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  Title	Berry Corporation Reports Fourth Quarter and Full Year 2024 Financial and Operational Results, Year-End Reserves and 2025 Outlook
  ID	7677741
  External ID	200500138
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  Published Date	March 12, 2025, 3:05 p.m.
  Summary	Unlock stock picks and a broker-level newsfeed that powers Wall Street. Upgrade Now Berry Corporation Reports Fourth Quarter and Full Year 2024 Financial and Operational Results, Year-End Reserves and
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  Content ID	4982987
  Key	16287441-239e-40c7-ae42-e2212be86e27
  Content	Unlock stock picks and a broker-level newsfeed that powers Wall Street. Upgrade Now Berry Corporation Reports Fourth Quarter and Full Year 2024 Financial and Operational Results, Year-End Reserves and 2025 Outlook Berry Corporation (Bry) Wed, Mar 12, 2025, 3:05 PM 26 min read In This Article: BRY -11.54% Berry Corporation (Bry) DALLAS, March 12, 2025 (GLOBE NEWSWIRE) -- Berry Corporation (bry) (NASDAQ: BRY) (“Berry” or the “Company”) today announced financial and operating results for the fourth quarter and full year 2024, as well as a quarterly cash dividend of $0.03 per share. Berry has provided a supplemental slide deck on its results, which can be found at www.bry.com. The Company plans to host a conference call and webcast to discuss its fourth quarter and full year 2024 results, as well as its 2025 outlook, at 10:00 a.m. CT, Thursday, March 13, 2025. Details can be found in this release. Full Year 2024 Highlights Delivered results better than the midpoint of guidance on production, operational expenses, G&A and capital expenditures Reported net income of $19 million, or $0.25 per diluted share and Adjusted Net Income (1) of $52 million, or $0.68 per diluted share Generated operating cash flow of $210 million, Adjusted EBITDA (1) of $292 million and Free Cash Flow (1) of $108 million Produced 25.4 MBoe/d (93% oil), in upper end of guidance and even to prior year Reduced LOE (net of hedges) by 12% year-over-year; lowered G&A compared to 2023 including 6% reduction in Adjusted G&A (1) Reduced methane emissions by over 80%, with execution completed ahead of plan Finalized year-end proved reserves of 107 MMBoe, up 4% over prior year, with a reserve replacement ratio of 147% (1) and an SEC PV-10 value of $2.3 billion ( 2 ) Fourth Quarter 2024 Highlights Reported a net loss of $2 million, or $(0.02) per diluted share, Adjusted Net Income (1) of $17 million, or $0.21 per diluted share Generated operating cash flow of $41 million, Adjusted EBITDA (1) of $82 million and Free Cash Flow (1) of $24 million Produced 26.1 MBoe/d (93% oil), a 5% increase over third quarter and 1% increase year-over-year Declared a fixed dividend of $0.03 per share, which represents a 3% yield ( 3 ) on an annual basis 2025 Outlook Full year estimated production of 24.8 - 26.0 MBoe/d, with oil production expected to comprise ~93% of total Full year capital program of $110 - $120 million, with flexibility to adjust as commodity prices dictate Approximately 40% of Berry’s 2025 capital will be directed to Utah compared to 25% in 2024 (1)  Please see “Non-GAAP Financial Measures and Reconciliations” later in this press release for a reconciliation and more information on these Non-GAAP measures. (2)  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. (3)  Based on BRY share price of $4.07 as of February 28, 2025. MANAGEMENT COMMENTS Fernando Araujo, Berry’s Chief Executive Officer, said, “Our fourth quarter and year-end results highlight our continued success advancing our long-term strategy of generating sustainable free cash flow with high rate of return projects, while improving capital efficiency and our cost structure. Our thermal diatomite asset continues to deliver value enhancing results and provides a catalyst for future opportunities. In 2024, we successfully drilled 28 sidetracks with exceptional results and a rate of return exceeding 100%. These results have unlocked the potential to drill an additional 115 more sidetracks in this asset over the next few years, including up to 34 planned for 2025. Additionally, we expanded development of our 100,000 net acre position in the Uinta Basin. We executed two farm-ins/acreage exchanges providing critical technical data from 6 horizontal wells with peak rates up to 2,000 Boe/d. We closed the year with a refinancing to strengthen our balance sheet and entered 2025 with a disciplined plan designed to ensure capital for development and create value for shareholders.” Story Continues Araujo continued, “It’s an exciting time to be at Berry. In addition to operating and developing our existing assets efficiently, we are actively pursuing scale and diversification and evaluating accretive deals both large and small. We have the roadmap and the options to enhance our cash flows and sustain production, while simultaneously expanding our inventory and strengthening our balance sheet. Our team has an established track record of delivering on key objectives through cycles and regulatory challenges, and we have a compelling pipeline of value enhancing opportunities.” FOURTH QUARTER 2024 FINANCIAL AND OPERATING SUMMARY Selected Comparative Results Three Months Ended December 31, 2024 September 30, 2024 December 31, 2023 ($ in millions, except per share amounts) Production (mboe/d) 26.1 24.8 25.9 Oil, natural gas & NGL revenues (1) $ 158 $ 154 $ 172 Net (loss) income $ (2 ) $ 70 $ 63 Adjusted Net Income (2) $ 17 $ 11 $ 10 Adjusted EBITDA (2) $ 82 $ 67 $ 70 Earnings per diluted share $ (0.02 ) $ 0.91 $ 0.81 Adjusted earnings per diluted share (2) $ 0.21 $ 0.14 $ 0.13 Cash Flow from Operations $ 41 $ 71 $ 79 Capital expenditures $ 17 $ 26 $ 17 Free Cash Flow (2) $ 24 $ 45 $ 62 (1)  Revenues do not include hedge settlements. (2)  Please see “Non-GAAP Financial Measures and Reconciliations” later in this press release for reconciliation and more information on these Non-GAAP measures. FULL YEAR 2024 FINANCIAL AND OPERATING SUMMARY Selected Comparative Results Year Ended December 31, 2024 2023 ($ in millions, except per share amounts) Production (mboe/d) 25.4 25.4 Oil, natural gas & NGL revenues (1) $ 647 $ 669 Net income $ 19 $ 37 Adjusted Net Income (2) $ 52 $ 39 Adjusted EBITDA (2) $ 292 $ 268 Earnings per diluted share $ 0.25 $ 0.48 Adjusted earnings per diluted share (2) $ 0.68 $ 0.51 Cash Flow from Operations $ 210 $ 199 Capital expenditures $ 102 $ 73 Free Cash Flow (2) $ 108 $ 126 (1)  Revenues do not include hedge settlements. (2)  Please see “Non-GAAP Financial Measures and Reconciliations” later in this press release for reconciliation and more information on these Non-GAAP measures. CAPITAL STRUCTURE As of December 31, 2024, Berry had $450 million outstanding on our 2024 Term Loan (defined below) and no borrowings outstanding under the 2024 Revolver (defined below). As of December 31, 2024, the Company had $110 million of liquidity, consisting of $15 million of cash and cash equivalents, $63 million available for borrowings under the 2024 Revolver and $32 million available for delayed draw borrowings under the 2024 Term Loan. Based on current forward commodity prices, Berry expects to be able to fund its 2025 capital development program from cash flow from operations. As of December 31, 2024, the Company had a leverage ratio (1) of 1.49x. (1)  Please see “Non-GAAP Financial Measures and Reconciliations” later in this press release for reconciliation and more information on these Non-GAAP measures. SHAREHOLDER RETURNS In October 2024, in connection with the 2024 Term Loan, Berry transitioned to a capital allocation approach that prioritizes debt reduction and aligns with the covenants contained in the 2024 Term Loan while facilitating the Company’s operating strategy and enabling investment in development opportunities. In March 2025, Berry’s Board of Directors approved a fixed cash dividend of $0.03 per share, payable to shareholders of record as of March 22, 2025 and is expected to be paid on April 1, 2025. For 2025, the Company expects to continue with its fixed dividend while prioritizing debt reduction. 2025 GUIDANCE Full Year 2025 Guidance Low High Average Daily Production (boe/d) 24,800 26,000 % Oil Production 91 % 95 % Non-energy LOE ($/boe) ( 1) $ 13.00 $ 15.00 Energy LOE (unhedged) ($/boe) ( 2) $ 12.70 $ 14.50 Natural Gas Purchase Hedge Settlements ($/boe) ( 3)(4) $ 1.00 $ 1.60 Taxes, Other Than Income Taxes ($/boe) $ 5.50 $ 6.50 Adjusted G&A expenses - E&P Segment & Corp ($/boe) ( 5)(6) $ 6.35 $ 6.75 Capital Expenditures ($ millions) ( 7) (8) $ 110 $ 120 (1)  Non-energy LOE consists of lease operating costs not included in Energy LOE. (2)  Energy LOE (unhedged) consists of costs to generate steam and electricity the Company produces and uses in its operations and the power the Company purchases for its E&P operations. (3)  Natural gas purchase hedge settlements is the cash (received) or paid from these derivatives on a per boe basis. (4)  Based on natural gas hedge positions and basis differentials as of December 31, 2024, and the Henry Hub gas price of $3.00 per mmbtu. (5)  Adjusted G&A expenses is a non-GAAP financial measure. The Company does not provide a reconciliation of this measure because the Company believes such reconciliation would imply a degree of precision and certainty that could be confusing to investors and is unable to reasonably predict certain items included in or excluded from the GAAP financial measures without unreasonable efforts. This is due to the inherent difficulty of forecasting the timing or amount of various items that have not yet occurred and are out of the Company’s control or cannot be reasonably predicted. Non-GAAP forward-looking measures provided without the most directly comparable GAAP financial measures may vary materially from the corresponding GAAP financial measures. (6)  See further discussion and reconciliation in “Non-GAAP Financial Measures and Reconciliations”. (7)  Total company capital expenditures, including E&P segment, well servicing & abandonment segment and corporate. (8)  Approximately 60% of Berry’s 2025 capital is expected to be directed to California, with 40% allocated to Utah. RISK MANAGEMENT Berry utilizes hedges to manage commodity price risk, protect the balance sheet and ensure cash flow to fund its annual capital program. Based on the midpoint of the Company’s guidance and its hedge book as of January 31, 2025, Berry has 75% of its estimated oil production volumes hedged for 2025 at average strike price of $74.24 per barrel of Brent factoring in swaps and the floor price of collars. The Company has gas purchase hedges for approximately 70% of its expected 2025 gas demand, with an average swap price of $4.25 per MMBtu. As part of the debt refinancing, Berry is required to hedge a minimum of 75% of PDP volumes for the first 24 months and 50% of volumes for months 25-36 on a rolling basis. Complete details on the Company’s derivative positions can be found in its investor presentation located at https://ir.bry.com/reports-resources. PROVED RESERVES Berry’s year-end 2024 proved reserves totaled 107 MMBoe, of which 58% were proved developed and 96% were oil. The Company’s YE24 reserve report contains 548 PUD locations. Only 5% of Berry’s California PUD reserves are in areas where new drill permits are constrained and the Company is not currently pursuing alternative CEQA compliance. Berry’s proved reserves and PV-10 estimates as of December 31, 2024 were prepared by DeGolyer and MacNaughton in accordance with applicable rules and guidelines of the SEC. At year-end, The Company’s standardized measure of discounted future cash flows of proved reserves was $1.8 billion and PV-10 (1)( 2 ) , utilizing SEC pricing, was $2.3 billion. Complete details on Berry’s year-end 2024 reserves can be found in its investor presentation located at https://ir.bry.com/reports-resources . (1)  Please see “Non-GAAP Financial Measures and Reconciliations” later in this press release for a reconciliation and more information on these Non-GAAP measures. (2)  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. CONFERENCE CALL DETAILS Berry plans to host a conference call to discuss its fourth quarter and full year 2024 results, as well as its 2025 outlook: Call Date: Thursday, March 13 , 2025 Call Time: 11:00 a.m. Eastern Time / 10:00 a.m. Central Time / 8:00 a.m. Pacific Time Join the live listen-only audio webcast at https://edge.media-server.com/mmc/p/jocmjm36 or at https://bry.com/category/events. Accompanying slides will also be available at the time of the call at www.bry.com. If you would like to ask a question on the live call, please preregister at any time using the following link: https://register.vevent.com/register/BI79bd222b5a56464a890cc7ab0156d115 Once registered, you will receive the dial-in numbers and a unique PIN number. You may then dial-in or have a call back. When you dial in, you will input your PIN and be placed into the call. If you register and forget your PIN or lose your registration confirmation email, you may simply re-register and receive a new PIN. A web based audio replay will be available shortly after the broadcast and will be archived at https://ir.bry.com/reports-resources or visit https://edge.media-server.com/mmc/p/jocmjm36 or https://bry.com/category/events ABOUT BERRY CORPORATION (BRY) Berry is a publicly traded (NASDAQ: BRY) western United States independent upstream energy company with a focus on onshore, low geologic risk, long-lived oil and gas reserves. We operate in two business segments: (i) exploration and production (“E&P”) and (ii) well servicing and abandonment services. Our E&P assets are located in California and Utah, are characterized by high oil content and are predominantly located in rural areas with low population. Our California assets are in the San Joaquin Basin (100% oil), and our Utah assets are in the Uinta Basin (65% oil). We provide our well servicing and abandonment services to third party operators in California and our California E&P operations through C&J Well Services (CJWS). More information can be found at the Company’s website at www.bry.com . FORWARD-LOOKING STATEMENTS The information in this press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can typically identify forward-looking statements by words such as aim, anticipate, achievable, believe, budget, continue, could, effort, estimate, expect, forecast, goal, guidance, intend, likely, may, might, objective, outlook, plan, potential, predict, project, seek, should, target, will or would and other similar words that reflect the prospective nature of events or outcomes. All statements other than statements of historical facts included in this report that address plans, activities, events, objectives, goals, strategies or developments that we expect, believe or anticipate will or may occur in the future, such as those regarding our financial position, liquidity, cash flows (including, but not limited to, Free Cash Flow), financial and operating results, capital program and development and production plans, operations and business strategy, potential acquisition and other strategic opportunities, reserves, hedging activities, capital expenditures, return of capital, future repurchases of stock or debt, capital investments, our ESG strategy and the initiation of new projects or business in connection therewith, recovery factors and other guidance, are forward-looking statements. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. For any such forward-looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results, sometimes materially. Therefore, such forward-looking statements involve significant risks and uncertainties that could materially affect our expected financial position, financial and operating results, liquidity, cash flows (including, but not limited to, Free Cash Flow) and business prospects. Factors (but not all the factors) that could cause results to differ include among others: (1) the regulatory environment, including availability or timing of, and conditions imposed on, obtaining and/or maintaining permits and approvals, including those necessary for drilling and/or development projects; (2) the impact of current, pending and/or future laws and regulations, and of legislative and regulatory changes and other government activities, including those related to permitting, drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products; (3) volatility of oil, natural gas and NGL prices, including as a result of political instability, armed conflicts or economic sanctions; (4) inflation levels and government efforts to reduce inflation, including related interest rate determinations; (5) overall domestic and global political and economic trends, geopolitical risks and general economic and industry conditions, such as inflation, high interest rates, increased volatility in financial and credit markets, global supply chain disruptions, government interventions into the financial markets and economy and volatility related to recent and upcoming elections in the United States and other major economies; (6) the imposition of tariffs or trade or other economic sanctions, political instability or armed conflict in oil and gas producing regions, including the ongoing conflict in Ukraine, the ongoing conflict in the Middle East, or a prolonged recession, among other factors; (7) supply of and demand for oil, natural gas and NGLs, including due to the actions of foreign producers, importantly including OPEC+ and change in OPEC+'s production levels; (8) the California and global energy future, including the factors and trends that are expected to shape it, such as concerns about climate change and other air quality issues, the transition to a low-emission economy and the expected role of different energy sources; (9) concerns about climate change and air quality issues; (10) price fluctuations and availability of natural gas and electricity and the cost of steam; (11) disruptions to, capacity constraints in, or other limitations on the pipeline systems that deliver our oil and natural gas and other processing and transportation considerations; (12) our ability to recruit and/or retain key members of our senior management and key technical employees; (13) competition and consolidation in the oil and gas E&P industry; (14) our ability to replace our reserves through exploration and development activities or acquisitions; (15) our ability to make acquisitions and successfully integrate any acquired businesses; (16) information technology failures or cyberattacks; (17) inability to generate sufficient cash flow from operations or to obtain adequate financing to fund capital expenditures, meet our working capital requirements or fund planned investments; (18) our ability to satisfy our debt obligations and comply with all covenants, agreements and conditions under our 2024 Term Loan and our 2024 Revolver; and (19) the other risks described under the heading “Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2024 and subsequent filings with the SEC. Any forward-looking statement speaks only as of the date on which such statement is made. Except as required by law, we undertake no responsibility to correct or update any forward-looking statements, whether as a result of new information, future events or otherwise except as required by applicable law. All forward-looking statements, expressed or implied, included in this press release are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Investors are urged to consider carefully the disclosure in our filings with the Securities and Exchange Commission, available from us at via our website or via the Investor Relations contact below, or from the SEC’s website at www.sec.gov. TABLES FOLLOWING The financial information and certain other information presented have been rounded to the nearest whole number or the nearest decimal. Therefore, the sum of the numbers in a column may not conform exactly to the total figure given for that column in certain tables. In addition, certain percentages presented here reflect calculations based upon the underlying information prior to rounding and, accordingly, may not conform exactly to the percentages that would be derived if the relevant calculations were based upon the rounded numbers, or may not sum due to rounding. SUMMARY OF RESULTS Quarter Ended December 31, 2024 Quarter Ended September 30, 2024 Quarter Ended December 31, 2023 Year Ended December 31, 2024 Year Ended December 31, 2023 ($ and shares in thousands, except per share amounts) Consolidated Statement of Operations Data: Revenues and other: Oil, natural gas and natural gas liquids sales $ 157,957 $ 154,438 $ 172,439 $ 647,494 $ 669,110 Service revenue 23,554 25,465 40,746 111,857 178,554 Electricity sales 3,262 4,410 2,905 15,606 15,277 (Losses) gains on oil and gas sales derivatives (5,730 ) 75,434 83,918 (7,340 ) 40,006 Marketing and other revenues 8,744 37 319 8,884 513 Total revenues and other 187,787 259,784 300,327 776,501 903,460 Expenses and other: Lease operating expenses 56,337 54,801 67,342 225,824 316,726 Cost of services 20,907 22,911 32,783 96,143 141,771 Electricity generation expenses 1,557 1,245 1,827 4,447 7,079 Transportation expenses 1,122 1,332 1,260 4,552 4,486 Marketing expenses 8,100 — — 8,100 — Acquisition costs — 971 284 4,982 3,338 General and administrative expenses 18,389 19,111 20,729 76,615 95,873 Depreciation, depletion and amortization 43,579 42,749 40,937 172,002 160,542 Impairment of oil and gas properties — — — 43,980 — Taxes, other than income taxes 8,498 10,351 15,826 47,212 57,973 Losses on natural gas purchase derivatives 7,883 7,775 21,397 22,781 26,386 Other operating expenses (income) 3,763 (4,687 ) 36 (4,261 ) (1,788 ) Losses on debt retirement 7,066 — — 7,066 — Total expenses and other 177,201 156,559 202,421 709,443 812,386 Other (expenses) income: Interest expense (10,859 ) (8,986 ) (9,680 ) (39,035 ) (35,412 ) Other, net 136 56 (10 ) 56 (237 ) Total other expenses (10,723 ) (8,930 ) (9,690 ) (38,979 ) (35,649 ) Income (loss) before income taxes (137 ) 94,295 88,216 28,079 55,425 Income tax expense 1,622 24,432 25,665 8,828 18,025 Net income (loss) $ (1,759 ) $ 69,863 $ 62,551 $ 19,251 $ 37,400 Net income (loss) per share: Basic $ (0.02 ) $ 0.91 $ 0.83 $ 0.25 $ 0.49 Diluted $ (0.02 ) $ 0.91 $ 0.81 $ 0.25 $ 0.48 Weighted-average common shares outstanding - basic 76,939 76,939 75,667 76,769 76,038 Weighted-average common shares outstanding - diluted 77,213 77,060 77,349 76,998 77,583 Adjusted Net Income (1) $ 16,531 $ 10,839 $ 10,426 $ 52,435 $ 39,230 Weighted-average common shares outstanding - diluted 77,213 77,060 77,349 76,998 77,583 Diluted earnings per share on Adjusted Net Income (1) $ 0.21 $ 0.14 $ 0.13 $ 0.68 $ 0.51 Adjusted EBITDA (1) $ 81,780 $ 67,121 $ 70,036 $ 291,764 $ 268,257 Free Cash Flow (1) $ 24,144 $ 44,821 $ 62,015 $ 107,868 $ 125,530 Adjusted General and Administrative Expenses (1) $ 16,325 $ 16,466 $ 17,886 $ 68,772 $ 73,495 Effective Tax Rate N/A 26 % 29 % 31 % 33 % Cash Flow Data: Net cash provided by operating activities $ 41,361 $ 70,695 $ 79,018 $ 210,220 $ 198,657 Net cash used in investing activities $ (19,907 ) $ (24,502 ) $ (48,822 ) $ (105,556 ) $ (175,272 ) Net cash (used in) provided by financing activities $ (889 ) $ (43,410 ) $ (42,561 ) $ (79,463 ) $ (64,800 ) (1)   See further discussion and reconciliation in “Non-GAAP Financial Measures and Reconciliations”. December 31, 2024 December 31, 2023 ($ and shares in thousands) Balance Sheet Data: Total current assets $ 149,643 $ 140,800 Total property, plant and equipment, net $ 1,320,380 $ 1,406,612 Total current liabilities $ 187,880 $ 223,182 Long-term debt $ 384,633 $ 427,993 Total stockholders’ equity $ 730,636 $ 757,976 Outstanding common stock shares as of 76,939 75,667 The following table represents selected financial information for the periods presented regarding the Company's business segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis. Year Ended December 31, 2024 E&P Well Servicing and Abandonment Services Corporate/Eliminations Consolidated ($ in thousands) Revenues (1) $ 671,984 $ 132,452 $ (20,595 ) $ 783,841 Net income (loss) before income taxes $ 145,396 $ (556 ) $ (116,761 ) $ 28,079 Capital expenditures $ 97,331 $ 3,355 $ 1,666 $ 102,352 Total assets $ 1,535,292 $ 57,752 $ (75,358 ) $ 1,517,686 Year Ended December 31, 2023 E&P Well Servicing and Abandonment Services Corporate/Eliminations Consolidated ($ in thousands) Revenues (1) $ 684,900 $ 185,767 $ (7,213 ) $ 863,454 Net income (loss) before income taxes $ 163,425 $ 13,413 $ (121,413 ) $ 55,425 Capital expenditures $ 64,844 $ 5,805 $ 2,478 $ 73,127 Total assets $ 1,652,979 $ 68,670 $ (127,491 ) $ 1,594,158 (1)  These revenues do not include hedge settlements. COMMODITY PRICING Quarter Ended December 31, 2024 Quarter Ended September 30, 2024 Quarter Ended December 31, 2023 Year Ended December 31, 2024 Year Ended December 31, 2023 Weighted Average Realized Sales Prices Oil without hedges ($/bbl) $ 69.08 $ 72.40 $ 76.00 $ 73.70 $ 75.05 Effects of scheduled derivative settlements ($/bbl) $ 1.64 $ (1.39 ) $ (3.35 ) $ (1.59 ) $ (3.38 ) Oil with hedges ($/bbl) $ 70.72 $ 71.01 $ 72.65 $ 72.11 $ 71.67 Natural gas ($/mcf) $ 3.47 $ 2.01 $ 4.48 $ 2.70 $ 6.94 NGLs ($/bbl) $ 29.67 $ 24.01 $ 24.01 $ 26.82 $ 24.47 Purchased Natural Gas Purchase price, before the effects of derivative settlements ($/mmbtu) $ 3.76 $ 2.70 $ 5.29 $ 3.23 $ 8.21 Effects of scheduled derivative settlements ($/mmbtu) $ 0.62 $ 1.64 $ 0.44 $ 1.30 $ (1.79 ) Purchase price, after the effects of derivative settlements ($/mmbtu) $ 4.38 $ 4.34 $ 5.73 $ 4.53 $ 6.42 Index Prices Oil – Brent (bbl) $ 74.01 $ 78.71 $ 82.85 $ 79.86 $ 82.18 Oil – WTI (bbl) $ 70.33 $ 75.26 $ 78.49 $ 75.79 $ 77.61 Natural gas (mmbtu) – SoCal Gas city-gate (1) $ 3.57 $ 2.68 $ 6.25 $ 3.08 $ 10.96 Natural gas (mmbtu) – Northwest, Rocky Mountains (2) $ 3.09 $ 1.92 $ 4.53 $ 2.45 $ 8.28 Natural gas (mmbtu) – Henry Hub (2) $ 2.44 $ 2.11 $ 2.74 $ 2.19 $ 2.53 (1)  The natural gas we purchase to generate steam and electricity is primarily based on Rockies price indexes, including transportation charges, as we currently purchase a substantial majority of our gas needs from the Rockies, with the balance purchased in California. SoCal Gas city-gate Index is the relevant index used only for the portion of gas purchases in California. In May 2022, we began purchasing a majority of our fuel gas in the Rockies using the Northwest, Rocky Mountains index. (2)  Most of our gas purchases and gas sales in the Rockies are predicated on the Northwest, Rocky Mountains index, and to a lesser extent based on Henry Hub. Natural gas prices and differentials are strongly affected by local market fundamentals, availability of transportation capacity from producing areas and seasonal impacts. Our key exposure to gas prices is in our costs. We purchase substantially more natural gas for our California steamfloods and cogeneration facilities than we produce and sell in the Rockies. In May 2022, we began purchasing most of our gas in the Rockies and transporting it to our California operations using our Kern River pipeline capacity. We buy approximately 48,000 mmbtu/d in the Rockies, and the remainder comes from California markets. The volume purchased in California fluctuates and averaged 3,000 mbbtu/d in 2024, and 5,000 mmbtu/d in 2023.The natural gas we purchase in the Rockies is shipped to our operations in California to help limit our exposure to California fuel gas purchase price fluctuations. We strive to further minimize the variability of our fuel gas costs for our steam operations by hedging a significant portion of our gas purchases. Additionally, the negative impact of higher gas prices on our California operating expenses is partially offset by higher gas sales for the gas we produce and sell in the Rockies. The Kern River pipeline capacity allows us to purchase and sell natural gas at the same pricing indices. CURRENT HEDGING SUMMARY As of February 28, 2025 we had the following crude oil production and gas purchases hedges: Q1 2025 Q2 2025 Q3 2025 Q4 2025 FY 2026 FY 2027 FY 2028 Brent - Crude Oil Production Swaps Hedged volume (bbls) 1,388,344 1,637,198 1,613,083 1,518,000 3,345,268 3,056,000 1,278,000 Weighted-average price ($/bbl) $ 74.81 $ 74.36 $ 74.48 $ 75.28 $ 70.94 $ 70.08 $ 68.46 Collars Hedged volume (bbls) 206,127 — — — 1,161,500 318,500 — Weighted-average ceiling ($/bbl) $ 88.56 $ — $ — $ — $ 85.76 $ 80.03 $ — Weighted-average floor ($/bbl) $ 60.00 $ — $ — $ — $ 60.00 $ 65.00 $ — Purchased Puts (net) ( 1 ) Hedged volume (bbls) — — — — 547,500 — — Weighted-average price ($/bbl) $ — $ — $ — $ — $ 65.00 $ — $ — NWPL - Natural Gas Purchases ( 2 ) Swaps Hedged volume (mmbtu) 3,600,000 3,640,000 3,680,000 3,680,000 12,160,000 — — Weighted-average price ($/mmbtu) $ 4.29 $ 4.29 $ 4.29 $ 4.15 $ 3.93 $ — $ — (1)  Purchased puts and sold puts with the same strike price have been presented on a net basis. (2)  The term “NWPL” is defined as Northwest Rocky Mountain Pipeline and represents the index used for these gas purchase hedges. GAINS (LOSSES) ON DERIVATIVES A summary of gains and losses on the derivatives included on the statements of operations is presented below: Quarter Ended December 31, 2024 Quarter Ended September 30, 2024 Quarter Ended December 31, 2023 Year Ended December 31, 2024 Year Ended December 31, 2023 ($ in thousands) Realized gains (losses) on commodity derivatives: Realized gains (losses) on oil and gas sales derivatives $ 7,173 $ (2,907 ) $ (7,405 ) $ (10,217 ) $ (28,917 ) Realized (losses) gains on natural gas purchase derivatives (3,184 ) (7,490 ) (2,211 ) (24,400 ) 34,812 Total realized gains (losses) on derivatives $ 3,989 $ (10,397 ) $ (9,616 ) $ (34,617 ) $ 5,895 Unrealized (losses) gains on commodity derivatives: Unrealized (losses) gains on oil and gas sales derivatives $ (12,903 ) $ 78,341 $ 91,323 $ 2,877 $ 68,923 Unrealized (losses) gains on natural gas purchase derivatives (4,699 ) (285 ) (19,186 ) 1,619 (61,198 ) Total unrealized (losses) gains on derivatives $ (17,602 ) $ 78,056 $ 72,137 $ 4,496 $ 7,725 Total (losses) gains on derivatives $ (13,613 ) $ 67,659 $ 62,521 $ (30,121 ) $ 13,620 PRODUCTION STATISTICS Quarter Ended December 31, 2024 Quarter Ended September 30, 2024 Quarter Ended December 31, 2023 Year Ended December 31, 2024 Year Ended December 31, 2023 Net Oil, Natural Gas and NGLs Production Per Day (1) : Oil (mbbl/d) California 21.8 20.1 21.5 21.0 20.7 Utah 2.5 2.7 2.5 2.5 2.8 Total oil 24.3 22.8 24.0 23.5 23.5 Natural gas (mmcf/d) Utah 8.4 9.5 7.8 8.7 8.8 Total natural gas 8.4 9.5 7.8 8.7 8.8 NGLs (mbbl/d) California — — — — — Utah 0.4 0.4 0.6 0.4 0.4 Total NGLs 0.4 0.4 0.6 0.4 0.4 Total Production (mboe/d) ( 2 ) 26.1 24.8 25.9 25.4 25.4 (1)  Production represents volumes sold during the period. We also consume a portion of the natural gas we produce on lease 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 $2.19 per mmbtu respectively. CAPITAL EXPENDITURES Quarter Ended December 31, 2024 Quarter Ended September 30, 2024 Quarter Ended December 31, 2023 Year Ended December 31, 2024 Year Ended December 31, 2023 ($ in thousands) Capital expenditures (1)(2) $ 17,217 $ 25,874 $ 17,003 $ 102,352 $ 73,127 (1)  Capital expenditures include capitalized overhead and interest and exclude acquisitions and asset retirement spending. (2)  Capital expenditures in the quarters ended December 31, 2024, September 30, 2024 and December 31, 2023 included $1 million, less than $1 million and $1 million, respectively, for the well servicing and abandonment business. Capital expenditures in the years ended December 31, 2024 and December 31, 2023 included approximately $3 million and $6 million, respectively, for the well servicing and abandonment business. NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS Adjusted EBITDA is not a measure of either net income (loss) or cash flow, Free Cash Flow is not a measure of cash flow, Adjusted Net Income (Loss) is not a measure of net income (loss), and Adjusted General and Administrative Expenses is not a measure of general and administrative expenses, in all cases, as determined by GAAP. Rather, Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss), and Adjusted General and Administrative Expenses are supplemental non-GAAP financial measures used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as earnings before interest expense; income taxes; depreciation, depletion, and amortization; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and unusual and infrequent items. Our management believes Adjusted EBITDA provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry and the investment community. The measure also allows our management to more effectively evaluate our operating performance and compare the results between periods without regard to our financing methods or capital structure. We also use Adjusted EBITDA in planning our capital expenditure allocation to sustain production levels and to determine our strategic hedging needs aside from the hedging requirements of the 2024 Term Loan. We define Free Cash Flow as cash flow from operations less capital expenditures. We use Free Cash Flow as the primary metric to measure our ability to pay dividends, pay down debt, repurchase stock, and make strategic growth and bolt-on acquisitions. Management believes Free Cash Flow may be useful in an investor analysis of our ability to generate cash from operating activities from our existing oil and gas asset base after capital expenditures and to fund such activities. Free Cash Flow does not represent the total increase or decrease in our cash balance, and it should not be inferred that the entire amount of Free Cash Flow is available for dividends, debt repayment, share repurchases, strategic acquisitions or other growth opportunities, or other discretionary expenditures, since we have mandatory debt service requirements and other non-discretionary expenditures that are not deducted from this measure. We define Adjusted Net Income (Loss) as net income (loss) adjusted for derivative gains or losses net of cash received or paid for scheduled derivative settlements, unusual and infrequent items, and the income tax expense or benefit of these adjustments using our statutory tax rate. Adjusted Net Income (Loss) excludes the impact of unusual and infrequent items affecting earnings that vary widely and unpredictably, including non-cash items such as derivative gains and losses. This measure is used by management when comparing results period over period. We believe Adjusted Net Income (Loss) is useful to investors because it reflects how management evaluates the Company’s ongoing financial and operating performance from period-to-period after removing certain transactions and activities that affect comparability of the metrics and are not reflective of the Company’s core operations. We believe this also makes it easier for investors to compare our period-to-period results with our peers. We define Adjusted General and Administrative Expenses as general and administrative expenses adjusted for non-cash stock compensation expense and unusual and infrequent costs. Management believes Adjusted General and Administrative Expenses is useful because it allows us to more effectively compare our performance from period to period. We believe Adjusted General and Administrative Expenses is useful to investors because it reflects how management evaluates the Company’s ongoing general and administrative expenses from period-to-period after removing non-cash stock compensation, as well as unusual or infrequent costs that affect comparability of the metrics and are not reflective of the Company’s administrative costs. We believe this also makes it easier for investors to compare our period-to-period results with our peers. While Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss), and Adjusted General and Administrative Expenses are non-GAAP measures, the amounts included in the calculation of Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss), and Adjusted General and Administrative Expenses were computed in accordance with GAAP. These measures are provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP and should not be considered as an alternative to, or more meaningful than income and liquidity measures calculated in accordance with GAAP. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. Our computations of Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss), and Adjusted General and Administrative Expenses may not be comparable to other similarly titled measures used by other companies. Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss), and Adjusted General and Administrative Expenses should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP. Leverage Ratio is a non-GAAP financial measure, which is used by management and external users of our financial statements to evaluate the financial condition of the Company. It is calculated as net debt divided by Adjusted EBITDA (defined above) for the most recently completed 12-month period. Net debt is calculated as long-term debt (from our 2024 Term Loan and 2024 Revolver), including the current portion and excluding unamortized discount and debt issuance costs, less unrestricted cash and cash equivalents. Management believes that Leverage Ratio provides useful information to investors because it is widely used by analysts, investors and ratings agencies in evaluating the financial condition of companies. PV-10 is a non-GAAP financial measure, which is widely used by the industry to understand the present value of oil and gas companies. It represents the present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and does not give effect to derivative transactions or estimated future income taxes. Management believes that PV-10 provides useful information to investors because it is widely used by analysts and investors in evaluating oil and natural gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, management believes the use of a pre-tax measure is valuable for evaluating the Company. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP. ADJUSTED EBITDA The following tables present reconciliations of the GAAP financial measures of net income (loss) and net cash provided (used) by operating activities to the non-GAAP financial measure of Adjusted EBITDA, as applicable, for each of the periods indicated. Quarter Ended December 31, 2024 Quarter Ended September 30, 2024 Quarter Ended December 31, 2023 Year Ended December 31, 2024 Year Ended December 31, 2023 ($ in thousands) Adjusted EBITDA reconciliation: Net (loss) income $ (1,759 ) $ 69,863 $ 62,551 $ 19,251 $ 37,400 Add (Subtract): Interest expense 10,859 8,986 9,680 39,035 35,412 Income tax expense 1,622 24,432 25,665 8,828 18,025 Depreciation, depletion, and amortization 43,579 42,749 40,937 172,002 160,542 Impairment of oil and gas properties — — — 43,980 — Stock compensation expense 2,315 2,301 3,020 6,991 14,356 Losses (gains) on derivatives 13,613 (67,659 ) (62,521 ) 30,121 (13,620 ) Net cash received (paid) for scheduled derivative settlements 722 (10,397 ) (9,616 ) (37,884 ) 5,895 Acquisition costs (1) — 971 284 4,982 3,338 Non-recurring costs (2) — 562 — 1,653 8,697 Other operating expenses (income) 3,763 (4,687 ) 36 (4,261 ) (1,788 ) Losses on debt retirement ( 3 ) 7,066 — — 7,066 — Adjusted EBITDA $ 81,780 $ 67,121 $ 70,036 $ 291,764 $ 268,257 Net cash provided by operating activities $ 41,361 $ 70,695 $ 79,018 $ 210,220 $ 198,657 Add (Subtract): Cash interest payments 14,129 16,174 1,794 46,954 32,251 Cash income tax payments 651 2,286 525 3,428 3,282 Acquisition costs (1) — 971 284 4,982 3,338 Non-recurring costs (2) — 562 — 1,653 8,697 Changes in operating assets and liabilities - working capital ( 4 ) 13,535 (13,605 ) (11,070 ) 25,766 25,654 Other operating expenses (income) - cash portion ( 5 ) 7,664 (9,962 ) (515 ) (5,679 ) (3,622 ) Losses on debt retirement - cash portion ( 6 ) 4,440 0 0 4,440 0 Adjusted EBITDA $ 81,780 $ 67,121 $ 70,036 $ 291,764 $ 268,257 (1)  Includes legal and other professional expenses related to various transaction activities. (2)  In 2024, non-recurring costs included the cost of various savings initiatives. In 2023, non-recurring costs included executive transition costs and workforce reduction costs in the first quarter, and costs related to the settlement of shareholder litigation in the third quarter. (3)  Includes expenses related to the retirement of the 2026 Notes, the 2021 RBL Facility and the 2022 ABL Facility, as well as financing activities we terminated upon successful completion of the 2024 Term Loan and the 2024 Revolver. (4)  Changes in other assets and liabilities consists of working capital and various immaterial items. (5)  Represents the cash portion of other operating (income) expenses from the income statement, net of the non-cash portion in the cash flow statement. (6)  Includes expenses related to the financing activities we terminated upon successful completion of the 2024 Term Loan and the 2024 Revolver. FREE CASH FLOW The following table presents a reconciliation of the GAAP financial measure of operating cash flow to the non-GAAP financial measure of Free Cash Flow for each of the periods indicated. Quarter Ended December 31, 2024 Quarter Ended September 30, 2024 Quarter Ended December 31, 2023 Year Ended December 31, 2024 Year Ended December 31, 2023 (in thousands) Free Cash Flow reconciliation: Net cash provided by operating activities $ 41,361 $ 70,695 $ 79,018 $ 210,220 $ 198,657 Subtract: Capital expenditures (17,217 ) (25,874 ) (17,003 ) (102,352 ) (73,127 ) Free Cash Flow $ 24,144 $ 44,821 $ 62,015 $ 107,868 $ 125,530 LEVERAGE RATIO The following table presents our leverage ratio as of December 31, 2024. Year Ended December 31, 2024 (in thousands) Net debt reconciliation: 2024 Term loan borrowings $ 450,000 2024 Revolver borrowings — Subtract: Unrestricted cash (15,336 ) Net Debt $ 434,664 Trailing twelve month Adjusted EBITDA $ 291,764 Leverage Ratio 1.49x ADJUSTED NET INCOME (LOSS) The following table presents a reconciliation of the GAAP financial measures of net income (loss) and net income (loss) per share — diluted to the non-GAAP financial measures of Adjusted Net Income (Loss) and Adjusted Net Income (Loss) per share — diluted for each of the periods indicated. Quarter Ended December 31, 2024 September 30, 2024 December 31, 2023 (in thousands) per share - diluted (in thousands) per share - diluted (in thousands) per share - diluted Adjusted Net Income (Loss) reconciliation: Net (loss) income $ (1,759 ) $ (0.02 ) $ 69,863 $ 0.91 $ 62,551 $ 0.81 Add (Subtract): Losses (gains) on derivatives 13,613 0.18 (67,659 ) (0.88 ) (62,521 ) (0.81 ) Net cash received (paid) for scheduled derivative settlements 722 0.01 (10,397 ) (0.13 ) (9,616 ) (0.12 ) Other operating expenses (income) 3,763 0.04 (4,687 ) (0.07 ) 36 — Acquisition costs (1) — — 971 0.01 284 — Non-recurring costs (2) — — 562 0.01 — — Losses on debt retirement ( 3 ) 7,066 0.09 — — — — Total (subtractions) additions, net 25,164 0.32 (81,210 ) (1.06 ) (71,817 ) (0.93 ) Income tax (expense) benefit of adjustments ( 4 ) (6,874 ) (0.09 ) 22,186 0.29 19,692 0.25 Adjusted Net Income (Loss) $ 16,531 $ 0.21 $ 10,839 $ 0.14 $ 10,426 $ 0.13 Basic EPS on Adjusted Net Income $ 0.21 $ 0.14 $ 0.14 Diluted EPS on Adjusted Net Income $ 0.21 $ 0.14 $ 0.13 Weighted average shares of common stock outstanding - basic 76,939 76,939 75,667 Weighted average shares of common stock outstanding - diluted 77,213 77,060 77,349 (1)  Includes legal and other professional expenses related to various transaction activities. (2)  In 2024, non-recurring costs included the cost of various savings initiatives. (3)  Includes expenses related to the retirement of the 2026 Notes, the 2021 RBL Facility and the 2022 ABL Facility, as well as financing activities we terminated upon successful completion of the 2024 Term Loan and the 2024 Revolver. (4)  The federal and state statutory rates were utilized in all periods presented. Year Ended December 31, 2024 December 31, 2023 (in thousands) per share- diluted (in thousands) per share- diluted Adjusted Net Income (Loss) reconciliation: Net income $ 19,251 $ 0.25 $ 37,400 $ 0.48 Add (Subtract): Losses (gains) on derivatives 30,121 0.39 (13,620 ) (0.18 ) Net cash received (paid) for scheduled derivative settlements (37,884 ) (0.49 ) 5,895 0.08 Other operating (income) expenses (4,261 ) (0.05 ) (1,788 ) (0.01 ) Impairment of oil and gas properties 43,980 0.57 — — Acquisition costs (1) 4,982 0.06 3,338 0.04 Non-recurring costs (2) 1,653 0.02 8,697 0.11 Losses on Debt Retirement (3) 7,066 0.09 — — Total additions (subtractions), net 45,657 0.59 2,522 0.04 Income tax (expense) benefit of adjustments ( 4 ) (12,473 ) (0.16 ) (692 ) (0.01 ) Adjusted Net Income (Loss) $ 52,435 $ 0.68 $ 39,230 $ 0.51 Basic EPS on Adjusted Net Income $ 0.68 $ 0.52 Diluted EPS on Adjusted Net Income $ 0.68 $ 0.51 Weighted average shares of common stock outstanding - basic 76,769 76,038 Weighted average shares of common stock outstanding - diluted 76,998 77,583 (1)  Includes legal and other professional expenses related to various transaction activities. (2)  In 2024, non-recurring costs included the cost of various savings initiatives. In 2023, non-recurring costs included executive transition costs and workforce reduction costs in the first quarter, and costs related to the settlement of shareholder litigation in the third quarter. (3)  Includes expenses related to the retirement of the 2026 Notes, the 2021 RBL Facility and the 2022 ABL Facility, as well as financing activities we terminated upon successful completion of the 2024 Term Loan and the 2024 Revolver. (4)  The federal and state statutory rates were utilized in all periods presented. ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES The following table presents a reconciliation of the GAAP financial measure of general and administrative expenses to the non-GAAP financial measure of Adjusted General and Administrative Expenses for each of the periods indicated. Quarter Ended December 31, 2024 Quarter Ended September 30, 2024 Quarter Ended December 31, 2023 Year Ended December 31, 2024 Year Ended December 31, 2023 ($ in thousands) Adjusted General and Administrative Expense reconciliation: General and administrative expenses $ 18,389 $ 19,111 $ 20,729 $ 76,615 $ 95,873 Subtract: Non-cash stock compensation expense (G&A portion) (2,064 ) (2,083 ) (2,843 ) (6,190 ) (13,681 ) Non-recurring costs (1) — (562 ) — (1,653 ) (8,697 ) Adjusted General and Administrative Expenses $ 16,325 $ 16,466 $ 17,886 $ 68,772 $ 73,495 Well servicing and abandonment services segment $ 2,015 $ 2,351 $ 2,177 $ 9,749 $ 11,171 E&P segment, and corporate $ 14,310 $ 14,115 $ 15,709 $ 59,023 $ 62,324 E&P segment, and corporate ($/boe) $ 5.96 $ 6.19 $ 6.59 $ 6.35 $ 6.73 Total mboe 2,400 2,281 2,384 9,291 9,258 (1)  In 2024, non-recurring costs included the cost of various savings initiatives. In 2023, non-recurring costs included executive transition costs and workforce reduction costs in the first quarter, and costs related to the settlement of shareholder litigation in the third quarter. E&P OPERATIN G COSTS Overall, management assesses the efficiency of our E&P operations by considering core E&P operating costs. The substantial majority of such costs is our lease operating expenses (“LOE”) which includes fuel gas, purchased power, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. A core component of our E&P operations in California is steam, which we use to lift heavy oil to the surface. The most significant cost component of generating steam is the fuel gas purchased to operate traditional steam generators and our cogeneration facilities. The following table includes key components of our LOE as well as the gas purchase hedge effect of the fuel used in our steam generation. Energy LOE consists of the costs to generate the steam and electricity we produce and use in our operations and the power we purchase for our E&P operations. Non-energy LOE consists of all remaining LOE costs. Energy LOE - hedged includes the realized (cash settled) hedge effects on the fuel gas we purchase. LOE - hedged includes the realized (cash settled) hedge effects on our total LOE. Quarter Ended Year Ended December 31, 2024 September 30, 2024 December 31, 2023 December 31, 2024 December 31, 2023 ($ in thousands) Energy LOE - unhedged $ 28,171 $ 24,448 $ 37,999 $ 104,125 $ 195,893 Non-energy LOE 28,166 30,353 29,343 121,699 120,833 Lease operating expenses (1) 56,337 54,801 67,342 225,824 316,726 Gas purchase hedges - realized 3,184 7,490 2,211 24,400 (34,812 ) Lease operating expenses - hedged $ 59,521 $ 62,291 $ 69,553 $ 250,224 $ 281,914 Energy LOE - unhedged $ 28,171 $ 24,448 $ 37,999 $ 104,125 $ 195,893 Gas purchase hedges - realized 3,184 7,490 2,211 24,400 (34,812 ) Energy LOE - hedged $ 31,355 $ 31,938 $ 40,210 $ 128,525 $ 161,081 Quarter Ended Year Ended December 31, 2024 September 30, 2024 December 31, 2023 December 31, 2024 December 31, 2023 (per boe) Energy LOE - unhedged $ 11.74 $ 10.72 $ 15.94 $ 11.21 $ 21.16 Non-energy LOE 11.74 13.30 12.31 13.10 13.05 Lease operating expenses (1) 23.48 24.02 28.25 24.31 34.21 Gas purchase hedges - realized 1.33 3.28 0.93 2.63 (3.76 ) Lease operating expenses - hedged 24.81 27.30 29.18 26.94 30.45 Energy LOE - unhedged $ 11.74 $ 10.72 $ 15.94 $ 11.21 $ 21.16 Gas purchase hedges - realized 1.33 3.28 0.93 2.63 (3.76 ) Energy LOE - hedged $ 13.07 $ 14.00 $ 16.87 $ 13.84 $ 17.40 (1)  Lease operating expenses (“LOE”) is also referred to as LOE - unhedged. Energy LOE - hedged and LOE - hedged are not complete measures of our operating costs. These are supplemental non-GAAP financial measures used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. Our management believes Energy LOE - hedged and LOE - hedged provide useful information in assessing our operating costs and results of operations and are used by the industry and the investment community. These measures also allow our management to more effectively evaluate our operating performance and compare the results between periods. While Energy LOE - hedged and LOE - hedged are non-GAAP measures, the amounts included in the calculation of these measures were computed in accordance with GAAP. These measures are provided in addition to, and not as an alternative for, operating costs in accordance with GAAP and should not be considered as an alternative to, or more meaningful than cost measures calculated in accordance with GAAP. Our computations of Energy LOE - hedged and LOE - hedged may not be comparable to other similarly titled measures used by other companies. Energy LOE - hedged and LOE - hedged should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP. PROVED RESERVES AND PV-10 The following table summarizes our estimated proved reserves and related PV-10 as of December 31, 2024: Proved Reserves as of December 31, 2024 (1) California (San Joaquin basin) Utah (Uinta basin) Total Proved developed reserves: Oil (mmbbl) 54 4 58 Natural gas (bcf) — 15 15 NGLs (mmbbl) — 1 1 Total (mmboe) (2)(3) 54 8 62 Proved undeveloped reserves: Oil (mmbbl) 41 4 45 Natural gas (bcf) — 3 3 NGLs (mmbbl) — — — Total (mmboe) (3) 41 4 45 Total proved reserves: Oil (mmbbl) 95 8 103 Natural gas (bcf) — 18 18 NGLs (mmbbl) — 1 1 Total (mmboe) (3) 95 12 107 PV-10 (in millions) (4) $ 2,143 $ 110 $ 2,253 (1)  Our estimated net reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $80.42 per bbl Brent for oil and NGLs and $2.13 per mmbtu Henry Hub for natural gas at December 31, 2024. The volume-weighted average realized prices over the lives of the properties were $74.21 per bbl of oil and condensate, $23.27 per bbl of NGLs and $2.85 per mcf. The prices were held constant for the lives of the properties and we took into account pricing differentials reflective of the market environment. Prices were calculated using oil and natural gas price parameters established by current guidelines of the SEC and accounting rules including adjustments by lease for quality, fuel deductions, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. (2)  For proved developed reserves approximately 18% of total and 19% of oil are non-producing. (3)  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 $2.19 per mmbtu, respectively. (4)  For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flows, please see the table below. PV-10 does not give effect to derivatives transactions. The following table provides a reconciliation of PV-10 of our proved reserves to the standardized measure of discounted future net cash flows at December 31, 2024: At December 31, 2024 ($ in millions) California PV-10 $ 2,143 Utah PV-10 110 Total Company PV-10 2,253 Less: present value of future income taxes discounted at 10% (442 ) Standardized measure of discounted future net cash flows $ 1,811 The following table presents reserves changes and production for 2024: Total Company California (in mmboe) Extensions and discoveries 1 — Revisions of previous estimates 11 11 Purchases of minerals (1) 1 1 Total reserves changes 13 12 Production (9 ) (7 ) Reserve replacement ratio 147 % 166 % (1)  Purchases of minerals are related to the Round Mountain acquisition. CONTACT: CONTACT Contact: Berry Corporation (bry) Todd Crabtree - Director, Investor Relations (661) 616-3811 ir@bry.com View Comments Terms and Privacy Policy Your Privacy Choices More Info Recommended Stories
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