PEDEVCO Corp. (PED) Earnings Call Transcript & Summary

Thanks, operator. Good afternoon, all. Pleasure to have you join PEDEVCO's Q1 2026 earnings call. Joining me are Doug Schick, our President and Chief Executive Officer; R.T. Dukes, Chief Operating Officer; and Bobby Long, Chief Financial Officer. Prior to starting, I want to remind each of you that this conversation contains forward-looking statements as defined under the Federal Securities Laws, and those carry risks and uncertainties that might make actual outcomes differ materially from what we expect. For additional details, please see our Form 10-Q for the first quarter of 2026 along with our other SEC filings. No duty is assumed by the company to update or revise any forward-looking statements. On this call, we'll also cover some non-GAAP financial measures, such as Adjusted EBITDA and working capital, excluding derivative contract assets and liabilities. You can find reconciliations to the most directly comparable GAAP measures in our earnings release and 10-Q; these non-GAAP measures shouldn't be viewed on their own or as a replacement for GAAP results. I'd also like to point out that every per share and share count figure mentioned today accounts for the company's 1-for-20 reverse stock split that took effect March 13, 2026, applied retroactively across all periods shown. As of March 31st, 2026, roughly 13.3 million shares of common stock were outstanding for the company. Here's what we have planned. Doug will kick things off with opening remarks, then R.T. will provide an operational update. After that, Bobby will take us through our financial performance. Once our prepared remarks wrap up, the management team will open the call for questions. So with that, I'll hand things over to Doug.

Thanks, Laurent, and good afternoon, everyone. I appreciate you all joining us. During our first complete quarter operating as one entity after the Juniper merger, the results came in above what we had anticipated internally on every key metric. We averaged 8,091 BOE per day of production, brought in $40.2 million of revenue, and generated $21.5 million in Adjusted EBITDA. The 31 DJ Basin wells brought online in late 2025 largely outperformed their type curves, and that is what pushed production above our internal projections. Our costs matched what we had expected, and we achieved meaningful improvement in shrinking the working capital deficit that stood at year end. All told, Q1 showed a business carrying out the plan we described when the merger closed. Before going deeper into the quarter, I want to take a moment to discuss our review of development inventory, since I believe it demonstrates the depth and optionality this platform offers. Starting at the beginning of 2026, our team has been conducting thorough asset reviews in order to plan our future development work in late 2026, 2027, and beyond, with an emphasis on generating substantial value for our shareholders. Looking at the rest of 2026, in the DJ Basin we have one well that is drilled but uncompleted, where we hold more than a 90% working interest, and we intend to complete it and bring it online in mid-summer 2026. Beyond that, we remain in constant dialogue with our partners regarding additional 2026 development opportunities in the DJ Basin; in the Powder River Basin, we hold more than 200,000 net acres of early-stage multi-formation inventory, which we are moving through technical evaluation, with development decisions to come as we build further confidence in the highest return targets. In the Permian, our San Andres wells keep producing in line with what we expect, and we are assessing additional activity for the back half of the year. Across all three basins, any additional capital commitments will be weighed against our return thresholds, our liquidity position, and the strength of our balance sheet. When commodity prices are higher and stay that way, the return profile of our inventory shifts, but the discipline of our framework does not. The commodity price environment is favorable today, and if that continues, we have both the inventory and the operational capacity to respond. We will not put capital to work ahead of returns that justify it; even so, we are focused on creating value for our shareholders, and there are many ways for us to do that. We believe our inventory is among the deepest relative to our size of any publicly traded oil and gas company, and we intend to prove that over the quarters and years ahead. Turning to our first quarter results, I want to begin by addressing our net reported loss of $25.6 million. That number stemmed almost entirely from a $31.3 million net loss on derivative contracts, $27.9 million of which was a non-cash mark-to-market adjustment reflecting commodity prices moving above our hedge strike prices during the quarter. If you take out that one item along with other non-cash charges, the business produced $6.7 million in operating income and, even more significantly, $21.5 million in Adjusted EBITDA. We think the EBITDA figure is the best reflection of how the business actually performed during the quarter, and it marks a 404% jump compared with the $4.3 million we posted in Q1 2025. You can find the complete reconciliation going from GAAP net loss to Adjusted EBITDA in the press release. During the quarter, the balance sheet made a decisive move in the right direction. Our working capital deficit — setting aside current assets and liabilities tied to derivative contracts — got better by $27.1 million, going from $34.1 million at year end to $7 million at March 31st. That gain reflects the settlement of development capital and merger related payables that were still outstanding at year end, and it shows just how strongly the expanded asset base generates cash. Once you adjust for our cash on hand, which includes roughly $3.6 million of restricted cash that we expect will return to unrestricted status over the coming months, net debt at quarter end stood at approximately $87 million, which is $11 million under our funded debt of $98 million. We see this as a significant milestone. When we came out of the merger, we were carrying a meaningful working capital deficit driven by the transaction and the development program that was underway at closing. A quarter later, that hangover is mostly behind us, which leaves us with strong liquidity. WTI prices during the last couple of months have kept the company generating solid cash. Our costs landed where we expected across every category, which demonstrates efficient integration of the combined asset base. Per unit lease operating expense, including recurring and non-recurring lease operating expense, workovers, gathering, processing and transportation expense, and severance and ad valorem taxes, was $22.46 per BOE, basically flat versus the $22.21 per BOE recorded in the prior year. Total G&A came to $3.1 million for the quarter, while cash G&A was $2.6 million for the quarter, equal to cash G&A of $3.59 per BOE. Some residual merger integration costs were included in Q1 G&A. As those costs roll off over the rest of the year, we anticipate additional improvement. I'm also glad to share that every one of our capital expenditures incurred in Q4 2025 and paid in Q1 2026 tied to the 31 wells that were in process when the merger closed came in within or below our expectations. Now for production cadence, I want to be clear on what to expect for the rest of 2026, since I believe the context matters. Q1 got a boost from the timing of the 31 DJ Basin wells that came online in late 2025, all of which hit peak production in Q1 2026. Through the middle quarters of the year, production should moderate as those wells track their natural decline curves. Our second half development activity and optimization work should then support incremental volumes as we head into 2027. We anticipated that Q1 of this year would be a fairly strong quarter for production, and it's important to us that investors understand that. For the rest of the year, output is projected to decrease somewhat across the coming one to two quarters, and what we spend on development and what we achieve in the next several months will probably affect our production in the second half. Given approved net capital expenditures of $16 million-$20 million at present, our expectation for the full year remains average production of 6,500 BOE-7,000 BOE per day along with $60 million-$70 million of Adjusted EBITDA. Should our development and capital plans change later on, we will also share updated expectations for production and Adjusted EBITDA. Going forward, we stay committed to carrying out the optimization program, mapping out our future development plans, all while keeping capital discipline and turning the platform we have constructed into a durable Rockies-focused energy company as we enhance cash flow and returns for our shareholders. With that, I'll hand things over to R.T. Dukes.

Thanks, Doug, and good afternoon to all of you. My comments will stay centered on our operational position and the direction we're taking. What I want to convey for this quarter really comes down to a pair of items: the work already finished and the work still ahead of us. Regarding what's done, we spent $3.8 million in capital expenses this quarter across 10 non-operated DJ basin wells, where our working interests fall somewhere between roughly 1% and 6.3%. Production is underway on all 10. Stepping back, we remain disciplined about managing our acreage position. Our portfolio offers a substantial runway, and our focus and capital will keep flowing toward the inventory we plan to develop soon. Turning to what's next in the DJ, we intend to begin completion operations on one drilled but uncompleted well in Wyoming, where our working interest exceeds 90%. We expect first production in early Q3, giving a clean boost to second half volumes. We're always reviewing non-operator proposals from nearby operators and will join in when the economics work; in the Powder River Basin, our acreage totals roughly 202,000 acres. The first quarter saw no operated drilling and completion work, and output beat the company's internal plan, with no significant downtime or operational problems, as the asset gained from a fairly mild winter. The company keeps assessing inventory development chances throughout its sizable PRB position. On top of that, the company holds about 14,505 net acres in the Permian Basin; during the first quarter, no development activity took place, and the asset met internal expectations. The company kept enhancing operational efficiency by speeding up lift conversions, which lowered operating costs sooner than planned. The company keeps reviewing optimization and development possibilities for the back half of 2026. Now, the remaining piece of the operational story I want to address is our optimization program, since I believe it's essential to what it can deliver for our cost structure down the road. The $10 million-$13 million set aside in our operational optimization budget for 2026 targets a handful of areas. First, pump conversions, shifting wells from jet pump and ESP to rod pumps, which come with significantly lower operating costs and reduced ongoing workover obligations. Beyond that, we're targeting well interventions and well cleanouts on wells where we see incremental production available at low incremental cost. Put simply, we're switching wells to cheaper lift systems and selectively intervening in wells where we think additional production can be recovered at low incremental cost. Once achieved, these recurring cost savings persist. They appear in LOE every period after that. The aim throughout is to bring down total lease operating costs across the combined asset base. Via our 2026 and 2027 optimization programs, we're targeting LOE reductions capable of reaching as much as $1 million per month in cost savings. With this initiative scaling up during the third and fourth quarters, we anticipate seeing meaningful gains in overall lease operating expenses, and the complete advantage should become clearer in 2027. Regarding the schedule, we got this effort underway and developed the proof of concept in late 2025, kept pushing it forward and planning throughout the first quarter, and have stepped up activity even more this spring, since field conditions have permitted it. Most of the effort is going to get finished across the third and fourth quarters, and the LOE upside will build during the back half before showing up more completely in 2027. That ordering is deliberate, not something being put off. Our team has put in serious effort to expand and get the most out of our program, and that effort is now showing up more and more in the pace of activity we anticipate over the rest of the year. The bottom line when it comes to operations is that the asset base is delivering at or above what we expected on every front. Integration keeps moving forward, and we have a clear view toward a cheaper, more profitable operating profile as the year unfolds. Our optimization work is built to compound during the back half, and the expense savings will serve as the evidence we can show investors across the coming quarters. With that, I'll turn things over to Bobby.

Thanks, R.T., and good afternoon to all of you. I'll take you through the main financial points for the quarter, zeroing in on what drove the numbers instead of restating figures Doug and R.T. have already gone over. Beginning with our first quarter results, revenue came in at $40.2 million for the quarter, which is up 360% from $8.7 million in Q1 2025; that growth is nearly all attributable to volume. This marked the first complete quarter with a combined asset base, and the production outperformance R.T. described carried straight through to the top line. Oil made up $36.6 million of total revenue, or approximately 91%, with the remainder divided between natural gas at $1.9 million and NGLs at $1.8 million. Our realized oil price was $68.39 per bbl, roughly unchanged versus the prior year. Gas and NGL realizations came in below the prior year period, which mirrors the wider commodity price environment for those products, although their contribution to total revenue is modest. Total operating expenses came to $33.5 million, producing operating income of $6.7 million. Inside that figure, LOE was $16.4 million and G&A was $3.1 million, and both have been addressed by R.T. and Doug. DD&A was $12.5 million, pushed higher by increased production volumes on the expanded asset base. We also booked a $1.6 million non-cash impairment on the DJ Basin acreage that expired. Nothing unexpected in the operating cost structure. Below the operating line, the notable item was a $31.3 million net loss on derivative contracts. I'd like to break this into two components clearly, since they differ greatly in nature. The realized portion, tied to positions that settled during the quarter on an income statement basis, was a loss of $3.4 million because realized crude oil prices came in above the fixed prices in our contracts; on a net cash basis, derivative settlements in the quarter were a small inflow, since not all settled positions had cleared cash by quarter end. The gap between income statement timing and cash settlement timing shows up on our balance sheet and should normalize across the next several periods. The unrealized portion, tied to non-cash mark-to-market on our open positions, was a loss of $27.9 million, mirroring how oil prices moved above our hedge strike prices during the latter part of Q1. That $27.9 million is an accounting entry rather than a cash outlay, since our hedge positions are mark-to-market every quarter. Adjusted EBITDA of $21.5 million, which adds back the non-cash derivative loss along with other non-cash and non-recurring items, is the measure we believe best captures how the business actually performed; as for the structure of our hedge book, our position is balanced across swaps, costless collars, and three-way collars. The aim of the program is to reduce cash flow volatility, protect the capital plan, and ensure project economics. While our credit facility requires us to maintain a certain level of hedging, we would expect to carry a prudent hedge position even without funded debt, given how important it is to protect cash flow and maintain flexibility around our development activities. Moving on to cash flow, operating activities provided net cash of $10.5 million during the quarter. This shows solid cash margins stemming from our larger production base, though that was partly offset by roughly $10.7 million of cash used for working capital, mostly tied to settling accounts payable that had been carried over from year end 2025. Drilling and completion costs paid in cash came to $16.5 million, and that figure includes about $3 million in carryover payments from the 2025 program. Looking at it on an accrual basis, our 2026 capital spend is tracking inside the guidance range. During the quarter we drew $11 million under the revolving credit facility to fund non-operated well participation along with other obligations. As of March 31st, total cash and restricted cash stood at $11.3 million, with $98 million outstanding under our revolving credit facility against a $120 million borrowing base, which leaves roughly $22 million of availability. The $3.6 million of restricted cash is tied to bonding requirements and is expected to be released within the next 90 days. To be specific, that $3.6 million is a leftover from pre-merger surety bond requirements that had been cash collateralized. After the merger, we put a new surety program in place that does not call for cash collateral. If you adjust for total cash and restricted cash, net debt at quarter end came to approximately $87 million, and total liquidity was approximately $33 million. Thank you for your attention. I will hand it back to the operator for questions.

Evening, guys.

Hey, Nick. How are you?

Good, good. I've got a few things to ask you about. R.T., I believe you were talking about how CapEx is divided, and the effect of that optimization CapEx you're considering. In Q1, I was wondering how much of the CapEx spending — like, how far have you all progressed on the optimization CapEx up to now, since I realize it's only been a brief stretch of time since the companies came together, but I'm just curious how much of that you all have managed to get into so far.

Yeah. Nick, we truly began in earnest during Q2. Just a general update: two wells were converted by us to rod pump in Q1, under budget and performing as planned, and we're really pleased with where things stand. Solid momentum this quarter too.

And just, when I look at, say, what workover expenses came in at for the quarter, it appears, you know, that was a, you know, smaller figure compared with how those were trending in Q4. I guess, does that sort of connect to the same sort of getting things underway more seriously? Because I'd imagine there are some links between that workover line item and, you know, a portion of the optimization CapEx work. I'm just wondering, as you sort of examine the field and as you've sort of brought assets together here, you know, a bit of that sort of easy win on the cost side, where those stand and how that could shape up later on.

Yeah. A few items there. The winter was fairly mild, and beyond that, we devoted a couple of years to truly getting the fields ready, really following a cold winter a couple of years back, and we had solid reliability. It sort of demonstrated what we believed, ensuring our wells remained online through, you know, the chillier periods in winter and in the Rockies matters. We've put in effort so our operations hold up, and I believe that's visible. No significant problems during the winter; we intentionally aim for that and work to ensure strong reliability in winter. If there are preventive steps available to take in Q4, ahead of the colder stretch of the year, we take them. I think that shows up in Q1.

R.T., and just to build on what was said — Nick here — that's part of the reason our optimization projects tend to be scheduled mainly for spring, or for fall or spring, summer and fall: it keeps us from being out there in the middle of winter.

Understood. I'm just hoping to get a bit more clarity regarding those development plans all of you mentioned. So, you know, after that gets going, I believe the team said there's 1 DUC being worked over in Wyoming, and then, is it the rest — or actually, hold on, yeah, that 1 DJ DUC, is that right?

That's right.

My apologies. What I'm trying to get at is how things break down between DJ and Powder River when you consider that plan for development in the second half.