管理層發言
Good morning, and welcome to U.S. Energy Corp.'s First Quarter 2026 Earnings Conference Call. Operator provided instructions were given to participants. 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, 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 capital 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 capital 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 three successful drilled wells plus two 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. 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 underpin 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-one revenue stream of our multi-revenue platform. 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. 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. 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, no fermentation and no energy-intensive capture step. That is a structural cost advantage that very few projects in the world can claim. 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. 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 three 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 transferability or 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 mature. 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 the 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. 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 two to three times 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. 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 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 capital 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.
分析師問答
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 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 metric tons per annum you might sell outside of tax credits and just some more information on that.
John, that's a great question, and those numbers you laid out are accurate. Just backing up a little bit, it was very important for us to be able to forecast our base-case projections on Phase 1 to what we can control. We can control our helium sales, our carbon sequestration (aka CCUS) activities and our oilfield. Everything we've modeled internally reflects the $85 per metric ton CO2 sequestration rate and utilization numbers. That being said, the end-user market pricing you referenced is robust. The end user would be accessed through a distributor similar to how we manage helium. Reallocating CO2 into large-scale, long-term investment-grade counterparty CO2 distribution channels, especially to the coasts or the Midwest, is extremely compelling. Even if you take an $850–$900 end-use number and cut it in half, that's four to five times a conservative revenue basis. For Phase 1, we plan on capturing 125,000-plus metric tons a year of CO2 for sequestration and EOR purposes. Not all of that CO2 is the same quality; roughly two-thirds of it is a higher-purity CO2 grade that would need a little incremental capital to achieve industry and food-and-beverage quality. Two-thirds of 125,000 is a large number—about 80,000 metric tons per year, a little over 200 metric tons per day. Running those numbers at a fairly conservative $350 to $400 per metric ton price materially increases our revenue profile, potentially by three- to fourfold out of the gate. We're currently working to understand that market and identify the big players, similar to our helium offtake approach. It's important to us to have a high-quality counterparty on the other side of those transactions. We've started early-stage discussions and will pursue this heavily in the second half of this year. As we grow the platform from Phase 1 to Phase 2, getting CO2 into end-user industrial merchant markets is an absolute goal. It takes the economics from extremely attractive to substantially greater if we can accomplish it. The CO2 merchant market is structurally short in the United States, similar to helium, and serves industries that are growing and will continue to require supply. It's a major focus for us going forward.
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, and the Middle East conflict has raised prices a little bit. Are you able to talk about how you arrived at that $285 per Mcf price?
Tom, great to hear from you. We had an offtake agreement on my desk to sign for a couple of weeks before the Middle East disruptions. We did not execute immediately and, when geopolitical events unfolded, we reopened negotiations and pricing. Pricing went up roughly 50% or so overnight for producers that drill, process and deliver gaseous helium. We ultimately signed at $285 per Mcf, which escalates with CPI beginning in March 2028, so effectively a low-$300s per Mcf average over the life of the contract. Our counterparty is picking helium up at the plant, and that's our bottom-line number. When comparing announced helium prices, it's important to understand that many companies announce a headline price but remain responsible for tolling and transportation fees, which can be significant—I've seen ranges of $125 to $175 deducted from headline prices. If you adjust for transportation and tolling, our $285 plant-gate price is competitive and, on a promotional basis, comparable to low-$400s when others publicly report top-line numbers but exclude tolling and transportation. We intentionally avoided taking on transportation risk; we preferred our counterparty to collect at the plant, using their infrastructure for liquefaction and distribution. Regarding term, we had options from one to ten years and chose five years with a pricing revisit after three years, which was important to preserve upside. It's possible we could not have achieved comparable terms before the Middle East disruptions. We remain optimistic about helium prices long term. At some point geopolitical events may subside, but secular demand drivers—AI, semiconductors, health care, national defense, aerospace—are increasing or sustaining helium demand. That demand is unlikely to diminish while U.S. domestic supply remains constrained. A helium molecule produced in the United States has increasing value relative to supply from Qatar, Russia or Algeria, and we believe the market will continue to value domestic supply accordingly.
Your next question comes from the line of Dennis Richter from Securities Pricing & Research.
My question is regarding shut-in opportunities with the Cut Bank field. It's a legacy oilfield and you're looking to inject CO2 starting in the first quarter next year. Are there currently opportunities to bring back wells that may not have been economic at past prices but now, at the $90 to $100 WTI level, could provide incremental cash flow until you get Phase 1 accomplished? And as a follow-up, could you talk about your Montana field office, your staffing and the people implementing these capital infrastructure aspects and their experience?
Good questions. On the shut-in wells, there are opportunities and we've already acted on some of them. That oil asset is an older, proven legacy field with many vertical wells that have been shut in. Without increasing reservoir pressure through tertiary recovery—injecting CO2—turning legacy vertical wells back on typically yields low steady-state production, perhaps one to two barrels per day per well. To get meaningful incremental cash flow that would add materially to our bottom line would require more substantial work and capital. That said, there is low-hanging fruit: we have turned some wells back on and added 40 to 50 barrels per day over the last month from such efforts. It's not a huge number, but with low capital expense, we'll continue to pursue these opportunities. The largest upside, however, comes from raising reservoir pressure via CO2 injection; that converts marginal wells into significantly higher producers. On Montana operations and staffing: we have a sizable presence in Montana relative to the region. We're one of the largest employers locally after municipal health care and school districts. We have roughly 13 to 15 people running day-to-day operations there. These individuals have operated this asset since prior owners like Quicksilver and Blackstone; we inherited them with the acquisition. There are few people more familiar with this asset than those on the ground. They focus exclusively on this asset and its operations. We have a field office in town and an equipment yard outside of town for staging. From a day-to-day operations perspective, it's hard to improve on the existing local team given their familiarity with the asset. Senior management here in Houston and a senior technical lead based in Denver, with prior experience at EOG and Anadarko, oversee operations and spend significant 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 mentioned getting EPA approvals for the 45Q credits and that some of these credits can be monetized. Could you provide more color on your options once you get that approval, which you expect this summer? And what would be the hurdles to get Phase 2 implemented earlier?
Yes. I'll address your questions, starting with Phase 2 hurdles. Phase 2's primary hurdle is securing the optimal capital stack. Much of what we've done so far is infrastructure-heavy. Phase 1 incurred a high portion of upfront infrastructure cost, and Phase 2 will require significant capital as well, although the incremental capital per unit is materially lower because the heavy lifting—permitting, land, much of the infrastructure—is already in place. Our resource is proven with high deliverability and low feedstock risk, so the focus becomes how to finance the expansion. We are already working on Phase 2 planning and the blueprint for scale. If all capital were available today, we could start immediately, but the realistic path is layering appropriate financing. There are multiple avenues. Project finance debt is attractive as we derisk through MRV approvals and contracted offtake. Tax-equity-style financing, which you see in wind and solar, is another attractive avenue: forward-selling a portion of the 45Q credit stream can pull value forward. Under many structures, an investor would purchase a portion of a forecasted tax credit stream at a discount. Based on market comps, a buyer might purchase 60% to 70% of a 12-year forecasted 45Q stream at a discount rate in the low double digits, providing substantial upfront capital without diluting shareholders. That monetization could be paired with project finance debt to form an optimal capital stack for Phase 2. We intentionally over-equitized Phase 1 on the front end to reduce covenant risk during construction and protect shareholders from dilution. For Phase 2, we expect to see more project-level debt and structured tax credit monetization to drive efficient expansion capital. On monetizing 45Q credits for Phase 1 while accelerating Phase 2: forward-selling a significant portion of the Phase 1 45Q credits and recycling that capital into the ground for Phase 2 development is an attractive, potentially self-financing strategy. It's something we're actively evaluating and pursuing now.
I appreciate that. Forward-pulling those credits has become a very effective financing tool. I also want to say I agree with your comments, Ryan and Mark, about the market underappreciating what you've assembled. The disconnect between the value you're creating and the market price looks significant. I applaud you for what you've accomplished and appreciate the commentary.
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 and thank everyone who asked questions. I also want to thank our shareholders for sticking with us through this process. We've made a lot of tangible progress over the last two months; that was the fruition of the work we've been doing for the last 18 months. We have a lot of objectives we expect to accomplish this year before bringing the project online in the first quarter of next year. The Board and management are very excited and very confident about the value we are building at this company, and we look forward to continuing to share updates, both through direct engagement and on quarterly calls going forward.
Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.