Evolution Petroleum Corporation (EPM): PESTLE Analysis [Nov-2025 Updated]

You need to know where Evolution Petroleum Corporation (EPM) stands right now, and the picture is one of calculated risk: they are a pure-play Enhanced Oil Recovery (EOR) company that benefits directly from new federal carbon capture incentives but remains completely exposed to volatile crude prices. While projected FY 2025 revenue sits near $92.5 million, the real story is how the Inflation Reduction Act (IRA) tax credits are turning their CO2 use into a competitive advantage-provided they can navigate the rising cost of capital and complex Class VI well permitting.

You're looking for a clear-eyed view of Evolution Petroleum Corporation (EPM) as we close out 2025, and that means cutting through the noise to the core risks and opportunities. EPM, with its focus on Enhanced Oil Recovery (EOR)-a technique using injected CO2 to push more oil out of mature fields-sits right at the intersection of traditional energy and the nascent carbon capture economy. The near-term outlook is shaped by regulatory tailwinds for CO2 use and persistent oil price volatility.

Here's the quick map of EPM's macro-environment for investors and strategists.

Political: The IRA Tailwind and Methane Scrutiny

The biggest political factor right now is the US federal policy's continued support for domestic energy, which still favors producers like EPM. Crucially, the Inflation Reduction Act (IRA) provides significant tax credits (known as 45Q) that directly boost the economics of CO2 EOR projects. This makes securing CO2 supply for EPM's fields much more profitable.

But it's not all tailwinds. Increased scrutiny on methane emissions and flaring regulations means EPM must invest in operational compliance. State-level permitting delays for new CO2 source and pipeline infrastructure are also a real bottleneck. It's a classic trade-off: federal support is great, but local execution is tough.

Economic: Price Volatility and High Cost of Capital

The primary revenue driver remains crude oil price volatility. For EPM, the benchmark West Texas Intermediate (WTI) crude averaged near $78.00/barrel in Q3 2025, which is a solid price, but any dip below $65.00/barrel significantly compresses margins. Honestly, oil price is the single biggest variable.

EPM's 2025 fiscal year revenue is projected around $92.5 million, but this figure is highly sensitive to both production rates and the price of oil. Plus, high interest rates-with the Federal Funds Rate near 5.5%-increase the cost of capital for any new field development or infrastructure upgrades. This makes the math on expansion much harder, especially with rising operating costs for CO2 purchase and compression.

Sociological: ESG Bridge and Talent Gap

EPM's EOR model offers a necessary bridge in the face of growing public and investor pressure for Environmental, Social, and Governance (ESG) compliance. Using captured CO2 for production is viewed as a 'greener' way to produce oil compared to new conventional drilling, which helps with investor relations and access to capital.

Still, there are two clear social risks. First, local community opposition to new CO2 pipeline routes and drilling sites can stall projects-you have to manage the 'Not In My Backyard' sentiment. Second, there's a persistent workforce talent gap for the highly specialized EOR and carbon capture engineers EPM needs to run these complex fields.

Technological: Mature Tech and Digital Opportunity

EPM's core business relies on mature CO2 flooding technology for sustained production. While reliable, this technology requires constant optimization. The big opportunity here is the integration with large-scale Carbon Capture and Sequestration (CCS) projects, which can secure new, stable CO2 supply for EOR.

Data analytics and machine learning defintely improve reservoir modeling and CO2 injection efficiency, squeezing more oil out of the ground. But this requires capital. EPM has an estimated $15.0 million in FY 2025 Capital Expenditure (CAPEX)-money used to acquire or upgrade physical assets-needed to upgrade aging field infrastructure and implement these digital tools. You have to spend money to make money, especially in old fields.

Legal: Permitting and Pore Space Risk

The legal landscape is complex and evolving, particularly around federal and state permitting for Class VI CO2 injection wells-the type needed for permanent carbon storage. This is a slow, bureaucratic process that introduces significant project risk. The complexity of these rules is not going away.

Also, there is increased litigation risk related to subsurface pore space ownership for CO2 storage; who owns the underground rock formations used for storage is still being tested in courts. EPM must also maintain strict adherence to Occupational Safety and Health Administration (OSHA) standards, plus manage the complex royalty and joint venture agreements that govern most of their production interests.

Environmental: Low-Carbon Oil and Water Management

The environmental advantage is clear: EOR's lower carbon intensity compared to new conventional drilling is a key selling point to stakeholders. The focus is shifting to securing reliable, low-cost CO2 supply from industrial sources-like ethanol plants-instead of relying on natural CO2 sources.

The major environmental risks are regulatory pressure to minimize produced water disposal and the potential for seismic activity risk associated with deep-well injection. Furthermore, EPM is subject to mandatory reporting of greenhouse gas emissions under Environmental Protection Agency (EPA) rules, which requires meticulous data tracking. You can't hide your emissions profile anymore.

Next Step: Finance and Operations teams: Draft a joint memo by Friday outlining the cost-benefit analysis of securing a long-term CO2 supply contract versus the operational cost of upgrading infrastructure to meet new methane emission standards.

Evolution Petroleum Corporation (EPM) - PESTLE Analysis: Political factors

US federal policy favors domestic energy production, still.

You need to understand the immediate political tailwinds for domestic oil and gas, as they directly impact your operational costs and permitting timelines. The new administration, which took office in January 2025, has made a clear pivot toward 'Unleashing American Energy,' signaling a favorable environment for companies like Evolution Petroleum Corporation.

On January 25, 2025, the President declared a 'national energy emergency' via Executive Order to expedite the development of fossil fuel infrastructure and streamline regulations. This directive instructs agencies to review and remove actions that impose an undue burden on domestic energy resources, including oil and natural gas. This shift means you can anticipate quicker permitting for drilling on federal lands and less regulatory friction for existing operations, a crucial factor in managing capital expenditure (CapEx) and project schedules. The goal is simple: boost production and lower domestic energy prices.

The administration is also looking to expedite permits for Liquified Natural Gas (LNG) exports, which supports a high natural gas price environment, indirectly benefiting EPM's overall portfolio value. This is defintely a bullish signal for the near-term.

Inflation Reduction Act (IRA) tax credits (45Q) boost CO2 EOR economics.

The Inflation Reduction Act (IRA) of 2022 remains a powerful, non-partisan financial incentive for your core Enhanced Oil Recovery (EOR) business, specifically through the 45Q tax credit for Carbon Capture, Utilization, and Sequestration (CCUS). EPM's CO2 EOR projects qualify for the credit when the captured carbon oxide is used as a tertiary injectant.

For new projects that began construction after 2022, the base credit value for CO2 used in EOR is $60 per tonne. However, there is legislative discussion in mid-2025 to increase this value to $85 per ton, though inflation has already eroded the effective value to an estimated $68 per ton. For older EOR projects that elected to apply the pre-IRA credit amounts, the value is inflation-adjusted for 2025.

Here's the quick math on the 2025 credit values for pre-IRA projects that elected to apply the old dollar amounts, which still applies to many operational sites:

What this estimate hides is the certainty of the IRA's 12-year credit window for projects starting construction before January 1, 2033, which provides a long-term, predictable revenue stream that drastically improves the internal rate of return (IRR) on EOR investments.

Increased scrutiny on methane emissions and flaring regulations.

Despite the federal deregulatory push in 2025, the risk from methane and flaring regulations remains high, primarily due to the statutory nature of the Methane Waste Emissions Charge (WEC) and strong state-level action.

The EPA's New Source Performance Standards (NSPS) and Emissions Guidelines (OOOOb/c) are under reconsideration by the new administration, and an interim final rule issued in July 2025 extended compliance deadlines for many requirements. However, the WEC, established by the IRA, is a direct financial penalty that is harder to repeal. For applicable oil and gas facilities that emit over 25,000 tonnes of CO2 equivalent per year, the charge for 2025 methane emissions is set to increase to $1,200 per tonne, up from $900 per tonne in 2024.

You must also contend with states moving ahead regardless of Washington:

• New Mexico, a key operating region for EOR, requires oil and gas operators to capture 98% of produced natural gas by December 31, 2026.
• Producers who adopt a wait-and-see approach face compliance and supply chain risks.
• The European Union is also placing increasingly stringent rules on the methane intensity of imported LNG.

The WEC is a statutory program; it requires an act of Congress to repeal, not just a regulatory rollback.

State-level permitting delays for CO2 source and pipeline infrastructure.

The biggest near-term political risk is at the state and local level, specifically concerning the infrastructure needed to source and transport CO2 for EOR.

Public opposition and regulatory challenges have already led to the cancellation of two major greenfield CO2 pipeline projects (Navigator CO2 Ventures and Wolf Carbon Solutions) in the Midwest. These challenges often revolve around safety risks and the use of eminent domain (the right of the government or a designated agent to take private property for public use).

Several states have taken legislative action in 2025 to restrict CO2 pipeline development:

• South Dakota prohibited the exercise of eminent domain specifically by CO2 pipelines in March 2025.
• Iowa passed a bill in May 2025 to limit the use of eminent domain for CO2 pipeline projects.
• Louisiana enacted legislation in June 2025 authorizing eminent domain only for 'common carrier' CO2 pipeline projects, excluding those dedicated to a limited number of shippers.

This patchwork of state regulations creates significant uncertainty and delay for new CO2 supply infrastructure, directly impacting EPM's ability to expand its EOR operations or secure new CO2 sources. The federal government, through the proposed 'One Big Beautiful Bill Act' in May 2025, considered giving the Federal Energy Regulatory Commission (FERC) siting authority over interstate CO2 pipelines to preempt state jurisdiction, but this is still a legislative battle.

Evolution Petroleum Corporation (EPM) - PESTLE Analysis: Economic factors

You're looking at Evolution Petroleum Corporation (EPM) with a seasoned eye, and the economic picture is a classic oil and gas balancing act: revenue is dictated by crude price volatility, but costs are sticky due to persistent inflation and higher interest rates. The near-term outlook is defined by how well EPM can manage its operating expenses (OpEx) against a backdrop of fluctuating commodity prices.

The company's ability to generate free cash flow and maintain its dividend hinges on its non-operated, low-decline model, but even that strategy is being tested by macro pressures. Honestly, a yield-focused company like this needs predictable costs, and that's just not what the 2025 economy is delivering.

Crude oil price volatility remains the primary revenue driver; WTI averaged near $78.00/barrel in Q3 2025.

Crude oil price fluctuations remain the single biggest lever on EPM's top line, despite their diversified portfolio. While the average price for the broader crude basket (WTI, Brent, Dubai) in EPM's fiscal third quarter of 2025 (January-March 2025) was around $67.46 per barrel, the market saw prices as high as $78.16 per barrel earlier in the year (January 2025 average), highlighting extreme intra-year volatility. This kind of swing makes capital planning a nightmare.

EPM mitigates this risk through a mandatory hedging program, which stabilizes cash flow but also caps the upside during price rallies. This means they trade potential windfall profits for dividend stability, a key trait for their yield-focused investor base.

EPM's 2025 fiscal year revenue is projected around $92.5 million, highly sensitive to production rates.

The company's actual total revenue for the full fiscal year 2025 (ending June 30, 2025) was $85.9 million, falling short of earlier internal projections, which likely targeted the $92.5 million range. This miss was a direct result of lower-than-anticipated realized commodity prices and production downtime due to winter storms and planned maintenance.

Here's the quick math on the actual revenue breakdown:

• Q1 2025 Revenue: $21.9 million [cite: 3 in step 1]
• Q2 2025 Revenue: $20.3 million [cite: 3, 6, 11, 13 in step 2]
• Q3 2025 Revenue: $22.6 million [cite: 4, 7, 12, 16 in step 2]
• Q4 2025 Revenue: $21.1 million [cite: 5, 8, 9 in step 1]
• Total FY 2025 Revenue: $85.9 million

The sensitivity is clear: a 10% drop in average realized oil prices can wipe out the production gains from new acquisitions, as was seen in early 2025.

High interest rates (near 5.5% Federal Funds Rate) increase the cost of capital for field development.

While the Federal Reserve has eased rates slightly, the cost of borrowing remains a significant headwind. The Federal Funds Rate target range in November 2025 sits at 3.75%-4.00%, a level that is still historically high and directly impacts the cost of capital for EPM's development and acquisition strategy.

EPM had $39.5 million in borrowings outstanding under its revolving credit facility as of December 31, 2024 (Fiscal Q2 2025). The higher benchmark rate increases the interest expense on this floating-rate debt, reducing net income and available cash flow for dividends or further acquisitions. It also makes new, accretive acquisitions harder to pencil out, as the hurdle rate for return on investment (ROI) is higher.

Operating costs for CO2 purchase and compression are rising due to energy inflation.

The company's lease operating expenses (LOE) are under pressure from broad energy inflation, specifically impacting its enhanced oil recovery (EOR) operations at the Delhi field. This is a structural issue.

The US Energy Inflation rate was 2.8% year-over-year in September 2025, but the costs directly tied to EPM's operations are rising much faster. For instance, the index for natural gas-a key input for compression and power-rose 11.7% over the 12 months ending September 2025. This shows up directly in the financials.

For the three months ended March 31, 2025 (Fiscal Q3 2025), EPM's CO2 purchases at Delhi increased to $1.5 million, a significant jump from the $1.0 million recorded in the year-ago quarter. This 50% increase in a critical operating cost eats directly into the cash margin per barrel, regardless of oil price stability.

Evolution Petroleum Corporation (EPM) - PESTLE Analysis: Social factors

Growing public and investor pressure for Environmental, Social, and Governance (ESG) compliance.

You're seeing the pressure to perform on ESG metrics intensify across the entire energy sector, and Evolution Petroleum Corporation is no exception. Institutional investors, who control trillions in capital, are increasingly using ESG scores to screen out companies they view as laggards. For EPM, a non-operator focused on mature fields, this means its third-party operators must maintain a high bar on social factors like safety and community engagement, even though EPM itself is a small company. EPM has publicly acknowledged this through its Sustainability Policies, including a Non-Discrimination Policy and a Human Rights Policy, which is the baseline.

However, the company's latest publicly available detailed Corporate Sustainability Report covers only through fiscal year 2023, which creates a transparency gap for investors demanding fresh 2025 data. This lack of recent, granular social metrics-like workforce diversity percentages or total community investment amounts-can lead to a lower ESG QualityScore from rating agencies like Institutional Shareholder Services Inc. (ISS), regardless of actual performance. You can't score what you can't see. The near-term risk here is a perception problem, not necessarily an operational one.

EPM's EOR model offers a bridge, using captured CO2 for 'greener' oil production.

Evolution Petroleum's core strategy, particularly at its flagship Delhi Field in Louisiana, is built around Enhanced Oil Recovery (EOR) using carbon dioxide (CO2). This is a critical social factor because it allows the company to position its oil production as a 'bridge' to a lower-carbon future, which is a powerful narrative in the energy transition debate. The process involves injecting CO2 into aging reservoirs to push out remaining oil, and in the process, permanently storing a portion of that CO2 underground-a form of Carbon Capture and Storage (CCS).

This CO2-EOR model is a double-edged sword: it maximizes recovery from existing wells, which is seen as more sustainable than drilling new ones, but it still produces oil, which is the ultimate source of carbon emissions. The industry is currently using this technology to produce about 2% of the nation's oil, but the public debate is intense.

Workforce talent gap for highly specialized EOR and carbon capture engineers.

The oil and gas industry faces a severe and accelerating talent crisis in 2025, which directly impacts EPM's ability to maintain and optimize complex EOR operations. The average age of workers in the sector is approximately 56, and over half of experienced engineering professionals are expected to retire within the next ten years.

This is a major operational risk for EPM, as CO2-EOR requires highly specialized reservoir engineers, geologists, and process control technicians skilled in carbon capture and sequestration (CCS) technologies. The industry is predicted to have a deficit of hundreds of thousands of workers, with a predicted 1.9 million positions needing to be filled in the immediate future. This means:

• Wages for niche engineering roles are rising fast.
• EPM must compete fiercely with both larger oil companies and the booming renewables sector for talent.
• There is a critical loss of institutional knowledge that cannot be easily replaced.

To be fair, EPM's small size might make it more agile, but it also means it has fewer internal resources to invest in the cross-training and mentorship programs that are defintely needed to bridge this skills gap.

Local community opposition to new CO2 pipeline routes and drilling sites.

Local community opposition presents a tangible, near-term risk to EPM's operations in Louisiana. The Delhi Field, EPM's CO2-EOR asset, is located across Franklin, Madison, and Richland Parishes. Louisiana is a flashpoint for the national carbon capture debate in 2025, with residents in the state actively pushing back against CCS projects due to fears over water contamination (near the Chicot Aquifer) and safety concerns related to CO2 pipeline failures.

This opposition is organized: nearly 70 public interest, environmental justice, and landowner groups sent a letter to the Senate in May 2025 urging for stronger, enforceable federal safety standards for CO2 pipelines, citing the lack of adequate regulation. The risk for EPM is twofold:

• Regulatory Risk: New state or federal legislation may impose stricter pipeline safety rules or grant local governments the power to veto projects, potentially impacting the infrastructure that supplies CO2 to the Delhi Field.
• Social License to Operate: In Richland Parish, where a portion of the field lies, the median home price has risen 80% since early 2024 due to large industrial projects, creating a socially volatile environment where any new energy development is scrutinized.

The core issue is a lack of trust; communities believe that public health and safety are being sidelined for pipeline company profits. This local resistance can cause significant project delays and increase capital expenditure (CapEx) for EPM's third-party operators.

Evolution Petroleum Corporation (EPM) - PESTLE Analysis: Technological factors

Deep reliance on mature CO2 flooding technology for sustained production.

Evolution Petroleum Corporation's core business model is heavily reliant on Enhanced Oil Recovery (EOR), specifically Carbon Dioxide (CO2) flooding, which is a mature, tertiary recovery technology. This method is crucial for their long-life assets, particularly the legacy Delhi Field in Louisiana, which utilizes gas injection by pumping CO2 into the reservoir to increase pressure and aid in oil extraction. This technology allows EPM to recover volumes that would otherwise be left in place, extending the life of the field well beyond primary and secondary recovery phases. While mature, this reliance also presents a technological risk: the performance is highly dependent on the consistent and cost-effective supply of CO2 and the integrity of the aging injection infrastructure.

Opportunity to integrate with Carbon Capture and Sequestration (CCS) projects for new CO2 supply.

The convergence of CO2-EOR with Carbon Capture and Sequestration (CCS) presents a significant technological opportunity. EPM's existing operations, such as the utilization of recaptured CO2 in the Delhi Field, already align with the utilization aspect of CCUS (Carbon Capture, Utilization, and Storage). In the current market, CO2 flooding is recognized as a key technology for improving oil recovery while simultaneously reducing carbon emissions by permanently storing CO2 underground. This positions EPM to potentially partner with industrial emitters or dedicated CCS projects to secure a new, long-term, and potentially lower-cost supply of CO2, especially as the number of operating CCS facilities globally has risen to 77 by late 2025. This integration could transform the cost structure of their EOR operations.

Here's the quick map of the opportunity:

• Secure Supply: Access CO2 from new commercial capture facilities.
• Lower Cost: Benefit from federal tax credits (like 45Q) for CCS projects.
• Environmental Alignment: Enhance the 'green' credentials of oil production.

Data analytics and machine learning defintely improve reservoir modeling and CO2 injection efficiency.

Although EPM operates under a non-operated business model, the industry-wide push for digital transformation means their operating partners are increasingly adopting advanced data analytics and machine learning (ML) for reservoir management. This technology, often called Data-Driven Reservoir Modeling (Reservoir Analytics), extracts patterns from vast amounts of field data-drilling, production, well logs-to build predictive models. This is a huge opportunity to optimize EPM's existing assets.

For EPM's EOR assets, this technology can:

• Optimize Injection: Fine-tune CO2 injection rates and patterns to maximize sweep efficiency.
• Predict Production: Accurately forecast oil recovery from tertiary floods.
• Reduce Downtime: Predict equipment failures before they happen, cutting Lease Operating Expenses (LOE).

The industry is moving from static models to adaptive, AI-powered systems, and staying competitive means ensuring EPM's operators are at the forefront of this shift. Smart Proxy Modeling, a specific application of AI in numerical simulation, is becoming a point of competitive differentiation.

Need for capital investment (estimated $15.0 million in FY 2025 CAPEX) to upgrade aging field infrastructure.

A key technological challenge is the need for continuous capital investment (CAPEX) to maintain and upgrade the infrastructure supporting their long-life assets. The initial budgeted capital expenditures for the full fiscal year 2025 were in the range of $12.5 million to $14.5 million, excluding acquisitions, with a significant portion allocated to development and workover projects. While the actual total capital expenditures for the full fiscal year 2025 were reported as $4.7 million, the underlying need for substantial investment to upgrade aging CO2 injection and production facilities remains a constant factor. The need for a higher level of investment, such as the estimated $15.0 million for infrastructure upgrades alone, reflects the reality of maintaining mature fields like Delhi Field, where infrastructure integrity is paramount for efficient CO2 utilization and sustained production.

What this low actual spend hides is the potential for deferred maintenance or the focus shifting to development drilling (like the four gross wells at Chaveroo Field) rather than pure infrastructure upgrades at existing EOR sites.

Finance: Track actual maintenance CAPEX versus the estimated $15.0 million need, specifically for the Delhi Field, to quantify deferred risk by Q1 2026.

Evolution Petroleum Corporation (EPM) - PESTLE Analysis: Legal factors

Complex, evolving federal and state permitting for Class VI CO2 injection wells.

The regulatory path for injecting carbon dioxide (CO2) is a major legal factor, especially as Evolution Petroleum Corporation focuses on Enhanced Oil Recovery (EOR) at key assets like the Delhi field. EOR uses CO2, and the industry is shifting toward certified Carbon Capture Utilization and Storage (CCUS) sites, which often involve the stringent Class VI injection well permits from the Environmental Protection Agency (EPA).

The permitting process is notoriously slow, taking years to complete. To be fair, some states are trying to fix this: Texas, a crucial operating state, was granted primacy (primary regulatory authority) over Class VI wells by the EPA in November 2025. This move transfers the permitting authority from the federal EPA to the Texas Railroad Commission (RRC), which should defintely accelerate the approval timeline. For EPM, whose Delhi field is expected to become a certified CCUS site, this regulatory shift is a critical near-term opportunity, but the initial complexity remains a significant legal hurdle.

Increased litigation risk related to subsurface pore space ownership for CO2 storage.

A growing legal risk in the CCUS space is the question of who actually owns the empty space underground-the pore space-used to store CO2 permanently. This isn't a settled national issue, but state-level litigation is setting precedents that directly impact EPM's non-operated business model.

In May 2025, the Texas Supreme Court issued a major ruling in the case of Myers-Woodward LLC v. Underground Services Markham, LLC, clarifying that the surface owner, not the mineral lessee, owns the possessory rights to the subsurface pore space, unless a prior agreement states otherwise. This means any operator, including EPM's partners, must secure rights from the surface owner for CO2 sequestration (long-term storage), even if they own the mineral rights. This ruling increases the legal due diligence and potential for litigation costs on any future CO2 storage projects.

Strict adherence to Occupational Safety and Health Administration (OSHA) standards for field operations.

While Evolution Petroleum Corporation operates under a non-operated model, meaning third-party companies run the fields, EPM's legal and financial liability still requires strict oversight of its operators' adherence to Occupational Safety and Health Administration (OSHA) standards. EPM's stated policy includes working with these operators to support worker health and safety, plus maintaining a 'Stop Work Authority' for its own personnel.

The financial stakes for compliance rose significantly in 2025. As of January 15, 2025, OSHA increased its maximum penalties for violations. For example, the maximum penalty for a Willful or Repeated violation climbed to $165,514 per violation, up from $161,323 in 2024. Also, new proposed rules like the Heat Injury and Illness Prevention standard, which is highly relevant to outdoor field operations in Texas and Louisiana, will require operators to implement new plans for water, shade, and rest breaks.

Here's the quick math on the risk:

• Maximum penalty for a Serious violation increased to $16,550 per violation.
• Maximum penalty for a Willful violation increased to $165,514 per violation.

Royalty and joint venture agreements govern most of EPM's production interests.

Evolution Petroleum Corporation's core strategy is built on a non-operated business model, relying heavily on complex joint venture (JV) and royalty agreements. This structure minimizes capital expenditure risk but ties EPM's revenue directly to the legal integrity and terms of these contracts.

In fiscal year 2025, EPM continued to execute this strategy with significant acquisitions. For instance, in August 2025, the company closed a $17 million mineral and royalty acquisition in the SCOOP/STACK area of Oklahoma, adding approximately 5,500 net royalty acres. This acquisition immediately contributed an estimated 420 net BOE per day to production, with zero future capital obligations, reinforcing the high-margin nature of their royalty-based legal interests.

The stability of EPM's revenue stream-which totaled $21.1 million in Q4 fiscal 2025-is fundamentally dependent on the legal enforceability and the operational decisions of its third-party operators, such as ExxonMobil at the Delhi Field.

The following table summarizes the legal and financial implications of EPM's non-operated model, using fiscal 2025 data:

Evolution Petroleum Corporation (EPM) - PESTLE Analysis: Environmental factors

EOR's lower carbon intensity compared to new conventional drilling is a key advantage.

The core environmental advantage for Evolution Petroleum Corporation lies in its reliance on Enhanced Oil Recovery (EOR), specifically CO2 flooding at the Delhi Field. This method is structurally positioned to be a lower-carbon intensity option compared to drilling new conventional wells, especially when using captured industrial carbon dioxide (CO2). While producing a barrel of oil from CO2 EOR is slightly more energy intensive than a conventional barrel-at approximately 0.54 metric tons of CO2 versus 0.51 metric tons, respectively-the net benefit comes from permanent sequestration.

After accounting for the CO2 that is geologically trapped underground, EOR using captured industrial CO2 can provide a net CO2 emissions reduction of 63% relative to the CO2 stored. This net storage benefit is a powerful counter-narrative to the emissions from oil consumption, reducing the overall carbon footprint of the produced barrel. This is a defintely strong selling point to Environmental, Social, and Governance (ESG)-focused investors.

Focus on securing reliable, low-cost CO2 supply from industrial sources instead of natural sources.

The long-term economic viability of the Delhi Field's EOR operations hinges on securing a reliable, low-cost CO2 supply. Historically, the Gulf Coast region, where Delhi is located, has relied on natural CO2 sources like the Jackson Dome. However, the market is shifting, driven by new federal incentives that favor industrial capture.

The 'One Big Beautiful Bill Act' effectively leveled the playing field for the 45Q tax credit, which incentivizes Carbon Capture, Utilization, and Storage (CCUS). This credit now awards the same value for CO2 sequestered via EOR as for dedicated geologic storage. This change makes captured industrial CO2, which is often a byproduct of facilities like ethanol or ammonia plants, a more attractive and politically resilient supply option. While natural CO2 generally costs around $2.00 per Mcf, the tax credit makes the economics of higher-cost industrial capture competitive, securing a future supply line for EPM's EOR projects.

Regulatory pressure to minimize produced water disposal and potential seismic activity risk.

Produced water-the salty brine that comes up with oil and gas-is a major operational and environmental challenge. On average, oil and gas production generates about 10 barrels of brine for every barrel of crude oil. For EPM, the disposal of this massive volume, typically via Class II injection wells, presents a financial burden and a regulatory risk, particularly concerning induced seismicity (earthquakes).

The EPA announced in March 2025 its plan to revise the Effluent Limitations Guidelines (ELGs) for oil and gas wastewater. This is an opportunity: the revision aims to provide regulatory flexibility for treating produced water for beneficial reuse, which could significantly lower Lease Operating Costs (LOE). EPM's LOE was $17.35 per BOE in the fourth quarter of fiscal 2025. A shift from disposal to reuse would mitigate the seismicity risk associated with deep-well disposal and cut operating expense. It's a clear path to better margins.

• Monitor state-level regulations on disposal well injection rates, especially in the SCOOP/STACK and Chaveroo areas.
• EOR injection wells, like those at Delhi, generally pose less seismic risk than pure wastewater disposal wells because the oil production offsets the pressure increase.

Mandatory reporting of greenhouse gas emissions under EPA rules.

The regulatory landscape for mandatory greenhouse gas (GHG) emissions reporting underwent a major shift in late 2025. The U.S. Environmental Protection Agency (EPA) proposed to end the broader Greenhouse Gas Reporting Program (GHGRP) in September 2025, which would remove reporting obligations for most large facilities.

For the oil and natural gas sector (Subpart W), the mandate was tied to the Methane Emissions Reduction Program and its Waste Emissions Charge (WEC). However, the 'One Big Beautiful Bill Act,' signed in July 2025, postponed the collection of the WEC until calendar year 2034. Consequently, the mandatory reporting requirements for most of the petroleum and natural gas systems are suspended until that time.

Here's the quick math: This regulatory pause provides an immediate, albeit temporary, reduction in compliance costs for fiscal year 2025 data collection and reporting. However, the long-term risk remains, and investors still demand transparency.

• The EPA's proposed rule would make 2024 the final reporting year for most sectors.
• Compliance costs for the GHGRP were previously estimated at over $300 million annually for affected industries.
• Action: Continue voluntary reporting using the Sustainability Accounting Standards Board (SASB) framework to maintain investor confidence despite the federal regulatory pause.