PRESS RELEASE

For Immediate Release

Berry Corporation Announces Second Quarter 2025 Financial and Operational Results, Continued Debt Reduction and Quarterly Dividend

DALLAS, TX - August 6, 2025 (GLOBE NEWSWIRE) – Berry Corporation (bry) (NASDAQ: BRY) (“Berry” or the “Company”) today announced its financial and operational results for the second quarter of 2025, as well as a quarterly cash dividend of $0.03 per share. Berry has provided a supplemental slide deck summarizing these results, which can be found at www.bry.com. The Company plans to host a conference call and webcast to discuss its second quarter 2025 results and latest 2025 outlook, at 10:00 a.m. CT, Thursday, August 7, 2025; access details can be found in this release.

Highlights

•Reaffirmed FY25 guidance; favorable hedge position protects cash flows and liquidity position

•Produced 23.9 MBoe/d (92% oil), in-line with plan

•Paid down approximately $11 million of total debt; year-to-date total debt reduction of approximately $23 million, in-line with target of at least $45 million of total debt reduction in 2025

•Returned cash to shareholders via quarterly dividend, representing a 4% dividend yield(1) on an annual basis

•Year-to-date hedged LOE trending 6% below midpoint of FY25 guidance

•Reported net income of $34 million, or $0.43 per diluted share

•Generated operating cash flow of $29 million and Adjusted EBITDA(2) of $53 million

•Reported zero recordable incidents and zero lost-time incidents in our E&P operations

Other Updates

•Oil volumes 71%(3) hedged for remainder of 2025 at $74.59/Bbl and 63%(3) hedged for 2026 at $69.55/Bbl

•Mark-to-market (crude oil) hedge value of $30 million as of July 31, 2025

•Production from all four horizontal Uinta wells expected in August, with first well currently on flowback and second well running final completion

__________

(1) Based on BRY share price of $3.02 as of July 31, 2025.

(2) Please see “Non-GAAP Financial Measures and Reconciliations” in this release for reconciliations to GAAP and more information on these Non-GAAP measures.

(3) Based on the midpoint of full year 2025 oil production guidance.

MANAGEMENT COMMENTS

Fernando Araujo, Berry’s Chief Executive Officer, said, “Our full year drilling activity is now complete and we are positioned for sequential production growth through the end of the year. On the regulatory front, we are encouraged by positive developments in California which could potentially open up new drill permitting pathways by year-end. Irrespective of the outcome, we have the permits in hand today to execute our multi-year development plans.”

Mr. Araujo continued, “In Utah, we began flowback of our first well and our second well is running final completion today, with the remaining two expected to be online later this month. Our Uinta wells should help drive production growth over the second half of the year. Due to an early startup of frac operations, we pulled forward a portion of full-year capex into the second quarter. Our average well cost is approximately 20% below the average cost of our non-op wells. We will also be testing the Castle Peak through a non-operated well just north of our acreage which we expect to be online in the fourth quarter. Berry is poised for strong free cash flow generation through the remainder of the year.”

SECOND QUARTER 2025 FINANCIAL AND OPERATING SUMMARY

Selected Comparative Results


	Three Months Ended
	June 30, 2025		March 31, 2025		June 30, 2024
	(unaudited) (in millions, except per share amounts)
Production (MBoe/d)	23.9		24.7		25.3
Oil, natural gas & NGL revenues(1)	$	126	$	148	$	169
Net income (loss)	$	34	$	(97)	$	(9)
Adjusted Net Income(2)	$	0	$	9	$	14

Adjusted EBITDA(2)	$	53	$	68	$	74
Earnings per diluted share	$	0.43	$	(1.25)	$	(0.11)
Adjusted earnings per diluted share(2)	$	0.00	$	0.12	$	0.18

Cash Flow from Operations	$	29	$	46	$	71
Capital expenditures	$	54	$	28	$	42
Free cash flow(2)	$	(26)	$	17	$	29

__________

(1) Revenues do not include hedge settlements.

(2) Please see “Non-GAAP Financial Measures and Reconciliations” in this press release for more information on these Non-GAAP measures and reconciliations to the nearest GAAP measures.

CAPITAL STRUCTURE

As of June 30, 2025, Berry had $428 million outstanding on its term loan facility and no borrowings outstanding under its revolving credit facility. As of June 30, 2025, the Company had $101 million of liquidity consisting of $20 million of cash, $49 million of available borrowing capacity and $32 million of available commitments under the delayed draw portion of the term loan facility. Based on current commodity prices, Berry expects to fund the remainder of its 2025 capital program with cash flow from operations.

DEBT REDUCTION AND SHAREHOLDER RETURNS

During the quarter, the Company paid down approximately $11 million of debt bringing total debt reduction to approximately $23 million year-to-date.

On August 5, 2025, Berry’s Board of Directors approved a quarterly cash dividend of $0.03 per share of common stock, payable on August 28, 2025 to shareholders of record as of the close of business on August 18, 2025.

2025 GUIDANCE (REAFFIRMED)


Full Year 2025 Guidance	Low	High
Average Daily Production (boe/d)(1)	24,800	26,000

Non-energy LOE ($/boe)(2)	$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)(2)	$6.35	$6.75


Capital Expenditures ($ millions)(5)(6)	$110	$120

__________

(1) Oil production is expected to be approximately 93% of total.

(2) Non-energy LOE, Energy LOE and Adjusted G&A expense are non-GAAP financial measures. The Company does not provide a reconciliation of these forward-looking measures 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. See further discussion in “Non-GAAP Financial Measures and Reconciliations.”

(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) Total company capital expenditures, including E&P segment, well servicing & abandonment services segment and corporate.

(6) Approximately 60% of Berry’s 2025 capital program is expected to be directed to California with 40% allocated to Utah.

RISK MANAGEMENT

The Company 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 Berry’s 2025 full year oil production guidance and its hedge book as of July 31, 2025, the Company has 71% of its estimated oil production volumes hedged for the remainder of 2025 at an average price of $74.59/Bbl of Brent, and 63% of oil production (assuming the midpoint of 2025 annual guidance) hedged for 2026 at $69.55/Bbl of Brent. Berry has gas purchase hedges for approximately 80% of its expected gas demand for the remainder of 2025, with an average swap price of $4.22/MMBtu.

Complete details on the Company’s derivative positions can be found in its investor presentation located at https://ir.bry.com/events-presentations.

CONFERENCE CALL DETAILS

Berry plans to host a conference call to discuss its second quarter 2025 results:

Call Date: Thursday, August 7, 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/nngi4arf or at https://ir.bry.com/events-presentations. 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-conf.media-server.com/register/BIb2be5f52d4874ace92c29a164ea18802

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/financial-reports/quarterly-results or visit https://edge.media-server.com/mmc/p/nngi4arf.

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.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This press release includes forward-looking statements within the meaning of the federal securities laws, including 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 press release 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, 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 distributions, 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. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this press release. Unless legally required, the Company does not undertake any obligation to update, modify or withdraw any forward-looking statements as a result of new information, future events or otherwise, unless required by law.

Factors that could cause actual results to differ from management’s expectations include, but are not limited to: 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; 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; volatility of oil, natural gas and NGL prices, including as a result of political instability, armed conflicts or economic sanctions; inflation levels and government efforts aimed to reduce inflation, including related interest rate determinations; overall domestic and global political and economic trends, geopolitical risks and general economic and industry conditions; 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; our ability to satisfy our debt obligations and comply with all covenants, agreements and conditions under our debt agreements; any future impairments to the Company’s proved or unproved oil and gas properties or write-downs of productive assets; 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; changes in 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; the competitiveness and rate of adoption of alternative energy sources, including the factors and trends that are expected to shape it, such as concerns about climate change and other air quality issues; the price and availability of natural gas and electricity to generate stream used in our operations; disruptions to, capacity constraints in, or other limitations on pipeline and other transportation systems that deliver our oil and natural gas to customers and other

processing and transportation considerations; our ability to recruit and/or retain key members of our senior management and key technical employees; potential liability resulting from pending or future litigation, government investigations or other legal proceedings; competition and consolidation in the E&P industry; our ability to replace our reserves through exploration and development activities or acquisitions; our ability to make acquisitions and successfully integrate any acquired businesses; information technology failures or cyberattacks; and 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 Securities and Exchange Commission (the “SEC”).

Investors are urged to consider carefully the disclosure in our filings with the SEC, available from us at via our website or via the Investor Relations contact below, or from the SEC’s website at www.sec.gov.

CONTACT

Contact: Berry Corporation (bry)

Christopher Denison: Director - Investor Relations & Sustainability

(661) 616-3811

ir@bry.com

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


	Three Months Ended
	June 30, 2025		March 31, 2025		June 30, 2024
	(unaudited) ($ and shares in thousands, except per share amounts)
Consolidated Statement of Operations Data:
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	125,637	$	147,862	$	168,781
Service revenue	22,824		23,664		31,155
Electricity sales	4,886		4,967		3,691
Gains (losses) on oil and gas sales derivatives	56,423		5,475		(5,844)
Marketing and other revenues	308		683		1,851
Total revenues and other	210,078		182,651		199,634

Expenses and other:
Lease operating expenses	53,193		57,282		53,885
Cost of services	19,001		20,825		25,021
Electricity generation expenses	624		1,209		586
Transportation expenses	1,225		939		1,039
Marketing expenses	345		292		1,885
Acquisition costs	310		—		1,394
General and administrative expenses	20,270		20,305		18,881
Depreciation, depletion and amortization	35,294		40,392		42,843
Impairment of oil and gas properties	—		157,910		43,980
Taxes, other than income taxes	12,957		9,240		12,674

Losses (gains) on natural gas purchase derivatives	3,130		(5,691)		2,642
Other operating expense (income)	1,365		401		(3,204)

Total expenses and other	147,714		303,104		201,626

Other (expenses) income:
Interest expense	(15,513)		(15,172)		(10,050)
Other, net	(59)		272		(53)
Total other expenses	(15,572)		(14,900)		(10,103)

Income (loss) before income taxes	46,792		(135,353)		(12,095)
Income tax expense (benefit)	13,188		(38,673)		(3,326)
Net income (loss)	$	33,604	$	(96,680)	$	(8,769)



Net income (loss) per share:
Basic	$	0.43	$	(1.25)	$	(0.11)
Diluted	$	0.43	$	(1.25)	$	(0.11)

Weighted-average shares of common stock outstanding - basic	77,596		77,196		76,939
Weighted-average shares of common stock outstanding - diluted	77,697		77,196		76,939

Adjusted Net Income (Loss)(1)	$	(364)	$	9,370	$	14,155
Weighted-average shares of common stock outstanding - diluted	77,596		77,371		77,161
Diluted earnings per share on Adjusted Net Income (Loss)(1)	$	0.00	$	0.12	$	0.18



	Three Months Ended
	June 30, 2025			March 31, 2025			June 30, 2024
	(unaudited) ($ and shares in thousands, except per share amounts)
Adjusted EBITDA(1)	$	52,915		$	68,450		$	74,329
Free Cash Flow(1)	$	(25,611)		$	17,483		$	28,566


Adjusted General and Administrative Expenses(1)	$	18,313		$	18,300		$	17,038

Effective Tax Rate	28		%	29		%	28		%




Cash Flow Data:
Net cash provided by operating activities	$	28,638		$	45,872		$	70,891
Net cash used in investing activities	$	(34,162)		$	(19,770)		$	(42,486)
Net cash used in financing activities	$	(13,760)		$	(16,876)		$	(25,174)

__________

(1) See further discussion and reconciliations in “Non-GAAP Financial Measures and Reconciliations.”


	June 30, 2025		December 31, 2024
	(unaudited) ($ and shares in thousands)
Balance Sheet Data:
Total current assets	$	158,048	$	149,643
Total property, plant and equipment, net	$	1,176,078	$	1,320,380
Total current liabilities	$	190,927	$	187,880
Long-term debt	$	364,602	$	384,633
Total stockholders' equity	$	664,941	$	730,636
Outstanding common stock shares as of	77,596		76,939

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.


	Three Months Ended June 30, 2025
	E&P		Well Servicing and Abandonment Services		Corporate/Eliminations		Consolidated Company
	(unaudited) (in thousands)









Revenues(1)	$	130,831	$	31,082	$	(8,258)	$	153,655


Net income (loss) before income taxes	$	81,001	$	(296)	$	(33,913)	$	46,792


Capital expenditures	$	53,350	$	333	$	566	$	54,249

Total assets	$	1,429,078	$	43,451	$	(44,414)	$	1,428,115


	Three Months Ended March 31, 2025
	E&P		Well Servicing and Abandonment Services		Corporate/Eliminations		Consolidated Company
	(unaudited) (in thousands)









Revenues(1)	$	153,512	$	29,747	$	(6,083)	$	177,176


Net (loss) income before income taxes	$	(101,417)	$	(1,711)	$	(32,225)	$	(135,353)


Capital expenditures	$	27,618	$	56	$	715	$	28,389

Total assets	$	1,385,674	$	52,392	$	(33,728)	$	1,404,338



	Three Months Ended June 30, 2024
	E&P		Well Servicing and Abandonment Services		Corporate/Eliminations		Consolidated Company
	(unaudited) (in thousands)
Revenues(1)	$	174,323	$	36,680	$	(5,525)	$	205,478
Net income (loss) before income taxes	$	13,860	$	1,117	$	(27,072)	$	(12,095)



Capital expenditures	$	41,735	$	468	$	122	$	42,325
Total assets	$	1,547,334	$	63,329	$	(77,754)	$	1,532,909

__________

(1) These revenues do not include hedge settlements.

COMMODITY PRICING


	Three Months Ended
	June 30, 2025		March 31, 2025		June 30, 2024
Weighted Average Realized Prices
Oil without hedge ($/bbl)	$	61.26	$	69.48	$	78.18
Effects of scheduled derivative settlements ($/bbl)	6.28		0.08		(4.60)
Oil with hedge ($/bbl)	$	67.54	$	69.56	$	73.58
Natural gas ($/mcf)	$	2.30	$	3.95	$	1.78
NGLs ($/bbl)	$	26.04	$	30.56	$	24.46

Purchased Natural Gas
Purchase price, before the effects of derivative settlements ($/mmbtu)	$	2.80	$	4.35	$	2.24
Effects of derivative settlements ($/mmbtu)	1.89		0.35		2.05
Purchase price, after the effects of derivative settlements ($/mmbtu)	$	4.69	$	4.70	$	4.29

Index Prices
Brent oil ($/bbl)	$	66.71	$	74.98	$	85.03
WTI oil ($/bbl)	$	63.92	$	71.51	$	80.60
Natural gas ($/mmbtu) – SoCal Gas city-gate(1)	$	3.11	$	4.50	$	1.86
Natural gas ($/mmbtu) – Northwest, Rocky Mountains(2)	$	2.18	$	3.88	$	1.40
Henry Hub natural gas ($/mmbtu)(2)	$	3.19	$	4.14	$	2.07

__________

(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.

(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 costs. We purchase 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 the Kern River pipeline capacity. Beginning in 2025, we purchased approximately 43,000 mmbtu/d in the Rockies (48,000 mmbtu/d prior to this change), with the remaining volumes purchased in California markets. Gas volumes purchased in California fluctuate, and averaged 2,000 mmbtu/d in the second quarter of 2025, 4,000 mmbtu/d in the first quarter of 2025 and 2,000 mmbtu/d in the second quarter of 2024. The natural gas we purchased 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 July 31, 2025, we had the following crude oil production and gas purchase hedges.


	Q3 2025		Q4 2025		FY 2026		FY 2027		FY 2028
Brent - Crude Oil production
Swaps
Hedged volume (bbls)	1,613,083		1,610,000		5,382,518		3,901,500		2,045,000
Hedged volume (mbbls) per day	17.5		17.5		14.7		10.7		5.6
Weighted-average price ($/bbl)	$	74.48	$	74.69	$	69.71	$	69.29	$	67.59
Collars
Hedged volume (bbls)	—		—		90,000		364,000		106,000
Hedged volume (mbbls) per day	—		—		0.2		1.0		0.3
Weighted-average ceiling ($/bbl)	$	—	$	—	$	82.25	$	72.58	$	67.67





Weighted-average floor ($/bbl)	$	—	$	—	$	60.00	$	62.50	$	60.00








NWPL - Natural Gas purchases(1)
Swaps
Hedged volume (mmbtu)	3,680,000		3,680,000		14,600,000		12,160,000		—
Hedged volume (mmbtu) per day	40.0		40.0		40.0		33.3		—
Weighted-average price ($/mmbtu)	$	4.29	$	4.15	$	3.97	$	4.18	$	—

__________

(1) The term “NWPL” is defined as Northwest Rocky Mountain Pipeline.

GAINS (LOSSES) ON DERIVATIVES

A summary of gains and losses on the derivatives included on the statements of operations is presented below:


	Three Months Ended
	June 30, 2025		March 31, 2025		June 30, 2024
	(unaudited) (in thousands)
Realized gains (losses) on commodity derivatives:
Realized gains (losses) on oil sales derivatives	$	8,593	$	164	$	(9,801)
Realized losses on natural gas purchase derivatives	(7,698)		(1,476)		(9,314)
Total realized gains (losses) on derivatives	$	895	$	(1,312)	$	(19,115)

Unrealized gains on commodity derivatives:
Unrealized gains on oil sales derivatives	$	47,830	$	5,311	$	3,957
Unrealized gains on natural gas purchase derivatives	4,568		7,167		6,672
Total unrealized gains on derivatives	$	52,398	$	12,478	$	10,629
Total gains (losses) on derivatives	$	53,293	$	11,166	$	(8,486)

PRODUCTION STATISTICS


	Three Months Ended
	June 30, 2025	March 31, 2025	June 30, 2024
Net Oil, Natural Gas and NGLs Production Per Day(1):
Oil (mbbl/d)
California	19.7	20.4	21.1
Utah	2.3	2.6	2.3

Total oil	22.0	23.0	23.4
Natural gas (mmcf/d)

Utah	9.1	7.9	8.9

Total natural gas	9.1	7.9	8.9
NGLs (mbbl/d)

Utah	0.4	0.4	0.4

Total NGLs	0.4	0.4	0.4
Total Production (mboe/d)(2)	23.9	24.7	25.3

__________

(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 three months ended June 30, 2025, the average prices of Brent oil and Henry Hub natural gas were $66.71 per bbl and $3.19 per mmbtu, respectively.

CAPITAL EXPENDITURES


	Three Months Ended
	June 30, 2025		March 31, 2025		June 30, 2024
			(unaudited) (in thousands)
Capital expenditures (1)(2)	$	54,249	$	28,389	$	42,325

__________

(1) Capital expenditures include capitalized overhead and interest and exclude acquisitions and asset retirement spending.

(2) Capital expenditures for the three months ended June 30, 2025, March 31, 2025 and June 30, 2024 were less than $1 million related to the well servicing and abandonment services segment.

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 and 2024 Revolver.

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.

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.


	Three Months Ended
	June 30, 2025		March 31, 2025		June 30, 2024
	(unaudited) (in thousands)
Adjusted EBITDA reconciliation:
Net income (loss)	$	33,604	$	(96,680)	$	(8,769)
Add (Subtract):
Interest expense	15,513		15,172		10,050
Income tax expense (benefit)	13,188		(38,673)		(3,326)
Depreciation, depletion, and amortization	35,294		40,392		42,843

Impairment of oil and gas properties	—		157,910		43,980
Stock compensation expense	2,026		2,406		1,990
(Gains) losses on derivatives	(53,293)		(11,166)		8,486
Net cash received (paid) for scheduled derivative settlements	4,908		(1,312)		(19,115)
Acquisition costs(1)	310		—		1,394

Other operating expense (income)	1,365		401		(3,204)


Adjusted EBITDA	$	52,915	$	68,450	$	74,329



Net cash provided by operating activities	$	28,638	$	45,872	$	70,891
Add (Subtract):
Cash interest payments	14,487		13,459		1,395
Cash income tax payments	5,239		66		491

Acquisition costs(1)	310		—		1,394


Changes in operating assets and liabilities - working capital(2)	3,852		9,265		3,293
Other operating income - cash portion(3)	389		(212)		(3,135)


Adjusted EBITDA	$	52,915	$	68,450	$	74,329

__________

(1) Includes legal and other professional expenses related to various transaction activities.

(2) Changes in other assets and liabilities consists of working capital and various immaterial items.

(3) Represents the cash portion of other operating (income) expenses from the income statement, net of the non-cash portion in the cash flow statement.

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.


	Three Months Ended
	June 30, 2025		March 31, 2025		June 30, 2024
	(unaudited) (in thousands)
Free Cash Flow reconciliation:
Net cash provided by operating activities	$	28,638	$	45,872	$	70,891

Capital expenditures	(54,249)		(28,389)		(42,325)
Free Cash Flow	$	(25,611)	$	17,483	$	28,566

LEVERAGE RATIO

The following table presents our leverage ratio.


		Three Months Ended
		June 30, 2025
	(unaudited) (in thousands)
Net debt reconciliation:
2024 Term loan borrowings		$	427,500
2024 Revolver borrowings		—
Subtract:
Unrestricted cash		(19,728)
Net Debt		$	407,772

Trailing twelve month Adjusted EBITDA		$	270,266

Leverage Ratio		1.51x

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.


	Three Months Ended
	June 30, 2025				March 31, 2025				June 30, 2024
	(in thousands)		per share - diluted		(in thousands)		per share - diluted		(in thousands)		per share - diluted
	(unaudited)
Adjusted Net Income (Loss) reconciliation:
Net income (loss)	$	33,604	$	0.43	$	(96,680)	$	(1.25)	$	(8,769)	$	(0.11)

Add (Subtract):
(Gains) losses on derivatives	(53,293)		(0.69)		(11,166)		(0.14)		8,486		0.11
Net cash received (paid) for scheduled derivative settlements	4,908		0.07		(1,312)		(0.02)		(19,115)		(0.25)
Other operating expenses (income)	1,365		0.03		401		0.00		(3,204)		(0.05)
Impairment of oil and gas properties	—		—		157,910		2.04		43,980		0.57
Acquisition costs(1)	310		0.00		—		—		1,394		0.02


Total additions, net	(46,710)		(0.59)		145,833		1.88		31,541		0.40

Income tax expense (benefit) of adjustments(2)	12,742		0.16		(39,783)		(0.51)		(8,617)		(0.11)
Adjusted Net Income (Loss)	$	(364)	$	0.00	$	9,370	$	0.12	$	14,155	$	0.18

Basic EPS on Adjusted Net Income	$	0.00			$	0.12			$	0.18
Diluted EPS on Adjusted Net Income	$	0.00			$	0.12			$	0.18

Weighted average shares of common stock outstanding - basic	77,596				77,196				76,939
Weighted average shares of common stock outstanding - diluted	77,596				77,371				77,161

__________

(1) Includes legal and other professional expenses related to various transaction activities.

(2) The federal and state statutory rates were utilized for 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.


	Three Months Ended
	June 30, 2025		March 31, 2025		June 30, 2024
	(unaudited) ($ in thousands)
Adjusted General and Administrative Expense reconciliation:
General and administrative expenses	$	20,270	$	20,305	$	18,881
Subtract:
Non-cash stock compensation expense (G&A portion)	(1,957)		(2,005)		(1,843)

Adjusted General and Administrative Expenses	$	18,313	$	18,300	$	17,038







Well servicing and abandonment services segment	$	2,124	$	2,300	$	2,454

E&P segment, and corporate	$	16,189	$	16,000	$	14,584
E&P segment, and corporate ($/Boe)	$	7.44	$	7.19	$	6.34

Total MBoe	2,177		2,225		2,300

E&P OPERATING 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 other 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.


	Three Months Ended
	June 30, 2025		March 31, 2025		June 30, 2024
	(unaudited) ($ in thousands)
Energy LOE - unhedged	$	22,476	$	26,323	$	21,891
Non-energy LOE	30,717		30,959		31,994
Lease operating expenses(1)	53,193		57,282		53,885
Gas purchase hedges - realized	7,699		1,476		9,314
Lease operating expenses - hedged	$	60,892	$	58,758	$	63,199

Energy LOE - unhedged	$	22,476	$	26,323	$	21,891
Gas purchase hedges - realized	7,699		1,476		9,314
Energy LOE - hedged	$	30,175	$	27,799	$	31,205


	Three Months Ended
	June 30, 2025		March 31, 2025		June 30, 2024
	(unaudited) (per Boe)
Energy LOE - unhedged	$	10.32	$	11.83	$	9.52
Non-energy LOE	14.11		13.91		13.91
Lease operating expenses(1)	24.43		25.74		23.43
Gas purchase hedges - realized	3.54		0.66		4.05
Lease operating expenses - hedged	$	27.97	$	26.40	$	27.48

Energy LOE - unhedged	$	10.32	$	11.83	$	9.52
Gas purchase hedges - realized	3.54		0.66		4.05
Energy LOE - hedged	$	13.86	$	12.49	$	13.57

__________

(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.

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Berry Corp (bry) 8-K