TWST: Let’s start with an introduction of sorts to Berry. The company has a more-than-100-year history, but could you review the important points in its recent history, as well as an overview of the company’s assets and operations today?
Mr. Araujo: We’re an upstream energy company operating conventional onshore assets in two mature basins with predictable geology. Our assets have low decline rates, and this gives us a competitive advantage compared to other basins. Our assets have significant inventory of development opportunities, which gives us the potential for growth. So, one of the strengths that we have as a company truly is the quality of our assets.
We currently operate in two basins, in California and in Utah. We produce oil from the San Joaquin Basin in central California, and as you may know, this is one of the great oil basins in the world. This is a basin that has some of the highest oil in place per acre in the world, and Berry has successfully produced oil and gas from the San Joaquin basin for over 100 years.
We also produce oil and gas from the Uinta Basin in Utah. This is another mature basin with low geologic risk. There we currently operate about 1,200 wells from five different reservoirs across our 100,000-acre footprint. In Utah we also have significant oil and gas infrastructure. About 20% of our total production comes from Utah.
We’re really excited about Utah, especially because of the potential development we have with horizontal wells, which is something that we have not done. Our neighbors are having very encouraging results drilling horizontal wells. In fact, in the second quarter of 2024, we farmed-in four horizontal wells in acreage adjacent to ours, and the results are very encouraging, better than pre-drill estimates.
We have a big hydrocarbon column in Utah, a 2,000-foot hydrocarbon column, stack-based. So, we have the potential to develop with horizontal wells in four or five different reservoirs.
Getting back to Berry as a whole, I do want to highlight that over the past six years or so we’ve kept production flat, net of divestments. This is more impressive than it may sound when you realize that during that same time, overall production in California has dropped by 40%. We’re the only company in California that has kept production flat during that time.
I also want to highlight that because of the great assets that we have, our projects have very attractive full-cycle economics, especially in California. In California, because of the shallow nature of the reservoirs, we can drill and complete a well for about $500,000. The economics that we get from those wells are excellent — in a lot of cases, north of 100% rate of return.
It’s very hard to compete with California economics. And because of that, we’re able to sustain production with low capital intensity projects, so that’s an advantage that we have.
The other advantage that we have in California is the fact that we’re indexed to Brent pricing, and that gives us an attractive pricing advantage. So, we’ve been delivering great results, and we’re looking forward to a great 2025.
We also have a service company, C&J Well Services, in California, where we provide well maintenance and P&A services to Berry and other producers in California. But this is a very small part of our overall business.
TWST: The company’s roots were in California for many decades. When did Berry expand into Utah?
Mr. Araujo: The company has a long history, mostly as a private company. The company has over 100 years of production in California. It went through several cycles, including a time when it was bought out by a company called Linn, and then they went bankrupt. The new version of Berry really started in 2017 with Trem Smith and his management team. I came into the company in 2020, so I’ve been with the company for just over four years, and I’ve been the CEO here for the last couple of years.
The company acquired the Utah assets back in 2003, so we’ve had the Utah assets for over 20 years now. We’ve had the California assets, in some cases, for over 100 years.
TWST: Can you give us more details that would be helpful for readers about your current production levels as well as future development potential and opportunity?
Mr. Araujo: We currently produce close to 26,000 barrels a day. As I mentioned before, about 80% of that production is in California, about 20% of that production comes from Utah. Most of our production is oil; about 94% of our total production is oil, the rest is gas, and the gas production that we do have is in Utah.
We have great development opportunities in both basins. In Utah, we’re very excited about the potential development with horizontal wells. As I mentioned before, our neighbors are having very encouraging results, as we are with the farm-in that we talked about earlier, which started in 2024. Our goal is to accelerate the appraisal phase and de-risk our acreage position. Again, we’ve got 100,000 acres; about 90% of it is held by production.
We’re doing a couple of things to de-risk our Utah acreage. One is, we entered another farm-in to drill an additional 12 horizontal wells in the Uteland Butte reservoir over the next 18 to 24 months. We’ve already drilled two of those wells, and they’re under completion now, and they will be on production in January. Another six wells are expected to be drilled in 2025, and the rest of the wells will be drilled in 2026.
At the same time, we want to be able to drill our own wells. For that, we are in the process of looking for an ideal JV partner to help us mitigate the capital expenditures required to drill some of these horizontal wells, because we want to be consistent with our disciplined capital strategy and financial policy, which is to deliver positive free cash.
Because of that, we are looking for a JV partner for the 2025 and 2026 drilling programs, and we’re currently in the process of doing that through Petrie Partners. We should be able to make an announcement on who that will be in February. We want to start drilling horizontal wells in Utah before the end of Q1 2025. So, we’re really excited about that.
The potential development that we have in Utah is tremendous. It truly could be transformational for the company. Based on the acreage that we have, and based on the current spacing of horizontal wells being drilled, just taking into account one reservoir, we could easily drill over 200 wells in the acreage that we have. That’s many years’ worth of drilling activity.
Another thing I want to say about Utah is that we have a significant cost advantage in the play. To begin with, we’re there already, so we don’t have to pay to get into the play. Second, we are in the shallow end of the basin, so it’s a little bit cheaper to drill wells there than in other deeper parts of the Uinta Basin. Plus, we have significant infrastructure in place, both oil and gas infrastructure, to be able to tie in our wells.
And then, in terms of completions activity, we will be able to reduce our completion costs in relation to other producers, mainly because we have oil and gas infrastructure in our fields, and we’re going to be using gas to fuel a lot of the frac equipment, so that’s going to be a significant source of savings. We expect to drill and complete wells about 20% less than the average cost in the basin, so that’s a significant advantage.
Again, the potential that we have in Utah is tremendous, and it could be transformational for the company.
Now, let’s talk about the activity and the potential for growth that we have in California. We have significant potential in California. In 2024 we focused on drilling wells in the Diatomite reservoir, with great results. We drilled 20 or so wells in the Diatomite reservoir, with rates of return in excess of 100% from those wells.
And we have a deep inventory of those wells. These are mainly sidetracks; sidetracks are wells where you’re utilizing existing wellbores, but you’re sidetracking to your target reservoir. We’ve got enough sidetrack inventory for the next three or so years in the Diatomite reservoir.
The Diatomite reservoir is a very thick reservoir, about 300 feet in thickness, with very high porosity, so it holds a lot of oil. Again, it has some of the highest oil in place per acre in the world.
We’ve been able to successfully work with the Diatomite over the last several years. In fact, from 2019 to 2023, we didn’t drill any wells in the Diatomite reservoir, but we did workovers and recompletions, and we optimized our injection strategy, and without drilling any wells, we were able to increase production by about 19% in that asset. It’s a really, really good asset.
Now we’re focusing on the drilling activity in the Diatomite through sidetracks, and that’s going to be a big part of the 2025 plan in California.
So, between what we have in Utah and the potential that we have in California, we expect to keep production essentially flat for the first half of next year, but we expect to have single-digit production growth in the second half of the year. We’re really excited about the activity and the potential opportunities that we have in both California and Utah.
TWST: Are acquisitions in the mix of potential growth?
Mr. Araujo: Part of our daily business is pursuing growth opportunities, especially through accretive, producing bolt-ons in both California and Utah. As you may know, in 2023 we acquired a company, Macpherson Energy, in California, and it was a very successful acquisition. Soon after we acquired those assets, we were able to reduce operating expenses by about 40%. These are assets that are sitting right next to our existing fields.
So, we have opportunities like that in California. In California we’re focusing in Kern County, which is where we have 100% of our production, and in places where we can truly realize operational synergies like we did with Macpherson in 2023.
There are a handful of opportunities in California, a handful of small private producers that are now willing to have a conversation about the possibility of transacting. These are companies that years ago were just generating a lot of cash, and they were not really interested in doing anything. But nowadays, in the life cycle of the ownership of the companies, they’re now willing to have a conversation, and we’re having those conversations.
So, we have a handful of those bolt-on opportunities in California, as well as in Utah. In addition to that, we’re always in conversations to pursue other opportunities in other basins, in places where we can capitalize on our strengths and our expertise and bring additional value to the assets.
Generally speaking, we’re always looking for producing assets that align with our strategy, which is to enhance our ability to generate free cash flow sustainably.
So, we’re in conversations all the time with different players, but the ones that we’re focusing on a little bit more lately are the bolt-ons. One thing about the bolt-ons is they give us the opportunity to acquire these bolt-ons as a capital reallocation exercise. Instead of drilling wells, we buy production at a better capital efficiency. That’s something that we’ve done in the last couple of years.
TWST: What specifically is the company doing to enhance production and maximize revenues? Are there particular technologies or equipment or methodology advancements?
Mr. Araujo: You know, the beauty of our assets in California is that they’re steam-flooded reservoirs, and we’re probably the premier steam-flooded company in California. We get really excellent results by doing detailed surveillance in all of the reservoirs that we operate. There’s really not a magic bullet to what we do, it’s just drilling in places where we see the potential to have significant economic production, and we’ve been doing that for years and years.
Now, in Utah, it is going to be different in that these are going to be horizontal wells. We’re going to be drilling three-mile lateral wells and fracking these wells 60, 65 times. That’s a different technology, but it’s a technology that is very successful and is getting applied every day in the Uinta Basin right next to us. So, it’s really nothing new, but it will provide a significant avenue for growth, both in production and in cash flows.
TWST: You mentioned earlier being indexed to Brent pricing. Would you tell us more about that, about how the dynamics and sometimes volatility of commodities pricing affect your revenues, and how you manage that?
Mr. Araujo: First let me tell you why we’re indexed to Brent in California. As you may know, California is an energy island. There are no oil pipelines that come into or out of California, and this creates some interesting market dynamics.
To begin with, the demand for oil in California is pretty constant; it’s not dropping, if anything it’s increasing slightly. But at the same time, as I mentioned before, production in California has dropped close to 40% in the last six years.
Currently, about 77% of the oil demand in California is imported through tankers from places like Saudi Arabia or the rainforest in South America, which doesn’t make any sense to me. But with imports increasing, the ports of L.A., the ports of San Francisco, the ports of Long Beach, they’re reaching capacity. Obviously, this dynamic is not sustainable.
California needs local production now and into the future, and there’s really no other short-term alternative. We want to be part of that energy solution for California. We want to be able to deliver affordable and reliable energy to California. So, because of the fact that we do have this energy island and we are independent of the rest of the U.S., we’re not indexed to WTI like the rest of the U.S., we’re indexed to Brent.
Now, how do we mitigate the fluctuations in pricing, generally speaking? We do that by hedging. Normally about 75% of our production in a given year is hedged, and we’re required to hedge according to our RBL regulations. We are required to hedge our production 75% of PDP the first two years and 50% of PDP production in year three. But in a given year, we normally hedge 75% to 80% of our total production.
So, we protect our future cash flows by hedging, and protect from fluctuations of oil pricing by hedging.
TWST: You also mentioned earlier the well servicing business segment. How much of your overall focus and revenues does this account for? What’s the importance to your overall business?
Mr. Araujo: C&J Well Services is the name of our service company. In 2023, it was about 9% of our total EBITDA. We offer maintenance services to other operators in California, and also P&A services to other operators in California, as well as ourselves.
The beauty of that business line is that with regulations in California enhancing the operators’ commitment to abandoning wells, abandonment activities in California will increase over the next few years, so the potential opportunity for growth in that segment is significant because of the number of idle wells.
In California there are about 30,000 idle wells operated by different players, including the state for orphan wells, and all these wells will need to be abandoned. We want to be the company of choice to abandon a lot of these wells. So, there’s the potential for growth in that segment over the next few years because we are in California.
TWST: I know it’s too early to discuss your year-end results, but would you point out the key takeaways from your third quarter?
Mr. Araujo: Third quarter production averaged 24,800 BOE per day, with production increasing at the end of the quarter as additional wells were brought online. Annual 2024 production is expected to reach the mid-point of guidance of 24,600 to 25,800 BOE per day. We increased free cash flow 55% quarter over quarter, and declared third quarter fixed dividends of $0.03 per share.
Production in Q3 2024 was flat to where we were in 2023, and we generated significant EBITDA and free cash. We recently put out some production numbers from January through November 2024, with a production average of 25,400 BOE per day.
That is going to be the theme as we head into 2025 — maintaining production with significant, sustainable free cash flow generation. We have built a plan that will continue in 2025 to have sustainable free cash flow generation as a core priority. As I mentioned before, we expect to have flat to low-single-digit production growth for the second half of the year, and fairly flat in the first half of the year.
In terms of capital expenditures for 2025, we expect to be slightly higher than in 2024. We’re going to be in the $105 million to $125 million range in 2025. A lot of that increase is related to Utah.
Of the total capex in 2025, about 60% will be allocated to California, and about 40% will be allocated to Utah. Compare that to 2024, when it was about 25% Utah, 75% California. So, we’re going to be enhancing our capital commitments to Utah in order to drill the horizontal wells that we talked about earlier.
But 2025 is going to be another year when we expect to have strong free cash flow generation. In fact, over the five years prior to 2024, we generated over $1 billion in cash flow from operations. During that same time, we generated about $400 million in returns to shareholders. We expect to continue providing returns to our shareholders in the coming years through our recently revised fixed dividend along with debt reduction.
TWST: In December the company completed a debt refinancing. Tell us about this transaction and what it means for Berry’s liquidity and general financial position going forward.
Mr. Araujo: Yes, we signed a new $450 million term loan agreement that allowed us to pay off our notes that was due in February 2026. At the same time, we also put in place a new RBL facility, which was led by Texas Capital Bank, with a total borrowing base of $95 million, which is good. The term loan agreement is a three-year term, and we have the option for an additional two years after that. The RBL is a three-year agreement.
But the beauty of this loan agreement, to begin with, is it was fit for purpose, in that one of the key elements it has is that we’re able to take out the loan at par in the first two years, which is very good. It gives us more flexibility, especially on the M&A side of the business. At the same time, the loan agreement ensures that we have capital and liquidity to be able to execute on our development plans, both in Utah and California, which will allow us to unlock significant long-term shareholder value.
We’re going to be able to sustain our production levels and have the ability to have the capital necessary to be able to do that, and that, in the end, will help us with our plans to pay dividends and reduce our debt.
TWST: You’ve been CEO for the past two years. What is your focus for the next couple of years? And how do you see guiding the company’s corporate strategy for the future beyond that, especially in light of a broader transition in our energy sources, including renewables? What does that mean for your strategy, your focus, and the company’s future?
Mr. Araujo: Our strategy is fairly simple, and that is to create long-term value by capitalizing on the long history that we have operating the great assets that we have.
It’s really underpinned by three important pillars. The first pillar is the quality of the assets that we talked about — the truly world-class assets that we have, that give us the ability to sustain our production levels. Number two is our 100% commitment to health, safety, and full compliance. And number three is our pursuit of strategic growth opportunities.
That could be organic, as in the case of Utah with the potential that we have for transformational growth there, or it could be through M&A activity, and through M&A activity it could be through the bolt-ons that we talked about or other bigger transactions.
At the end of the day, we want to be able to generate sustainable free cash flow year after year after year, just like we’ve done in the past.
In terms of our ESG strategy, we have a couple of things that we’ve worked on. In 2024, for example, we were able to reduce our methane emissions by 80%. We did this by replacing our gas pneumatic devices in Utah with air compression devices. We spent about $2.5 million doing this to reduce our methane emissions, but this is going to deliver some cost savings in the future under the new EPA emission charges.
At the same time, we are in conversations with players in California to be able to deliver our CO2 emissions to certain carbon capture projects in the works close to where we are. The plan for us is not to have our own project, just because our footprint is too small and we’re too small of a company to get into that business, but we do want to work with the companies that do have carbon capture projects and deliver our emissions to them.
And then, through our C&J Well Services business, we abandon about 2,000 wells a year on average. In California, a lot of the methane emissions that we have are from idle wells, so by abandoning a lot of these wells, we are able to reduce methane emissions or fugitive emissions from wells in California.
TWST: Is there anything else you want to include or anything you want to emphasize to wrap up?
Mr. Araujo: Why is Berry a good investment? I want to touch on that.
To begin with, as I’ve mentioned throughout the call, we have consistently delivered sustainable free cash flows and consistently created long-term value for the company. We have been able to keep production flat over the last six years, net of divestments, the only company in California to be able to do that.
At the same time, we’ve generated over $1 billion in cash flow from operations in the five years prior to 2024, and returned $400 million to our shareholders in that same period. We have world-class assets, and we’ve managed those assets for many years very successfully, with operational excellence.
We have significant growth opportunities in both basins where we operate, in California and in Utah. A lot of the projects that we have in both California and Utah are very attractive in terms of full-cycle economics, and could provide the potential for transformational growth for the company, especially in Utah. We are also pursuing diversification and scale to enhance that ability to generate sustainable free cash.
It’s a very exciting time to be where we are at Berry. We expect to have a great 2025, and we expect to have a great future beyond that.
TWST: Thank you. (MN)