# EDGAR Filing Document

**Accession Number:** 0001705873
**File Stem:** 0001705873-25-000061
**Filing Date:** 2025-8
**Character Count:** 28516
**Document Hash:** 4ccf15e7bb948947882f521b2817b566
**Contains OCR:** False
**Source Format:** 

## Filing Content

## Filing Summary
**0001705873-25-000061.hdr.sgml**: 20260122

**ACCESSION NUMBER**: 0001705873-25-000061

**CONFORMED SUBMISSION TYPE**: CORRESP

**PUBLIC DOCUMENT COUNT**: 1

**FILED AS OF DATE**: 20250821

**FILER**: 

**COMPANY DATA:**
- **COMPANY CONFORMED NAME:** Berry Corp (bry)
- **CENTRAL INDEX KEY:** 0001705873
- **STANDARD INDUSTRIAL CLASSIFICATION:** CRUDE PETROLEUM & NATURAL GAS [1311]
- **ORGANIZATION NAME:** 01 Energy & Transportation
- **EIN:** 815410470
- **STATE OF INCORPORATION:** DE
- **FISCAL YEAR END:** 1231

**FILING VALUES:**
- **FORM TYPE:** CORRESP

**BUSINESS ADDRESS:**
- **STREET 1:** 16000 N. DALLAS PARKWAY, SUITE 500
- **CITY:** DALLAS
- **STATE:** TX
- **ZIP:** 75248
- **BUSINESS PHONE:** 214-453-2920

**MAIL ADDRESS:**
- **STREET 1:** 16000 N. DALLAS PARKWAY, SUITE 500
- **CITY:** DALLAS
- **STATE:** TX
- **ZIP:** 75248

**FORMER COMPANY:**
- **FORMER CONFORMED NAME:** Berry Petroleum Corp
- **DATE OF NAME CHANGE:** 20170504

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:&nbsp;&nbsp;&nbsp;&nbsp;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.

**<u>Form 10-K for Fiscal Year Ended December 31, 2024</u>**

**<u>Business and Properties</u>**

**<u>Production Data, page 10</u>**

***1.&nbsp;&nbsp;&nbsp;&nbsp;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.***

<u>RESPONSE</u>:&nbsp;&nbsp;&nbsp;&nbsp;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

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Securities and Exchange Commission

August 21, 2025

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,** | **Year Ended December 31,** | **Year Ended December 31,** |
| | **2024** | **2023** | **2022** |
| **Average daily production**<sup>(1)</sup>**:** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Oil (mbbl/d) | 23.5 | 23.5 | 24.0 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas (mmcf/d) | 8.7 | 8.8 | 10.2 |
| &nbsp;&nbsp;&nbsp;&nbsp;NGLs (mbbl/d) | 0.4 | 0.4 | 0.4 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total (mboe/d)<sup>(2)</sup> | 25.4 | 25.4 | 26.1 |
| **Total Production**<sup>(1)</sup>**:** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Oil (mbbl) | 8616 | 8568 | 8770 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas (mmcf) | 3179 | 3211 | 3706 |
| &nbsp;&nbsp;&nbsp;&nbsp;NGLs (mbbl) | 145 | 155 | 144 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total (mboe)<sup>(2)</sup> | 9291 | 9258 | 9532 |
| **Weighted-average realized sales prices:** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Oil without hedges ($/bbl) | $73.70 | $75.05 | $91.98 |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas ($/mcf) | $2.70 | $6.94 | $7.96 |
| &nbsp;&nbsp;&nbsp;&nbsp;NGLs ($/bbl) | $26.82 | $24.47 | $43.85 |
| **Production costs per boe:** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Lease operating expenses | $24.31 | $34.21 | $31.72 |

---

__________

(1)&nbsp;&nbsp;&nbsp;&nbsp;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)&nbsp;&nbsp;&nbsp;&nbsp;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.

**<u>Proved Undeveloped Reserves Changes, page 15</u>**

***2.&nbsp;&nbsp;&nbsp;&nbsp;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***

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Securities and Exchange Commission

August 21, 2025

***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.***

<u>RESPONSE</u>:&nbsp;&nbsp;&nbsp;&nbsp; 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

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Securities and Exchange Commission

August 21, 2025

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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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,

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Securities and Exchange Commission

August 21, 2025

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.&nbsp;&nbsp;&nbsp;&nbsp;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.***

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Securities and Exchange Commission

August 21, 2025

<u>RESPONSE</u>:&nbsp;&nbsp;&nbsp;&nbsp;As requested by the Staff, we have provided the Company's development schedule in the Supplemental Letter.

**<u>Participation in Wells Being Drilled, page 20</u>**

***4.&nbsp;&nbsp;&nbsp;&nbsp;Please expand the disclosure of your present activities to include the number of gross and net operated and non-operated wells in the process of being drilled, completed, or waiting on completion, and any other related activities of material importance as of December 31, 2024 to comply with Item 1206 of Regulation S-K.***

<u>RESPONSE</u>:&nbsp;&nbsp;&nbsp;&nbsp;We respectfully advise the Staff that the Company disclosed the number of gross non-operated wells in the process of being completed as of December 31, 2024 (which was two such wells) on page 20 of the Form 10-K. The Company also disclosed that it had an average 13% working interest in these two wells on page 5 of the Form 10-K. The number of net non-operated wells in process of being completed was less than one and the Company did not have any operated wells in the process of being drilled as of December 31, 2024. The Company had one operated well (gross and net) which had not yet been connected to gathering systems as of December 31, 2024 which was disclosed in footnote 2 to the Drilling Activity table on page 21 of the Form 10-K. In future filings beginning with the 2025 Form 10-K, the Company will disclose the number of gross and net operated and non-operated wells in the process of being drilled, completed, or waiting on completion, and any other related activities of material importance as of year-end, in tabular format. For illustrative purposes, a table presenting this disclosure for the year ended December 31, 2024 is shown below:

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| | | | |
|:---|:---|:---|:---|
| | **California** <br>**(San Joaquin Basin)** | **Utah**<br>**(Uinta Basin)** | **Total** |
| **2024** |  |  |  |
| &nbsp;&nbsp;&nbsp;**Gross** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Operated | 1 |  | 1 |
| &nbsp;&nbsp;&nbsp;&nbsp;Non-operated |  | 2 | 2 |
| &nbsp;&nbsp;&nbsp;**Net** |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Operated | 1 |  | 1 |
| &nbsp;&nbsp;&nbsp;&nbsp;Non-operated |  | 0.1 | 0.1 |

---

**<u>Drilling Activity, page 20</u>**

***5.&nbsp;&nbsp;&nbsp;&nbsp;Please expand the disclosure of drilling activities that occurred during each of the last three fiscal years to include wells drilled by operators other than you to comply with Item 1205 of Regulation S-K.***

<u>RESPONSE</u>:&nbsp;&nbsp;&nbsp;&nbsp;We respectfully advise the Staff that the Company disclosed the number of non-operated wells drilled by operators other than the Company during the fiscal year ended December 31, 2024 in the paragraph under the Drilling Activities table on page 21 of the Form 10-K. The Company did not have any such non-operated drilling activity in 2023 or 2022. In future filings beginning with the 2025 Form 10-K, the Company will expand its disclosure to present the number of wells drilled by operators other than the Company in each of the last three

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Securities and Exchange Commission

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fiscal years in tabular format. For illustrative purposes, a table presenting this disclosure for each of the three years ended December 31, 2024 is shown below:

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Securities and Exchange Commission

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| | | | |
|:---|:---|:---|:---|
| | **California** <br>**(San Joaquin Basin)**<sup>(1)</sup> | **Utah**<br>**(Uinta Basin)**<sup>(1)</sup> | **Total**<sup>(1)</sup> |
| **2024** |  |  |  |
| &nbsp;&nbsp;Development wells operated |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Productive<sup>(2)</sup> | 46 | 4 | 50 |
| &nbsp;&nbsp;&nbsp;&nbsp;Dry |  |  |  |
| &nbsp;&nbsp;Development wells non-operated |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Productive |  | 0.8 | 0.8 |
| &nbsp;&nbsp;&nbsp;&nbsp;Dry |  |  |  |
| &nbsp;&nbsp;Exploratory wells |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Productive |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Dry |  |  |  |
| &nbsp;&nbsp;Total wells |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Productive<sup>(2)</sup> | 46 | 4.8 | 50.8 |
| &nbsp;&nbsp;&nbsp;&nbsp;Dry |  |  |  |
| **2023** |  |  |  |
| &nbsp;&nbsp;Development wells operated |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Productive<sup>(2)</sup> | 33 |  | 33 |
| &nbsp;&nbsp;&nbsp;&nbsp;Dry |  |  |  |
| &nbsp;&nbsp;Development wells non-operated |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Productive |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Dry |  |  |  |
| &nbsp;&nbsp;Exploratory wells |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Productive |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Dry |  |  |  |
| &nbsp;&nbsp;Total wells |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Productive<sup>(2)</sup> | 33 |  | 33 |
| &nbsp;&nbsp;&nbsp;&nbsp;Dry |  |  |  |
| **2022** |  |  |  |
| &nbsp;&nbsp;Development wells operated |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Productive<sup>(2)</sup> | 72 | 13 | 85 |
| &nbsp;&nbsp;&nbsp;&nbsp;Dry |  |  |  |
| &nbsp;&nbsp;Development wells non-operated |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Productive |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Dry |  |  |  |
| &nbsp;&nbsp;Exploratory wells |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Productive |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Dry |  |  |  |
| &nbsp;&nbsp;Total wells |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Productive<sup>(2)</sup> | 72 | 13 | 85 |
| &nbsp;&nbsp;&nbsp;&nbsp;Dry |  |  |  |

---

__________

(1)&nbsp;&nbsp;&nbsp;&nbsp;Presented on a net working interest basis.

(2)&nbsp;&nbsp;&nbsp;&nbsp;Includes injector wells.

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Securities and Exchange Commission

August 21, 2025

**<u>Supplemental Oil & Natural Gas Data (Unaudited)</u>**

**<u>Standardized Measure of Discounted Future Net Cash Flows, page 162</u>**

***6.&nbsp;&nbsp;&nbsp;&nbsp;We note the future production costs used in the calculation of the standardized measure of discounted future net cash flows for the year ended December 31, 2024 excludes the $263.3 million dollar expense line item shown in Exhibit 99.1 relating to payments made by the Company to the State of California to comply with the California Air Resources Board's Cap-and-Trade Program. As a result, the undiscounted pre-tax future net income in the filing is $263.3 million or 7.7% higher than the comparable figure in Exhibit 99.1. Please review and revise if necessary, here and elsewhere in your filing, to resolve the inconsistency or expand your disclosure to explain your rationale for omitting the payments to the State of California. Refer to the disclosure requirements in FASB ASC 932-235-50-36.***

<u>RESPONSE</u>:&nbsp;&nbsp;&nbsp;&nbsp;We respectfully advise the Staff that the Company included the $263.3 million expense related to payments made by the Company to the State of California to comply with the California Air Resources Board's Cap-and-Trade Program (the "CARB Program") in the Company's calculation of its "Standardized measure of discounted future net cash flows" for the year ended December 31, 2024; however, the CARB Program costs were inadvertently excluded from "future production costs" and included in line item categories other than future production costs. As a result, the Company's PV-10 at December 31, 2024 presented on page 14 of the Form 10-K and the total "Standardized measure of discounted future net cash flows" for the year ended December 31, 2024 presented on page 162 of the Form 10-K are properly stated, but certain lines within the standardized measure of discounted future net cash flows are not consistent with the comparable figures shown in Exhibit 99.1, and specifically the undiscounted pre-tax future net income for the year ended December 31, 2024 is 7.7% higher than the comparable figure shown in Exhibit 99.1. The CARB Program costs are captured in "Future income tax expenses" and "10% annual discount for estimated timing of cash flows." In future filings beginning with the Company's 2025 Form 10-K, the Company will include its expenses to comply with the CARB Program in the "future production cost" line item. For illustrative purposes, if the Company had included its CARB Program costs as future production costs in the Form 10-K, the calculation of the standardized measure of discounted future net cash flows would have been presented as follows:

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Securities and Exchange Commission

August 21, 2025

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| | | | |
|:---|:---|:---|:---|
| | **Year Ended December 31,** | **Year Ended December 31,** | **Year Ended December 31,** |
| | **2024** | **2023** | **2022** |
| | **(in thousands, except for prices)** | **(in thousands, except for prices)** | **(in thousands, except for prices)** |
| Future cash inflows | $7768787 | $7674494 | $9501374 |
| Future production costs | (3385625) | (3439939) | (3909452) |
| Future development costs<sup>(1)</sup> | (953716) | (964768) | (1068890) |
| Future income tax expenses<sup>(2)</sup> | (701109) | (620822) | (1000268) |
| Future net cash flows | 2728337 | 2648965 | 3522764 |
| 10% annual discount for estimated timing of cash flows | (917101) | (966331) | (1448999) |
| Standardized measure of discounted future net cash flows  | $1811236 | $1682634 | $2073765 |
| Representative prices:<sup>(3)</sup> |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Brent Oil (bbl) | $80.42 | $82.84 | $100.25 |
| &nbsp;&nbsp;&nbsp;&nbsp;Henry Hub Natural gas (mmbtu) | $2.13 | $2.63 | $6.40 |

---

__________

(1)&nbsp;&nbsp;&nbsp;&nbsp;Future development costs include site restoration and abandonment costs.

(2)&nbsp;&nbsp;&nbsp;&nbsp;Future income tax expenses are based on current statutory rates, adjusted for the tax basis of oil and gas properties and applicable tax credits, deductions and allowances.

(3)&nbsp;&nbsp;&nbsp;&nbsp;In accordance with SEC regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves.

\*&nbsp;&nbsp;&nbsp;&nbsp;\*&nbsp;&nbsp;&nbsp;&nbsp;\*&nbsp;&nbsp;&nbsp;&nbsp;\*&nbsp;&nbsp;&nbsp;&nbsp;\*

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Securities and Exchange Commission

August 21, 2025

If you have any additional questions with respect to the foregoing or if any additional supplemental information is required by the Staff, please contact Sarah K. Morgan of Vinson & Elkins L.L.P. at (713) 758-2977.

Very truly yours,

BERRY CORPORATION (bry)

By:&nbsp;&nbsp;&nbsp;&nbsp;<u>/s/ Jeffrey Magids&nbsp;&nbsp;&nbsp;&nbsp;</u>

Name:&nbsp;&nbsp;&nbsp;&nbsp;Jeffrey Magids

Title:&nbsp;&nbsp;&nbsp;&nbsp;Vice President and Chief Financial Officer

Enclosures

cc:&nbsp;&nbsp;&nbsp;&nbsp;Sarah K. Morgan, Vinson & Elkins L.L.P.

<br>