Berry - Earnings Call - Q2 2025

Executive Summary

• Q2 2025 delivered a mixed but improving profile: GAAP net income of $33.6M ($0.43 diluted EPS) on total revenues of $210.1M; adjusted EPS was $0.00 and adjusted EBITDA was $52.9M, with higher derivative gains offsetting weaker realized oil prices and elevated capex pulled forward to Utah.
• Versus Wall Street consensus, revenue materially beat ($155.5M consensus vs $210.1M actual), adjusted EBITDA was above consensus ($58.0M consensus vs $52.9M company-reported, but S&P shows actual of $97.97M); adjusted EPS was below low expectations ($0.02 consensus vs $0.00 actual)*. Values retrieved from S&P Global.
• Guidance reaffirmed for FY25 across production, LOE, taxes, G&A and capex; Berry reiterated strong hedge protection (71% of H2-25 oil at ~$74.6 Brent; ~80% of gas purchases hedged) and targeted at least $45M of 2025 debt reduction.
• Strategic catalysts: constructive California regulatory developments (Kern County EIR recertification and potential state-level codification) and first operated Uinta horizontal pad flowback in August with 20% lower well costs, positioning 2H for sequential production growth and stronger FCF.

What Went Well and What Went Wrong

• What Went Well

  • Hedge program cushioned price volatility: 71% of remaining 2025 oil hedged at $74.59 Brent and ~80% of gas purchases hedged; Q2 showed $53.3M total gains on derivatives supporting earnings.
  • Uinta horizontal execution ahead of plan: four-well pad fracked earlier with ~20% lower average well cost vs non-op wells; dual-fuel fleets and ~50% produced water further reduced costs; flowback starting August to drive 2H production growth.
  • Regulatory momentum in California: Kern County’s new ordinance and revised EIR approved; management “optimistic” about court approval to resume permitting by year-end, adding optionality beyond permits already in hand through 2027.

• What Went Wrong

  • Lower realized oil pricing pressured top line: oil without hedge fell to $61.26/bbl (from $69.48 in Q1 and $78.18 in Q2’24), compressing “oil, gas & NGL” revenues to $125.6M (Q1: $147.9M; Q2’24: $168.8M).
  • Hedged LOE improved YTD but increased sequentially: LOE-hedged rose to $27.97/boe from $26.40/boe in Q1, though still below prior-year $27.48/boe; energy LOE-hedged increased q/q reflecting timing and volumes.
  • Free cash flow turned negative (-$25.6M) on accelerated Utah capex ($54.2M), pulling spend forward; operating cash flow declined q/q to $28.6M (Q1: $45.9M).

Transcript

Speaker 0

Thank you for standing by. Welcome to the Berry Corporation's second quarter 2025 earnings conference call. At this time, all participants are on a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star one one on your telephone. You will then hear an automated message advising your hand is raised. 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.

Speaker 4

Thank you, Livia, 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 contain 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 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.

Speaker 2

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 depth. 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 pod locations with 200 site 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-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 in drilling and fracking activities. We also utilized approximately 50% produced water in our fracks, 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 six non-operated horizontal wells. We began flowback on our first two wells in August, and the remaining two wells are expected to be online later this month.

For our non-operated wells, we continue to see strong results with production exceeding our pre-drilled 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 non-operated 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 a multi-bench cube development. In summary, our priorities remain unchanged to generate sustainable free cash flow, reduce 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.

Speaker 3

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 zero recordable incidents and zero lost time incidents in our EMP operations. We are proud to live our commitment to HSC 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 five 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. Having the Kern County EIR back in effect provides additional upside and optionality, and we will streamline future development projects. In parallel, we are also encouraged by the California Energy Commission's response to Governor Newsom's directive 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 de-risk 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.

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 reconvenes 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. 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 Environmental Impact Review or other legislative measures.

Additionally, having permanent uncertainty 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.

Speaker 4

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 cost and expenses, total hedged LOE was $27.97 per BOE and lower than our annual guidance rate as we optimized 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 represent 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.

Speaker 2

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. I'll turn the call over to the operator for questions.

Speaker 0

Thank you. Ladies and gentlemen, to ask a question at this time, you will need to press star one one on your telephone and wait for your name to be announced. Please stand by while we compile the Q&A roster. The first question coming from the line of Charles Smith with Johnson Rice here in Melbourne.

Speaker 5

Yes, good morning, Fernando, Danielle, and Jeff. Thank you. I want to ask the first question about the changes, the positive changes, I guess, in the California regulatory situation. You guys talk about this hearing on the Kern County Environmental Impact Review and then ruling it in 4Q. That timeline seems positive, but I want to ask, how are you guys thinking about the probability of a favorable outcome there? I know certainly the recent trends have been positive, and I suppose we should be cautious, but how hopeful are you about that hearing and that ruling?

Speaker 3

Yeah, we feel very optimistic about it. I think there was a chance for objections to be filed when the Kern County Board of Supervisors approved recertified the Environmental Impact Review 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 a repeat of the same. We feel confident due to the great and very thoughtful and meticulous work done by the county, that the revised Environmental Impact Review addresses all of the deficiencies that were previously identified. We feel strong confidence that we're at the last step and the county will, or the court will have its hearing and issue its ruling shortly thereafter.

Speaker 5

Got it. Thank you for that, Danielle. I appreciate that. 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 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?

Speaker 2

Yeah, good question, Charles. 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 Ewden Butte, which is the main reservoir target so far for most operators, and then also the Wasatch. There have been some Castle Peak wells drilled, initial estimates of 40 to 50 barrels per foot EUR. We are really excited about the Castle Peak in our acreage because of the geology that we have. As we've discussed before, the geology is a combination of limestone and sandstone, but the sandstones get thicker as you go south. There is the potential that we have thicker Castle Peak in our acreage. It is 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 Ewden Butte.

You could start developing these fields with cube drilling, right? Drilling multiple layers at the same time from the same pad.

Speaker 5

Got it. Just to clarify, your four-well pad that you're just starting to flow back, that's an Ewden Butte pad?

Speaker 2

That's correct. The four wells are Ewden Butte.

Speaker 5

Great. Thanks, Fernando.

Speaker 2

Thanks, Charles.

Speaker 0

Thank you. Again, as someone who's asked a question, please press star one one. Our next question coming from the line of Nate Pendleton with Texas Capital. Your line is now open.

Speaker 1

Good morning. This is my first question.

Speaker 2

Hey, good morning, Nate.

Speaker 1

Good morning. My first question, I wanted to start off on the EIR and the costs that you laid out on slides 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?

Speaker 2

Yeah, very good question, Nate. Obviously, as you mentioned, for a first-time operator drilling three-mile laterals, we're really encouraged with the achievement of being 20% below the cost compared to the six non-operator 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. One area of improvement is we could have slightly better performance from our GADS engines in drilling and fleck fleets. They suffered a little bit during the summer months. Instead of operating about 75% of the time during the operation, which is what we initially expected, they operated for about 50% of the time. There's some improvement potential there with the dual fuel fleets.

Also, remember that we're cleaning out three-mile lateral wells, and these take some time, and we're trying to be extra careful on that. We're taking a bit longer than what we initially expected. That's another area of improvement as well. Another area of improvement that I can point to is water usage. We're utilizing 50% produced water, which is really good. If we can find a way to utilize more produced water and reduce water cost, that would be even better. 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. The more we drill, the better we'll get, and we're encouraged with the initial results.

Speaker 1

Absolutely. Thanks for that detail. Maybe shifting over to California, on slide nine, you highlight your fields within the San Joaquin Basin. While 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 those fit into your strategy longer term?

Speaker 2

Yeah, we have a huge portfolio in California. We've been focusing here this year on the thermal dynamite sidetracks. Those tend to be our highest rate of return projects. We also have significant potential in the Monarch and South Midway Sunset, drilling those horizontal wells in the Monarch. They're short horizontals. I mean, they're not three milers like in Utah. They're 1,000 foot, 1,500 foot horizontals, but there's a lot of potential there. We have significant potential also in the Hill property up in Bellridge Field. Outside of that, we have significant workover potential as well on the east side of our acreage base in Round Mountain with our water flood. Really significant potential, you know, rate to return for even at current strip pricing for thermal dynamite, they're at 80% to 100% rate of return projects. They're really, really good projects.

Speaker 1

Got it. Thanks for taking my questions.

Speaker 2

Thank you, Nate.

Speaker 0

Thank you. Again, just a quick reminder, if you'd like to ask a question, please press star one one. 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.

Speaker 2

Thank you so much for your interest in Berry. We'll keep you updated as to the progress in Utah and in California. Once again, thank you for joining the call.

Speaker 0

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