PEDEVCO Corp. (PED) Earnings Call Transcript

Thanks, operator, and good afternoon to all of you. I'd like to welcome you to PEDEVCO's earnings call for the third quarter of 2026. Joining me on this call are R.T. Dukes, our Interim President and Chief Executive Officer and Chief Operating Officer, along with Bobby Long, our Chief Financial Officer. Before we get started, I want to remind everybody that this discussion today contains forward-looking statements as defined under the federal securities laws, and those statements carry risks and uncertainties that may cause actual results to differ materially from what we expect. For additional detail, please see our Form 10-Q for the third quarter of 2026 along with our other SEC filings. Management is under no duty to refresh or amend forward-looking statements. During this call, we will additionally discuss specific non-GAAP financial metrics, such as Adjusted EBITDA. Reconciliations comparing these to the closest GAAP equivalents appear in our earnings release along with our 10-Q filing. Such non-GAAP figures must not be considered on their own or treated as a substitute for GAAP outcomes. Also note that all per-share amounts and share counts mentioned here reflect the 1-for-20 reverse stock split that became effective March 13, 2026, with retroactive application to every period shown. By September 30th, 2026, the company's common stock outstanding totaled approximately 13.3 million shares. The agenda for today is as follows. R.T. will start us off with a strategic and operational update, and after that Bobby will take us through our financial performance. Once our prepared remarks are done, the management team will open up the call for questions. With that said, I'll hand things over to R.T.

Thanks, Laurent, and good afternoon, everyone. Before we dive into the quarter, I want to take a few minutes to talk about where PEDEVCO is headed. Since I took on the interim CEO role in September, I've kept overseeing operations while the board runs its search for a permanent CEO. Having familiarity with both these properties and the teams running them, I feel good about what lies ahead for us to develop; we hold a substantial inventory throughout the Rockies, and we're concentrated on activating that inventory to generate robust output expansion in 2027 and subsequent years. This quarter, we finished a well in Wyoming's D-J Basin. We also drilled and operated a well in the Powder River Basin and grew our Mowry position in a region that has us especially enthusiastic. These represent concrete progress toward capturing the opportunities before us. But first, allow me to frame the quarter in context. We turned in a strong top line, bringing in $35.5 million of revenue, a bit better than what we had expected. We did post a net loss for the quarter, though that figure was heavily influenced by non-cash changes in our derivative positions. Adjusted EBITDA came in below the prior quarter, since both production and realized prices fell off from the second quarter. On the operations side, we experienced somewhat more downtime than we had budgeted, tied to our completion activity—including well work that we intentionally pulled forward into Q3 from Q4, which we believe will speed up the production gains going forward. I'll get to what the fourth quarter means in a moment, but that effort fits into a wider push to lift performance from our current wells and get ready for development down the road. Across the last year we've achieved a great deal; going forward we'll deploy more of the inventory we already hold in order to grow; operating control covers large parts of our acreage, and that allows us to decide where and when capital gets deployed; we can also join other operators in opportunities where the economics look attractive. Those chances will be weighed against our own projects, and our commitment to creating value for shareholders will not waver. We're moving toward plans that solidify our standing as a high-growth company next year, and further details will come after the CEO search concludes and plans are settled in early 2027; the sequencing is being worked through right now, including the choices required to get next year's activity ready. That planning will shape where we put investment and how our Rocky Mountain inventory becomes production growth. Beyond development plans, we're chasing acquisitions capable of bolstering our Rockies position and supporting growth later on. We'll keep assessing opportunities that suit our Rockies position and compete strongly for capital. The Mowry lease purchase illustrates well the sort of opportunity that draws our interest, since it adds acreage in an area we understand and intend to develop; we'll stay selective regarding what we go after and the price we pay. Because our current inventory is attractive, any acquisition must compete with our development portfolio within a reasonable timeframe. Now let me take you through the three basins and the work under way, beginning with production. Third quarter production came in at 538,231 BOE, or 5,850 BOE per day, which is 14% lower on an average daily basis than the second quarter. Volumes were affected by temporary shut-ins tied to drilling and completion activity in the D-J and Powder River Basin. Several rod conversions slated for the fourth quarter were also shifted into the third quarter; in addition, we divested non-core assets. That cut production by roughly 150 BOE per day, yet it lowered our well count considerably and trimmed the effort our staff devotes to mature assets. Temporary shut-ins plus accelerated conversions took almost 200 bbl of oil equivalent per day off during the quarter. The shut-in wells affected have come back on production since then. With those wells producing again, we anticipate stronger production sequentially in the fourth quarter; in the D-J Basin we hold about 85,898 net acres, an interest in 74 gross, or 66.9 net, operated wells, along with 110, or 12.5 net, non-operated wells. During the quarter we finished the Hastings well that had been drilled earlier. Completing it demanded offset shut-ins, so there was a near-term production effect from finishing that well. We're a couple of months into flowback now, assessing how the well performed and how the offset parent well responded, which will inform future investment choices in that area. We moved forward on multiple rod conversions in the D-J as well. That effort alters the way we produce from wells that are already in place, and the aim is to bring down recurring operating costs along with workover needs. When a well is taken offline for that modification, it has an impact on the current quarter, yet we assess the investment by what it can deliver across the well's remaining life. On a separate note, in July we divested a single non-core, non-producing location together with related acreage in Weld County for $2.5 million. Within the Powder River Basin, we hold roughly 183,829 net acres plus interests in 39 gross, or 28.2 net, wells, which includes 8 gross and 0.3 net non-operated wells. One new operated well was drilled by us during the quarter. Completion on that well is planned for near year-end, and first flowback is anticipated in early 2027. Also in the Powder River, we picked up about 5,678 net acres via a BLM lease sale for roughly $5.9 million. That essentially doubled our Mowry position in this particular prospect area, bringing it to about 12,000 net acres. Among the areas we expect to grow most in our portfolio, this ranks high. By expanding there, we gain additional operated spacing units and therefore more control over inventory, and it demonstrates our readiness to put capital into inventory we think can move our business ahead.

Regarding non-operated properties, three PRB wells that were finished recently started producing in early November, and more wells had been spudded before Q3 ended. That involvement gives us an additional channel of development work to go with what our operator program is doing. All told, our second half program, which carries into early 2027, spans roughly 15 gross wells, and those completions will stretch into next year too. We likewise closed the assignment of certain non-operated acreage under a settlement previously disclosed and divested some mature operated assets that no longer fit our high-growth priorities moving forward; those two deals explain the bulk of the drop in our Powder River acreage and well count since the second quarter. In the Permian Basin, we hold about 14,505 net acres along with interests in 38 gross, 34.5 net wells, every one of which we operate. Now, a few words about the optimization program. We are roughly halfway through it and anticipate finishing the remaining work in 2027. The team keeps performing at a high level and finished the 2026 program ahead of schedule. Beyond lift conversions, the effort involves compression optimizations and additional well cleanouts. These projects aim to bring down the cost of running the existing production base and, where it makes sense, to capture extra production at a comparatively low incremental cost. We still target over $10 million in annualized LOE savings once the program wraps up. More work lies ahead, and the benefits will accumulate as that work gets done. We also carried out more workovers in the third quarter than we did earlier in the year. Where we can, we attempt to plan that activity for the summer, when field conditions are at their best, and we stayed inside our internal workover and maintenance budget; that seasonal work helps keep existing wells productive as we get the next set of development opportunities ready. Looking forward, our near-term focus is the production recovery in the fourth quarter, ongoing non-operated activity, and wrapping up our near-term development plans. The inventory and the growth opportunity it offers a company of our size encourage us. Bobby will go over the updated capital guidance and how we are funding that activity. Bobby, over to you.

Thank you, R.T., and good afternoon to all of you. The third quarter showed the development and optimization work R.T. outlined, together with production and realized oil prices that came in below second-quarter levels; we paid down revolver borrowings even while putting capital into development and added leasehold. I'll go through each of those areas, starting with revenue and operating costs. Turning to our third quarter results, revenue came in at $35.5 million, which is up 411% from $7 million in the same period last year and down roughly 23% versus the second quarter. The year-over-year gain comes from the contribution of the expanded asset base plus a higher average realized oil price. Of that $28.6 million rise, $26.7 million was driven by greater sales volumes, while $1.9 million stemmed from higher realized pricing. Before derivatives, our average realized oil price stood at $83.81 per bbl, compared with $63.76 a year earlier and $94.07 in the second quarter. Total operating expenses were approximately $31.4 million, yielding operating income of $8.9 million, which includes a $4.7 million net gain on the sale of oil and gas properties. Within operating expenses, LOE accounted for $14.3 million and G&A for $4.9 million. In absolute terms, LOE declined from $16.4 million in the second quarter. G&A increased year over year, largely due to $2.1 million in severance tied to the leadership transition, plus higher payroll costs from a bigger organization. DD&A came in at $9.7 million, up $5.7 million from a year earlier, reflecting greater production and a larger asset base. In addition, we booked $2.4 million of impairment on the undeveloped D-J leases that we allowed to expire and don't intend to drill. Interest expense was $1.7 million, consisting of $1.5 million of interest on credit facility borrowings and $0.2 million of deferred financing cost amortization, versus $0.1 million of interest expense in the same period last year. Under the operating line, derivative contracts produced a net loss of $16.6 million, the biggest single item. Just like in prior quarters, I'd like to break that into its realized and unrealized components. We booked $4.6 million in realized settlement losses, which mirror settlements on our derivative positions; on top of that came a $12 million unrealized mark-to-market loss that is non-cash, driven mostly by commodity prices climbing from June 30th to September 30th on positions we held open. That $12 million unrealized figure is an accounting entry, not cash going out the door. Realized settlement losses remain within Adjusted EBITDA, while the unrealized portion gets excluded. The purpose of our hedge program is to curb cash flow volatility, safeguard the capital plan, and keep financial flexibility intact. Our hedge book contains swaps, costless collars, and three-way collars, so our price exposure differs across contracts. Certain participating collars give back part of the upside above $80 oil on the covered volumes; that said, it does not apply to the whole hedge book. After the quarter closed, we put on fixed-price crude oil swaps for roughly 400,000 bbl of production in 2027 and 2028, at weighted average prices of $77.45 per bbl on the 2027 volumes and $70.95 per bbl on the 2028 volumes. Those later additions are not reflected in the September 30th schedule in our release. On a GAAP basis, our net loss was $9.2 million, equal to $0.70 per share, compared with a net loss of $0.3 million in the third quarter of 2025. The swing reflects the fact that stronger operating income, which included the net gain on property sales, was more than offset by derivative losses and increased interest expense. Adjusted EBITDA reached $14.7 million, versus $4.3 million a year earlier and $18.7 million in the second quarter. Beginning with this quarter, severance costs, which came to $2.1 million, are also excluded from Adjusted EBITDA. Neither comparative period included any severance costs. You can find the complete reconciliation from net loss to Adjusted EBITDA in our earnings press release. Turning to the balance sheet and how we're allocating capital: at September 30th, cash on hand stood at $4.7 million, alongside restricted cash of $1.1 million. Over the quarter, we reduced what we owe under our senior secured revolving credit facility, bringing it to $80 million from $85 million as of June 30th — a $5 million paydown. At quarter end, we also had $45 million of availability to draw under that facility. Our borrowing base and elected commitments were reaffirmed at $125 million in October. Across the first nine months, operating activities generated net cash of $35.4 million. Drilling and completion costs consumed $30.3 million in cash, while leasehold acquisition took $6.1 million in cash. The cash outlays don’t line up with incurred capex, since payment timing and accruals create differences. From property sales, we collected $8.3 million in proceeds across the first nine months. On October 1st, we got the last $1 million installment tied to the Phoenix settlement. Incurred capital expenditures came to $23.3 million for the third quarter and $32.5 million year-to-date. That year-to-date figure broke down into roughly $17.6 million for development, $8 million for maintenance capital—mostly optimization—and $6.9 million for acquisition costs. Our full-year net capital expenditure guidance is being revised to $37 million-$42 million, which accounts for the Mowry lease acquisition plus development activity. We expect fourth-quarter spending to be concentrated mainly on our operated and non-operated Powder River Basin wells. Our guidance for full-year 2026 Adjusted EBITDA stays unchanged at $60 million to $70 million. Adjusted EBITDA came in at $51.5 million through September, and we still anticipate full-year production will land inside our guided range of 6,500 to 7,000 BOE per day. Thanks, everyone, for listening. I'll hand things back to the operator now for questions.

Good evening, and thanks for taking my question. I'd like to begin with the production growth you expect in 2027. How fast could you speed that growth up if you chose to? Are the constraints capital availability, permitting, timing, or something else? And I suppose you could connect that to any early outlook for CapEx spending in 2027. Is $10 million a quarter a good benchmark, or should it be somewhat lower once the Mowry lease is accounted for? Thank you.

Hey, Dave. R.T. Good to catch up with you. Very quickly, I think broadly speaking, we're going to put out far more detail once the CEO search wraps up, so you'll learn more around the end of the quarter going into Q4, perhaps with Q4 reporting. I think one way to think about our business going forward is that we're really pleased with the inventory we hold. We like the growth trajectory that we can see quite readily just by executing, just through normal blocking and tackling, let's go drill and complete some wells. You're going to see us plow our cash flow back into the business at a fairly aggressive rate. So that's probably not a bad starting point for this year in 2026, but I think we'll want to put more in the ground going forward.

Got it. Thanks for that. Could I just ask one quick follow-up, more to clarify something? You said certain shut-ins and rod pull cost you roughly 150 to 200 BOE per day, yet now you expect sequential gains from Q3 into Q4. Just so I'm sure I understand the logistics: bringing those wells back should more than offset the natural declines we typically see from one quarter to the next, producing that sequential BOE improvement, or is there something else we ought to be considering?

Yeah, Bobby may have the precise figures right there with him, but how I look at it is this: our guidance would more or less point to a flat Q3 to Q4, though clearly there's growth on the exit as those wells stay online for the whole quarter, and then we're putting a handful of wells on production. Some of them are already producing, with a couple more slated to come on before year-end. Really it's timing, once you hit the holidays and winter sets in, early winter, late fall, the timing tends to slip. At times you run into delays, but in the end you'll definitely see growth in the exit rate, and roughly flat quarter-over-quarter, judging by how our guidance reads.

That's great. I appreciate how clear that was, and best of luck in the coming quarter.

Thank you, Dave.

Good evening. Is this coming through okay?

Hi there, Nick, I'm hearing you fine. How are things going?