Drilling rigs operate in the Permian Basin oil and natural gas production area in Lea County, New Mexico, U.S., February 10, 2019. Picture taken February 10, 2019. REUTERS/Nick Oxford/File Photo Purchase Licensing Rights , opens new tab

March 14, 2025 – Recent actions by the Trump administration and by the Federal Energy Regulatory Commission (FERC) signal that the industry may see more streamlined reviews of proposed natural gas infrastructure projects that will focus less on the impacts of greenhouse gas (GHG) emissions and climate change.

Unleashing American Energy executive order

The Trump administration seeks to expedite and simplify the federal permitting process to facilitate the permitting and construction of interstate energy transportation and other critical energy infrastructure. In the Unleashing American Energy Executive Order, which was signed on Jan. 20, President Trump directed the Council on Environmental Quality (CEQ) to provide guidance on implementing the National Environmental Policy Act (NEPA) and to propose rescinding the rules on how agencies conduct their NEPA reviews.

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In response, on Feb. 16, the Chairman of the CEQ sent an interim final rule titled “Removal of National Environmental Policy Act Implementing Regulations” to the White House Office of Information and Regulatory Affairs for review.

The Unleashing American Energy Executive Order also directed the Secretaries of Defense, Interior, Agriculture, Commerce, Housing, Urban Development, Transportation, Energy, Homeland Security, the Administrator of the Environmental Protection Agency, the Chairman of CEQ and the heads of other relevant agencies to “undertake all available efforts to eliminate all delays within their respective permitting processes, including through, but not limited to, the use of general permitting and permit by rule.”

This is significant because it directs a government-wide review of rules and policies that could change how the effects of GHG emissions and climate change are assessed in federal reviews of proposed projects.

FERC termination of GHG policy statement proceeding

Four days after the Unleashing American Energy Executive Order was signed, FERC terminated its years-long proceeding to develop a policy statement that explains how FERC would assess the impacts of natural gas infrastructure projects on climate change in its reviews under NEPA and the Natural Gas Act (NGA).

FERC withdrew its draft Greenhouse Gas (GHG) Policy Statement, closed the proceedings, and will instead consider climate impacts of permitting actions on a case-by-case basis when raised by parties to a proceeding, as FERC has done for the last few years.

As the agency that reviews and approves the construction and operation of interstate natural gas pipelines and storage facilities, natural gas import or export facilities, and liquified natural gas terminals, FERC assesses the environmental consequences of a decision to approve such facilities. In April 2018, FERC initiated an inquiry asking for information to help it explore whether, and if so, how, it should revise its approach on determining whether a proposed project is consistent with the public convenience and necessity and evaluating the environmental impacts of the proposed project.

After receiving numerous comments, FERC issued a new notice of inquiry in February 2021 to solicit additional comments on how it should consider GHG emissions in its review. FERC received thousands of comments in response to that inquiry and subsequently held a technical conference in November 2021 to discuss methods that natural gas companies may use to mitigate the effects of direct and indirect GHG emissions resulting from their projects.

A divided Commission issued the Interim GHG Policy Statement in February 2022 that set forth FERC’s procedures for evaluating climate impacts under NEPA and integrating climate considerations into public interest determinations under the Natural Gas Act.

Under this Interim Policy Statement, FERC would (a) quantify a project’s GHG emissions that are reasonably foreseeable and have a reasonably close causal relationship to the proposed actions, including construction activities and downstream emissions from combustion of transported gas, (b) apply a 100% utilization rate to estimate a project’s emissions, (c) prepare the more detailed environmental impact statement (EIS) if the project would result in 100,000 or more metric tons per year of GHG emission, considering any mitigation measures proposed by the applicant, and (d) consider whether to require additional GHG emission mitigation when authorizing a project.

FERC reasoned that considering GHG emissions and climate change were encompassed by its public interest review standard. Commissioner Mark Christie (now FERC’s Chairman) filed a strong dissent, in part arguing that FERC, as an economic regulator, lacked jurisdiction to act as an environmental regulator and that this policy statement intended to stifle natural gas use.

The Interim Policy Statement was short-lived. In the face of strong opposition, FERC pulled it the following month, designating it as a draft policy statement, and invited further comments. FERC stated that, upon further consideration, it would not apply the draft policy statement to any pending or future applications until FERC issued final guidance.

As noted above, in January 2025, more than two and a half years after issuing the draft GHG Policy Statement, FERC issued an order terminating the draft GHG Policy Statement proceeding, stating that based on the record, GHG emissions are “better considered on a case-by-case basis, when raised by parties to those proceedings,” as FERC has been doing. FERC did not otherwise explain its decision.

Commissioners Willie Phillips, David Rosner, and Judy Chang issued a joint concurrence characterizing the draft GHG policy statement as a key part of FERC’s NEPA review that provided useful information to develop the “current bipartisan, court-affirmed approach to considering GHG issues on a case-by-case basis.”

The concurrence described this approach as estimating reasonably foreseeable GHG emissions, providing a qualitative discussion of potential adverse effects of such emissions, contextualizing the emission levels by comparing to applicable national and statewide emission levels, and calculating monetized values. It also expressed an expectation that projects evaluate means to mitigate or avoid GHG emissions during construction and operations, and opined that an evaluation of public convenience and necessity would consider potential adverse consequences, to include environmental impacts.

Finally, the same day that FERC terminated the draft GHG Policy Statement proceeding, FERC reinstated the authorization it granted to Transcontinental Gas Pipe Line Company, LLC (Transco) to construct and operate the Regional Energy Access Expansion Project (REA), an incremental expansion of Transco’s existing system designed to increase natural gas transportation capacity by up to 829,000 dekatherms per day from northeastern Pennsylvania to multiple delivery points in New Jersey, Pennsylvania, and Maryland.

FERC approved REA despite concluding that GHG emissions would not be mitigated. However, the District of Columbia U.S. Circuit Court of Appeals vacated and remanded FERC’s approval in part, finding that FERC did not explain its decision to not make a GHG significant determination or discuss GHG emission mitigation.

On remand from the D.C. Circuit, FERC held that it fulfilled its NEPA responsibility because it is “not obligated to make a binary determination of the significance of the climate impacts based on those emissions, particularly for impacts for which the significance is unknown.” FERC held in its order on remand that NEPA only requires it to discuss environmental impacts, which it did, and that where the significance of impacts are unknown, FERC would not summarize those impacts in its approval.

Although FERC’s termination of the draft GHG Policy Statement proceeding maintains the status quo of a case-by-case analysis, practically, it signals a likely return of restraint in using expected GHG emissions to impose conditions on permitting actions or otherwise hinder infrastructure development.

FERC, however, may still continue to expect that projects will propose GHG emission mitigation measures. And, while a more limited form of NEPA review will remain part of FERC’s permitting process, it is expected that CEQ’s interim final rule will expedite FERC’s permitting process for natural gas infrastructure.

Pamela Wu is a regular contributing columnist on energy and decarbonization issues for Reuters Legal News and Westlaw Today.

Opinions expressed are those of the author. They do not reflect the views of Reuters News, which, under the Trust Principles, is committed to integrity, independence, and freedom from bias. Westlaw Today is owned by Thomson Reuters and operates independently of Reuters News.

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1Increases are versus 2024. Earnings and cash flow from operations exclude identified items and are adjusted to 2024 $65/bbl real Brent (assumes annual inflation of 2.5%) and 10-year average Energy, Chemical, and Specialty Product margins, which refer to the average of annual margins from 2010-2019. Cash flow from operations also excludes working capital/other.

2$3 billion in Pioneer synergies is a >50% increase vs. prior disclosures and is based on a 10-year average.

3$3 billion by 2030 subject to additional investment by ExxonMobil, final 45V regulations for hydrogen production credits, and receipt of government permitting for carbon capture and storage projects.

4Lower emissions cash capex includes cash capex attributable to carbon capture and storage, hydrogen, lithium, biofuels, ProxximaTM, Carbon Materials, and activities to lower ExxonMobil’s emissions and/or third party (3P) emissions. Planned spend is from 2025-2030.

5See below for definition of reinvestment rate. Cash flow from operations excludes identified items and working capital/other is adjusted to 2024 $65/bbl real Brent (assumes annual inflation of 2.5%) and 10-year average Energy, Chemical, and Specialty Product margins, which refer to the average of annual margins from 2010-2019.

6Earnings and cash flow from operations exclude identified items and are adjusted to 2024 $65/bbl real Brent (assumes annual inflation of 2.5%) and 10-year average Energy, Chemical, and Specialty Product margins, which refer to the average of annual margins from 2010-2019. Cash flow from operations also excludes working capital/other.

7Third-party cash flow refers to cash flow excluding working capital/other and is calculated as earnings sourced from FactSet plus depreciation sourced from FactSet. 2019 to 2023 figures are actuals. 2024 figures are consensus estimates as of December 5, 2024. Three- and five-year CAGRs are from 2021 to 2024E and 2019 to 2024E respectively.

8Calculated as of November 29, 2024.

9Major investments represents investments over $500 million that are expected to start up between 2025 and 2030. Includes pre-2025 capex spend on these investments, except for the Permian work program, which is limited to capex between 2025-2030. Calculations for full-life major investments returns are based on ExxonMobil internal project plans for investments over $500 million that are expected to start up between 2025 and 2030 and the Permian work program. Calculations include internal project plan price assumptions.

10Surplus cash is calculated assuming 2024 $65 real Brent (assumes annual inflation of 2.5%) and 10-year average Energy, Chemical, and Specialty Product margins, which refer to the average of annual margins from 2010-2019. Any decisions on future dividend levels are at the discretion of the Board of Directors. This calculation assumes dividends are held flat relative to 4Q24 levels. The PP&E / I&A factor includes changes in non-controlling interests. 3Q24 cash balance excludes a $5 billion minimum cash assumption.

11Plans based on Scope 1 and Scope 2 emissions from operated assets. Intensity is calculated as emissions per metric ton of throughput/production. ExxonMobil reported emissions, reductions, and avoidance performance data are based on a combination of measured and estimated emissions data using reasonable efforts and collection methods. Calculations are based on industry standards and best practices, including guidance from the American Petroleum Institute (API) and Ipieca. There is uncertainty associated with the emissions, reductions, and avoidance performance data due to variation in the processes and operations, the availability of sufficient data, quality of those data, and methodology used for measurement and estimation. Performance data may include rounding. Changes to the performance data may be reported as part of the Company’s annual publications as new or updated data and/or emission methodologies become available. We are working to continuously improve our performance and methods to detect, measure and address greenhouse gas emissions. ExxonMobil works with industry, including API and Ipieca, to improve emission factors and methodologies, including measurements and estimates. ExxonMobil’s plans regarding expected GHG emissions reductions by 2030 can be found in our 2024 Advancing Climate Solutions report.

12Based on Enverus 2024 Permian Basin Play Fundamentals article with updated data as of 10/2024 | Locations normalized to 10,000-foot laterals; Peers include Apache Corporation, BP, ConocoPhillips, Coterra Energy, Chevron, Devon Energy, Diamondback Energy, EOG Resources, Matador Resources, Ovintiv, Occidental, and Permian Resources. PV-10 Breakeven @ 20:1 WTI:HH ($/bbl).

About ExxonMobil

ExxonMobil, one of the largest publicly traded international energy and petrochemical companies, creates solutions that improve quality of life and meet society’s evolving needs.

The corporation’s primary businesses – Upstream, Product Solutions and Low Carbon Solutions – provide products that enable modern life, including energy, chemicals, lubricants, and lower emissions technologies. ExxonMobil holds an industry-leading portfolio of resources, and is one of the largest integrated fuels, lubricants, and chemical companies in the world. ExxonMobil also owns and operates the largest CO 2 pipeline network in the United States. In 2021, ExxonMobil announced Scope 1 and 2 greenhouse gas emission-reduction plans for 2030 for operated assets, compared to 2016 levels. The plans are to achieve a 20-30% reduction in corporate-wide greenhouse gas intensity; a 40-50% reduction in greenhouse gas intensity of upstream operations; a 70-80% reduction in corporate-wide methane intensity; and a 60-70% reduction in corporate-wide flaring intensity.

With advancements in technology and the support of clear and consistent government policies, ExxonMobil aims to achieve net-zero Scope 1 and 2 greenhouse gas emissions from its operated assets by 2050. To learn more, visit exxonmobil.com and ExxonMobil’s Advancing Climate Solutions.

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Cautionary Statement

FORWARD-LOOKING STATEMENTS. Statements of future events, conditions, expectations, plans, performance, earnings power, opportunities, potential addressable markets, ambitions, or results in this release are forward-looking statements. Similarly, discussions of future projects or markets for carbon capture, transportation, and storage, biofuels, hydrogen, ammonia, lithium, direct air capture, and other low carbon business plans to reduce emissions and emission intensity of ExxonMobil, its affiliates, or third parties are dependent on future market factors, such as continued technological progress, stable policy support, and timely rule-making and permitting, and represent forward-looking statements. Actual future results, including financial and operating performance; potential earnings, cash flow, surplus cash, dividends, share repurchases, or shareholder returns; total cash capital expenditures and mix, including allocations of capital to low carbon investments; realization and maintenance of structural cost reductions and efficiency gains, including the ability to offset inflationary pressures; plans to reduce future emissions and emissions intensity; ambitions to reach Scope 1 and Scope 2 net zero from operated assets by 2050, to reach Scope 1 and 2 net zero in heritage Upstream Permian Basin unconventional operated assets by 2030 and Pioneer Permian assets by 2035, to eliminate routine flaring in-line with World Bank Zero Routine Flaring, to reach near-zero methane emissions from operated assets and other methane initiatives, to meet ExxonMobil’s emission reduction plans and goals, divestment and start-up plans, and associated project plans as well as technology advances, including in the timing and outcome of projects to capture and store CO 2 , produce hydrogen and ammonia, produce biofuels, produce lithium, create new advanced carbon materials, and use plastic waste as feedstock for advanced recycling; maintenance and turnaround activity; drilling and improvement programs; price and margin recovery; planned Pioneer or Denbury integration benefits; resource recoveries and production rates; and product sales levels and mix could differ materially due to a number of factors. These include global or regional changes in oil, gas, petrochemicals, or feedstock prices, differentials, seasonal fluctuations, or other market or economic conditions affecting the oil, gas, and petrochemical industries and the demand for our products; new or changing government policies for lower carbon and new market investment opportunities, or policies limiting the attractiveness of investments such as European taxes on energy and unequal support for different methods of carbon capture; consumer preferences including willingness and ability to pay for reduced emissions products; variable impacts of trading activities; the outcome of competitive bidding and project awards; regulatory actions targeting public companies in the oil and gas industry; the development or changes in local, national, or international laws, regulations, and policies affecting our business including with respect to the environment, taxes, and trade sanctions; adoption of regulatory rules consistent with written laws; the ability to realize efficiencies within and across our business lines and to maintain current cost reductions as efficiencies without impairing our competitive positioning; decisions to invest in future reserves; reservoir performance, including variability and timing factors applicable to unconventional projects and the success of new unconventional technologies; the level, outcome, and timing of exploration and development projects and decisions to invest in future resources; timely completion of construction projects; war, civil unrest, attacks against the company or industry, and other political or security disturbances; expropriations, seizures, and capacity, insurance, or shipping limitations by foreign governments or international embargoes; changes in market strategy by national oil companies; opportunities for and regulatory approval of investments or divestments; the outcome of other energy companies’ research efforts and the ability to bring new technology to commercial scale on a cost-competitive basis; the development and competitiveness of alternative energy and emission reduction technologies; unforeseen technical or operating difficulties, including the need for unplanned maintenance; and other factors discussed here and in Item 1A. Risk Factors of our Form 10-K and under the heading “Factors Affecting Future Results” available under the “Earnings” tab through the “Investors” page of our website at www.exxonmobil.com. All forward-looking statements are based on management’s knowledge and reasonable expectations at the time of this release and we assume no duty to update these statements as of any future date. Neither future distribution of this material nor the continued availability of this material in archive form on our website should be deemed to constitute an update or re-affirmation of these figures as of any future date. Any future update of these figures will be provided only through a public disclosure indicating that fact.

Supplemental Information

See the Supplemental Information below through the end of this press release for additional important information required by Regulation G for non-GAAP measures, measures that the company considers useful to investors, and definitions of terms used in herein, including cash capex; cash opex excluding energy and production taxes; earnings and cash flow ex. identified items and working capital / other adjusted to 2024 $65/bbl real Brent and 10-year average Energy, Chemical, and Specialty Products margins; operating costs; shareholder distributions; and structural cost savings. Supplemental Information also includes information on the assumptions used in these materials, including assumptions on future crude oil prices and product margins used to develop outlooks regarding future potential outcomes of current management plans.

IMPORTANT INFORMATION AND ASSUMPTIONS REGARDING CERTAIN FORWARD-LOOKING STATEMENTS. For all price point comparisons, unless otherwise indicated, we assume $65/bbl Brent crude prices, $3/mmbtu Henry Hub gas prices, and $6.5/mmbtu TTF gas prices. Unless otherwise specified, crude prices are Brent prices. These are used for clear comparison purposes and are not necessarily representative of management’s internal price assumptions. Crude and natural gas prices for future years are adjusted for inflation (assumption of 2.5%) from 2024. Operating costs and capex are also inflated consistent with plans done on a country-by-country basis. Energy, Chemical, and Specialty Product margins reflect annual historical averages for the 10-year period from 2010-2019 unless otherwise stated. Lower emissions returns are calculated based on current and potential future government policies based on ExxonMobil projections as of the date of this presentation. These prices are not intended to reflect management’s forecasts for future prices or the prices we use for internal planning purposes. Unless otherwise indicated, asset sales and proceeds and Corporate and Financing expenses are aligned with our internal planning. Corporate and Financing expenses reflect estimated potential debt levels under various disclosed scenarios. All references to production rates, project capacity, resource size, and acreage are on a net basis, unless otherwise noted. All references to tons refer to metric tons, unless otherwise noted.

ExxonMobil has business relationships with thousands of customers, suppliers, governments, and others. For convenience and simplicity, words such as venture, joint venture, partnership, co-venturer, operated by others, and partner are used to indicate business and other relationships involving common activities and interests, and those words may not indicate precise legal relationships.

Competitor data and ExxonMobil data used for comparisons to competitor data are sourced from publicly available information and FactSet and are done so consistently for each company in the comparison. Future competitor data and future ExxonMobil data used for comparison to future competitor data, unless otherwise noted, are sourced from FactSet and have not been independently verified by ExxonMobil or any third party. We note that certain competitors report financial information under accounting standards other than U.S. GAAP (i.e., IFRS).

Our capital allocation plans do not extend beyond 2030. Statements about our businesses that reference periods beyond 2030 are made on a basis consistent with ExxonMobil’s Global Outlook, which is publicly available on our website.

Frequently Used Terms and Non-GAAP Measures

Advantaged assets (Advantaged growth projects). When used in reference to our Upstream business, includes Permian (heritage Permian and Pioneer), Guyana, and LNG.

Advantaged projects. Capital projects and programs of work that contribute to Energy, Chemical, and/or Specialty Products segments that drive integration of segments/businesses, increase yield of higher value products, or deliver higher than average returns.

Capital and exploration expenditures (Capital expenditures, Capex). Represents the combined total of additions at cost to property, plant and equipment, and exploration expenses on a before-tax basis from the Consolidated Statement of Income. ExxonMobil’s Capex includes its share of similar costs for equity companies. Capex excludes assets acquired in nonmonetary exchanges, the value of ExxonMobil shares used to acquire assets, and depreciation on the cost of exploration support equipment and facilities recorded to property, plant and equipment when acquired. While ExxonMobil’s management is responsible for all investments and elements of net income, particular focus is placed on managing the controllable aspects of this group of expenditures.

Cash capital expenditures (Cash Capex) (Non-GAAP). Sum of Additions to property, plant and equipment; Additional investments and advances; and Other investing activities including collection of advances; reduced by Inflows from noncontrolling interests for major projects, each from the Consolidated Statement of Cash Flows. Prior to fourth quarter 2024, Inflows from noncontrolling interests for major projects was included within Changes in noncontrolling interests on the Consolidated Statement of Cash Flows. This measure is useful for investors to understand the current period cash impact of investments in the business.

Cash operating expenses (cash opex) excluding energy and production taxes (non-GAAP). Subset of total operating costs that are stewarded internally to support management’s oversight of spending over time. This measure is useful for investors to understand our efforts to optimize cash through disciplined expense management for items within management’s control.

Compound annual growth rate (CAGR). Represents the consistent rate at which an investment or business result would have grown had the investment or business result compounded at the same rate each year.

Distributions to shareholders (shareholder distributions). The Corporation distributes cash to shareholders in the form of both dividends and share purchases. Shares are acquired to reduce shares outstanding and to offset shares or units settled in shares issued in conjunction with company benefit plans and programs. For the purposes of calculating distributions to shareholders, the Corporation includes only the cost of those shares acquired to reduce shares outstanding.

Divestments. Refers to asset sales; results include associated cash proceeds and production impacts, as applicable, and are consistent with our internal planning.

Earnings (loss) excluding Identified Items (Earnings ex. Ident. Items) (non-GAAP). Earnings (loss) excluding individually significant non-operational events with, typically, an absolute corporate total earnings impact of at least $250 million in a given quarter. The earnings (loss) impact of an Identified Item for an individual segment may be less than $250 million when the item impacts several periods or several segments. Earnings (loss) excluding Identified Items does include non-operational earnings events or impacts that are generally below the $250 million threshold utilized for Identified Items. When the effect of these events is significant in aggregate, it is indicated in analysis of period results as part of quarterly earnings press release and teleconference materials. Management uses these figures to improve comparability of the underlying business across multiple periods by isolating and removing significant non-operational events from business results. The Corporation believes this view provides investors increased transparency into business results and trends and provides investors with a view of the business as seen through the eyes of management. Earnings (loss) excluding Identified Items is not meant to be viewed in isolation or as a substitute for net income (loss) attributable to ExxonMobil as prepared in accordance with U.S. GAAP.

Heritage Permian. Permian basin assets excluding assets acquired as part of the acquisition of Pioneer Natural Resources that closed in May 2024.

High-value products. Includes performance products and lower-emissions fuels.

Industry-leading results (industry-leading returns, industry-leading financial performance, industry-leading shareholder value). Includes our leadership in metrics such as earnings, cash flow, dividends paid, share buybacks, and total shareholder return versus the IOCs. Similar terms, such as industry-leading performance or industry-leading shareholder value, refer to our leadership versus the IOCs in metrics such as production or individual terms such as return on capital employed and total shareholder return as applicable in the context presented.

IOCs. Unless stated otherwise, IOCs include each of BP, Chevron, Shell, and TotalEnergies.

Lower-emission fuels. Fuels with lower life cycle emissions than conventional transportation fuels for gasoline, diesel, and jet transport.

Operating costs (Opex) (non-GAAP). Operating costs are the costs during the period to produce, manufacture, and otherwise prepare the company’s products for sale – including energy, staffing, and maintenance costs. They exclude the cost of raw materials, taxes, and interest expense and are on a before-tax basis. While ExxonMobil’s management is responsible for all revenue and expense elements of net income, operating costs, as defined above, represent the expenses most directly under management’s control, and therefore are useful for investors and ExxonMobil management in evaluating management’s performance.

Performance products (performance chemicals, performance lubricants). Refers to products that provide differentiated performance for multiple applications through enhanced properties versus commodity alternatives and bring significant additional value to customers and end-users.

Project. The term “project” as used in this presentation can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports. Projects or plans may not reflect investment decisions made by the company. Individual opportunities may advance based on a number of factors, including availability of supportive policy, technology for cost-effective abatement, and alignment with our partners and other stakeholders. The company may refer to these opportunities as projects in external disclosures at various stages throughout their progression.

Reinvestment rate. Cash capex as a percentage of cash flow from operations excluding identified items and working capital / other.

Returns, rate of return, investment returns, project returns, IRR. Unless referring specifically to ROCE or external data, references to returns, rate of return, IRR, and similar terms mean future discounted cash flow returns on future capital investments based on current company estimates. Investment returns exclude prior exploration and acquisition costs.

Structural cost savings (structural cost reductions, structural cost efficiencies, structural efficiencies, structural cost improvements). Structural cost savings describe decreases in cash opex excluding energy and production taxes as a result of operational efficiencies, workforce reductions, divestment-related reductions, and other cost-savings measures, that are expected to be sustainable compared to 2019 levels. Relative to 2019, estimated cumulative structural cost savings totaled $11.3 billion as of September 30, 2024. The total change between periods in expenses will reflect both structural cost savings and other changes in spend, including market factors, such as inflation and foreign exchange impacts, as well as changes in activity levels and costs associated with new operations, mergers and acquisitions, new business venture development, and early-stage projects. Estimates of cumulative annual structural savings may be revised depending on whether cost reductions realized in prior periods are determined to be sustainable compared to 2019 levels. Structural cost savings are stewarded internally to support management’s oversight of spending over time. This measure is useful for investors to understand our efforts to optimize spending through disciplined expense management.

Structural earnings improvements (structural improvements, growing earnings power, improved earnings power). Structural earnings improvements consist of efforts to improve earnings on a like-for-like price and margin basis and incorporate improvement efforts by the corporation such as growing advantaged assets, improving mix, and reducing structural costs.

Synergies. Synergies refer to pre-tax increases in cash flow due to factors such as higher resource recovery, lower development costs, lower operating costs, among others.

Technology investments. Expenditures to fund and support the activities of the ExxonMobil Technology and Engineering Company, which includes research, development, engineering, and information technology. Other technology expenditures are not included in the definition for this disclosure.

Total shareholder return (TSR). For the purposes of this disclosure, total shareholder return is as defined by FactSet and measures the change in value of an investment in common stock over a specified period of time, assuming dividend reinvestment. For this purpose, FactSet assumes dividends are reinvested in stock at market prices on the ex-dividend date. Unless stated otherwise, total shareholder return is quoted on an annualized basis.

Posted Thursday, March 6, 2025 10:30 am

Emphasizing Fossil Fuels and Energy Independence

As of March 2025, President Donald Trump has enacted a series of policy shifts and executive orders that closely align with the recommendations outlined in the Department of Energy and Related Commissions’ Project 2025 playbook . This initiative, developed by conservative organizations, serves as a blueprint for restructuring federal agencies to prioritize energy independence, deregulation, and economic growth. The Trump administration’s recent actions reflect many of these proposals, signaling a substantial reorientation of U.S. energy policy.

Both Project 2025 and President Trump’s policies underscore the importance of fossil fuels in achieving energy dominance. The playbook advocates for reversing what it describes as the “war on oil and natural gas” by rolling back regulations that restrict fossil fuel production. In parallel, Trump has issued executive orders expanding oil and gas exploration, reopening federal lands for drilling, and reducing restrictions on traditional energy industries.

In early 2025, the administration approved a significant expansion of offshore drilling in the Gulf of Mexico and the Arctic, reversing prior restrictions. The Environmental Protection Agency (EPA) has also relaxed methane emission regulations, allowing for increased production in the Permian Basin and other key oil fields. Additionally, Project 2025 calls for repealing major climate-focused legislation, including the Inflation Reduction Act (IRA) and Infrastructure Investment and Jobs Act (IIJA), both of which allocated substantial funding to renewable energy initiatives. The Trump administration has already taken steps to cut renewable energy subsidies and halt federal support for solar and wind projects, redirecting resources toward fossil fuel development.

DOE Restructuring and Deregulation Efforts

A core recommendation of the “historic movement” is the restructuring of the Department of Energy (DOE) to focus on energy production rather than regulatory oversight. The playbook suggests eliminating offices that support renewable energy initiatives, including the Office of Energy Efficiency and Renewable Energy. Trump’s policies reflect this vision, with efforts underway to shift the department’s priorities toward traditional energy production and national energy security.

Similarly, the playbook calls for limiting the Federal Energy Regulatory Commission’s (FERC) authority over energy markets, focusing instead on ensuring the reliability of fossil fuel-based energy. Trump’s administration has initiated reforms within FERC, prioritizing energy security over climate-focused regulations. In February 2025, FERC commissioners appointed by Trump introduced new rules that ease restrictions on natural gas pipeline approvals, accelerating infrastructure development.

Rolling Back Climate Policies and Environmental Regulations

A key theme in Project 2025 is the rollback of environmental policies implemented under previous administrations. The playbook advocates for reducing government intervention in energy markets, eliminating federal clean energy mandates, and withdrawing from international climate agreements.

In alignment with these recommendations, President Trump has once again withdrawn the U.S. from the Paris Agreement, officially notifying the United Nations in January 2025. The administration has also repealed executive orders requiring federal agencies to consider climate impacts in decision-making and directed agencies to eliminate references to climate change in policy frameworks. The Department of the Interior has reversed previous bans on coal leasing on federal lands, increasing production in states like Wyoming and Montana. Furthermore, regulatory agencies are now tasked with prioritizing economic growth over environmental considerations, mirroring the playbook’s emphasis on energy affordability and national security.

Strategic Administrative Appointments

Beyond policy changes, Project 2025 stresses the importance of appointing leaders who support its energy and deregulation agenda. The Trump administration has followed suit, nominating Chris Wright, a known advocate for fossil fuels, as Secretary of Energy. Wright’s tenure is expected to focus on reducing regulatory barriers for oil and gas companies while limiting government intervention in energy markets.

Additionally, the administration is working to streamline federal agencies by consolidating energy-related functions into a newly proposed “Department of Government Efficiency,” which aligns with the playbook’s recommendation for reducing bureaucratic complexity and oversight. Meanwhile, key positions in the EPA, Department of the Interior, and FERC have been filled by individuals with deep ties to the oil and gas industry, ensuring that the administration’s pro-fossil fuel stance is reflected across federal agencies.

Growing Alignment

The alignment between Project 2025 and President Trump’s energy policy shifts is evident across multiple dimensions, from fossil fuel promotion and DOE restructuring to climate policy rollbacks and strategic appointments. As the administration continues to implement its agenda, the U.S. energy landscape is set to undergo a fundamental transformation, prioritizing traditional energy sources over renewables while reducing federal oversight. These developments highlight a broader conservative effort to reshape national energy policy, reinforcing economic and energy security as central pillars of governance.

Waha woes

Relative strength in crude oil prices—the US oil-to-gas ratio is at a 10-year high of 40:1—has incentivized leading operators in the Permian basin to prioritize oil operations, resulting in an abundance of associated natural gas production.8 Additionally, large shale operators are exploring tier 2 and tier 3 acreage—which are generally much more gas-heavy—to help offset flattening production from their tier 1 acreage, unlock invested capital, and test new productivity and cost-efficiency measures.9 The result: The Permian Basin’s natural gas production has nearly doubled to 25 billion cubic feet per day (Bcf/d) in the last five years.10 However, the takeaway capacity of natural gas remains highly constrained in the basin, with natural gas pipeline utilization exceeding 90% in 2024, pushing regional Waha Hub spot prices below zero.11 As of early September 2024, prices at the Waha Hub were below zero for 46% of trading days in 2024, including every day since July 26.12

However, new midstream infrastructure, such as the 2.5 Bcf/d Matterhorn Express Pipeline, which began transporting natural gas in October 2024, is expected to alleviate some bottlenecks.13 In addition to Matterhorn, three new Permian Basin pipeline projects with a combined capacity of 7.3 Bcf/d are in various stages of development and are expected to be completed between 2026 and 2028.14 However, any slowdown in shale production growth over the next 6 to 18 months, especially if large shale operators reduce their drilling and completion activity due to weak prices, could lead midstream companies to shift their focus toward optimizing existing pipelines, rather than constructing new ones. Some major midstream companies have already highlighted this cautious investment approach for the Permian Basin.15

Stable production and timely completion of pipeline projects can help reduce volatility in natural gas prices and support the broader liquified natural gas (LNG) export market, but also meet the rising power demand driven by increasing numbers of data centers. It is projected that data centers will consume 9% of US electricity by 2030, driving over 3 Bcf/d of new natural gas demand by the end of the decade.16

Growing responsibly

Over the past decade, US upstream companies have prioritized capital discipline, digital transformation, and strategic acquisitions to grow profitably. This strategy contributed to a 7% rise in their net income from 2014 to 2023, despite an 18% drop in oil prices.17 In the coming year, companies will likely adapt their strategy to address challenges including low oil prices, peaking productivity gains (with rigs in the Midland basin having drilled an average of 47 miles of horizontal lateral wells over the year to June 2024), an all-time low inventory of drilled but uncompleted wells at 4,500, and the forecasted resurgence in global liquids consumption that is expected to increase by 1.5 MMbbl/d (million barrels/day) in 2025.18 Against the backdrop of major acquisitions, eyes will be on US shale majors to share and execute their “what’s next?” strategy for the Permian Basin.

Consolidating acquired assets and leveraging investments in new technologies, while benefiting from strengthening natural gas prices due to new pipelines, will likely support the profitable growth strategy of shale majors in 2025. However, a bigger prize could be in how shale majors rethink their tier 2 and tier 3 acreage across shale basins. By adopting new refracturing, enhanced oil recovery, and innovative completion techniques, they have the potential to enhance their capital returns and well productivity. Development in tier 1 acreage is growing by 5% to 10% annually in the Bakken Shale Play, while tier 2 acreage is growing by 20% annually.19

Additionally, by implementing new water-treatment protocols and oil-skimming technologies, shale majors may also strive to reduce their environmental footprint and costs associated with managing produced water. In fact, the industry’s cost of reusing water now stands at US$0.15 to US$0.20 per barrel, which is cheaper than the disposal cost of US$0.25 to US$1 per barrel.20

M&A frontiers

With nearly US$136 billion in deals since 2023, the upstream sector has seen major M&A consolidation in the Permian Basin.21 However, higher acreage prices and limited high-quality acquisition targets in the basin, combined with favorable financial markets, may lead to increased drilling and buying activities in other basins, primarily Eagle Ford and Bakken. In fact, the availability of acquisition targets and refracturing opportunities, without significant infrastructure constraints, makes these basins strong rotational candidates for the short to medium term.22 In the first three quarters of 2024, these two basins have already seen a buying interest of around US$7.7 billion.23 This competition, or rotation, can be necessary and healthy. Not only can it reduce the concentration risk on the Permian Basin, but it can also bridge the valuation gap across the shale basins, keep the overall production profile of US shale basins stable, and help bring back private equity or venture capital players. This is especially true in the US upstream sector, where public company consolidations offer more favorable valuations for undeveloped inventory, compared to private equity buyouts, with premiums remaining modest at 10% to 15%.24