California Resources Corp (CRC) Risk Analysis

Senate Bill No. 905 contemplates the development of unitization, permitting and pipeline safety regulations over a multi-year period to facilitate the development of CCS projects in California, though the legislation does not provide for compulsory unitization. A unified permit application is to be adopted by January 1, 2025. We believe our Carbon TerraVault projects, for which the EPA has issued draft permits that are open to public notice and comment until March 20, 2024, will continue to be developed on a timeline consistent with our initial expectations. These initial projects are not reliant on the unitization or permitting regulations being developed. In addition, our Carbon TerraVault projects are expected to either use emitters that are directly sited above these storage facilities or rely on pipelines for transporting CO2 that will need to comply with yet to be developed CO2 pipeline safety regulations from the federal Pipeline and Hazardous Materials Safety Administration, which could take a number of years to effect. Delays in developing required pipeline safety regulations would delay projects requiring pipeline transportation of CO2. The lack of compulsory unitization could also delay project timelines. The unified permitting process contemplated by Senate Bill No. 905 will be optional for project applicants and is intended to simplify the permitting process for CCS projects. In the meantime, pursuant to this legislation we are permitted to proceed with our existing and future CCS Class VI permit applications with the EPA. This law also contemplates the implementation of a new regulatory program incorporating standards that are not yet defined and that could affect the timing of future CCS projects in California. Senate Bill No. 905 also prohibits CCS projects that utilize and permanently sequester CO2 in connection with EOR projects. Although we do not have any existing oil and natural gas production or proved reserves associated with EOR projects, this legislation required us to transition our CalCapture project to target CCS and may require us to make other adjustments to projects in the future.

Successful development of CCS projects in the United States require that we comply with what we anticipate will be a stringent regulatory scheme requiring that we obtain certain permits applicable to subsurface injection of CO2 for geologic sequestration. Moreover, as operator of our CCS projects, we must demonstrate and maintain levels of financial assurance sufficient to cover the cost of corrective action, injection well plugging, post injection site care and site closure, and emergency and remedial response. There are no assurances that we will be successful in obtaining or maintaining permits or adequate levels of financial assurance for one or more of our CCS projects or that permits can be obtained on a timely basis, whether due to difficulty with the technical demonstrations required to obtain such permits, public opposition, or otherwise. Separately, permitting CCS projects requires obtaining a number of other permits and approvals unrelated to subsurface injection from various U.S. federal and state agencies, such as for air emissions or impacts to environmental, natural, historic or cultural resources resulting from the construction and operation of a CCS facility. We cannot guarantee that we will be able to obtain or maintain all applicable permits for CCS activities on a timely basis or on favorable terms. Moreover, to the extent any of our CCS projects will require any supporting pipeline infrastructure, we could face additional costs and delays obtaining the necessary permits and rights of ways for such infrastructure, and increased risk of opposition to our projects, which may ultimately mean we are unable to successfully pursue certain CCS projects because of these risks. As CCS and carbon management represent an emerging sector, laws and regulations may evolve rapidly, which could impact the feasibility of one or more of our anticipated projects. To the extent additional legal or regulatory requirements are imposed, are amended, or more stringently enforced, we may incur additional costs in the pursuit of one or more of our carbon capture projects, which costs may be material or may render any one or more of our projects uneconomical.

Our operations are subject to complex and stringent federal, state, local and other laws and regulations relating to the exploration and development of our properties, as well as the production, transportation, marketing and sale of our products. To operate in compliance with these laws and regulations, we must obtain and maintain permits, approvals and certificates from federal, state and local government authorities for a variety of activities including siting, drilling, completion, stimulation, operation, inspection, maintenance, transportation, storage, marketing, site remediation, decommissioning, abandonment, protection of habitat and threatened or endangered species, air emissions, disposal of solid and hazardous waste, fluid injection and disposal and water consumption, recycling and reuse. For example, our operations in the Wilmington Oil Field utilize injection wells to reinject produced water pursuant to waterflooding plans. These operations are subject to regulation by both the City of Long Beach and CalGEM. We are currently in discussions with the City of Long Beach and CalGEM with respect to what injection well pressure gradient complies with CalGEM's requirements for the protection of underground aquifers while at the same time mitigating subsidence risks. CalGEM's local office has preliminarily indicated that the injection well pressure gradient should be reduced from the gradient that has been used for several decades. As part of our ongoing discussions, we and the City of Long Beach have provided CalGEM with technical information regarding how the historical injection well pressure gradient complies with CalGEM's requirements and to inform them of the absence of risk of leakage and a plan to gradually lower the injection gradient over time in a manner that we believe would mitigate subsidence risks. If CalGEM were to ultimately disagree and determine to reduce the injection well pressure gradient other than in a gradual manner, and we were unable to reverse that decision on appeal or other legal challenge, we expect any material reduction in injection well pressure gradient for our operations in the Wilmington Oil Field would result in a decrease in production and reserves from the field. Failure to comply may result in the assessment of administrative, civil and/or criminal fines and penalties, liability for noncompliance, costs of corrective action, cleanup or restoration, compensation for personal injury, property damage or other losses, and the imposition of injunctive or declaratory relief restricting or prohibiting certain operations or our access to property, water, minerals or other necessary resources, and may otherwise delay or restrict our operations and cause us to incur substantial costs. Under certain environmental laws and regulations, we could be subject to strict or joint and several liability for the removal or remediation of contamination, including on properties over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties. Our ability to timely obtain and maintain permits for our operations in 2023, including from CalGEM, has been subject to significant delays and uncertainties and is subject to factors that are not within our control. These factors include changes in agency practices, new regulations, or legal challenges to existing approvals for our operations from individual citizens and non-governmental organizations. For example, beginning in 2021, CalGEM ceased issuing new well stimulation permits. In 2023, CalGEM virtually ceased issuing permits for new wells, sidetracks, deepenings, and reworks throughout the state (though it recently resumed issuing permits for reworks, and has slowly been resuming the issuance of permits for sidetracks), even as it continues approving permits for plugging and abandonment. CalGEM communicated that permitting would resume (with the exception of permits for new wells in Kern County, the issuance of which has been stayed pending the final ruling of the Appellate Court) upon its development of standard operating procedures for reviewing permit applications and cited staffing shortages within its CEQA unit as an additional reason for the delays. See Part I, Item 1 and 2 – Business and Properties, Regulation of the Industries in which we Operate, Regulations of Exploration and Production Activities. We cannot guarantee that these issues or new ones that may arise in the future will not continue to delay or otherwise impair our ability to obtain drilling permits. In the past we have generally been able to mitigate permitting risks by building up a reserve of drilling permits for use throughout the year, but as a result of the issues described above, we have not been able to build our reserve of approved permits to the same level as we have in the past. Changes to elected or appointed officials or their priorities and policies could result in different approaches to the regulation of the oil and natural gas industry. If we cannot obtain new drilling or sidetrack permits in a timely manner, we have limited options to meet our drilling plans, such as the use of workovers to extend the life of existing production, that may not ultimately be sufficient to achieve our business goals. Any continuing failure to obtain certain permits or the adoption of more stringent permitting requirements could have a material adverse effect on our business, operations, properties, results of operations, and our financial condition.

On October 7, 2023, the California Governor signed into law Assembly Bill 1167 (AB 1167), which imposes more stringent financial assurance requirements on persons who acquire the right to operate a well or production facility in the state of California, requiring them to file either an individual indemnity bond for single-well or production facility acquisitions, or a blanket indemnity bond for multiple wells or production facilities. The bond imposed on the acquirer will be in an amount determined by the state to sufficiently cover plugging and abandonment costs, decommissioning, and site restoration, and AB 1167 prohibits the closing of any acquisition of a well or production facility until a determination on the appropriate bond amount has been completed by the state and the bond has been filed. We are still assessing the impact of AB 1167. In addition, although AB 1167 has been signed into law, Governor Newsom has called for further legislative changes to these new requirements to mitigate against the potential risk of the implementation of AB 1167 ultimately increasing the number of orphaned idle or low-producing wells in California, although no such changes have yet been announced. We cannot predict what form these changes may ultimately take or if the legislature will act on the Governor's request. Implementation of this law may lead to the delay or additional costs with respect to acquisitions or dispositions, which could impact our ability to grow or explore new strategic areas – or exit others – within the state of California.

We must obtain various governmental permits to conduct exploration and production activities, as well as other aspects of our operations. Obtaining the necessary governmental permits is often a complex and time-consuming process involving numerous federal, state and local agencies. The duration and success of each permitting effort is contingent upon many variables not within our control. In the context of obtaining permits or approvals, the Company will need to comply with known standards, existing laws (such as CEQA), and regulations that may entail greater or lesser costs and delays depending on the nature of the activity to be permitted and the interpretation of the laws and regulations implemented by the permitting authority. In 2023 we experienced significant delays with respect to obtaining new well, sidetrack, deepening and rework permits from CalGEM for our operations. A variety of factors outside of our control can lead to such delays. Recent changes in CalGEM management have contributed to permitting delays and uncertainty with respect to our ability to timely obtain permits for our operations. Following such change in management, during the second half of 2023 CalGEM focused on the development of standard operating procedures (SOPs) for permit review, and as a practical matter ceased issuing permits pending the completion of this process. CalGEM released its SOP for the review of applications for rework permits in late Q4 2023 and recently finalized its Lead Agency Preliminary Review process for sidetrack permits. CalGEM has recently resumed issuing permits for reworks to CRC and other operators. It has issued some permits for sidetracks to other operators. Subject to limited exceptions, CalGEM has not issued any permits for new production wells to any operators since December 2022. We have experienced delays obtaining permits as a result of litigation related to the Kern County EIR for the past several years. Following a favorable trial court order in 2022, plaintiffs appealed, and, the appellate court issued a preliminary order reinstating a suspension of Kern County's ability to rely on the existing EIR pending the outcome of a final order determining whether oil and natural gas permitting shall remain suspended for the duration of the appeals process. We expect the Appellate Court to issue its ruling on the matters at issue in the second quarter of 2024. We are in the process of pursuing alternative pathways for addressing CEQA compliance for our oil and natural gas permitting process, this would be a lengthy process and we cannot predict with complete certainty whether we would be able to timely obtain permits using this alternative. As a result of these issues and current lack of permits with respect to our Kern County properties, we currently plan to operate one active rig within Kern County in the first half of 2024, and have the requisite number of permits in hand to keep that rig active throughout the year. We plan to increase our active rig count in Kern County from one rig to three in the second half of 2024, assuming new well and sidetrack permitting resumes in Kern County. However, there is no certainty that we will obtain permits on that timeline or at all, which may further adversely affect our future development plans, proved undeveloped reserves, business, operations, cash flows, financial position and results of operations. Approximately $75 million of our aggregate capital for oil and natural gas development in 2024 relates to drilling and completing wells in Kern County for which we do not presently have a permit. We have also experienced delays obtaining drilling permits from CalGEM since the passage of Senate Bill No. 1137, which established 3,200 feet as the minimum distance between new oil and natural gas production wells and certain sensitive receptors such as homes, schools and businesses open to the public. The law became effective January 1, 2023 and CalGEM issued emergency regulations implementing the requirements of the law on January 6, 2023. However, on February 3, 2023, the Secretary of State of California certified voter signatures collected in connection with a referendum for the November 2024 ballot to repeal Senate Bill No. 1137. As a result, any implementation of Senate Bill No. 1137 is stayed until it is put to a vote. There is significant uncertainty with respect to the ability to book proved undeveloped reserves and drill within the setback zone established by Senate Bill No. 1137 and, as a result, we have only booked proved undeveloped reserves for which we already have permits within the zone or intend to have permits for prior to the November 2024 ballot. As a result of Senate Bill No. 1137, in 2023 we reduced the net present value of our proved undeveloped reserves by 19% and our overall proved reserves by 2%. (See Part I, Item 1 and 2 – Business and Properties, Regulation of Exploration and Production Activities for more information). In addition, commencing in February 2023, CalGEM began returning our applications for permits in the Wilmington Oil Field, including permits for new production wells, workovers and plugging and abandonment operations. CalGEM cited concerns regarding the adequacy of the related environmental impact report for purposes of meeting CEQA requirements. We are working together with the City of Long Beach to address CalGEM's concerns regarding conducting future re-drills, workover and plugging and abandonment activities. Approximately $25 million of our aggregate capital for oil and natural gas development in 2024 relates to drilling and completing wells in Wilmington for which we do not presently have a permit. We plan to operate one active rig on the THUMS Islands in the second half of 2024, assuming permitting of sidetracks and deepenings resumes. However, there is no certainty that we will obtain permits on that timeline or at all, which may further adversely affect our future development plans, proved undeveloped reserves, business, operations, cash flows, financial position and results of operations. We cannot guarantee that these issues or new ones that may arise in the future will not continue to delay or otherwise impair our ability to obtain drilling permits. In the past we have generally been able to mitigate permitting risks by building up a reserve of drilling permits for use throughout the year, but as a result of the issues described above, we have not been able to build our reserve of approved permits to the same level as we have in the past. If we cannot obtain new drilling or sidetrack permits in a timely manner, we have limited options to meet our drilling plans, such as the use of workovers to extend the life of existing production, that may not ultimately be sufficient to achieve our business goals. Any continuing failure to obtain certain permits or the adoption of more stringent permitting requirements could have a material adverse effect on our business, operations, properties, results of operations, and our financial condition.

Due to certain restrictions in the Merger Agreement on the conduct of business prior to completing the Aera Merger, we may be unable, during the pendency of the Aera Merger, to pursue strategic transactions, undertake certain significant financing transactions and otherwise pursue other actions, even if such actions would prove beneficial, and we may have to forgo certain opportunities we might otherwise pursue. In addition, the Merger Agreement prohibits us from initiating, soliciting or knowingly encouraging any competing acquisition proposals, subject to certain limited exceptions. The Merger Agreement also contains certain termination rights for us and Aera. Upon termination of the Merger Agreement in accordance with its terms, under certain circumstances, we will be required to pay Aera a termination fee of $50 million, or $100 million in certain circumstances, including if the Merger Agreement is terminated by Aera due to our Board changing its recommendation in favor of the Aera Merger to support a competing acquisition proposal.