U.S. Energy Corp. Aktie

Good morning, and welcome to U.S. Energy Corp.'s First Quarter 2026 Earnings Conference Call. [Operator Instructions] Today's call is being recorded, and a replay will be available on the Investor Relations section of the company's website at usnrg.com.

Before we begin, I would like to remind everyone that today's discussion will include forward-looking statements within the meaning of the federal securities laws. These statements are based on management's current expectations and are subject to risks and uncertainties that could cause actual results to differ materially. Please refer to the company's most recent SEC filings included in the Form 10-Q filed today and the Form 10-K for a discussion of these risks. Statements made on this call speak only as of today, and the company undertakes no obligation to update them.

Joining us this morning are Ryan Smith, President and Chief Executive Officer; and Mark Zajac, Chief Financial Officer. I will now turn the call over to Mr. Ryan Smith.

Thank you, Mason, and good morning, everyone. Thank you for joining U.S. Energy's First Quarter 2026 Earnings Call. I appreciate your time. And more importantly, I appreciate the engagement we've had with so many of you over the past few months as our story has come into clearer focus.

I want to start by framing what this quarter actually represents because the context matters for how investors should evaluate our reported results. The first quarter reflects a company in the middle of a deliberate transition. We've intentionally divested noncore legacy oil and gas assets. We have intentionally redirected the proceeds into the largest organic development project in our company's history. And we've intentionally accepted near-term financial optics that don't reflect the legacy E&P business because the U.S. Energy of 2027 and beyond is not a legacy E&P. It's an integrated industrial gas, energy and carbon management platform anchored by one of the most distinctive geologic assets in the country.

So while the headline numbers reflect the company in the build phase, we believe the business is more clearly positioned around Big Sky than at any point in this transition. In the past 90 days alone, we have reached final investment decision on our Big Sky Carbon Hub processing facility, executed a fixed-scope EPC contract with CANUSA, completed our Phase 1 cap stack through a March equity offering and an expanded senior secured credit facility, formally suspended our equity line of credit and signed a 5-year 100% take-or-pay helium offtake agreement with an investment-grade global industrial gas counterparty.

Each of these on its own would be a meaningful catalyst. Together, they materially advance U.S. Energy's transition from a legacy E&P company toward an integrated industrial gas, energy and carbon management platform.

I'd like to walk through this morning in four parts. First, the operational and strategic progress at Big Sky; second, the helium offtake and what the broader industrial gas and carbon market backdrop means for us; third, our capital structure, where Mark will take a few minutes; and fourth, the path from here, near-term catalysts, Phase 2 and the value creation opportunity ahead.

Let me start with operational progress because this is where the work gets done. On March 18, we announced final investment decision on the Phase 1 processing facility at the Big Sky Carbon Hub and executed a fixed scope engineering, procurement and construction agreement with CANUSA EPC, an experienced engineering firm with a track record in gas processing and energy infrastructure. This was the pivotal milestone that moves us from a development stage project to a project under construction. Capital is now flowing into the project. Long lead equipment is on order. The plant is designed for approximately 8 million cubic feet per day of inlet capacity, targeting roughly 14 million cubic feet of high-purity helium and approximately 125,000 metric tons of refined CO2 per year at initial operations. Commercial operations remain targeted for the first quarter of 2027.

I want to be very specific about what FID actually means at U.S. Energy because in our part of the market, the term is sometimes used very loosely. For us, FID was supported by completed engineering, completed permitting, a fixed scope EPC contract with a credible counterparty, a fully funded Phase 1 cap stack and a contracted helium offtake. That is the institutional standard, and we hold ourselves to it.

On the field side, drilling and completions wrapped in August of 2025 with 3 successful drilled wells plus 2 that we acquired. Two Class II permitted injection wells, which are the standard wells used for CO2 injection in oilfield operations are operational. Gathering infrastructure installation is scheduled for this summer with facility commissioning targeted for the third quarter and first gas through the plant in the first quarter of 2027. The modular plant design materially limits on-site complexity, which is one of the reasons we have confidence in our schedule and budget.

On the regulatory side, both of our monitoring, reporting and verification submissions at Big Rose and Cut Bank are in active EPA review. Based on our interactions to date, we have not identified any material issues, and we continue to expect approvals during the summer of 2026. These approvals are required to access the Section 45Q tax credit framework that underpins approximately $130 million of credit value over the first 12 years of Phase 1 operations alone.

I want to pause on that number for a moment, $130 million in federal tax credits from a single Phase 1 facility for a company with a market capitalization that is a fraction of that figure. That represents a policy-backed commodity independent revenue stream that sits underneath everything else that we're building. And under the Inflation Reduction Act, the 45Q credit at $85 per metric ton has bipartisan support and is currently available for 12 years for projects that begin construction before the year 2033.

Our base case uses today's rate and any future enhancement is pure upside. With that foundation in place, I'd like to now turn to our recent helium commercial agreements, which underpins our initial revenue profile. On April 27, we announced the execution of a 5-year helium sales agreement with an investment-grade global industrial gas company, a leading helium distributor, for the sale of contained helium produced at Big Sky. The contract is structured as 100% take-or-pay over a 5-year initial term. Phase 1 capacity is up to 1.2 million cubic feet per month or roughly 14.4 million cubic feet per year at a fixed plant gate price of $285 per Mcf with CPI-linked escalation beginning March 1, 2028, and a year-3 pricing redetermination that preserves upside.

I want to be very direct about what this contract does. It eliminates volume risk, it eliminates demand risk and it establishes helium as the initial contracted day 1 revenue stream of our multi-revenue platform, and it converts what was until April, a commercial assumption into a signed agreement with an investment-grade counterparty. It also says something about how the broader market views our asset. Investment-grade industrial gas companies do not sign 5-year 100% take-or-pay agreements with development-stage projects without extensive technical and commercial diligence. This is, in effect, a third-party validation of the Big Sky resource, the development plan and our ability to execute.

Now let me put this in the context of the broader market because the macro backdrop for what we are building has gotten more favorable since we set out on this path. Global helium supply remains structurally constrained. Geopolitical disruption, including ongoing instability in the Middle East and uncertainty around long-term supply from Russia, Algeria and Qatar has tightened an already tight market. Helium is a nonsubstitutable critical input for semiconductors, MRI machines, fiber optics, aerospace and the entire AI data center build-out. Demand is inelastic and domestic supply is limited.

Our pricing of $285 per Mcf, while excellent, is, in our view, conservative relative to current market dynamics, which is why we incorporated a potential 3-year reprice into our offtake agreement. And crucially, U.S. Energy is an American domestic producer of a critical industrial gas with all the policy tailwinds that implies.

Beyond helium, the carbon management side of our business is equally important. Section 45Q has bipartisan support and was reaffirmed and extended under the IRA. The market for carbon management services is forecast to grow more than 145x from 2023 captured volumes to 2050. Today, there are roughly 20 operational CCUS projects in the United States. We will be the 17th largest by capacity. And uniquely, we are the first U.S. project that does not depend on natural gas processing, ethanol fermentation, ammonia, power generation or direct air capture as the source of CO2. Our CO2 is the byproduct of helium extraction. There is no combustion, there's no fermentation. There's no energy-intensive capture step. That is a structural cost advantage that very few projects in the world can claim.

And that in turn connects directly to how we're approaching the remaining oil business. Cut Bank continues to provide low decline established cash flow that supports the platform build-out. But more importantly, Cut Bank has approximately 70 million barrels of incremental recovery potential through phased CO2 enhanced oil recovery with feedstock supplied internally by Big Sky, eliminating third-party CO2 supply risk.

Our 170-plus permitted Class II injection wells provide a low incremental CapEx path to a multi-decade production tail. We have approached the oil business with discipline. We're not adding incremental rigs or chasing growth for growth's sake. We're using Cut Bank as the captive CO2 outlet that completes our integrated value chain. With that operational and commercial picture in place, I'd like to turn it over to Mark to walk through the capital structure, where we've made significant progress this quarter.

Thanks, Ryan, and good morning, everyone. I want to keep my remarks focused on the capital structure because that is where the most consequential financial work has happened this quarter. There are 3 pieces I'll cover, the Phase 1 capital stack, the equity line of credit and the path forward. First, the Phase 1 capital stack is now complete. In March, we executed an equity offering that brought in capital needed to fund development and strengthen the balance sheet. On April 20, we amended our senior secured credit agreement, doubling the borrowing base to $20 million, fixing the interest margin at 200 basis points over the alternative base rate and importantly, suspending quarterly financial covenant testing through the fiscal quarter ending March 31, 2027.

The facility allows revolving borrowings through its May 31, 2029 maturity with no prepayment penalties. These are favorable terms for a project under construction, and they provide the flexibility to execute construction without covenant pressure during the build phase. This capital stack will take us through completion of Phase 1 and into revenue generation.

Second, on the equity line of credit, we have not drawn on the ELOC since March 2 and concurrent with the closing of the expanded debt facility, we have formally suspended further use of the ELOC. We took this step deliberately to address a perceived dilution overhang associated with the facility. The message is clear, the equity capital structure is set for Phase 1 and the focus from here is execution, not further dilution.

Third, the path forward as we transition from Phase 1 build to Phase 1 operations and begin positioning for Phase 2, the multistream nature of our platform opens capital avenues that were not available to us as a legacy E&P. Project finance debt becomes more accessible as we derisk through our MRV approvals and contracted offtake. The 45Q tax credit stream itself becomes a financeable asset, either through a transferability or a structured monetization, representing a potential nondilutive capital source not currently in our base case.

Longer term, our existing senior secured facilities are appropriately sized today. We expect to transition to a larger longer-dated facility as revenues and credit profile matures. From a near-term liquidity standpoint, we have the capital we need to deliver Phase 1 into commercial operations in the first quarter of 2027. From here, the focus on capital side is optimization and prepositioning rather than funding the build.

With that, I'll hand it back over to Ryan.

Thanks, Mark. Let me close with how we see this path forward because I think this is where the gap between intrinsic value and where the stock trades is most apparent.

Looking out over the coming quarters, we have a sequence of identifiable independent derisking events. MRV approvals are anticipated this summer, Gathering and EOR prep installation is scheduled across this summer and fall. Plant commissioning is targeted towards the end of 2026 with first gas and first revenue in the first quarter of 2027. And alongside the operational catalysts, we are beginning to advance commercial discussions on direct merchant CO2 sales, a second monetization path beyond sequestration credits and one we believe could meaningfully enhance unit economics with very modest incremental capital.

Beyond those near-term milestones, the next layer of value is in how the platform scales. Phase 2 is the first step in that scaling, and it is entirely excluded from our base case financial model. Phase 2 is a second processing plant on the same footprint, leveraging the same infrastructure, the same regulatory approvals, the same field operations and the same commercial relationships. Our acreage, our permitted wells and our geology already support 2 to 3x the Phase 1 capacity with no new land and no new approvals.

Because the heavy lifting is already done, the incremental capital required to execute Phase 2 is meaningfully lower on a per unit basis. And as our credit profile matures and the asset derisks, we would also expect the cost of capital to improve. When you compound these two effects, lower per unit CapEx and a lower cost of capital across a second standardized unit, the project economics become quite compelling. Our internal modeling supports project NPV that is multiples of where Phase 1 stands today and equity returns that fundamentally rerate the company.

Alongside that operational scaling, there is also a financial dimension to how value can be realized. I mentioned $130 million of 45Q credit value across the first 12 years of Phase 1 operations. Under current rules, those credits are transferable. We have a credible pathway to monetize a significant portion of that stream ahead of the underlying schedule, either through a transferability transaction or a structured credit sale. That is a nondilutive capital acceleration that, again, is not in our base case.

We are working that work stream now, and we will share more as transactions advance towards execution. When you step back, those operational and financial elements ultimately shape how the market should evaluate this business.

I'd like to close with a candid observation about valuation because it gets to the heart of why we made the strategic pivot in the first place. Small-cap E&P companies trade at roughly 3x trailing EBITDA in today's market. Small and mid-cap midstream and gas processing companies have traded roughly 8x. Blue-chip industrial gas companies trade at roughly 17x or significantly higher than that. Those are not our forecast. Those are public market multiples that anyone can verify. Once Phase 1 is operating, U.S. Energy is no longer a small-cap E&P. We're an industrial gas producer with a contracted offtake, a regulated carbon management business with policy-backed revenue and a low-decline oil business that is integrated into the platform as the captive CO2 outlet.

We don't need every part of that re-rating to happen for shareholders to do very well from here. Today, we trade at a meaningful discount to our internally calculated Phase 1 NAV against a forward EBITDA multiple that is well below where any of those referenced categories trade. The arithmetic of closing even a portion of that gap is very significant. Our job between now and Phase 1 commissioning is to keep executing the operational and commercial milestones that allow the market to make that re-rating.

To put a fine point on the quarter, we reached FID, we executed our EPC. We completed the Phase 1 cap stack. We signed a 5-year take-or-pay helium offtake. Construction is underway. The commercial operations countdown is months and not years. And the macro backdrop for helium for carbon management and for American energy production has rarely been more favorable than it is now. I'm more confident in the business plan today than at any point since we set out on this path.

I want to thank our team in Houston, in Montana and across our partner network for outstanding execution this quarter, and I want to thank our shareholders for their continued support and patience as we transition through the build phase into the cash flow phase. We have a tremendous amount of work ahead of us, but the path is clearer today than it ever has been. Operator, with that, please open the line for questions.

[Operator Instructions]

Your first question comes from the line of John Davenport from Johnson Rice.

I wanted to start on the CO2 side. You had mentioned that you're evaluating the revenue stream outside of just the tax credits, and doing some research on our own, we've seen it's -- the spot market for CO2 is trading as high as $900 per ton. So I'm curious what you guys have been evaluating there? Maybe how much of that 125,000 million tons per annum you might sell outside of tax credits and just some more information on that.

John, yes, no, that's a great question. And those numbers that you just laid out are accurate. I think just backing up a little bit, it was very important for us to be able to forecast our base case projections on Phase 1 of this project to what we can control, right? And we can control our helium sales. We can control our carbon sequestration, AKA CCUS activities. We can control our oilfield. So everything that we've talked about, that we've modeled out, that we've underwritten internally to reflects that $85 per metric ton of CO2 sequestration and utilization numbers.

That being said, everything you said is spot on. The end user, call it, whether it's food and beverage grade, whether it's other industrial users, the pricing for that market is robust. The end user, which -- it would be tough for us to distribute to the end users. You'd have to go through a distributor similar to how we do it with helium. But being able to, call it, reallocate that CCUS CO2 into, again, large-scale, long-term investment-grade counterparty CO2 distributor, especially to one of the coasts or the Midwest, the numbers are extremely compelling.

Even if you take that $850, $900 end-use number and cut it in half, right, that's 4 to 5x on a pretty conservative basis of revenue selling into that market. So right now, our initial plant, which we plan on capturing 125,000-plus metric tons a year of CO2 for sequestration and EOR purposes, not all of that CO2 that comes off of that plant is the same. Roughly 2/3 of it is a higher purity CO2 grade, that would need a little bit of incremental capital to kick up that purification for industry and food and beverage.

But 2/3 of 125,000, it's a big number, right? It's about ballpark 80,000 metric tons a year, a little over 200 metric tons a day. So running those numbers at a fairly conservative, $350 to $400 per metric ton price, it's -- I mean, it increases our revenue profile something like three or fourfold right out of the gate. So one thing I think that we're currently working on now is, one, understanding that market and who the big players are similar to our helium offtake. It's very important to me to have the highest quality counterparty on the other side of those transactions.

We've started discussions early stage with a couple of them, and it's something that we're going to pursue heavily in the second half of this year. And then going forward, as we grow the platform from Phase 1 to Phase 2, which would be multiples of Phase 1s getting that CO2 into the end user industrial merchant markets is an absolute goal for us. It takes this from extremely attractive economics to something much, much greater than that if we could accomplish that. So you're spot on. It's an extremely attractive market, similar to helium. It's structurally short in the United States, similar to helium. It goes to industries that are growing and constantly need it. So it's a big focus for us going forward.

Okay. And so if I heard you right, basically, the stream of CO2 that's produced wouldn't be able to go directly to those industrial users. There would have to be some incremental processing before that can happen. Obviously, it would be worth it to get 10, 20x the tax credit price. But that's -- I just wanted to make sure I had that correct.

It would be. It would be either -- it could be two things, right? It depends on the end user and the distributor. It would be either a little bit of extra equipment on our site. I would say nothing overly meaningful, maybe a mid-single-digit capital increase on the whole project or some of the end users have their next stage purification facilities at their distribution sites, whether it's in the Gulf Coast, whether it's in the West Coast, whether it's in the Midwest. So I guess it could be ready for straight distribution. It would really just depend on economics and what the distributor wanted us to do.

Your next question comes from the line of Tom Kerr from Zacks Small-Cap Research.

On the new helium offtake agreement, are you able to talk about the pricing and how that was determined or achieved? Some of the helium spot prices are higher than that, the Middle East conflict have risen prices a little bit. Are you able to talk about how you arrived at that price, the $285, I think.

Yes. I mean I think from a high level, absolutely, and good to hear from you, Tom. Thanks for the question. We had an offtake agreement on my desk to sign for a couple of weeks before the Middle East stuff kicked off. And I don't sign stuff when it shows up the same day. So we kind of set out it for a while, made sure that all the numbers were right. And then either fortunately or unfortunately, all of the stuff in the Middle East kicked off. So we immediately kind of reopened negotiations and pricing. So pricing ended up going up 50-plus percent kind of overnight on the production side, meaning the producers that drill and process and deliver gaseous helium. And -- so I guess, simplistically, like I would call it 50% or so was what was realized by that happening.

I think it's important as part of our agreement to understand that we signed for $285 escalates CPI every year over 5 years, so call it $300 and change over the life of the contract. Our counterparty is coming and picking it up at the plant, and that's our bottom line number that we're getting. Something that you see quite often, I would say, the vast majority of the time is companies that announce their helium pricing are giving a top line number, and they're still responsible for tolling fees for transporting it a couple of thousand miles on their own nickel and those costs are extremely significant.

I've seen ranges from $125 to $175 all in from what is being deducted from the top line price that people announce. So if you're comparing our announcement with, call it, some other announcements out there, I think a more promotional way to think about our price would probably be in the low $400 range from where you've seen other people announce it. Transportation was something that I was very concerned about not taking on that risk on our side. Driving a tube trailer over the Rocky Mountains in the winter was something that it doesn't seem like it has a lot of upside to me with the size of our counterparty and they're just ingrained infrastructure on their level as well as owning all the -- further down the supply chain, liquefaction and distribution capabilities.

It just -- it made a whole lot of sense for us to have them pulling up to our plant a couple of times a month and paying us on the spot. So that's kind of how I would look about price. In regards to term, we had all kinds of choices, options in front of us on term, ranging from 1 year to 10 years. And we settled on 5, as you know, with a revisit pricing after 3 years, which was something that was extremely important to us. And to be honest, I'm not sure we could have gotten it before the Middle East kicks off, right? Like we're optimistic about helium prices going forward.

At some point in time, the Middle East will slow down. Some of these supplies will come back online. But I do believe that all of the -- in the news -- industries, whether it be AI, semiconductors, health care, national defense, aerospace, et cetera, like that demand for helium is not going anywhere, but up and to the right. And I believe the analysis shows that the demand is going to grow significantly more than the supply options both on a global basis and then extremely more on a domestic basis.

If the Middle East tensions that have happened over the last few months have shown both the end users and the distributors anything, it's that a molecule of helium coming from the United States is worth a whole lot more than something coming from Qatar, Russia or Algeria. So I think there's kind of a 2-step value thesis on helium going forward based on domestic supply and then just market demand.

Got it. That makes more sense. One more quick one for me. Can you update us or refresh our memory on sort of the all-in CapEx for the projects, for all 3 projects? I know it's in the $20 million to $30 million range. And just how much have we spent and how much is left to spend at this point in time?

Yes, great question. That's always kind of a moving number just because -- I mean, of course, we have it pinned down. But like building out this infrastructure is very phased, right? I mean it's a 14 different time line thresholds for payment and construction going forward. I would say the way to think about it at the beginning was it was in the low $30 million for all of the kind of go-forward infrastructure that we hadn't already spent money on. We've made a significant dent in that number so far.

We started ordering our long lead time items and equipment whenever we announced it, a few -- I don't know when exactly the FID announcement was, maybe a month ago or so. But I think that we cut our first big check on the remainder that same week. We've done it recently. We probably have another $25 million or so to spend over the projects. A lot of that is front weighted here over the next, call it, 2 or 3 months and then a little bit of a kind of a trickle on the remaining 25% between then and the end of the year.

Your next question comes from the line of Dennis Richter from Securities Pricing & Research.

My question is regarding if there are shut-in opportunities with the Cut Bank field. I mean it's a legacy old oilfield and obviously, you're looking to inject CO2 starting in first quarter next year. Are there currently opportunities in terms of bringing back wells that are -- have maybe not been economic at past prices, but now at the $90, $100 level could basically provide incremental cash flow until you got the Phase 1 accomplished? And then kind of a follow-up question to that, could you talk about your Montana field office and your staffing and in terms of people that are implementing these capital infrastructure aspects and your experience there or the folks that are experienced there?

Yes. No, great question. So on the first one, I think there is, and we've done some of them on available opportunities on shut-in wells. I think that backing up a little bit, understanding that oil asset is paramount to answering that question. It's an older proven legacy oilfield. It has a lot of wells on it. The wells are vertical wells. And a lot of those have been shut-in. Until you kind of, I'll call it, build/rebuild that reservoir pressure through tertiary recovery, i.e., injecting CO2 like we're going to be doing, turning legacy vertical wells back on is -- it's not overly attractive because you'll get some barrels out of the ground right off the bat.

But without increasing the reservoir pressure from legacy levels to something more enhanced, you're probably looking at like a 1 or a 2 barrel a day type of steady state once they're back and flowing. And then to get something that's meaningful, i.e., adding $1 million -- a couple of million dollars to our bottom line, doing the level of that work going and working over those wells, I'm not sure that -- I know we would make money on it, but I'm not sure that it's a compelling enough return to kind of spend that capital.

So some of the proverbial like very low-hanging fruit, turning some wells back on that we normally would not have done. We've already done that. We've added 40 to 50 barrels a day over the last month just doing that. And I think that, again, not a huge number, but just if you can pick up a few dollars laying on the ground with low capital expense, that's always something that we'll do, and we'll continue to evaluate.

But without a doubt, most of the upside comes from those wells that I'm discussing, getting the reservoir pressure up, turning them back on. And instead of having 1 or 2 barrels a day come out of 10 wells, you have 10 or 15 plus coming out of those shut-in wells.

On the Montana operations side, great question. And I think you might be the first person that's asked me that. We absolutely have a -- again, relative to the size of the area, a fairly large presence in Montana. I think we're the third largest employer up there after local municipal health care and school districts. We have roughly 13 to 15 people that run our day-to-day operations that are up there. They've been with this asset ever since Quicksilver and Blackstone owned it, and we inherited them with the deal. And I mean, there's not 15 people more familiar with this asset in the world than the folks that are up there. This is their sole focus. This is their sole job because this is what they do every day.

And like everything else, we have a field office up there under our subsidiary in a nice little building that looks like a small insurance company. And we have an equipment yard a little bit outside of town just for staging and holding equipment, et cetera. So from a day-to-day operations perspective, it would be very hard, in my opinion, if not impossible, to improve that just due to the familiarity with the asset that these folks have. And then of course, we have our -- a little more senior on the corporate chain people here in Houston, along with one of our senior guys who's based out of Denver, that's ex EOG, ex Anadarko that kind of oversees them and spends a lot of time in the field as well.

I'll go back into the queue. I have a follow-up question, but I think...

You can go ahead and ask it now, if you want.

Okay. In terms of accelerating to Phase 2, Mark, you mentioned in terms of the -- getting the EPA approvals for the 45Q credits. Some of these credits you mentioned can be monetized. Could you kind of talk about what's -- provide more color on your options once you get that approval as you expect in that summer time period? And what would be the hurdles to get Phase 2 implemented earlier?

Yes. Another good question. This is Ryan. I'll address that because I'm pretty close to that situation. So I'm going to answer them in a different order than you asked. I'm going to answer the second one first. Our Phase 2 hurdles, of course, you always have operational and technical stuff you need to do. But by far, our Phase 2 hurdle is optimal capital stack for that Phase 2. So much of what we're doing is infrastructure heavy cost, right? Like Phase 1 is 90% of the capital we've spent on this project so far is on the infrastructure side.

And I expect Phase 2 to be very similar. Our resource there is extremely proven, resource, meaning resource under the ground, helium, CO2, et cetera, and it's so large that the deliverability risk of feedstock into perpetuity for these phases is extremely low. The caveat there is the infrastructure costs are very significant. So our Phase 2, which we're already working on early stage, right? Like it's not anything that's new from Phase 1. It's just bigger. So all of the work that we've done on the technical side, on the engineering side, on the processing side has materially been completed. So really just coming up with the blueprint for Phase 2 and all the little things that come into that and getting everything on a piece of paper, if you will, to plan that process out and get it going.

And we're working on that now. If the money fairy put all the money I needed on my desk today to do that project, we could start on it today but I don't think that's going to happen. So how do we come up with the right mixture of capital to fund that is concurrently what we spend a lot of time on here. And I think that's twofold.

One, just like you've seen in midstream companies and gas processing companies with so much value on the infrastructure, on the pipelines, on the plant facilities, these things are tailor-made to add debt capital to, right? Like I mean you see some of the big midstream companies run at 6 to 7x leverage. I would never do that here. But I do think once Phase 1 is up and running, we've been very conservative about applying leverage to this. We over-equitized it on the front end on this first phase just because I wanted to kind of a 50-50 equity debt capital stack going into it. But as we get going, I think it's fair to assume more project finance layered debt to expand is something you'll see.

And then how do you plug that equity piece? I don't want to go out and do a big giant common equity blast, right? Like it's not good for the shareholders, of which our Board and management team here are extremely significant shareholders. So we would be wearing that dilution just like everybody else. One avenue, a very attractive avenue is what I'll call tax equity financing. You've seen a lot of them in wind. You've seen a lot of them in solar of companies that are generating, whether it's 45Z, 45-some other letter and a little bit on the 45Q side, which is what we are of a forward selling of those credits over the life of your credit realization forecast to end user buyers that want that offset.

And that ranges from Microsoft and Google to big insurance companies to East Coast institutional funds. So it's a pretty large and pretty dignified group of buyers of those credits. And everyone is a negotiation. Every one is a different structure. But I think like a way to think about it is whatever your -- a reasonable outcome is whatever your forecasted 45Q credit stream is, nobody is going to pay you 100% of it, 100% for all of it just because they want to leave a little bit of cushion, but somebody -- and there's comps in the market for this, will come in and buy 60% or 70% of your 12-year forecasted 45Q stream at a discount rate of 10%, still pay you to operate it going forward and then you pull a very meaningful portion of that capital forward.

So one thing, I've talked about this a little bit, probably maybe not in this much detail that we're looking at concurrently with Phase 2 on capital optimization is forward selling through a tax equity financing, Phase 1 45Q credits, getting that capital upfront and then on a dollar-for-dollar basis, recycling that capital straight into the ground for Phase 2 development. It makes a lot of sense from a financial projection perspective, from a rate of return, from an ROCE perspective, it's really a no-brainer, pulling 12 years of value forward on day 1 and redeploying that capital into something that scales up into the right on a nonlinear basis compared to Phase 1.

I appreciate that. Yes. I mean that forward pulling those credits, I mean, I see this with other companies, it's almost become self-financing. I mean it's a fantastic setup. And I don't think -- I think your comments earlier from both Mark and you, Ryan about that the market doesn't really appreciate what you have accomplished and what you have put -- these assets you have put together. I have to kind of -- I totally agree in terms of having valued companies for 25 years, the disconnect between the value that you are creating here and have already and the market price is just significant. So I applaud you for what you have accomplished. I appreciate it.

There are no further questions at this time. I will now turn the call over to Mr. Ryan Smith, CEO, for closing remarks.

Yes. I want to thank everybody for joining us this morning. Thank you to everybody that asked questions. I was happy to answer them. And I want to thank our shareholders for sticking with us through this process. We've made a lot of tangible progress over the last 2 months. That was kind of the fruition of the work we've been doing for the last 18 months. And we have a lot of stuff in front of us that we expect to accomplish this year before getting this project online in the first quarter of next year. So the Board and management here are very excited and very confident about the value we are building at this company, and we look forward to continue sharing it with you, both on a daily basis as people reach out to me and on calls quarterly going forward.

Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.

Greetings, and welcome to the U.S. Energy Corporation Second Quarter 2025 Results Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mason McGuire, VP of Finance and Strategy. Thank you. You may begin.

Thank you, operator, and good morning, everyone. Welcome to U.S. Energy Corp.'s Second Quarter 2025 Results Conference Call. Ryan Smith, our Chief Executive Officer, will provide an overview of our operating results and discuss the company's strategic outlook; and our Chief Financial Officer, Mark Zajac, will give more detailed overview of our financial results.

Before this morning's market opening, U.S. Energy issued a press release summarizing operating and financial results for the quarter ended June 30, 2025. This press release, together with accompanying presentation materials, are available in our Investor Relations section of our website at www.usnrg.com. Today's discussion may contain forward-looking statements about the future business and financial expectations. Actual results may differ significantly from those projected in today's forward-looking statements due to the various risks and uncertainties, including the risks described in our periodic reports filed with the Securities and Exchange Commission. Except as required by law, we undertake no obligation to update our forward-looking statements.

Further, please note that non-GAAP financial measures may be disclosed during this call. A full reconciliation of GAAP to non-GAAP measurements are available in our latest quarterly earnings release and conference call presentation.

With that, I would like to turn the call over to Ryan Smith.

Good morning, everyone, and thank you for joining us today. I'm pleased to walk you through our second quarter results, highlight key milestones and share a strategic update as we continue advancing U.S. Energy's transformation and growth. As we've discussed in prior quarters, our primary focus is the development of our Montana-based industrial gas project, an asset we believe is uniquely positioned to meet growing demand, deliver strong economics and achieve meaningful scale in the public markets.

This summer, we completed the initial phase of our development program and remain firmly on track to bring operations online. This first phase included drilling 2 new development wells, advancing engineering on an acquired already productive well, flow testing all existing producing wells, reaching a final investment decision on infrastructure and making significant progress on our carbon management strategy.

I will walk you through these in more detail now. Starting with upstream development. In the second quarter, we drilled our second and third industrial gas wells targeting the helium and CO2-rich Duperow Formation, both within budget. Including the productive well we acquired earlier this year, peak rates reached approximately 12.2 million cubic feet per day with a premium gas composition of approximately 85% CO2, 5% natural gas and 0.4% helium.

To optimize reservoir performance and maximize value, we subsequently managed production in the 8 million cubic feet a day range with similar compositions. With 3 producing industrial gas wells and 2 injection wells, we are well positioned for near-term cash flow generation. These results validate the quality and scale of our resource, further reinforced by our independent resource report.

Following drilling, we engaged Ryder Scott to prepare a volumetric resource assessment of our Montana asset. The report confirmed net contingent resources of 444 billion cubic feet of CO2 and 1.3 billion cubic feet of helium, among the largest known deposits of its kind. We expect to release a commercial resource report once processing facility development plans are finalized. It's worth emphasizing the unique competitive positioning of the Kevin Dome. While most U.S. helium production is tied to heavy hydrocarbon gas streams, our project is sourced from a limited hydrocarbon stream, delivering a lower environmental footprint and aligning with growing market demand for sustainable solutions.

With the initial development program concluding in September, we will break ground on our Kevin Dome processing plant. This facility will separate our upstream gas into helium, natural gas and CO2 streams, each with its own monetization pathway. We expect construction costs of under $10 million funded by our existing balance sheet and a modest strategic use of debt.

Importantly, this infrastructure will not only serve our operations, but will also provide a platform to support undercapitalized producers in the region.

With control over the majority of the basin's helium supply, we see multiple opportunities to expand our value capture. Lastly, I would like to touch on U.S. Energy's carbon management front. U.S. Energy controls one of the largest CO2 deposits in the U.S. with geology ideally suited for both permanent storage and enhanced oil recovery. Our proximity to the Cutbank oil field just 15 miles away offers a unique and lucrative integration opportunity between CO2 supply and hydrocarbon recovery. We already hold multiple Class II injection permits with additional approvals expected in August.

Recent injection testing at 2 disposal wells achieved sustained rates of over 17 million cubic feet a day, supporting a sequestration capacity of approximately 240,000 metric tons of CO2 annually. We've also initiated our EPA monitoring, reporting and verification plan, targeting submission this September and approval by spring 2026, positioning us to potentially access federal carbon credits under Section 45Q.

We are highly optimistic about the road ahead. The Kevin Dome represents a first-mover opportunity in the industrial gas sector and one that cannot be replicated. Our vision is to build a full cycle platform that spans upstream production, midstream processing and long-term carbon management while maintaining strict capital discipline. The data collected to date supports a highly economic development path, both at the wellhead and infrastructure levels. Initial phases have modest funding requirements with a clear and measured capital plan designed to scale returns over time.

Turning briefly to our legacy oil and gas portfolio. Lower commodity prices have weighed on earnings across the sector, including ours. While these assets are no longer our primary focus, they do remain valuable. Our 2024 monetization program eliminated debt and strengthened liquidity, and we remain opportunistic in pursuing value-maximizing divestitures. As we progress through 2025, our strategy remains clear: invest in our core Montana industrial gas project, monetize noncore legacy assets where appropriate and maintain capital discipline to position 2026 as a breakout year in our transformation.

We believe U.S. Energy stands apart with a scalable, high-margin development platform supported by legacy assets that require minimal reinvestment. This structure allows us to pursue high-return growth in industrial gases while reducing exposure to commodity volatility. In short, U.S. Energy is emerging as a differentiated and growth-oriented industrial gas company with exposure across upstream, midstream and carbon management. Our strong financial position and clean capital structure give us a competitive advantage, and we believe the strategy we're executing today will deliver sustainable long-term shareholder value.

With that, I'll now turn the call over to our Chief Financial Officer, Mark Zajac, who will provide an update on our financial results for the quarter.

Thank you, Ryan. Hello, everyone. Let's delve into the financial details for the second quarter of 2025. Our operating results reflect the cumulative impact of our divestitures since the fourth quarter of 2023. Revenue was approximately $2 million, down from $6 million same quarter last year, reflecting the impact of divestitures in the second half of 2024. Oil comprised over 90% of the revenue this quarter, reflecting our focus on optimizing our remaining oil assets.

Lease operating expense for this quarter was $1.6 million or $32.14 a BOE, compared to $3.1 million or $27.69 per BOE in the same quarter last year.

The overall decrease reflects our divestitures since first quarter last year and on a BOE basis, the increase is a function of the assets remaining in our portfolio. Cash, general and administrative expense was $1.7 million for the second quarter of 2025, which is in line with our run rate expectations quarterly. We have made significant improvements to our organization and structured the team around our industrial gas development. As for our balance sheet, as of June 30, 2025, there was no debt outstanding on our $20 million revolving credit facility, and our cash position stood at over $6.7 million, reflecting the net proceeds of $10.3 million generated from our successful equity offering during the first quarter.

This was offset by $4.6 million of industrial gas acquisition and capital expenditures. We have agreed on terms on the renewal of our credit agreement, extending it to May 31, 2029. We are completing customary closing activities now and expect to execute the amendment in the coming days. The renewed agreement includes covenant waivers for the first quarter of 2026 as we achieve profitability on our industrial gas operations.

Overall, our operating performance and financial results reflect our recent divestitures as well as the company's new initiatives. We continue to maintain balance sheet discipline and integrity. My objectives continue to ensure that the company's reporting processes maintain a high standard of excellence, and we feel confident in our ability to support the growth initiatives we currently have underway.

Thank you for your participation this morning. We are now ready to take your questions.

[Operator Instructions] The first question comes from Charles Meade with Johnson Rice.

Ryan, I wanted to -- you used the word in your press release about the resource report, I guess, you used the word pleased. I wanted to ask a little more detail there. Was there anything in that? So you used the word pleased, it's good. But was there anything in there that surprised you either to the upside or downside, whether it be the total resource that they came up with or the concentrations? Or -- if you could just give us the kind of inside baseball on how that process rolled out to get to that final numbers that you gave us.

Yes. No, good question. So I am pleased with it. I would say not surprised because those numbers, again, when you're dealing with the quantum of billions of cubic feet, rounding errors can be pretty big numbers. But since we started this process, I don't know, 18 months ago or so and progressed it, we believe that the resource, both helium, both CO2, there's a 5% or so nat gas cut in that stream, which we didn't have in the resource report.

But we believe from the very beginning that the numbers here were very large, and that's why we went after the project. So having Ryder Scott, which for my money is as good and reputable as any reserve firm in the world, verify that and get a formal big company third-party stamp of approval for what we already believed internally, it was very -- I'll use the word again, very pleasing. It wasn't surprising because we thought it was there. And as we start our core development across the structure, and again, just looking at our maps, which we have on our website, et cetera, we think there's more upside to go.

This is kind of our initial core development area. So I think there's upside to those numbers as we continue to move outward off that structure. But no, we were -- I'm pleased with it. I'm very happy with it. It shows the immense running room of what we have as we continue to develop this going forward across multiple streams of that gas stream.

Got it. And that's a good segue to my follow-up question. I recognize it's early, but the question is on the commercial offtake agreements. And you talked a little bit about some CO2 going to the Cut Bank field for EOR and 45Q. But can you give us a sense of -- what are your goals for different offtake streams, whether it's the CO2 or the helium or I guess, natural gas is really a rounding error, so that's not important. But what are your goals for those different streams? And what's a time frame to -- that we should be thinking about to -- for some kind of a resolution or sometime additional information on your commercial offtake arrangements?

Yes. No, good question. So there's a few ways -- there's a few parts to that question. I think from a high level, you have your gaseous helium, you have your CO2, which can really be kind of a 3-pronged monetization via permanent sequestration via EOR use and via merchant retail market sales. Probably an obvious comment, but I would like to control the offtakes as much as possible. And what I mean by that is with the recent Big Beautiful Bill passage and the value for CO2 EOR use equaling permanent sequestration use, the fact that our Montana assets going back literally 100 years ago to Chevron, Unicol owning them was always targeted for CO2 tertiary flood.

And economics are always a little bit stretched based on oil prices and the expense of CO2. And now that, that expense has turned into an extremely significant revenue stream, we started looking at the EOR uses for the CO2 a whole lot more, one, because of the economics; two, because we're on both sides of the table in negotiating that use. So that gives us a very doable economic use for that CO2. I think on the -- and as well as the permanent sequestration side, right?

Like we don't need to get third-party approvals for that because we're agreeing to both sides of that because we own all the assets. I think on the helium side, I'll say, I think we enter into something by the end of the year. I'll caveat that by saying we're probably in a position to be able to do it now. We have some stuff in front of us. The offtake helium agreement market is pretty opaque. And when you go to market with something and you're not a massive company, the counterparties know that, and we'll reflect that in price.

So I think between now and the end of the year, we'll kind of pick our spot, but you'll see something on that front as well. And then kind of sprinkles on the ice cream would be us being able to sell merchant retail CO2 into the West Coast markets. I can't give a time frame on that just because it's -- you deal with very specific parties, but that's something that we're working on actively as well. So I think in summary, you'll see intercompany agreements on sequestration and EOR use for the CO2 in the relatively near term, helium offtake, which would basically be offtake agreements with the owner of helium liquefaction equipment by the end of the year and proactively merchant CO2 sales into the retail market. TBD, but something we're working on actively.

The next question comes from Tom Kerr with Zacks.

The helium concentration on the drilled wells, I think in the Texas at 0.47, but we had always talked about 0.6 in the last several quarters. Was there anything there or what happened there?

Yes. I mean it's less than our initial well that we acquired and did more work on. And I would love to have like a very dignified reason answer for you. I think the honest answer is when you're dealing with basis points on a gas stream, sometimes it comes in more, sometimes it comes in less. And the numbers were what kind of what they were, right? We think that if we drill another well to get the overall volumes up a little bit more, we have some ideas and some locations to where we think that, that composition is a little bit higher than what some of our subsequent wells produced in. But again, we go after the areas we think are prolific enough to defend processing economics, et cetera. We always expected some variation potentially to the upside potentially to the downside. Unfortunately, it was a little bit to the downside. I would say that those numbers are still highly economic for us as part of our full cycle program. But they kind of are what they are. So I don't know if that's what the answer you're looking for, but I think that's what I got.

Yes, you just answered my second question, which is still economically viable level in terms of economics and cash flow and that sort of stuff.

Yes, absolutely, right? Like we look at it starting off each economic driver kind of in its own silo and standing on its own 2 feet, right? Like we don't want to have an uneconomic process in one pocket and then depend on the other pocket to defend activity. So the helium concentrations on our current flows, and so much of it depends on processing and infrastructure, and that goes into the planning as well, right? Like the size and et cetera. What works for us and then layering on, I'll call it, revenues and incentives from CO2 sequestration, EOR usage really juices those economics very extensively on top of what we already have on the helium side.

Got it. All right. That makes sense. And then just on the processing plant, any sort of changes in the complications of developing that or cost levels or changes since we last talked?

I think there's a few changes. I won't -- we're still going through I'll say, a few design options right now. And the reason for that isn't for difficulty. It's really the incentives on the recent bill evening out EOR and sequestration dollars really kind of change the proverbial calculus for us. I mean, we have an extensive EOR asset in Montana. It's very large. It's very close. The geography couldn't be any better. And some of the equipment and processes to, call it, strip out helium, sell helium, strip out nat gas, sell nat gas, get the CO2 to a level where it's getting used for EOR purposes is actually a little more simple and a little bit cheaper than what we were originally planning for.

So obvious comment, if there's something that we can do that results in the same economics and do it at a cheaper cost, we're going to pursue that route. So, that's probably the main reason why we haven't started on the plant. We're just -- we're fine-tuning our economic model, our strategy, construction planning and exactly the lowest cost within reason that we can spend on the processing infrastructure side to access these multiple value chains as soon as possible.

Got it. All right. Last question, a financial one on the cash SG&A slightly elevated because of some business development in Montana. I think you said it will stabilize. Does that mean we're going to see that level probably in the next 2 quarters of $1.7 million? Or does that drift down because you don't have some of those Montana costs in there?

I think it's the latter. It should drift down. We've spent, I'd say, a fair amount of capital getting the project off the ground. And again, we're not a huge company. So onetime hits show up a lot more than they would with other larger entities. Consultants, both internal and third party, a fair amount of legal work just on the landowner right away, other ancillary charges, getting permits, getting disposal permits, all of that stuff. It's added up over the last couple of quarters. And it will continue to some extent just as we keep pushing stuff forward, but it definitely should lessen here in the very, very near term. It's probably already started to lessen a little bit as we go forward.

Thank you. At this time, I would like to turn the call back over to management for closing comments.

Great. I appreciate everybody for joining this morning and listening to what we have going on. We're excited about our project. We continue to move it forward. We're set up for 2026 to be a stellar year for U.S. Energy as we get this project off the ground and online. I appreciate your time. Thank you.

Thank you. This does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation, and have a great day.