PEDEVCO Corp. (PED) Earnings Call Transcript & Summary

Thanks, operator, and good morning, everybody. I'd like to welcome all of you to the earnings call for PEDEVCO covering the fourth quarter and the full year 2025. Joining me on this call are Doug Shick, our President and Chief Executive Officer, R.T. Dukes, our Chief Operating Officer, and Bobby Long, our Chief Financial Officer. Before we get started, I want to remind all of you that what we discuss today contains forward-looking statements that carry risks and uncertainties, and those could make actual results come in materially different. If you want more detail, please look at our 2025 Form 10-K along with our other SEC filings. The company has no obligation to update or revise any forward-looking statements. On this call, we may also talk about certain non-GAAP financial measures, adjusted EBITDA among them. You can find reconciliations to the most directly comparable GAAP measures in our earnings release and our 10-K filing. These non-GAAP measures shouldn't be viewed on their own or as replacements for GAAP results. I'd also point out that every per share and share count figure mentioned today reflects the company's one-for-20 reverse stock split, which took effect on March 13, 2026, and has been applied retroactively across all periods presented. On March 27, 2026, the company had 13,300,621 shares of common stock outstanding. As many of you are aware, this marks PEDEVCO's first earnings call as a combined company, coming after the Juniper merger closed on October 31st, 2025. Today you'll hear about the reported results as well as the normalized earnings power of the combined platform, and we think that second lens is the more relevant one for evaluating the company going forward. Here's the agenda for today. Doug will start us off with opening remarks covering the company's strategy and investment case, then R.T. will give an operational update, and after that Bobby will take us through our financial performance. Once our prepared remarks are done, the management team will open the call up for questions. With that, I'll hand things over to Doug.

Thanks for that, Laurent, and good morning, everyone. We appreciate you joining us for this initial quarterly report following the combination of the two businesses. For PEDEVCO, 2025 was a period of significant transformation. Upon completion of our merger with the Juniper portfolio companies on October 31st, we built an energy platform of substantial scale focused on the Rockies, which we believe is distinct among publicly traded oil and gas companies due to a development inventory that is sizable compared to our market cap. We went from about 1,500 barrels of oil equivalent per day of production to a combined average exceeding 5,300 BOE per day in the fourth quarter. Proved reserves nearly doubled, hitting 32.1 million BOE, equivalent to roughly $27 per share on a post-split basis. In the DJ Basin, Powder River Basin, and Permian Basin, we possess over 310,000 net acres, with a liquids mix around 88% and well beyond ten years of identified inventory. The value our independent reserve engineers placed on proved reserves provides a useful floor when talking about asset value, and that number excludes over 1,000 other identified drilling locations, most of which are high-impact wells suited to pad drilling across multiple formations, allowing us to optimize efficiency and cash returns on the capital we invest. I also want to point out how unified this company is. Insiders, including the management team, own a substantial majority of PEDEVCO, so our priority is increasing shareholder value while managing risk. Juniper Capital, our largest investor, is a seasoned oil and gas private equity firm with over 20 years of experience investing in this industry. At the time of the merger, Juniper contributed about $18.6 million in new equity, demonstrating their strong confidence in what this company can accomplish. Now to our fourth quarter results — remember that because the merger closed on October 31, our reported figures include only a partial contribution from the acquired assets. In the fourth quarter, adjusted EBITDA was $15.4 million on production of more than 5,300 barrels of oil equivalent per day, reflecting the early phase of combined operations. Bobby will walk you through the full bridge and our 2026 expectations, but here's the main takeaway. Even as realized crude oil prices fell 16% year-over-year, fourth quarter adjusted EBITDA rose 203% from the prior year, which highlights both the merger's impact and the underlying operational strength; growing larger was never the sole purpose of this merger. The purpose was to achieve scale and add new capabilities to the team, driving efficiencies and further growth. Our production and cash flow base now enables us to operate this business more efficiently and achieve strong margins, while using internally generated cash flow to continue developing our extensive asset base. Equally important, the core business can stand alone. As of March 27, 2026, the company had 30,300,621 shares of common stock outstanding. Acquisitions aren't necessary for this to be a solid enterprise, since the development inventory already on hand is quite vast. Looking ahead, purchases are intended to build on the foundation already in place. Any time we evaluate acquiring something, we ask whether it enhances the efficient operation we run today — one generating considerable cash flow and maintaining a large pipeline of attractive development prospects. Every transaction is judged against the opportunities already ours; throughout all 3 basins we hold significant development upside, and we'll advance it at a pace aligned with financial discipline. Both leadership and our major stockholders want this to remain a robust enterprise able to perform well regardless of where commodity prices stand. Regarding what lies ahead, our priorities are straightforward. First, continue optimizing operations — driving costs down and boosting margins across the entire asset base. We're equally focused on ranking our enormous set of development opportunities, seeking the greatest risk-adjusted return achievable on capital deployed over many years. With over 1,000 identified drilling locations across 3 basins and more than a dozen formations, we have substantial flexibility regarding where capital is directed. Here's a clear message for investors about what matters to us. First, cash realized per bbl produced will rise during 2026 as the optimization projects now underway keep strengthening our cost structure. Second, we'll execute a capital plan delivering solid returns on capital while keeping the balance sheet strong. And finally, PEDEVCO will preserve and expand its deep inventory of development opportunities, which we intend to describe in greater detail across upcoming quarters. When we consider 2026, the macro backdrop has turned more favorable these last few weeks, as geopolitical events push oil prices higher. Even so, nothing about our approach shifts. The plan we're building doesn't hinge on commodity prices cooperating. What drives us is squeezing the most efficiency from every bbl produced and every dollar spent, all while delivering steady cash flows through cycles. Should today's pricing persist, that hands us added upside — for cash flow and for how quickly we can carry out development plans. Our capital allocation stays disciplined, and we'll grow activity only to the extent the business can handle it; with that, I'll hand things over to R.T. Dukes. As of March 27, 2026, the company had 30,300,621 shares of common stock outstanding.

Appreciate that, Doug, and good morning to all of you. I'd like to begin with what we see as the easy wins — the high-return work we kicked off right when the merger closed: optimizing costs on the production base we already have. I'll walk through the main operational points. Looking toward 2026, one of our top priorities is definitely carrying out a wide-ranging cost optimization effort across our assets. Once we closed the transformative merger with Juniper's Rocky portfolio late last year, our company's scale and production grew substantially, and that gave us a chance to improve our overall cost structure. To be specific, we've pinpointed roughly $10 million-$13 million of capital projects that we think will deliver meaningful lease operating expense, or LOE, reduction. That covers items such as swapping high-cost jet pumps for more efficient rod pumps, plus compression optimization projects, recompletions and well cleanouts. We anticipate these projects will cut our LOE by as much as $1 million per month, which works out to $10 million-$12 million in yearly savings. To give you a sense of where things stand, we've started carrying out several of these optimization initiatives in the DJ Basin, including the first pump conversions and well work; this is an active, ongoing effort with identified projects and a clear plan of execution. As we progress through 2026, we expect steady advancement across these work streams and to start seeing the effect on our cost structure and margins. We'll give updates on that progress every quarter. Now shifting to operations. The DJ Basin is the biggest production base for the combined company; we hold roughly 100,000 net acres spanning southeastern Wyoming and northern Colorado. The DJ provided the large majority of Q4 and full-year production and is where most of the current 2026 capital budget is presently expected to go. During 2025 in the DJ Basin, we took part in 32 wells, 31 of which started producing in late 2025, while one operated well will be completed in 2026. Among the 31 new wells that came online in late 2025, two were operated and 29 were non-op. In the Permian Basin, we drilled and completed four operated wells in 2025. On the production side, a couple of points deserve highlighting. The development work that began before and around the merger close is now paying off. 31 of the 32 wells that were in progress at closing are online and producing, and the development program is performing well. That activity is boosting production in Q1 2026, since those wells remain in their flush production phase. In fact, it's important to remember that Q1 will probably be a peak production quarter for 2026. With so many wells brought online in such a short span, this isn't a run rate that should be annualized for us for the year. When those wells go through their decline curves, our expectation is that output will level off near the rates tied to the merger date, roughly 6,400 to 6,500 BOE per day, prior to factoring in natural declines from new activity. Thanks to the merger, we picked up more than 200,000 additional net acres in the Powder River Basin. That position has a longer time horizon, with substantial resource potential spanning several formations, among them the Parkman, Sussex, Niobrara, Turner, Mowry, Teapot, Shannon, and Frontier. Since break-even oil prices in certain of those formations run as low as $30 per bbl, other operators active in the area are already pursuing many of them on offset acreage, including some of the biggest and most advanced oil and gas companies such as EOG, Devon, Oxy, and Continental, among others. Commodity prices, cash flow, and our expected returns—which we keep updating in light of third-party drilling results close to our assets—will determine when we develop in the PRB; when it comes to the Permian, we hold about 14,000 net acres on the Northwest Shelf, where the San Andres formation is our main target. This asset gives us a long-term, low decline, oil-concentrated holding that delivers steady cash flow. Production is still tracking in line with what we anticipated. Throughout the portfolio, we concentrate on preserving flexibility, keeping costs in check, and directing capital toward the highest return opportunities. With that summary, I'll hand things over to Bobby.

Thanks, R.T., and good morning to all of you. There are four topics I'll walk through today. First, how we performed financially in the fourth quarter and across full year 2025; second, what we expect in 2026; third, our balance sheet along with the framework for liquidity; and fourth, our capital program. Beginning with the quarter four results, revenue came in at $23.1 million, Adjusted EBITDA was $15.4 million, and production totaled 483,159 BOE. What these figures show is two months of contribution from the assets we acquired after the merger closed on October 31, and they offer the clearest picture of the combined platform. Under GAAP, the reported numbers include a number of items connected to the merger and the transition. For the entire year, we posted a net loss of $10.4 million. That was driven by $7.5 million in non-recurring merger costs, $8.1 million of deferred income tax expense, $1.4 million of interest expense tied to our credit facility, a $1.4 million write-off on a note receivable, and $2.8 million of additional accelerated share-based compensation; gains on derivatives and asset sales partly offset those items. Adjusted EBITDA strips out the non-cash and non-recurring items, giving you a clearer picture of how the business is operating. On unit economics, direct LOE for the full year came to 11.62 per BOE, which is up from 10.36, and the entire increase stems from higher costs on the acquired assets. As our optimization work kicks in, we anticipate per unit LOE will come down over the course of 2026, and by the middle of the year the improvement should be clear. Cash G&A, once merger costs are excluded, ought to land in the $3.50-$4 per BOE range, since a bigger production base will absorb overhead. Moving to what we expect in 2026, as our earnings release mentioned, we project full year 2026 Adjusted EBITDA between $60 million and $70 million. That range rests on average realized oil prices of $65 per bbl and average realized gas prices of $3.50 per Mcf, and it incorporates the capital program we currently expect. Let me be precise about what that range does and doesn't include. It factors in the base production profile along with the benefit from our cost optimization efforts. It does not factor in any incremental operated development past what we've already planned. Should we decide to go after additional high return development, that range would have upside. This is a good illustration of the company's flexibility. Given our deep inventory, we have plenty of levers available to boost returns to shareholders. Now to the balance sheet. As of December 31st, we had $87 million drawn on our senior secured revolving credit facility, which is led by Citibank. That facility carries a $120 million borrowing base within a $250 million maximum commitment and comes due October 31, 2029. Since year-end, we've drawn another $11 million, which puts the total at $98 million as of February 5, 2026, leaving roughly $25 million of total liquidity. The spring redetermination will give us an updated view of borrowing base capacity. Onto the capital program. For 2026, the capital expenditures we currently know of total $16 million-$20 million: approximately $6 million-$7 million for DJ Basin drilling completion capital, which includes roughly $3 million of 2025 carryover, and approximately $10 million-$13 million for the optimization projects RT described. Roughly 90% of the capital budget right now is going toward the DJ Basin. That said, as we mentioned earlier, those amounts and how they're allocated will probably be adjusted as time goes on. Our plan is to fund the program using cash from operations, cash we already have on hand, and availability under our facility. With oil at $65, we're estimating a leverage ratio of about 1.2 to 1.3x net debt to EBITDA as we close out the year. Should we decide to grow the capital program, those choices will be driven by commodity prices, cash flow, and our dedication to keeping leverage conservative. Broadly speaking, our aim is to hold leverage at 1.5x or below while using conservative commodity price assumptions. We're not making a commitment right now to accelerating development in the second half, but we are looking at options for operating development. Once our cost optimization is fully ramped and the combined platform delivers a full year of cash flow, we anticipate this company's financial profile will improve substantially as we move into 2027. Thanks, everyone, for your time. I'll hand it back to the operator now for questions.

Hey, good morning, everyone.

Morning, Nick..

I'm a bit interested in the capital plan. Clearly, commodity prices have been rather high lately. So what would it take, I wonder, to shift toward greater activity? Specifically in the DJ Basin, how prepared is Devon right now to ramp up operations if these stronger prices stick around longer, and that turns into something you all would want to chase — just more drilling in that area? How ready are you, I suppose? Are the pipelines set? Are the rigs set? If you all choose to make that move at some point, how much time would shifting to greater activity require?

Yeah. Nick, given where prices stand today, we're conducting thorough asset evaluations regarding what our development programs for the second half of 2027 will look like. Especially in the DJ Basin, there's room to bring a rig online fairly fast — not within the coming month, but within the coming few months, should that chance arise. Beyond that, we have substantial partner-run developments that might land on us during 2027's second half in the DJ Basin. There's There's considerable room to grow both the development program and the CapEx program should prices justify it, and should the curve — you know, should backwardation in the curve flatten out somewhat.

When it comes to permits, how long does it take to be ready on that front? And I suppose, is there a difference between the two sides of the Colorado–Wyoming line?

Yes, the two sides of the border are not the same, correct? Things move much more slowly in Colorado. There's a single permitted DSU we hold — that's 6 to 7 wells, and it's actionable. Right now we've got a second DSU working its way through as well. That one, you know, amounts to 12 to 13 wells that might be set within the next, let's say, 6 to 9 months; over in Wyoming, we've got a few infill chances at our North Silo field. On top of that, every one of our partner-operated projects sits in Colorado, and you know, development of those isn't really under our control. A portion of those AFEs will probably land on our desk during the back half of the year and on into 2027 too.

So shifting our attention to the Powder River Basin now, I suppose, what remaining actions exist when it comes to assessing that resource along with its upside? As I recall, R.T., you touched on this somewhat. I suppose which uncertainties still stand regarding grasping that resource, and perhaps, you know, it seems like perhaps a 2027 or maybe later, sort of a scheme to sort of aim for additional operations in that area. Wondering which actions are still outstanding there to sort of grasp the upside.

A number of spots in that area can be acted on earlier than 2027 to 2028. Even so, at present we are in the middle of our asset reviews in order to genuinely grasp that asset. You know, we are pursuing a handful of distinct zones that we regard as extremely promising, yet we have nothing to announce regarding anything, you know, any sort of development scheme in that area over the coming six months.

Understood. Fine. That's excellent. Thanks for making room for us, everyone.

Appreciate it, Nick.