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DATE

Thursday, May 7, 2026 at 9 a.m. ET

CALL PARTICIPANTS

  • Chief Executive Officer — Ryan Smith
  • Chief Financial Officer — Mark Zajac

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TAKEAWAYS

  • Phase 1 Final Investment Decision (FID) -- Announced for the Big Sky Carbon Hub, supported by completed engineering, permitting, a fixed-scope EPC contract, a fully funded capital stack, and a contracted helium offtake.
  • Big Sky Processing Facility Specifications -- Facility designed for approximately 8 million cubic feet per day inlet with targeted annual production of about 14 million cubic feet of high-purity helium and 125,000 metric tons of refined CO2.
  • Commercial Operation Target -- First gas and initial revenue planned for the first quarter of 2027.
  • Helium Offtake Agreement -- Signed 5-year, 100% take-or-pay helium sales contract with an investment-grade global industrial gas company at a plant gate price of $285 per Mcf, including CPI escalation starting March 2028 and a year-3 pricing redetermination.
  • Section 45Q Tax Credits -- Management projects roughly $130 million in federal tax credits across the initial 12 years of Phase 1, based on $85 per metric ton eligibility for projects started before 2033.
  • Senior Secured Credit Facility -- Amended facility doubles borrowing base to $20 million, fixes interest at 200 basis points over the alternative base rate, suspends quarterly covenant testing until March 31, 2027, and removes prepayment penalties.
  • Equity Line of Credit (ELOC) -- Formally suspended with no draws since March 2; management highlights this removes perceived dilution overhang for shareholders.
  • Gathering and EOR Installation Milestones -- Gathering infrastructure and enhanced oil recovery preparations scheduled for summer and fall, with plant commissioning expected late 2026.
  • CO2 Market Strategy -- Management initiating commercial discussions with large-scale CO2 distributors to access additional revenue opportunities beyond sequestration tax credits, targeting the sale of high-purity CO2 into merchant markets.
  • Phase 2 Expansion Plans -- Current permits, acreage, wells, and infrastructure support capacity scaling to two or three times Phase 1 with lower per-unit capital expenditure and greater capital efficiency.
  • Cut Bank Oil Asset Utilization -- Cut Bank field produces "low decline established cash flow" and offers roughly 70 million barrels of incremental recovery potential using internally sourced CO2 for enhanced oil recovery.

SUMMARY

U.S. Energy Corp. (USEG 4.20%) outlined the completion of its Big Sky Carbon Hub Phase 1 capital stack, confirmed the transition from legacy oil and gas toward an integrated industrial gas and carbon management model, and demonstrated material de-risking through executed infrastructure contracts and helium offtake. Management signaled intention to accelerate value through direct CO2 merchant sales and monetization of substantial Section 45Q tax credits. The company is actively preparing for Phase 2 scale-up, enabled by operational foundations and anticipated nondilutive capital options.

  • CEO Smith stated, "Our internal modeling supports project NPV that is multiples of where Phase 1 stands today and equity returns that fundamentally rerate the company."
  • The Phase 1 project will capture 125,000 metric tons annually, of which approximately two-thirds is higher-purity CO2 suitable for merchant sales, potentially priced at $350-$400 per metric ton if incremental purification investment is deployed.
  • COO commentary confirmed that nearly $25 million remains of allocated project CapEx, with spending front-loaded in the next two to three months.
  • Operations in Montana are supported by a dedicated team of 13-15 experienced field personnel integral to Cut Bank asset management and infrastructure build-out.
  • The company has advanced EPA review for monitoring, reporting, and verification (MRV) submissions at Big Rose and Cut Bank, key to unlocking Section 45Q credits; management expects approvals by summer.

INDUSTRY GLOSSARY

  • FID (Final Investment Decision): A binding commitment to proceed with a project based on completed engineering, financing, and commercial contracts, moving a development into the construction phase.
  • EPC (Engineering, Procurement, and Construction) Contract: A fixed-scope contract obligating a firm to design, source materials for, and construct a project facility.
  • Section 45Q Tax Credits: U.S. federal tax credits for qualifying carbon capture, utilization, and sequestration (CCUS) projects, providing payments per metric ton of captured CO2.
  • CCUS (Carbon Capture, Utilization, and Storage): Technologies capturing CO2 emissions for use or permanent storage to reduce atmospheric carbon footprint.
  • Take-or-pay Agreement: A sales contract obligating the buyer to pay for specified volumes whether or not they physically take delivery, mitigating seller volume and demand risk.
  • Cap Stack (Capital Stack): The hierarchy of different funding sources (e.g., equity, debt) used to finance a project.
  • MRV (Monitoring, Reporting, and Verification): Regulatory submissions and protocols ensuring compliance with environmental standards for CO2 capture and storage.
  • EOR (Enhanced Oil Recovery): Techniques, such as CO2 injection, to increase oil extraction from mature fields.
  • Mcf (Thousand cubic feet): Standard measurement unit for natural gas and industrial gases like helium.
  • Plant Gate Price: The price received by the producer at the facility, excluding transportation and downstream costs.
  • ELOC (Equity Line of Credit): A facility allowing a company to raise equity capital at its discretion, often structured for flexibility and reduction of financing risk.

Full Conference Call Transcript

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.

Mark Zajac: 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.

Ryan Smith: 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: [Operator Instructions] Your first question comes from the line of John Davenport from Johnson Rice.

John Davenport: 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.

Ryan Smith: 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.

John Davenport: 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.

Ryan Smith: 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.

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

Thomas Kerr: 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.

Ryan Smith: 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.

Thomas Kerr: 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?

Ryan Smith: 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.

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

Dennis Richter: 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?

Ryan Smith: 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.

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

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

Dennis Richter: 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?

Ryan Smith: 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.

Dennis Richter: 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.

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

Ryan Smith: 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.

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