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 Document August 21, 2025 Division of Corporation Finance Office of Energy & Transportation United States Securities and Exchange Commission Division of Corporation Finance 100 F Street, N.E. Washington, D.C. 20549-3561 Re:    Berry Corporation (bry) Form 10-K for Fiscal Year Ended December 31, 2024 Filed March 13, 2025 File No. 001-38606 Ladies and Gentlemen: Set forth below are the responses of Berry Corporation (bry) (the “Company,” “we,” “us,” or “our”), to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) by letter dated July 25, 2025, with respect to the Company's Form 10-K for the Fiscal Year Ended December 31, 2024, File No. 001-38606, filed with the Commission on March 13, 2025 (the “Form 10-K”). We are concurrently providing certain information responsive to Comment No. 3 in a separate letter to the Staff (the “Supplemental Letter”). For your convenience, each response is prefaced by the exact text of the Staff’s corresponding comment in bold, italicized text. All references to page numbers and captions correspond to the Form 10-K unless otherwise specified. Form 10-K for Fiscal Year Ended December 31, 2024 Business and Properties Production Data, page 10 1.    Please expand the disclosure of your average daily production to additionally provide the average sales prices, net production quantities by final product sold, and average production costs per unit of production, for each of the last three fiscal years to comply with Item 1204 of Regulation S-K. RESPONSE :    We acknowledge the Staff’s comment and advise the Staff that the average daily production, average sales prices and net production quantities by final product sold for the fiscal years ended December 31, 2024 and 2023 are disclosed on page 80 of the Form 10-K, and Lease Operating Expenses (representing our production costs) per unit of production for the Securities and Exchange Commission August 21, 2025 Page 2 fiscal years ended December 31, 2024 and 2023 are disclosed on page 104 of the Form 10-K. These metrics for the fiscal year ended December 31, 2022 were provided in the Company's 2023 Form 10-K. The Company respectfully submits that it will, starting with its 2025 Form 10-K, expand its disclosure to provide the relevant disclosures for each of the last three fiscal years in tabular format, as illustrated below: Year Ended December 31, 2024 2023 2022 Average daily production (1) : Oil (mbbl/d) 23.5  23.5  24.0  Natural gas (mmcf/d) 8.7  8.8  10.2  NGLs (mbbl/d) 0.4  0.4  0.4  Total (mboe/d) (2) 25.4  25.4  26.1  Total Production (1) : Oil (mbbl) 8,616  8,568  8,770  Natural gas (mmcf) 3,179  3,211  3,706  NGLs (mbbl) 145  155  144  Total (mboe) (2) 9,291  9,258  9,532  Weighted-average realized sales prices: Oil without hedges ($/bbl) $ 73.70  $ 75.05  $ 91.98  Natural gas ($/mcf) $ 2.70  $ 6.94  $ 7.96  NGLs ($/bbl) $ 26.82  $ 24.47  $ 43.85  Production costs per boe: Lease operating expenses $ 24.31  $ 34.21  $ 31.72  __________ (1)    Production represents volumes sold during the period. A portion of the natural gas we produce on lease is also consumed in our operations to extract oil and gas. (2)    Natural gas volumes have been converted to boe based on energy content of six mcf of gas to one bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the year ended December 31, 2024, the average prices of Brent oil and Henry Hub natural gas were $79.86 per bbl and $2.19 per mmbtu respectively. Proved Undeveloped Reserves Changes, page 15 2.    We note disclosure provided in Form 10-K for the fiscal years ending December 31, 2024, 2023, 2022, 2021 and 2020 indicates you converted approximately 9%, 2%, 6%, 13% and 0%, respectively, of the opening balance of your proved undeveloped reserves during each of those periods. We also note that you have removed material amounts of previously disclosed proved undeveloped reserves during each of the last three fiscal years due to changes in your five-year development plan and that based on your fiscal 2024 conversion rate, it will Securities and Exchange Commission August 21, 2025 Page 3 take over eleven years to convert the proved undeveloped reserves disclosed as of December 31, 2024. Please tell us how you have taken into consideration your low historical conversion rates and the ongoing changes in your development plans in adopting a development plan that results in the conversion of the 45.6 MMBoe of proved undeveloped reserves as of December 31, 2024 within five years of initial disclosure of such reserves. Refer to Rule 4-10(a)(31)(ii) of Regulation S-X and the Question 131.04 in the Compliance and Disclosure Interpretations (C&DIs) regarding Oil and Gas Rules. RESPONSE :     We acknowledge the Staff’s comment regarding the Company's historic conversion rates of proved undeveloped reserves ("PUDs") in fiscal years 2020 through 2024 and the removal of material amounts of previously disclosed PUDs during each of the last three fiscal years due to changes in the Company's five-year development plan. The Company respectfully advises the Staff that these conversion rates and the removal of previously disclosed PUDs are attributable to various economic and regulatory factors that have impacted the Company's development plans in recent years, including (i) the low commodity price environment of 2020 caused by the global COVID-19 pandemic, (ii) the dynamic California regulatory environment from 2019 through 2024 that impacted the Company's ability to obtain drilling permits, and (iii) other factors that have contributed to changes to the Company's development plans over those years, which are discussed in further detail below. With respect to California regulatory matters, a number of developments at both the California state and local levels over the last several years have resulted in unpredictable and significant delays in the issuance of permits to drill new oil and gas wells in Kern County, where all of our California assets are currently located. These delays have had significant and unexpected impacts on our ability to convert our PUDs to proved developed reserves in recent years, and the Company has adjusted its development plan and PUD locations over the years in response to these regulatory shifts (in addition to economic and results-driven changes, as discussed herein). As a result of these challenges, we have written off PUD locations in the years in which they no longer meet the SEC's definition of "proved undeveloped reserves" due to these unforeseen changes. A complete discussion of the evolving California regulatory environment and its impact on our business and results of operations can be found in our Form 10-K and Form 10-Q filings from 2019 through 2025. In 2020, the 0% conversion rate was primarily attributable to the drastic decrease in commodity prices related to the global COVID-19 pandemic which resulted in a significant reduction in the Company’s 2020 drilling activity and a full write down of the Company’s PUDs in Utah. Additionally, in February 2020, the Kern County environmental impact report (“EIR”) supporting the issuance of new drill permits was temporarily suspended pending a court-ordered review by the County, which negatively impacted our development plans as new well permits could not be obtained. Prior to this temporary suspension, California oil and gas operators had regularly obtained new will drilling permits on a relatively consistent basis. The State of California also imposed a temporary moratorium on approving new high-pressure cyclic steam permits in November 2019 pending a study with experts from Lawerence Livermore National Laboratory on high-pressure cyclic steam injection that has impacted the development of certain Securities and Exchange Commission August 21, 2025 Page 4 of our thermal diatomite properties since 2020. This moratorium provided a path for all operators to resume development activity pending completion of the regulator's review and implementation of a revised Underground Injection Control (“UIC”) program to support our future development plans. As a result of these factors, our conversion rate was 0% during the year. However, at year-end 2020, the Company believed that the Kern County EIR, which had been in place since November 2015, would ultimately be reinstated in the near-term and that the temporary moratorium on new high-pressure cyclic steam permits would be lifted in the near-term; therefore, retaining PUDs related to locations impacted by these circumstances was appropriate as they remained in the Company’s five-year development plan. Coming out of the low commodity price environment of 2020, drilling activity increased in 2021; however, because 42% of the locations drilled in 2021 were not booked as PUD locations as of year-end 2020, the development of these locations did not contribute to the conversion of our PUDs. As a result of the continued and unexpectedly protracted regulatory uncertainty with respect to both the reinstatement of the Kern County EIR (which was reinstated in March 2021 before being unexpectedly suspended again in October 2021) and the ongoing moratorium impacting our thermal diatomite properties, during 2021 only a limited number of permits were issued to drill new wells in the areas related to our year-end 2020 PUDs. With respect to our five-year development plan, the Company continued to believe that the moratorium impacting thermal diatomite drilling was temporary in nature and that the Kern County EIR would ultimately be reinstated, so PUDs with respect to the Company’s thermal diatomite properties and new drill opportunities in Kern County, California were retained but re-timed to be developed within five years of their initial booking as of year-end 2021. Due to the dynamic regulatory environment in California, we increased our 2021 development of our Utah properties which resulted in additional Utah PUDs being booked for our Utah assets at year-end 2021. In 2022, due to ongoing regulatory uncertainty surrounding the timing of the reinstatement of the Kern County EIR (restricting the issuance of permits for new wells) and the lifting of the temporary moratorium in the thermal diatomite (restricting new development), the Company determined to shift its California development plan to focus on workover, sidetrack and recompletion activity, which was not impacted by the Kern County EIR suspension or the moratorium. Many of these locations were not previously booked PUD locations, so the Company booked more PUDs in 2022 as a result of a successful sidetrack development program. The Company also reallocated capital to its 2022 Utah development plan which resulted in more Utah PUDs at year-end 2022. The Kern County EIR was reinstated in November 2022, which impacted the Company’s development plan as of year-end 2022 as the Company believed it had line-of-sight to develop new-drill PUD locations in Kern County within five years of original booking. In 2023, the Company made a significant acquisition of producing California properties (the “Macpherson Acquisition”). As a result, the Company reallocated a significant portion of its capital initially designated for well development of PUDs in 2023 to instead fund the acquisition, resulting in much lower well development spend in 2023 than initially planned. In addition, the Kern County EIR was suspended again in early 2023, which also contributed to lower-than-planned well development in California during the year and a low conversion rate of its PUDs, Securities and Exchange Commission August 21, 2025 Page 5 and caused the Company to refocus its development plan on sidetrack and workover activity. Additionally, the Company acquired other properties in response to Senate Bill 1137, which limits oil and gas development within 3,200 feet of sensitive receptors (“SB 1137”) in order to mitigate the impact of SB 1137 on our development plans. This new regulation had a negative impact on our PUDs at the end of 2023 as we anticipated that certain locations had become undevelopable within five years of initial booking. In Utah, our vertical well drilling results in 2023 also led to a reduction of PUDs relative to those originally booked based on the Company's 2022 drilling plan. In 2024, the Company drilled fewer wells than anticipated in California due to an unexpected slowdown in sidetrack permitting approvals which negatively impacted our PUD conversion rate. During the year, CalGEM's process for the issuance of sidetrack drill permitting was impacted as CalGEM worked to better define what constitutes an “expansion” of an existing well (which would require CEQA approval) versus sidetrack drilling consistent with an original well approval (which does not require new CEQA approval). Additionally, in the wake of the implementation of SB 1137, CalGEM returned all pending permit applications to operators, including the Company, regardless of the proximity of the site to a sensitive receptor, which caused unforeseen delays in obtaining permits or sites associated with PUDs. While the implementation of California’s SB 1137 resulted in further PUD reductions for certain development locations in California where the Company could not acquire sensitive receptors, the Company's sidetrack drilling program continued to be successful, and the Company booked PUDs related to this development at year-end 2024. The Company’s PUD reserves were also consistent with resumed permitting by CalGEM by year-end 2024 for sidetrack drilling inventory. In Utah, the Company shifted its strategy from vertical well development to horizontal well development, resulting in many PUDs related to planned vertical wells not being converted during the year and ultimately removed at year-end 2024. These legacy PUDs in Utah that were written off were replaced with near-term horizontal wells, four of which were developed in 2025. While the significant variability in California’s regulatory environment over the last five years has required the Company to adapt and pivot its development plan over time, resulting in low PUD conversion rates, the Company believes that its PUD reserves as of year-end 2024 can be developed within five years as they are consistent with the Company’s recent success with respect to sidetrack drilling and the anticipated permanent reinstatement of the Kern County EIR by 2027, which we expect will allow for new oil wells to be permitted in support of developing our PUD locations. In support of this position, the Company has received all of the permits it needs to execute its 2026 drilling plan in California and into 2027. Accordingly, we advise the Staff that we anticipate converting all of our PUDs to proved developed reserves within five years of their initial booking. 3.    Please provide us with the development schedule relating to your proved undeveloped reserves as of December 31, 2024, including details that show for each future annual period, (1) the number of gross wells to be drilled, (2) the associated net quantities of reserves, (3) the estimated capital expenditures necessary to convert such reserves to developed reserves, and (4) any changes made or expected to be made in the schedule that would deviate from the definition in Rule 4-10(a)(31)(ii) of Regulation S-X. Securities and Exchange Commission August 21, 2025 Page 6 RESPONSE :    As requested by the Staff, we have provided the Company's development schedule in the Supplemental Letter. Participation in Wells Being Drilled, page 20 4.    Please expand the disclosure of your present activities to include the number of gross and net operated