Berry Corporation (NASDAQ:BRY) Q2 2025 Earnings Call Transcript

Berry Corporation (NASDAQ:BRY) Q2 2025 Earnings Call Transcript August 8, 2025

Operator: Good day. Thank you for standing by. Welcome to the Berry Corporation Second Quarter 2025 Earnings Conference Call. [Operator Instructions] Please note that today’s conference may be recorded. I will now hand the conference over to your speaker host Chris Denison, Director of Investor Relations. Please go ahead.

Christopher Denison: Thank you, Olivia, and welcome, everyone. Thank you for joining us for Berry’s Second Quarter 2025 Earnings Call. Yesterday afternoon, Berry issued an earnings release highlighting our quarterly results. Speaking this morning will be Fernando Araujo, our CEO; Danielle Hunter, our President and Jeff Magids, our CFO. Our website has a link to the earnings release and our updated investor presentation. I would like to call your attention to the safe harbor language found in the earnings release. The release, the presentation and today’s discussion contains certain projections and other forward-looking statements within the meaning of federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements.

These include risks and other factors that are disclosed in our filings with the SEC including our quarterly report on Form 10-Q, which will be filed shortly. We have no plans or duty to update our forward-looking statements, except as required by law. Please refer to the tables in our earnings release and on our website for a reconciliation between all adjusted measures mentioned in today’s call and the related GAAP measures. We will also post the replay link of this call on our website. With that, I will turn the call over to Fernando.

Fernando Araujo: Thank you, Chris, and good morning, everyone. Welcome to our second quarter earnings call. We continue to successfully execute our 2025 plan. Our strategy is focused on balance sheet strength, high-return development projects and delivering capital and operational efficiencies. Despite ongoing macro volatility, our 2025 guidance remains unchanged. Our business strategy is anchored by our high- return assets, stable production base, low capital intensity projects and inventory depths. We believe this unique combination of attributes provides a competitive advantage. Our ability to execute our strategy is supported by the fact that we have the permits in hand to fully support development projects into 2027. As Tier 1 inventory becomes increasingly scarce across the industry, I want to highlight that Berry is inventory rich.

In California, we have thousands of locations across this high-return, low-capital intensity conventional basin, including approximately 500 PUD locations with 200 side tracks. In Utah, our horizontal delineation program is progressing, and we expect to unlock upside across our position. Turning to our results. We are on track to generate meaningful free cash flow for the year. Our strong hedge position provides visibility and protects our production outlook. For the remainder of the year, we have 71% of our expected oil production hedged at approximately $75 per barrel of Brent. During the quarter, we paid down $11 million of debt, bringing our year-end to-date debt reduction to $23 million. In California, activity continued to ramp with 16 wells drilled in the second quarter, up from 12 in the first quarter and 6 in the fourth quarter of last year.

We expect full production to be brought online within the third quarter, which will increase California’s production through the second half of the year. In Utah, we finished a significant portion of the completion activity earlier than expected for our horizontal pad in the second quarter. We successfully fracked 64 stages per well on average. We delivered meaningful cost savings of approximately $500,000 per well, supported by our fuel cost advantage and the use of a dual fuel fleet and drilling and fracking activities. We also utilized approximately 50% produced water in our fracs, which contributed to the savings. Our current cost outlook is approximately $680 per lateral foot which is approximately 20% lower than the average of our 6 nonoperated horizontal wells.

We began flow back on our first 2 wells in August, and the remaining 2 wells are expected to be online later this month. For our nonoperating wells, we continue to see strong results with production exceeding our predrilled estimates pointing to an average EUR of about 55 to 60 barrels of oil per lateral foot and supporting further delineation of our acreage. We believe our 100,000-acre position with high working interest has significant upside and provides long-term optionality in capital allocation and growth. In the fourth quarter, we’ll be participating in an additional nonoperated well just north of our acreage to test the Castle Peak formation. This well is expected to be on production in November and assuming success, we see longer-term potential for multi-bench cube development.

In summary, our priorities remain unchanged: to generate sustainable free cash flow, reduced debt while returning dividends and create long-term value by investing in our deep inventory of high-return portfolio. With that, I will turn the call over to Danny.

Danielle E. Hunter: Thanks, Fernando. Good morning, everyone. Thank you for joining us and for your interest in our company. First, I want to recognize the Berry team for delivering another quarter of 0 recordable incidents and 0 lost time incidents in our E&P operations. We are proud to live our commitment to HSE excellence. We are finalizing our 2025 sustainability report, which we expect to publish this quarter. In addition to enhanced disclosures, including TCFD alignment, we’re excited to share highlights of how we demonstrate our commitment to responsible operations, environmental stewardship, stakeholder engagement and community investment. On the regulatory front, we’re seeing the most constructive tone in California in at least 5 years, and we’re excited about what’s on the horizon.

On June 26, the Kern County Board of Supervisors approved the new oil and gas ordinance and certified a revised environmental impact review or EIR, required under CEQA for oil and gas activities. In terms of next steps, the county’s request to resume permitting is now under review by the court, and we expect a decision prior to year-end. Court approval is required before Kern County can resume issuance of new drill permits in areas without an existing CEQA-compliant EIR. As Fernando mentioned, we already have the permits in hand to support development activity into 2027. So having the current county EIR back in effect provides additional upside and optionality and we’ll streamline future development projects. In parallel, we are also encouraged by the California Energy Commission’s response to Governor Newsom’s directives focused on ensuring that all Californians have access to safe, reliable and affordable energy through responsible in-state production.

This includes permitting and regulatory reforms announced by the Newsom administration a few weeks ago, which aim to stabilize in-state production. Of particular importance is a proposal to codify the Kern County EIR into state law, which will improve the permitting process and derisk the impact of continued litigation. These policies designed to support in-state production will also benefit our C&J Well Services business. As one of the largest and most reputable P&A providers across the state, C&J is well positioned to capitalize on the potentially significant increase in demand for P&A services in connection with the proposed plug-to-drill requirements in effect outside of Kern County coupled with the increased P&A requirements for all operators that went into effect January 1 of this year.

If this new measure passes, it should lead to a healthy ramp up in activity and margin expansion for C&J in the near future. And of course, having access and price control over an increasingly important part of our supply chain is a competitive advantage to our E&P operations. The legislature reconvened in mid-August to consider these proposals and we are optimistic that these important policies will be adopted in the coming weeks. Regardless of timing, these efforts reinforce the growing consensus that in-state oil production is vital to California’s energy security. As you’ve heard, Berry stands to benefit on multiple fronts from these reforms, including even greater ability to unlock value in our extensive inventory across our world-class asset base, but we are not dependent on them.

We have a proven ability to navigate California’s complex environment, evidenced by a robust sidetrack program and having the permits in hand today to deliver over the next few years irrespective of the Kern County EIR or other legislative measures. Additionally, having permanent certainty amongst other stabilizing factors from the proposed regulatory reforms, should spur new investment in California’s high-return reservoirs and the timing couldn’t be better as inventory is becoming increasingly scarce in areas outside of California. We applaud Governor Newsom’s leadership to champion thoughtful solutions that support local businesses, protect local jobs, reduce foreign oil dependence and ensure the critical energy needs of our communities.

Jeff, over to you.

Jeffrey Magids: Thanks, Danny. In my comments this morning, I will highlight our second quarter financial results as well as our hedging program, operating costs, capital structure and guidance. For more in-depth information, please refer to our earnings release issued yesterday afternoon and our Form 10-Q, which we expect to file shortly. Second quarter oil and gas sales were $126 million, excluding derivatives, with a realized oil price of 92% of Brent. Based on our hedge book as of July 31, and using the midpoint of our 2025 production guidance, we have 71% of our expected oil production hedged for the remainder of 2025 at an average price of $75 per barrel of Brent. Assuming our production guidance is held flat for future periods, our expected oil production is 63% hedged for 2026 at an average price of $70 per barrel of Brent.

Altogether, our hedge program protects returns and shields against price volatility. Second quarter adjusted EBITDA was $53 million and operating cash flow was $29 million. Capital expenditures on an accrual basis were $54 million for the quarter and elevated compared to the prior quarter given the accelerated drilling and completion activity in Utah. The timing of lower capital and higher production over the second half of the year sets us up for strong free cash flow generation for the full year. As a reminder, our free cash flow calculation factors in working capital changes during the quarter. Looking at Q2 costs and expenses. Total hedged LOE was $27.97 per BOE and lower than our annual guidance rate as we optimize steam injection volumes while sustaining production.

Taxes other than income taxes were $5.95 per BOE and adjusted G&A for E&P and corporate was $7.44 per BOE. Turning to our balance sheet. Our quarter end total debt was $428 million. We paid down $11 million during the quarter and are on track to pay down at least $45 million for the year. Our liquidity position was $101 million at quarter end and working capital changes during the quarter were $11 million of cash outflow. Additionally, the Board declared a dividend of $0.03 per share or a 4% annualized dividend yield payable in the third quarter. Taken together, our annual debt reduction and dividend represents nearly 10% of our enterprise value, underscoring our commitment to generating shareholder value. At quarter end, we were in full compliance with our financial covenants and we have sufficient headroom to execute our strategy.

With that, I will now turn the call over to Fernando to wrap up our prepared remarks.

Fernando Araujo: Thank you, Jeff. Berry continues to execute on its stated objectives. Our focus remains consistent: execute on our deep inventory of high-return development projects, generate sustainable free cash flow, reduce debt and evaluate strategic opportunities. We are well positioned to advance our goals and generate long-term value for our shareholders. We look forward to sharing our progress. And with that, I’ll turn the call over to the operator for questions.

Q&A Session

Operator: [Operator Instructions] And our first question coming from the line of Charles Meade with Johnson Rice.

Charles Arthur Meade: I want to ask the first question about the changes — the positive changes, I guess, in the California regulatory situation. You guys talked about this hearing on the Kern County EIR and then a ruling it in 4Q. That looks — that time line seems positive, but I want to ask how are you guys thinking about the — I guess the probability of a favorable outcome there. I know certainly, the recent trends have been positive, but — and I suppose we should be cautious. But what — how hopeful are you about that hearing in that ruling?

Danielle E. Hunter: We feel very optimistic about it. I think there was a chance for objections to be filed when the County Board of Supervisors approved, recertified the EIR and no new objections were filed. There has been an objection filed related to the court process, but it’s not bringing in new issues. It’s reasons of the same. We feel confident due to the great and very thoughtful and meticulous work done by the county that the revised EIR addresses all of the deficiencies that were previously identified and so feel strong confidence that we’re at the last step and the County — the court will have its hearing and issue its ruling shortly thereafter.

Charles Arthur Meade: Got it. I appreciate that. And then, Fernando, perhaps this is for you. The well that you farmed into to test the Castle Peak just north of your acreage. I’m imagining that you’ve looked at some other Castle Peak tests perhaps nearby as part of your decision to farm into that well. Can you kind of set some expectations or maybe just some guidelines on what we should expect there and what made you think that was a good well to farm into?

Fernando Araujo: Yes. Good question, Charles. And as you know, industry is generally targeting where we are, the lower cube, what they call the lower cube which includes the Castle Peak, includes the Uteland Butte, which is the main reservoir target so far for most operators and then also the Wasatch. Now there has been some Castle Peak wells drilled the initial estimates of 40 to 50 barrels per foot EUR. We are really excited about the Castle Peak and our acreage because of the geology that we have. And as we’ve discussed before, the geology is a combination of limestone and sandstone, but the sandstones get thicker as you go south. So there’s the potential that we have thicker Castle Peak in our acreage. So it’s going to be very interesting.

It could really open up development potential, not only in the Castle Peak, but we have obviously potential in the Uteland Butte. And then you could start developing these fields with cube drilling, right, drilling out multiple layers at the same time from the same pad.

Charles Arthur Meade: Got it. Just to clarify, your 4-well pad that you’re just starting to flow back, that’s a Uteland Butte pad?

Fernando Araujo: That’s correct. The 4 wells are Uteland Butte.

Operator: [Operator Instructions] Our next question coming from the line of Nate Pendleton with Texas Capital.

Nate Pendleton: My first question, I want to start off on the Uinta costs that you laid out on Slide 16 and 17. When we think about this development as Berry’s first operated horizontal pad in the basin, your achievement of the 20% cost reduction is really encouraging. Based on your experience, can you speak to your ability to meet the targeted well costs in the $650 to $670 per foot range over time?

Fernando Araujo: Yes. Very good question, Nate. And obviously, as you mentioned, for our first-time operator drilling 3-mile laterals, we’re really encouraged with the achievement of being 20% below the cost compared to the 6 non-operated wells that we have. And also actually compared to some of the other operators in the basin as well. In terms of improvements, I think there’s still room to improve on that and one area of improvement is we could have a slightly better performance from our gas engines in drilling and frac fleets, they suffered a little bit during the summer months. And instead of operating about 75% of the time during the operation, which is what we initially expected, they operate for about 50% of the time.

So there’s some improvement potential there with the dual fleet, the dual fuel fleets Also, remember that we’re cleaning out 3-mile lateral wells, and this takes some time, and it’s — and we’re trying to be extra careful on that. So we’re taking a bit longer than what we initially expected. So there’s — that’s another area of improvement as well. And another area of improvement that I can point to is water usage. We’re utilizing 50% produced water, which is really good. But if we can find a way to utilize more produced water and reduce water cost, that will be even better. So it’s really a few things added together where we can improve. We can definitely improve another 5% or a little bit more as we drill in the future. But the more we drill, the better we’ll get, and we’re encouraged with the initial results.

Nate Pendleton: Absolutely. And then maybe shifting over to California. On Slide 9, you highlight your fields within the San Joaquin Basin. Well, I know the near-term focus is understandably on the high-return sidetrack program. Can you speak to some of the other opportunities within your California portfolio and how this fit into your strategy longer term?

Fernando Araujo: Yes. We have a huge portfolio in California. We’ve been focusing this year on the thermal diatomite sidetracks. Those tend to be our highest rate of return projects. But we also have significant potential in the Monarch and South Midway-Sunset drilling those horizontal wells in the Monarch, they’re short horizontals are there. They’re not 3 milers in Utah, they’re 1,000 foot, 1,500 foot horizontals, but there’s a lot of potential there. And we have significant potential also in the Hill property up in Belridge Field. And outside of that, we have significant workover potential as well on the east side of our acreage base in Round Mountain with our Waterflood. So really significant potential. Rates of return even at current strip pricing for thermal diatomite, they’re at 80% to 100% rate of return projects. So they’re really, really good projects.

Operator: [Operator Instructions] I’m showing no further questions in the queue at this time. I will now turn the call back over to Fernando Araujo for any closing remarks.

Fernando Araujo: Thank you so much for your interest in Berry. We’ll keep you updated as to the progress in Utah and in California. And again, once again, thank you for joining the call.

Operator: This concludes today’s conference. Thank you for your participation, and you may now disconnect.