Good afternoon and welcome to DEVCO's Corp.'s third quarter 2026 earnings conference call. All participants are in a listen-only mode. After the prepared remarks, we will open the call for questions. I would like now to turn the call over to Laurent Weil of Elevate IR. Please go ahead.

Thank you, operator, and good afternoon, everyone. Welcome to Pedevco's Third Quarter 2026 Earnings Call. With me today are R.C. Dukes, Entering President and Chief Executive Officer and Chief Operating Officer, and Bobby Long, Chief Financial Officer. Before we begin, I'd like to remind everyone that today's discussion includes forward-looking statements within the meaning of the federal securities laws subject to risks and uncertainties that could cause actual results to differ materially from expectations. For more information, please refer to our third quarter 2026 Form 10-Q and other SEC filings. The company undertakes no obligation to update or revise any forward-looking statements. During today's call, we will discuss certain non-GAAP financial measures, including adjusted EBITDA. Reconciliations to the most directly comparable GAAP measures are available in our earnings release and 10-Q filings. These non-GAAP measures should not be considered in isolation or as substitutes for GAAP results. I would also like to note that all first share and share count figures referenced today reflect the company's 1-4-20 reverse stock split effective March 13, 2026, applied retroactively to all periods presented. As of September 30, 2026, the company had approximately 13.3 million shares of common stock outstanding. Here is today's agenda. RFC will begin with a strategic and operational update, and then Bobby will walk through our financial performance. After our prepared remarks, the management team will open the call for questions. With that, I will turn it over to RT.

Thank you, Laurent, and good afternoon, everyone. Before we get into the quarter, I want to spend a few minutes on where Pedevco is headed. Since taking on the interim CEO role in September, I've continued to oversee operations while the board conducts its search for a permanent CEO. I know these assets and the people behind them, and I'm encouraged by what we can build from here. We have a deep inventory across the Rockies, and our focus is on putting that inventory to work to drive strong production growth in 2027 and beyond. This quarter, we completed a well in the DJ Basin in Wyoming. We drilled and operated well in the Powder River Basin and expanded our Maori position in an area we're particularly excited about. Those are tangible steps towards executing on the opportunities we see ahead. Before I get into that, let me put the quarter in perspective. We delivered a Solid top line results, generating $35.5 million in revenue, which is slightly ahead of our expectations. We did report a net loss this quarter, but the result was significantly affected by the non-cash movement in our derivative positions. Adjusted EBITDA was lower sequentially as production and realized oil prices declined from the second quarter. Operationally, we had a little more downtime than we budgeted related to our completion activity, and including well work we deliberately brought forward into Q3 from Q4, which we expect to accelerate the increased production benefits going forward. I'll explain the fourth quarter implications shortly, but that work is part of a broader effort to improve performance across our existing wells and prepare for future development. Over the past year, we've made substantial progress. We will put more of our existing inventory to work to grow going forward. We have operating control across substantial portions of our acreage. which lets us make choices about where and when we deploy capital. We also have opportunities to participate alongside other operators where the economics are attractive. We'll evaluate those opportunities against our own projects and we'll remain steadfast in our focus on value creation for our shareholders. We are working towards plans to cement our place as a high growth company in the coming year and we'll release more details once the CEO search is complete and plans are finalized in early 2027. We're working through the sequencing now, including the decisions needed to prepare for next year's activity. That planning will guide where we invest and how we turn our Rocky Mountain inventory into production growth. Alongside our development plans, we're pursuing acquisitions that can strengthen our Rockies position and support future growth. We'll continue evaluating opportunities that fit our Rockies position and compete well for capital. The Maori lease purchase is a good example of the kind of opportunity that interests us. adding acreage in an area we know and want to develop. We'll remain selective about what we pursue and what we pay. Our existing inventory is attractive, so acquisitions have to compete with our development portfolio in a reasonable timeframe. Let me now walk through the three basins and work we're doing starting with production. Third quarter production was 538,231 BOE or 5,850 BOE per day. Down 14% on average daily basis from the second quarter. Temporary shut-ins associated with drilling and completion activity in the DJ and Powder River Basin affected volumes. We also moved several rod conversions originally planned for the fourth quarter into the third quarter. We also sold non-core assets. While reducing our production by approximately 150 BOE per day, it decreased our well count significantly and reduced our staff's efforts dedicated to mature assets. Temporary shut-ins and accelerated conversions curtailed almost 200 barrels of oil equivalent per day during the quarter. The affected shut-in wells have since returned to production. With those wells back online, we expect sequentially stronger production in the fourth quarter. In the DJ Basin, we hold approximately 85,898 net acres and interest in 74 gross or 66.9 net operated wells and 110 or 12.5 net non-operated wells. During the quarter, we completed the previously drilled Hastings well. That completion required offset shut-ins, so there was a near-term production impact associated with completing that well. We're in the first couple of months of flow back, evaluating results from the well and the offset parent well response for future investment decisions in the area. We also accelerated several rod conversions in the DJ. This work changes how we lift production from existing wells. With the objective of lowering recurring operating costs Tuck Dukes, Robert Long are 28.2 net wells, including eight gross 0.3 net non-operated wells. We drilled a new operated well in the quarter. That well is scheduled to be completed near year end and is expected to start flowing back in early 2027. In the Powder River, we also acquired approximately 5,678 net acres through a BLM lease sale for approximately 5.9 million. That nearly doubled Our Maori position in this specific prospect area to approximately 12,000 net acres. It is one of the highest growth areas we anticipate in our portfolio. Expanding there gives us more operated spacing units where we can control more inventory, and it reflects our willingness to invest in the inventory that we believe can drive our business forward. On the non-operated side, recently three completed PRB wells began contributing production in early November, and additional wells were spud before the end of Q3. that participation adds another source of development and activity alongside our operator program. In total, our second half program that spills over into early 2027 covers approximately 15 gross wells with those completions extending into next year as well. We also completed the assignment of some non-operated acreage under previously disclosed settlement and sold some mature operated assets that don't align with our high growth priorities going forward. Those two transactions account for most of the reduction in our Powder River acreage and well count since the second quarter. In the Permian Basin, we hold approximately 14,505 net acres and interest in 38 gross, 34 and a half net wells, all of which we operate. Now a word on the optimization program. We're approximately halfway through the program and expect to complete the remaining work in 2027. The team has continued to deliver at a high level completed the 2026 program ahead of schedule. Along with lift conversions, the work includes compression optimizations and other well clean outs. These projects are intended to lower the cost of operating the existing production base and where appropriate capture additional production at a relatively low incremental cost. We continue to target more than 10 million of annualized LOE savings once the program is complete. There is more work ahead and the benefits will build as the work is completed. We also performed more workovers in the third quarter than earlier in the year. When possible, we try to schedule that activity during the summer when field conditions are the best, and we remained within our internal workover and maintenance budget. That seasonal activity is part of keeping the existing wells productive as we prepare the next group of development opportunities. Looking ahead, our immediate focus is on the production recovery in the fourth quarter, continued non-operated activity, and finalizing our near-term development plan. We're encouraged by the inventory and the growth opportunity it provides accompanying our size. Bobby will cover the updated capital guidance and how we're funding that activity. Bobby, over to you.

Thank you, RT, and good afternoon, everyone. The third quarter reflected the development and optimization activity RT described alongside lower production and realized oil prices than in the second quarter. We reduced revolver borrowings while investing in development and additional leaseholds. I'll walk through each of these areas, beginning with revenue and operating costs. Starting with our third quarter results, revenue was $35.5 million, up 411% from $7 million in the prior year period and down approximately 23% from the second quarter. The year-over-year increase reflects the contribution from the expanded asset base and a higher average realized oil price. Of the $28.6 million increase, $26.7 million was and others. Our average realized oil price before derivatives was $83.81 per barrel compared to $63.76 a year ago and $94.07 in the second quarter. Total operating expenses were approximately $31.4 million resulting in operating income of $8.9 million including a $4.7 million net gain on the sale of oil and gas properties. Within operating expenses, LOE was $14.3 million and GNA was $4.9 million. LOE declined from $16.4 million in the second quarter on an absolute basis. The year-over-year increase in GNA primarily reflects $2.1 million of severance costs associated with the leadership transition and additional payroll expense associated with the larger company. DD&A was $9.7 million of $5.7 million year-over-year driven by higher production and expanded asset base. We also recorded $2.4 million of impairment expense related to the undeveloped DJ leases that we allowed to expire and do not plan to drill. We recorded $1.7 million of interest expense consisting of $1.5 million of interest on credit facility borrowings and 0.2 million of amortization of deferred financing costs, compared to 0.1 million of interest expense in the prior year period. Below the operating line, the most significant item was 16.6 million of net loss on derivative contracts. As in prior quarters, I want to separate the realized and unrealized components. We recorded 4.6 million of realized settlement losses, reflecting settlements on our derivative positions. We also recorded a $12 million non-cash unrealized mark-to-market loss, primarily reflecting the increase in commodity prices from June 30th to September 30th on our open positions. The $12 million unrealized loss is an accounting entry, not a cash outflow. Realized settlement losses remain included in adjusted EBITDA. The unrealized loss is excluded. The purpose of our hedge program is to reduce cash flow volatility protect the capital plan, and maintain financial flexibility. Our hedge book includes swaps, costless collars, and three-way collars, so our price exposure varies across contracts. Some participating collars restore a portion of the upside above $80 oil on the covered volumes. However, that does not apply to the entire hedge book. Subsequent to quarter end, we added fixed-price crude oil swaps covering approximately 400,000 barrels of production in 2027 and 2028 at weighted average prices of $77.45 per barrel for the 2027 volumes and $70.95 per barrel for the 2028 volumes. The September 30th schedule in our release excludes those subsequent additions. Gap note loss was $9.2 million or $0.70 per share. compared to a net loss of $0.3 million in the third quarter of 2025. This higher operating income, including the net gain on property sales, was offset by derivative losses and higher interest expense. Adjusted EBITDA was $14.7 million compared to $4.3 million in the prior year period and $18.7 million in the second quarter. Beginning this quarter, adjusted EBITDA also excludes severance costs, which totaled $2.1 million. There were no severance costs in the comparative periods presented. The full reconciliation from net loss to adjusted EBITDA is included in our earnings press release. Turning to the balance sheet and capital allocation, at September 30th, we had cash on hand of $4.7 million and restricted cash of $1.1 million. During the quarter, we reduced borrowings under our senior secured revolving credit facility to $80 million from $85 million at June 30th reflecting a $5 million pay down. We also had $45 million of funding availability under the credit facility at quarter end. In October, our borrowing base and elected commitments were reaffirmed at $125 million. For the first nine months, net cash provided by operating activities was $35.4 million. Cash paid for drilling and completion costs was $30.3 million, and cash paid for leasehold acquisition was $6.1 million. Those cash payments differ from capital expenditures incurred because of the timing of payments and accruals. We received $8.3 million of proceeds from property sales during the first nine months. The final $1 million payment under the Phoenix settlement was received on October 1st. Capital expenditures incurred were $23.3 million in the third quarter and $32.5 million year to date. The year to date total comprised approximately $17.6 million of development 8 million of maintenance capital, primarily optimization, and 6.9 million of acquisition costs. We are updating full-year net capital expenditure guidance to a range of 37 million to 42 million, reflecting the Maui lease acquisition and development activity. Fourth quarter spending is expected to relate primarily to our operated and non-operated Powder River Basin wells. We are reiterating our full year 2026 adjusted EBITDA guidance of $60 to $70 million. Through September, adjusted EBITDA was $51.5 million. We also continue to expect full year production within our guidance range of $6,500 to $7,000 VOE per day. Thank you all for your attention. I will now turn it back to the operator for questions.

Jim, please press star one one on your phone and wait for your name to be announced. To withdraw your question, please press star one one again. And our first question comes from Dave Storms with StoneGate. Your line is open.

Good evening and I appreciate you taking my question. I wanted to start with the production growth that you're expecting in 2027. Maybe how quickly could you accelerate this growth if you wanted to? Is the constraints capital availability, permitting, timing, you know, any constraints there? And I guess if you could tie that into any early outlooks for CapEx spend in 2027, is $10 million a quarter a good benchmark or should it be a little lower after accounting for the mal release? Thank you.

Hey Dave, R.T., good to catch up with you. Real quick, I think in general we're going to release a lot more details once the CEO search is complete, so you'll learn more kind of at the end of the quarter, into Q4, maybe in Q4 reporting. I think a way to think about our business going forward is We're real happy with the inventory we have. We like the growth trajectory that we can see fairly easily through just executing, you know, just normal blocking and tackling. Let's go drill and complete some wells. And so you're going to see us reinvest our cash flow back into the business at a pretty aggressive rate. So probably not a bad starting point for this year in 2026, but I think we'll want to put more of the ground going forward.

Understood. I appreciate that. If I could ask just one follow-up and more of a clarification question. You mentioned that some of the shut-ins and rod pull forward impact you about 150, 200 barrels a day. But now you're expecting sequential increases, Q3 to Q4. Just to make sure I'm clear on the logistics here, that getting those wells back online should outpace the natural declines that we tend to see quarter over quarter leading to that sequential increase. improvement in BOE or is there more there that we should be thinking about?

Brad and Bobby might have the exact numbers in front of them but the way I think about it is we're guiding to our guidance would kind of indicate flat Q3 to Q4 but obviously growth in the exit as we're those wells are back online for the full quarter and then we're bringing a handful of wells online a few of those are already online with a couple more coming online before the end of the year. and really timing. You know, you get around the holidays and the winter starts, you know, early winter, late fall, timing starts to get pushed. You know, sometimes you get delays, but ultimately you'll see growth through the exit rate for sure. Relatively flat quarter on quarter, you know, based on our guidance read through.

That's perfect. I appreciate the clarity and wish you luck in the next quarter. Thanks, Dave.

As a reminder, to ask a question, please press star 1 1 on your telephone. The next question will come from Nicholas Pope with Roth Capital. Your line's open.

Hey, I can hear you, Nick. How's it going?

All right. A couple quick questions here. You mentioned the operating costs, the optimization efforts that you've been working on. I know it's an effort that you've been focused on for a while. Curious what the order of magnitude y'all are expecting on what you can achieve at this point. Also trying to understand exactly where you were saying you were kind of in the...

you know mile post of where you where you are in the trajectory of of kind of the efforts that you were doing i know you mentioned several items here but just curious me what inning we're in and kind of what like what a magnitude we're talking about yeah so the overall target we've released is saving a million dollars um you know almost per month but about 10 million dollars per year is what we've guided to in that program uh we started that program in 2025 uh we executed on about almost 50% of the program this year with a head start in 2025 and then about the same amount of work to do next year. So we're in the middle innings of where we are in terms of what we can save in terms of recurring LOE. And obviously we're going to push that a little harder and always reevaluating where we can save and what we can bid out and so forth. And so we'll continue to do that. Got it. Appreciate it.

And then in the Powder River, you mentioned the plan kind of through early 2027 is, I think you said 15 gross wells. I think that's what the number was. I want to understand what the targets are of these and what type of wells you're going to be drilling as part of that group of PRB activity that you have slated right now.

Yeah, so the 15 gross wells, that's six wells. in the powder, and nine down in the DJ. And so those six wells in the powder are going to be in our core position. We drilled a Parkman well just a couple months ago. We'll complete that well over the holidays, you know, hopefully have it online or close kind of at the end of the year. And then the other four wells are non-up wells in that same area. Yeah.

I appreciate it. And then one more. It seems like it might be a little too early to talk about asset portfolio optimization. It looks like you've sold some pieces here, got some cash in the door. Not a lot of discussion of the Permian asset. Curious if there's any thought about that, or is that something that might are all big shareholders and we want to make sure we do what's best for the shareholders and value creation across our portfolio.

and the hard part of that is I love and believe in oil and gas long term and I think we've got a great opportunity in front of us but if it's pretty far out in our portfolio in terms of development and it's struggling to compete for development dollars we're going to think about how we bring value forward right we don't want that sitting on the shelf that's not the best thing for our shareholders so we're going to be rational and be smart with decisions we make about our assets and I think you can expect that going forward for the our size of company we have a really big portfolio of of Acreage and Assets. And we're going to try and put capital to work to grow this and be a high growth company. So I think you can expect what you saw this quarter and us going forward. And there's going to be bolt-ons and there's going to be dispositions at the same time. Gotcha. I appreciate it, Artie.

There's no further questions at this time. I will now turn the call back over to Artie Dukes for closing remarks.

Thank you, operator, and thank you all for your time and continued interest in Pedevco. We look forward to connecting with you next quarter and offline.

Thank you. This concludes today's conference call. Thank you for participating, and you may now disconnect.