Prairie Operating Co. (PROP) Earnings Call Transcript & Summary

Thank you, operator, and good morning to all of you. We appreciate you being on Prairie Operating Co.'s call covering third quarter 2026 results. Before we get into our prepared remarks, I want to remind everyone participating today that forward-looking statements will be part of our comments, and those carry certain risks, uncertainties, and assumptions. What actually happens could differ materially from what those forward-looking statements express or imply. We may also reference non-GAAP financial measures. If you want a more detailed discussion of the risks and uncertainties that could make actual results differ materially, and reconciliations of non-GAAP financial measures, please see the company's earnings release and public filings, including our Form 10-Q for the quarter ending September 30th, 2026. Those materials, plus an updated investor presentation, can be found on our website. With me today are Greg Patton, Chief Executive Officer, and Michael Shelly, Executive Vice President and Chief Financial Officer. With that, I'll hand the call over to Greg.

Thanks, Wobbe, and good morning. Development program. Average daily sales volumes grew 19% compared with the prior quarter, reaching 26,117 BOE per day, and we ended the quarter at 30,229 BOE per day. Revenue was up 31% from the previous quarter, coming in at $129.5 million. A substantial portion of our 2026 capital plan has now been completed, with 37 wells across five pads brought online so far, which bolsters our production base and increases our confidence in what's ahead. Third quarter sales volumes totaled roughly 2.4 million BOE, a 21% increase over the prior quarter, at 77% liquids, including 56% oil. Across the first nine months, sales volumes were about 6.5 million BOE, or roughly 23,730 BOE per day, at 74% liquids, including 52% oil. That production momentum continued into early October. Thanks to the wells turned in line during the third quarter, output kept rising, hitting about 32,287 BOE per day by early October. Our current results rest on how we've executed the development program. So far this year, we've drilled 27 wells across four pads, and 19 of those wells were drilled in a single run. On average these wells measured roughly 18,700 feet in measured depth, with an average rate of penetration of 380 ft per hour and an average spud to rig release time of 6.2 days. We've completed 37 wells over five pads, made up of 27 Niobrara and 10 Codell, and the last three new pads came online in the third quarter, all beating type curve. Right now we're drilling four more wells that will come online in 2027. At Castor, completion work on the six-well pad wrapped up in September, and those wells came online at the end of the month, mainly adding to fourth quarter production. Now to Burnett: that four-well development came online at the end of August and marks an important step in showing the value of Prairie's acreage. The wells were drilled across three separate drilling and spacing units, two of 1,280 acres and one of 1,920 acres. They hit an average maximum initial production rate of about 722 BOE per day per well, with an 81% oil cut on a two-stream basis, and produced cumulative gross production of 131,490 BOE through October 20th of this year. By drilling section line wells across each DSU, we showed the consistent reservoir quality and reserve potential of the acreage while securing all three units for future development. These early production results materially de-risked and confirmed the quality and future development potential of our acreage inside the 5,700-acre Genesis OGDP I, and they supported converting 30 gross possible locations into proved undeveloped locations, which grows our proved inventory, reinforces the commercial potential of nearby undeveloped locations, and lowers uncertainty around our near-term development program; we intend to come back to each of these DSUs in future drilling programs to finish developing them. So, when we consider what lies ahead for these DSUs and the broader Genesis OGDP, the infrastructure already in place positions us well to manage future production growth efficiently. The pipeline network as it currently stands provides reliable production flow along with long-term takeaway flexibility, and because we have oil, natural gas, and water connections, production can leave the location without trucking, which brings down operating costs, facility requirements, and environmental impacts. Our commercial agreements support our development plan and provide flexibility, and they also underpin our artificial lift strategy. The existing infrastructure was built with sufficient capacity to maintain flow assurance throughout our future development program. In addition to de-risking acreage, infrastructure capabilities, and production growth, we continue to push on operating efficiencies. Lease operating expense dropped to $5.71 per BOE, which reflects meaningful cost efficiencies following full integration of the Bayswater operations, and we remain focused on sustaining and extending those efficiencies across our larger production base. In the quarter, for example, we established Stagecoach Logistics LLC to bring field maintenance, logistics, and operational support functions in-house, lowering our reliance on third-party service providers. By centralizing these activities, we can exercise better control over costs, equipment, and inventory while also improving response times and field execution. All together, these initiatives help reduce LOE per BOE and demonstrate the operating leverage available across our expanded asset base. We will remain focused on sustaining field-level efficiencies as we manage a larger producing base. With our recently developed wells now online, our priorities are well performance, operating efficiency, and disciplined capital allocation. We believe the progress across our producing base establishes a foundation for continued value creation, including $6.85 per BOE and 17% improvements that reinforce this trajectory. I will now turn the call over to Michael to review our financial results, liquidity, and capital structure.

Thanks, Greg, and good morning, everyone. Third-quarter revenue reached $129.5 million, up 31% from the previous quarter, and that total includes $114 million of oil revenue. Across the first nine months of the year, revenue totaled $311.8 million, a 97% rise year-over-year, while adjusted EBITDA was $136.4 million, 37% higher year-over-year. At Prairie, third-quarter adjusted EBITDA stood at $65.3 million, up 92% from the prior quarter, helped by greater sales volumes and reduced unit operating costs. With Burnett and Castors now producing, our attention is on capturing the cash returns from the capital we put to work this year and on prudently managing the spending required to sustain that production. Prairie's net loss attributable to the company was $48.9 million for the quarter. After accounting for preferred stock dividends and remeasurement adjustments, net loss attributable to common stockholders was $34 million, equal to $0.26 per basic share and $0.28 per diluted share. The GAAP number includes $105.7 million of unrealized derivative losses, a $13.1 million fair value gain on financial instrument liabilities, and an $18.4 million income tax benefit. Average realized prices, excluding derivatives, were $84.48 per barrel for oil, $24.28 per barrel for NGLs, and $1.05 per MCF for natural gas. Including realized derivative settlements, those prices were $62.24, $19.98, and $2.14, respectively. Net cash from operating activities came to $123.4 million over the first nine months. On a per BOE basis, lease operating expense was $5.71, transportation and processing expense was $1, ad valorem and production taxes were $4.96, and G&A was $4.56, down 24% versus the prior quarter. As of September 30, cash was $7.8 million, and we had $3 million available under our reserve-based credit facility. The borrowing base and elected commitments were $475 million, with $472 million outstanding. During the quarter, we extended the Series F anniversary warrant issuance date to December 1, 2026; we continue to pursue ways to refinance the remaining Series F preferred stock as part of a wider effort to strengthen Prairie's balance sheet, improve financial flexibility, and better align our capital structure with the scale of our operations. Our commodity swaps extend into 2029. For the fourth quarter of 2026, oil swaps covered roughly 1.37 million barrels at $63.23 per barrel, and natural gas swaps covered approximately 4.3 million MMBtu at $4.09 per MMBtu. These contracts give us downside protection. Our aim is to support Prairie's operating momentum through disciplined financial management and capital allocation that creates sustainable long-term shareholder value, including per-share returns of $0.14. With that, I'll hand the call back to Greg for closing remarks.

Thank you, Michael. The latest Burnett pad results have shown how good our acreage is, and that has confirmed our development area while also growing our proved undeveloped inventory. Throughout Prairie, the team is concentrated on turning that operational momentum into cash generation and value for shareholders over the long term. As we go through the rest of 2026, our priorities stay the same: keep well performance strong, hold on to operating efficiencies, and deploy capital with discipline. On behalf of the board and the management team, I want to express our thanks to employees for their continued dedication and execution, and to our shareholders for their ongoing support; with that, I will hand the call back to the operator for Q&A.

Hi everyone. I just wanted to check in about your CapEx. It looks like you've spent roughly $185 million over the first three quarters, and that's the low end of the full-year budget. Where do you expect CapEx to land in Q4, given that you've got only about $10 million left to reach the high end of your budget? I'm just trying to get a feel for that.

Good morning, Leo. Glad to have you with us on the call today, and thanks for joining. That number you're referencing, I'm assuming it's on the cash flow statement, is the 185. At the end of the day, that reflects our cash out the door. Our D&C CapEx for the year actually sits at about 165, which leaves more of that 15 to 30 range for the remainder of the year. As mentioned in the remarks, we have four wells being drilled or about to be drilled this year. Thinking about D&C costs on a gross basis, four wells comes to roughly under that $8 million marker, including rig move and demove. With $165 million of D&C costs, some ancillary costs still trickling in around the final completions in the third quarter, combined with that D&C capital and a few other one-off projects here and there, we remain confident in our previously given guidance range of 180 to 195, and that spans from $180 million to $195 million. That said, there are some inflationary expenses, though we had many of our products locked in for the year, especially sand and steel products. There will be some inflationary effects we've observed at the end of the third quarter as costs come in, and as we move into the drilling expenses here in the fourth quarter, we're seeing somewhat higher costs around those products.

Alright, thanks for that. So I suppose, what would you folks peg as roughly the 2 mi lateral or well cost in today's terms, given inflation?

Good question. At the end of the day, when we examine the D&C costs, we've previously mentioned they come in around that $5.3 million-$5.5 million band, and those figures have risen. We're observing $300,000-$500,000 in extra costs, and that may keep climbing depending on the geopolitical situation. What we'd say is that it won't be this round of drilling costs for the steel, but when we look at Q1 for the year and as we consider our programs moving into 2027 and kicking off that process, it's somewhat of an unknown. We've witnessed a dramatic drop in oil costs recently; we've witnessed a dramatic rise in the number of ships passing through the strait; we've witnessed a dramatic rise in imports arriving. The cost increases might stay flat at that $300,000-$500,000 typical increase, or we might see more or less. It's somewhat of an unknown, so we're monitoring that very closely.

Okay, that's clear. Regarding your production, you clearly saw a good bump in Q3, but there's meaningful momentum on output as we head into Q4. You disclosed an early October figure that looked quite robust at 32,300 barrels a day. Is that level roughly holding now that we're around a month further along, into roughly mid-November? Are you beginning to see that level taper off? Where do you figure you'll land by the end of the year? Is production declining somewhat, and will we come in below that 32,000 and change in Q4?

I won't address Q4 quarterly guidance, but I can discuss the overall dynamics and economics of DJ horizontal laterals. 32,000 barrels a day, clearly in October, as we noted in our script, and as we consider the wells that came online and supported that, with public data, clearly the Burnetts and the Castors. Looking toward the remainder of the year from here on, output has remained quite strong, though there's clearly some natural decline too. When we consider 32,000 barrels a day, that figure has fallen across the last 60 days, which is all of October and November. As we keep moving ahead, ultimately we remain very supportive of our guidance at 23,000 to 25,000 BOEs per day on the annualized average. We feel very confident about how our well bores are performing. Natural decline is real, so I wouldn't tell you we'd finish the year at 32,000 barrels a day, but we're also not providing guidance on what that exit rate production will be right now.

Okay, that's clear. Turning to liquidity, it did look somewhat tight as of September 30, given the cash position and the fairly small amount available on the revolver, roughly $11 million in liquidity. Could you share your view on whether that gets noticeably better? From what you're saying, CapEx drops significantly in Q4 and production is strong. Are you expecting meaningful free cash flow in Q4?

Hi, Leo, I'll take that one. You've basically described it exactly. Since production is very strong and CapEx is fairly limited in the fourth quarter, our liquidity will keep improving quite dramatically as we move toward the end of Q4.

All right, that's clear. Regarding the Series F preferred, I suppose the deadline for a warrant — the anniversary warrant trigger — is approaching, I think at the close of this month. Do you feel you may need to push this out once more, or do you believe you could get something finalized by December 1?

Thanks for that question as well, Leo. As you know quite well and are close to the situation, since we've discussed this frequently during the past year, we've established a very solid relationship with High Trail. They've proven a good partner as we've grown and expanded the business. They've supported us across several amendments to push that anniversary warrant out. As we near the December 1st point you just referenced, with that anniversary warrant ultimately about to be issued, we are in discussions with High Trail. We are, of course, reporting very good results as part of the quarterly call here. As we consider what the next steps are, we're clearly evaluating many things. We're very supportive of working with High Trail, and they're supportive of our development plan; we believe an outcome will be available to us, and we'll be able to talk more about that as part of the year-end results.

All right, thanks.

Morning to you, Greg and Michael, along with everyone else on the Prairie team. Greg-