventory adjustment. Net unrealized gain (loss) from derivative instruments relates to derivative contracts that are not designated as hedges for accounting purposes. The change from 2021 is primarily due to 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.
Nine months ended
Gas & NGL Marketing Services Modified EBITDA decreased primarily due to higher
Other segment costs and expenses and higher net unrealized loss from derivative
instruments, partially offset by higher Commodity margins.
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--------------------------------------------------------------------------------Management's Discussion and Analysis (Continued) Table of Contents
Commodity margins increased
•A
•A$169 million increase in natural gas transportation capacity marketing margins primarily associated with the Sequent Acquisition in the third quarter of 2021 and favorable pricing spreads in the third quarter of 2022; partially offset by
•A
•A
•A$15 million charge in 2022 related to the remaining recognition of a purchase accounting inventory fair value adjustment which increased the weighted-average cost of inventory.
•A
•A
•A
•A
Net unrealized gain (loss) from derivative instruments changed primarily due to the Sequent Acquisition inJuly 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.
Other
Three Months Ended September Nine Months Ended September
30, 30,
2022 2021 2022 2021
(Millions)
Service revenues $ 6 $ 8 $ 22 $ 23
Product sales 238 111 522 216
Net realized gain (loss) from derivative
instruments (58) (6) (104) (6)
Net unrealized gain (loss) from derivative
instruments 29 (15) 10 (20)
Net gain (loss) on commodity derivatives (29) (21) (94) (26)
Segment revenues 215 98 450 213
Other segment costs and expenses (75) (60) (166) (122)
Other Modified EBITDA $ 140 $ 38 $ 284 $ 91
Net realized product sales $ 180 $ 105 $ 418 $ 210
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Management's Discussion and Analysis (Continued) Table of Contents
Three months ended
Other Modified EBITDA increased primarily due to
•A$75 million increase in Net realized product sales primarily due to higher net realized commodity prices and higher volumes associated with production from new wells, partially offset by an unfavorable change in Net realized gain (loss) from derivative instruments due to an increase in commodity prices relative to our hedge positions; •A$44 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$14 million increase in Other segment costs and expenses primarily due to the increased scale of our upstream operations and higher associated property and production taxes which were also impacted by higher commodity prices.
Other segment costs and expenses also includes an
Nine months ended
Other Modified EBITDA increased primarily due to
•A$208 million increase in Net realized product sales primarily due to higher net realized commodity prices in the second and third quarters of 2022, partially offset by lower prices from the absence of the favorable impact of Winter Storm Uri in the first quarter of 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. 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; and •A$30 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$48 million increase in Other segment costs and expenses primarily due to the increased scale of our upstream operations and higher associated property and production taxes which were also impacted by higher commodity prices. Other segment costs and expenses also includes an$11 million charge related to an accrual for loss contingency in the third quarter of 2022, substantially offset by the absence of a$10 million charge related to an accrual for loss contingency in 2021. 50 --------------------------------------------------------------------------------
Management's Discussion and Analysis (Continued) Table of Contents
Management's Discussion and Analysis of Financial Condition and Liquidity
Outlook
Our growth capital and investment expenditures in 2022 are currently expected to be in a range from$1.25 billion to$1.35 billion , which excludes approximately$1.5 billion in total acquisitions and follow-on expenditures for the Trace Acquisition and NorTex Asset Purchase. Growth capital spending in 2022, excluding the Trace Acquisition and NorTex Asset Purchase, primarily includesTransco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business, and an expansion in the Western Gulf area. We also expect to invest capital in the development of our upstream oil and gas properties. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments. We funded both the Trace Acquisition and the NorTex Asset Purchase with available sources of short-term liquidity and intend to fund substantially all additional planned 2022 capital spending with cash available after paying dividends. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities including the repurchase of our common stock. During the first quarter of 2022, we early retired$1.25 billion of 3.6 percent senior unsecured notes that were scheduled to mature inMarch 2022 using proceeds from ourOctober 2021 debt offering. During the second quarter of 2022, we early retired$750 million of 3.35 percent senior unsecured notes that were scheduled to mature inAugust 2022 using issuances of commercial paper. During the third quarter of 2022, we issued$1.75 billion of long-term debt that we used to pay down our commercial paper outstanding and, inOctober 2022 , to early retire our$850 million of 3.7 percent senior unsecured notes that were scheduled to mature inJanuary 2023 .
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
Repayments of borrowings under our credit facility and/orcommercial paper program
Debt service payments, including payments of long-term debt
Distributions to noncontrolling interests
Share repurchase program
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Management's Discussion and Analysis (Continued) Table of Contents
As ofSeptember 30, 2022 , we have$22.5 billion of long-term debt due after one year. Our potential sources of liquidity available to address these maturities include cash generated from operations, proceeds from refinancing, our credit facility, or our commercial paper program, as well as proceeds from asset monetizations.
Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook.
As of
Available Liquidity September 30, 2022
(Millions)
Cash and cash equivalents $ 859
Capacity available under our
3,750
$ 4,609
(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 September 30, 2022 . Through September 30, 2022 , the
highest amount outstanding under our commercial paper program and credit
facility during 2022 was $1.219 billion . At September 30, 2022 , we were in
compliance with the financial covenants associated with our credit facility.
Borrowing capacity under our credit facility as of October 27, 2022 was $3.630
billion .
Dividends
We increased our regular quarterly cash dividend to common stockholders by
approximately 3.7 percent from the
Distributions from Equity-Method Investees
The organizational documents of entities in which we have an equity-method investment generally require periodic distributions of their available cash to their members. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses.
Credit Ratings
The interest rates at which we are able to borrow money are impacted by our credit ratings. The current ratings are as follows:
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 and,
if ratings were to fall below investment-grade, could require us to provide
additional collateral to third parties, negatively impacting our available
liquidity.
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--------------------------------------------------------------------------------Management's Discussion and Analysis (Continued) Table of Contents
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):
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