Berry Petroleum (BRY) Risk Analysis

The marketing of oil, natural gas and NGLs production depends in large part on the availability, proximity and capacity of trucks, pipelines and storage facilities, gas gathering systems and other transportation, processing and refining facilities, as well as the existence of adequate markets. Storage and transportation capacity for our production is limited and may become unavailable on commercially reasonable terms or at all. For example, storage and transportation capacity became scarce during the second quarter of 2020 due to the unprecedented dual impact of a severe global oil demand decline coupled with a substantial increase in supply. As traditional tanks filled, large quantities of oil were being stored in offshore tankers around the world, including off the coast of California. Where storage was available, such as offshore tankers, storage costs increased sharply. The potential risk remains that storage for oil may be unavailable and our existing capacity may be insufficient to support planned production rates in the event of another deterioration in demand or a supply surge or both. Moreover, if the imbalance between supply and demand and the related shortage of storage capacity worsen, the prices we receive for our production could deteriorate and could potentially even become negative. Additionally, if we were unable to obtain the needed storage capacity, we could be forced to shut in a significant amount of our California production, which could have a material adverse effect on our financial condition, liquidity and operational results. If we are forced to shut in production, we would incur additional costs to bring the associated wells back online. While production is shut in, we would likely incur additional costs and operating expenses to, among other things, maintain the health of the reservoirs, meet contractual obligations and protect our interests, without the associated revenue. Additionally, depending on the duration of the shut-in, and whether we have also shut in steam injection for the associated reservoirs rather than incur those costs, the wells may not, initially or at all, come back online at similar rates to those at the time of shut-in. Depending on the duration of the steam injection shut-in time, and the resulting inefficiency and economics of restoring the reservoir to its energetic and heated state, our proved reserve estimates could be decreased and there could be potential additional impairments and associated charges to our earnings. A reduction in our reserves could also result in a reduction to our borrowing base under the 2024 Revolver and our liquidity. The ultimate significance of the impact of any production disruptions, including the extent of the adverse impact on our financial and operational results, will be dictated by the length of time that such disruptions continue, which will in turn depend on how long storage remains filled and unavailable to us, which is largely unpredictable and based on factors outside of our control. In addition to the constraints we may face due to storage capacity shortages, the volume of oil and natural gas that we can produce is subject to limitations resulting from pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, and physical damage to the gathering, transportation, storage, processing, fractionation, refining or export facilities that we utilize. The curtailments arising from these and similar circumstances may last from a few days to several months or longer and, in many cases, we may be provided only limited, if any, advance notice as to when these circumstances will arise and their duration. Any such shut-in or curtailment, or any inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results of operations. In October 2024, Phillips 66 announced that it plans to close its Wilmington refinery in Los Angeles in late 2025. We sold approximately 15% of our California production to this refinery in 2024. Following the closure of the Phillips 66 refinery, we expect California to have approximately 1.5 million bpd of remaining refining capacity which is over five times the amount of crude oil produced in California. As a result, we do not currently expect the Phillips 66 closure to negatively impact our price realizations, however, if there were significant other refinery closures, that could have an adverse impact on our ability to market our crude production.

We are dependent on four cogeneration facilities that, combined, provide approximately 10% of our steam capacity and approximately 46% of our field electricity needs in California at a discount to market rates. To further offset our costs, we sell surplus power to California utility companies produced by certain of our cogeneration facilities under long-term contracts. Should we lose, be unable to renew on favorable terms, or be unable to replace such contracts, we may be unable to realize the cost offset currently received. Our ability to benefit from these facilities is also affected by our ability to consistently generate surplus electricity and fluctuations in commodity prices. Furthermore, market fluctuations in electricity prices and regulatory changes in California could adversely affect the economics of our cogeneration facilities and any corresponding increase in the price of steam could significantly impact our operating costs. If we were unable to find new or replacement steam sources, lose existing sources or experience installation delays, we may be unable to maximize production from our heavy oil assets. If we were to lose our electricity sources, we would be subject to the electricity rates we could negotiate. For a more detailed discussion of our electricity sales contracts, see "Items 1 and 2. Business and Properties-Operational Overview-Electricity."

We evaluate the impairment of our oil and natural gas properties whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write down constitutes a non-cash charge to earnings.

The Dodd-Frank Act, enacted in 2010, establishes federal oversight and regulation of the over-the-counter ("OTC") derivatives market and entities, like us, that participate in that market. Rules and regulations applicable to OTC derivatives transactions may affect both the size of positions that we may hold and the ability or willingness of counterparties to trade opposite us, potentially increasing costs for transactions. Moreover, such changes could materially reduce our hedging opportunities which could adversely affect our revenues and cash flow during periods of low commodity prices. While many Dodd-Frank Act regulations are already in effect, the rulemaking and implementation process is ongoing, and the ultimate effect of the adopted rules and regulations and any future rules and regulations on our business remains uncertain. In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions or counterparties with other businesses that subject them to regulation in foreign jurisdictions, we may become subject to, or otherwise be affected by, such regulations. Even though certain of the European Union implementing regulations have become effective, the ultimate effect on our business of the European Union implementing regulations (including future implementing rules and regulations) remains uncertain.

Like many oil and natural gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have a material adverse impact on us because of legal costs, diversion of the attention of management and other personnel and other factors. In addition, resolution of one or more such proceedings could result in liability, loss of contractual or other rights, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change materially from one period to the next.

The Governor of California signed the Climate Corporate Data Accountability Act ("CCDAA"), or SB 253, into law on October 7, 2023, alongside the Climate-Related Financial Risk Act ("CRFRA"), or SB 261. The CCDAA requires both public and private U.S. companies that are "doing business in California" and that have a total annual revenue of $1 billion to publicly disclose and verify, on an annual basis, Scope 1, 2 and 3 GHG emissions. The CRFRA requires the disclosure of a climate-related financial risk report (in line with the Task Force on the Climate-related Financial Disclosures recommendations or equivalent disclosure requirements under the International Sustainability Standards Board's climate-related disclosure standards) every other year for public and private companies that are "doing business in California" and have total annual revenue of $500 million. Reporting under both laws would begin in 2026, though the Governor of California has directed further consideration of the implementation deadlines for each of the laws. Both laws have been challenged in the U.S. District Court for the Central District of California. While the litigation remains in its early stages, to date the court has dismissed all of the plaintiffs' claims except for the First Amendment challenge. No stay has been granted pending resolution of this litigation so both laws are currently in effect. Further, on September 27, 2024, the California Governor amended both SB 253 and SB 261 by signing into law Senate Bill 291 ("SB 291"), which extends the time in which CARB has to promulgate implementing regulations for SB 251 until July 1, 2025, a delay of six months. Otherwise, SB 291 does not change reporting deadlines. Currently, we are still assessing the potential impacts of these laws; however, implementation may result in additional costs to comply with these disclosure requirements as well as increased costs of and restrictions on access to capital if our disclosures are not perceived as meeting applicable third-party verification of GHG emissions and climate-related criteria. Separately, enhanced climate-related disclosure requirements could lead to reputational or other harm to our relationships with customers, regulators, investors or other stakeholders. In addition, we may also face increased litigation risks arising from enhanced climate-related disclosure requirements relating to alleged damages resulting from GHG emissions from our operations, statements alleged to have been made by us or others in our industry regarding climate change risks, or in connection with any future disclosures we may make regarding reported emissions, particularly given the inherent complexity of multiple, overlapping GHG reporting regulations with respect to calculating and reporting GHG emissions.

The U.S. inflation rate has become more significant in recent years. Similar to other companies in our industry, we experienced inflationary pressures on our operating costs- namely inflationary pressures have resulted in increases to the costs of our goods, services and personnel, which in turn, have caused our capital expenditures and operating costs to rise. Such inflationary pressures have resulted from supply chain disruptions caused by the COVID pandemic, increased demand, labor shortages and other factors, including the conflict between Russia and the Ukraine. During 2024, inflation rates began to stabilize and even decrease. We are unable to accurately predict if such inflationary pressures and contributing factors will continue through 2025. To the extent inflation begins to increase again, we may experience further cost increases for our operations, including natural gas purchases and oilfield services and equipment as increasing oil, natural gas and NGL prices increase drilling activity in our areas of operations, as well as increased labor costs. An increase in oil, natural gas and NGL prices may cause the costs of materials and services to rise. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to recover higher costs through higher commodity prices and revenues, would negatively impact our business, financial condition and results of operations.

The threat of climate change continues to attract considerable attention in the United States and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national,regional and state levels of government to monitor and limit existing emissions of GHGs, as well as to restrict or eliminate such future emissions. As a result, our oil and natural gas E&P operations are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs. In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, with the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA adopted rules that, among other things, established construction and operating permit reviews for GHG emissions from certain large stationary sources, required the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the DOT, implemented GHG emissions limits on vehicles manufactured for operation in the United States. However, from time to time, certain administrations have taken actions to repeal or revise such climate-related actions. For example, the regulation of methane from oil and gas facilities has been subject to uncertainty in recent years but, in December 2023, the EPA finalized more stringent methane rules for new, modified, and reconstructed facilities, known as "OOOOb", as well as standards for existing sources for the first time ever, known as "OOOOc". Under the final rules, states have two years to prepare and submit their plans to impose methane emissions controls on existing sources. The presumptive standards established under the final rule are generally the same for both new and existing sources and include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, reduction of emissions by 95% through capture and control systems, zero-emission requirements for certain devices, and the establishment of a "super emitter" response program that would allow third parties to make reports to EPA of larger methane emission events, triggering certain investigation and repair requirements. The rules have been subject to legal challenge, and in February 2025, the D.C. Circuit Court granted the EPA's motion to hold the cases in abeyance while the agency reviews the final rules. While the Trump administration may take action to repeal or modify the final rules, we cannot predict the substance or timing of such changes, if any. Moreover, compliance with the new rules may affect the amount we owe under the IRA, signed into law on August 16, 2022, which imposes a fee on the emissions of methane from certain sources in the oil and natural gas sector. However, compliance with the EPA's methane rule would exempt an otherwise covered facility from the requirement to pay the fee. For additional information, please see "-The Inflation Reduction Act could accelerate the transition to a low-carbon economy and could impose new costs on our operations." The requirements of the EPA's final methane rules and, as applicable, the IRA's methane emissions fee, could increase our operating costs and accelerate the transition away from oil and gas, which could adversely affect our business and results of operations. Moreover, failure to comply with these requirements could result in the imposition of substantial fines and penalties, as well as costly injunctive relief. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of GHG emissions, such as methane. For example, California, through the CARB has implemented a cap and trade program for GHG emissions that sets a statewide maximum limit on covered GHG emissions, and this cap declines annually to reach 40% below 1990 levels by 2030. Covered entities must either reduce their GHG emissions or purchase allowances to account for such emissions. Separately, California has implemented the LCFS and associated tradable credits that require a progressively lower carbon intensity of the state's fuel supply than baseline gasoline and diesel fuels. Recently, CARB finalized amendments to the LCFS program to include increasing 2030 carbon intensity targets from 20% to 30% and extending carbon intensity reduction targets to 90% by 2045. The final rulemaking package was submitted to the Office of Administrative Law on January 3, 2025, but on February 18, 2025, the Office of Administrative Law issued a Notice of Disapproval citing clarity and incorrect procedure as grounds for its disapproval. CARB may resubmit the finalized amendments within 120 days of receipt of the disapproval decision after resolving the identified issues. CARB has also promulgated regulations regarding monitoring, leak detection, repair and reporting of methane emissions from both existing and new oil and gas production facilities. In addition to the various actions described requiring California to achieve total economy-wide carbon neutrality by 2045 California has separately adopted a law requiring the use of 100% zero-carbon electricity within the state by 2045. Additionally, the Governor of California requested that the CARB analyze pathways to phase out oil extraction across the state by no later than 2045; however, the 2022 Final Scoping Plan, the blueprint for the state's carbon neutrality goals, determined such a phase out was not feasible because of continued projected demand for fossil fuels in the transportation sector notwithstanding significant projected decreases in demand for fossil fuels for such uses by 2045. Notwithstanding this, CARB will continue to assess opportunities for phase down in its next five-year scoping plan. The 2022 Final Scoping Plan also outlines a plan to phase out natural gas use in buildings, amongst other carbon emission reduction matters. We cannot predict how these various laws, regulations and orders may ultimately affect our operations. However, these initiatives could result in decreased demand for the oil, natural gas and NGLs that we produce, or otherwise restrict or prohibit our operations altogether in California, and therefore adversely affect our revenues and results of operations. California residents, as a whole, are highly focused on climate change matters, particularly as certain physical and economic impacts, such as the inability to secure reasonably priced insurance, becomes a heightened issue. As a result, California politicians have taken, and are expected to continue to take, steps that may make it more difficult or costly for traditional energy companies to operate in the state. For example, California has, similar to other states, attempted to introduce legislation creating a "climate superfund" whereby the state has recourse to recover financial damages from companies for the impacts of climate change. New York and Vermont have recently passed such laws and, although the legislation proposed in California has not meaningfully advanced at this stage, climate superfund laws which target larger oil and gas companies could negatively impact our business and financial condition. At the international level, in 2021, the United States formally rejoined the Paris Agreement, which requires member nations to submit non-binding GHG emissions reduction goals every five years. However, on his first day in office, January 20, 2025, President Trump signed an Executive Order once again withdrawing the United States from the Paris Agreement. Additionally, the Executive Order withdraws the United States from any other commitments made under the United Nations Framework Convention on Climate Change and revokes any purported financial commitment made by the United States pursuant to the same. It is unclear what participation, if any, the United States will have in future United Nations climate-related efforts. Notwithstanding these actions, some states, including California, have, through the United States Climate Alliance, indicated a continued commitment to the goal of the Paris Agreement. The full impact of these recent developments is uncertain at this time. Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates for public office. Prior federal actions have included bans on new oil and gas leases on public lands, calls for more stringent regulation of methane emissions from the oil and gas sector, increased use of zero emission vehicles, restrictions on pipeline and LNG export infrastructure, and increased emphasis on climate-related risk across agencies and economic sectors. Litigation risks are also increasing, as a number of parties have sought to bring suit against oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but withheld material information from their investors or customers by failing to adequately disclose those impacts. There is also a growing trend of parties suing public companies for "greenwashing," which is where a company makes unsubstantiated statements designed to mislead consumers or shareholders into thinking that the company's products or practices are more environmentally friendly than they are. There have also recently been increasing financial risks for fossil fuel producers as certain shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, in March 2024, the SEC released a finalized rule that established a framework for the reporting of climate risks, targets, and metrics. However, the future of the rule is uncertain at this time given that its implementation has been stayed pending the outcome of legal challenges. Moreover, on February 11, 2025, SEC Acting Chairman Mark T. Uyeda requested that the U.S. Court of Appeals for the Eighth Circuit not schedule arguments in the case while the SEC reconsiders the final rule. While the SEC may, under the new presidential administration, seek to repeal or otherwise modify the rules, we cannot predict whether such action will occur or its timings. For more information, see "Regulatory Matters-Regulation of Climate Change and Greenhouse Gas Emissions." The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from oil and natural gas producers such as ourselves or otherwise restrict the areas in which we may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for or erode value for, the oil and natural gas that we produce. Additionally, political, litigation, and financial risks may result in our restricting or canceling oil and natural gas production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing our ability to continue to operate in an economic manner. Moreover, climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns, that could adversely impact our operations, as well as those of our operators and their supply chains. Such physical risks may result in damage to our facilities or otherwise adversely impact our operations, such as if we become subject to water use curtailments in response to drought, or demand for our products, such as to the extent warmer winters reduce the demand for energy for heating purposes. Such physical risks may also impact our supply chain or infrastructure on which we rely to produce or transport our products. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.