Q4 2025 Riley Exploration Permian Inc Earnings Call

March 5, 2026

Operator: Hello, thank you for standing by. My name is Regina, I will be your conference operator today. At this time, I would like to welcome everyone to the Riley Exploration Permian, Inc. Q4 and full year 2025 earnings release and conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question-and-answer session. If you would like to ask a question during this time, simply press star then the number one on your telephone keypad. To withdraw your question, press star one again. I would now like to turn the conference over to Philip Riley, Chief Financial Officer. Please go ahead.

Hello, and thank you for standing by. My name is Regina, and I will be your conference operator. Today, at this time, I would like to welcome everyone to the Riley Exploration Permian Inc. fourth quarter and full year 2025 earnings release and conference call.

Philip Riley [Chief Financial Officer and Executive Vice President: Good morning. Welcome to our conference call covering our Q4 2025 and full year 2025 results. I'm Philip Riley, CFO. Joining me today are Bobby Riley, Chairman and CEO, and John Suter, COO. Yesterday, we published a variety of materials which can be found on our website under the Investors section. These materials in today's conference call contain certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. We'll also reference certain non-GAAP measures. The reconciliations to the appropriate GAAP measures can be found in our supplemental disclosure on our website. I'll now turn the call over to Bobby.

Philip Riley: Good morning. Welcome to our conference call covering our Q4 2025 and full year 2025 results. I'm Philip Riley, CFO. Joining me today are Bobby Riley, Chairman and CEO, and John Suter, COO. Yesterday, we published a variety of materials which can be found on our website under the Investors section. These materials in today's conference call contain certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. We'll also reference certain non-GAAP measures. The reconciliations to the appropriate GAAP measures can be found in our supplemental disclosure on our website. I'll now turn the call over to Bobby.

All lines have been placed on mute to prevent any background noise. After the speakers remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star, then the number 1 on your telephone keypad to withdraw. Your question, press star 1. Again, I would now like to turn the conference over to Philip Riley. Chief Financial Officer, please go ahead.

Good morning. Welcome to our conference call covering our fourth quarter 2025 and full year 2025 results. I'm Philip Riley CFO. Joining me today are Bobbie Riley, chairman and CEO and John Sutter coo.

Yesterday we published a variety of materials which can be found on our website under the investors section.

These materials in today's conference call contain certain projections and other forward-looking statements within the meaning of the federal Securities laws.

These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements.

We'll also reference certain non-GAAP measures. The reconciliations to the appropriate GAAP measures can be found in our supplemental disclosure on our website.

I'll now turn the call over to Bobby.

Bobby D. Riley: Thank you, Philip. 2025 was a transformation year for Riley Permian, we look forward to discussing our Q4 results and our 2026 plan this morning. Over the course of the year, we made significant progress across several strategic initiatives, positioning us for long-term value creation. Through our Silverback acquisition, which closed in July, we enhanced depth and duration of our undeveloped inventory in our portfolio. Combined with our previous acquisitions in New Mexico and our legacy champions position, we have seven to eight years of high cash-on-cash return undeveloped inventory. In December, we sold our interest in our New Mexico midstream project to Targa, a best-in-class Fortune 500 midstream infrastructure company with a premier integrated asset network for $123 million in cash plus $60 million in future potential earn-outs.

Bobby Riley: Thank you, Philip. 2025 was a transformation year for Riley Permian, we look forward to discussing our Q4 results and our 2026 plan this morning. Over the course of the year, we made significant progress across several strategic initiatives, positioning us for long-term value creation. Through our Silverback acquisition, which closed in July, we enhanced depth and duration of our undeveloped inventory in our portfolio. Combined with our previous acquisitions in New Mexico and our legacy champions position, we have seven to eight years of high cash-on-cash return undeveloped inventory. In December, we sold our interest in our New Mexico midstream project to Targa, a best-in-class Fortune 500 midstream infrastructure company with a premier integrated asset network for $123 million in cash plus $60 million in future potential earn-outs.

Thank you. Philip 2025 was a transformation year for Riley Permian and we look forward to discussing our fourth quarter results and our 2026 plan this morning.

Over the course of the year.

We made significant progress across several strategic initiatives.

Positioning us for long-term value creation.

Through our Silverbac acquisition, which closed in July, we enhanced the depth and duration of our undeveloped inventory in our portfolio.

Combined with our previous Acquisitions in New Mexico and our Legacy Champions position. We have 7 to 8 years of high cash on cash, return on developed inventory.

In December, we sold our interests in our New Mexico, Midstream project to Target a best-in-class Fortune. 500 Midstream infrastructure company with a premier, integrated asset Network for 123 million in cash plus 60 billion in future potential earnouts,

Bobby D. Riley: The project will provide flow assurance for our New Mexico gas production and enable us more robust development of our New Mexico assets as originally intended. This transaction eliminates all liabilities and future construction costs associated with the project, allowing us to focus more capital into the drill bit and less into infrastructure. The project is underway. Targa expects the project to be operational in the second half of 2026. We reduced our debt by $120 million during the Q4, reinforcing our financial flexibility and positioning the company to accelerate development in 2026. The disciplined groundwork laid in 2025, portfolio expansion, infrastructure build-out, and balance sheet improvement sets the stage for more active and value-enhancing development program in 2026 and the years ahead.

Bobby Riley: The project will provide flow assurance for our New Mexico gas production and enable us more robust development of our New Mexico assets as originally intended. This transaction eliminates all liabilities and future construction costs associated with the project, allowing us to focus more capital into the drill bit and less into infrastructure. The project is underway. Targa expects the project to be operational in the second half of 2026. We reduced our debt by $120 million during the Q4, reinforcing our financial flexibility and positioning the company to accelerate development in 2026. The disciplined groundwork laid in 2025, portfolio expansion, infrastructure build-out, and balance sheet improvement sets the stage for more active and value-enhancing development program in 2026 and the years ahead.

The project will provide flow Assurance for our New Mexico, gas production and enable us more. Robust development of our New Mexico assets as originally intended.

This transaction eliminates all liabilities and future construction costs associated with the project, allowing us to focus more Capital into the drill bit and lessened the infrastructure.

The project is underway and Target expects the project to be operational in the second half of 2026.

We reduced our debt by $120 million during the fourth quarter, reinforcing our financial flexibility and positioning the company to accelerate development in 2026.

Improvement sets the stage for a more active and value-enhancing development program in 2026 and the years ahead.

Bobby D. Riley: We authorized a stock repurchase program of up to $100 million of currently outstanding shares of the company's common stock and began repurchasing outstanding shares in January 2025. We repurchased approximately 152,000 shares at a weighted average price of $26.54. The decision for accelerated growth is not in response to the recent increase in oil price levels, but rather the results of Riley Permian's multi-year positioning and our long-term view on value creation. For 2026, we forecast over 20% year-over-year oil volume growth. While we are excited about this growth potential, we will remain flexible and ready to moderate activity and spend appropriately should oil price environment deteriorate. I would like to thank our entire team for the success and transformation we realized in 2025.

Bobby Riley: We authorized a stock repurchase program of up to $100 million of currently outstanding shares of the company's common stock and began repurchasing outstanding shares in January 2025. We repurchased approximately 152,000 shares at a weighted average price of $26.54. The decision for accelerated growth is not in response to the recent increase in oil price levels, but rather the results of Riley Permian's multi-year positioning and our long-term view on value creation. For 2026, we forecast over 20% year-over-year oil volume growth. While we are excited about this growth potential, we will remain flexible and ready to moderate activity and spend appropriately should oil price environment deteriorate. I would like to thank our entire team for the success and transformation we realized in 2025.

we authorized the stock repurchase program of up to $100 million of currently outstanding shares of the company's common stock, and begin repurchasing outstanding shares in January of this year,

We repurchased approximately 152,000 shares at a weighted average price of 2654.

The decision for Accelerated growth is not in response to the recent increase in oil, price levels, but rather the results of Riley Permian multi-year positioning and our long-term view on value creation.

For 2026, we forecast over 20% year-over-year oil volume growth.

While we are excited about this growth potential.

We will remain flexible and ready to moderate activity and spend appropriately should oil price environment deteriorate.

Bobby D. Riley: We're positioned for an exciting 2026 and beyond, thanks to our strong financial position and asset base. With that, I'll turn the call over to John Suter, our COO, for operational highlights, followed by Philip Riley, our CFO, who will review financial performance.

Bobby Riley: We're positioned for an exciting 2026 and beyond, thanks to our strong financial position and asset base. With that, I'll turn the call over to John Suter, our COO, for operational highlights, followed by Philip Riley, our CFO, who will review financial performance.

I would like to thank our entire team for the success and transformation we realized in 2025.

We're positioned for an exciting 2026 and beyond, thanks to our strong financial position and asset base.

with that, I'll turn the call over to John Sutter, our coo for operational highlights followed by Philip Riley, our CFO who will review financial performance

John Suter: Thank you, Bobby. Good morning. I'll briefly cover Q4 and full year results, followed by 2026 development plans. Beginning with Q4, our development activity was focused in Texas. Activity levels matched the ranges we provided in guidance with more drilling and completions than new wells turned to sales. Wells drilled but not turned to sales during Q4 should come online over Q1 and Q2 of 2026. Oil production increased by more than 1,700 barrels of oil per day or 9% quarter-over-quarter. This was primarily from improving volumes from the new wells brought online earlier in 2025 that continued to increase, as well as from the three new wells turned to sales during Q4. Comparing Q4 of 2025 to 2024, oil production increased by 26%.

Thank you, Bobby and good morning.

Beginning with the fourth quarter, our development activity was focused in Texas.

Activity levels match, the ranges, we provided and Guidance with more Drilling and completions than new wells turned to sales.

Wells drilled but not turned to sales during the fourth quarter should come online over the first and second quarters of 2026.

Oil production increased by more than 1700 barrels oil per day, or 9% quarter over quarter.

This was primarily from improving volumes from the new wells brought online earlier in 2025 that continued to increase.

As well as from the three new wells turned to sales during the fourth quarter.

Comparing the fourth quarter of 2025 to 2024.

Oil production increased by 26%.

John Suter: As for the full year 2025, I'd like to begin by highlighting another year of excellence in safety here at Riley Permian. We achieved a Total Recordable Incident rate of 0 in 2025. We also achieved 95% safe days, a metric requiring no recordable incidents, vehicle accidents, or spills over 10 barrels. Full year oil production increased by 15% year-over-year, while total equivalent production increased by 29%. The overwhelming majority of our full year production increase was from pre-2025 development, with modest contributions from 2025 new wells and smaller contributions from the Silverback acquisition for the second half of the year, including the benefits of workover volumes as discussed last quarter. Full year development activity counts were relatively modest compared to 2024 levels as we reduced activity mid-year last year following the oil price decline and our Silverback acquisition.

As for the full year 2025.

I'd like to begin by highlighting another year of excellence in safety here, at Riley Permian.

We achieved a total recordable incident rate of zero in 2025.

We also achieved 95% safe days of metric. Requiring no recordable incidents vehicle accidents or spills over 10 barrels.

Full year oil production increased by 15% year-over-year while total equivalent production increased by 29%.

The overwhelming majority of our full year production, increase.

Was from pre 2025 development.

With modest contributions from 2025 new wells, and smaller contributions from the Silverback acquisition for the second half of the year, including the benefits of workover volumes as discussed last quarter.

Full year development, activity counts, were relatively modest compared to 2024 levels.

John Suter: In total, we drilled 18 net wells in 2025, or 28% fewer than in 2024, and turned to sales 16.3 net wells or 23% fewer than in 2024. I highlight these metrics for a couple of reasons. First, we achieved impressive organic volume growth with relatively limited activity. This is a testament to our high-quality drilling portfolio. Volumes from the acquisition accounted for only 8% of total annual volumes. Second, this reinforces what Bobby discussed on framing our 2026 plans for significant increased activity relative to the lower activity in 2025 and readiness positioning with midstream and water takeaway projects. In Texas, we essentially held over 11,000 barrels oil per day of oil production flat year-over-year, with only 10 net wells turned to sales, again demonstrating the productivity and efficiency of our wells.

As we reduced activity, mid-year, last year, following the oil price decline and our silverbac acquisition.

In total we drilled 18 net wells in 2025 or 28% fewer than in 2024.

And turned to sales 16.3 net wells.

Or 23% fewer than in 2024.

I highlight these metrics for a couple of reasons.

First.

We achieved impressive organic, volume growth with relatively limited activity.

This is a testament to our high quality drilling portfolio.

Volumes from the acquisition. Accounted for only 8% of total annual volumes

Second this reinforces what Bobby discussed on framing? Our 2026 plans, for significant increased activity relative to the lower activity in 2025.

And water, takeaway projects.

In Texas, we essentially held over 11,000 barrels oil per day of oil production flat year-over-year with only 10 net Wells turned to sales.

John Suter: In New Mexico, production has been more consistent and reliable. Since commissioning the expansion of the compressor station in December, we've been able to send more gas to the high-pressure system, increasing uptime and unburdening the low-pressure system by which the remainder of our gas is gathered. Overall, New Mexico oil production grew by 74% or over 2,500 barrels oil per day year-over-year, benefiting from just 6.3 net wells turned to sales and from the Silverback volumes. New Mexico represents a growing share of our total company oil production from 23% of the total in 2024 to 34% in 2025. That trend will continue into 2026 and beyond. The Silverback acquisition continues to surpass by case expectations, producing at a 65% higher oil rate at year-end than anticipated.

Again, demonstrating the productivity and efficiency of our wells.

In New Mexico.

Production has been more consistent and reliable.

Since commissioning the expansion of the compressor station in December,

We've been able to send more gas to the high-pressure system, increasing uptime and unburdening the low-pressure system, by which the remainder of our gases are gathered.

Overall.

In New Mexico, oil production grew by 74%, or over 2,500 barrels of oil per day year-over-year.

From just 6.3, net Wells, turned to sales. And from the Silverback volumes,

New Mexico represents a growing share of our total company oil production from 23% of the total in 2024.

to, to 34% in 2025,

That Trend will continue into 2026 and Beyond.

The Silverback acquisition continues to surpass by-case expectations.

John Suter: This is primarily due to strategic workovers, including well bore cleanouts, artificial lift optimization, and return to production operations. As for drilling and completion operations, we're down 25% in cost per lateral foot in Red Lake year-over-year. Similar results were achieved in Texas with a 15% cost reduction per lateral foot in 2025. Both achievements were driven primarily by a focus on pad drilling, an increase in time spent drilling, and completion optimization. It should be noted that while completion optimization helped on the cost reduction side, we're also seeing it result in an increase in productivity in both our Texas and New Mexico wells, with both sets of wells generally beating internal forecasts. We're also optimistic about future optimization that could further drive costs down, including increasing completed lateral length and testing new completion methodology in New Mexico.

Producing at a 65% higher oil rate at your end than anticipated.

This is primarily due to strategic work overs, including World War cleanouts, artificial lift optimization and return to production operations.

As for drilling and completion operations.

We're down 25%, in costs for lateral foot and Red Lake year-over-year.

In Texas, with a 15% cost reduction for lateral foot in 2025,

Both achievements were driven primarily by a focus on pad Drilling.

An increase in time, spent Drilling?

And completion optimization.

It should be noted that while completion optimization helped on the cost reduction side.

We're also seeing it result in an increase in productivity. In both our Texas and New Mexico Wells.

With both sets of Wells, generally beating internal forecasts.

We're also optimistic about future optimization. That could further Drive costs down.

Including increasing completed lateral length and testing new completion methodology in New Mexico.

John Suter: Let's now discuss our plans for 2026. Our current plans call for significant increases in activity and volume, with activity and spending being more concentrated during the first half of the year, while volumes may grow each successive quarter. On a full year basis, we're essentially running slightly more than an equivalent continuous 1-rig program. In actuality, we have 2 rigs running for approximately 3 months through May, back down to 1 rig for the summer, down to 0 potentially for the fall, before picking 1 up again later in the year. We picked up a 2nd drilling rig last month that began drilling in New Mexico to complement the rig already running in Texas that was put in service October 2025.

Let's now discuss our plans for 2026.

Our current plans call for significant increases in activity and volume.

With activity and spending being more concentrated during the first half of the year, while volumes may grow, each successive quarter

On a full year basis, we're essentially running slightly more than an equivalent continuous 1 Rigg program.

In actuality, we have two rigs running for approximately three months, through May.

Back down to 1 Rigg for the summer.

Down to 0 potentially for the fall.

before picking 1 up again, later in the year,

We picked up a second drilling rig last month that began Drilling in New Mexico.

To complement the rig already running in Texas that was put in service.

October of last year.

John Suter: This two-rig program allows us the ability to continue to grow our Texas production base while also setting the stage for more New Mexico asset development when the long-haul high pressure line to Targa is completed in Q3. We'll begin to build volumes striving to meet our volume commitment payouts as per the terms of the sale of the midstream asset in Q4 2025. Both rigs have relatively short contract terms, allowing us to be flexible in the event market conditions change rapidly. We currently forecast drilling 46 to 53 gross wells, which may correspond to approximately 37 to 43 on a net basis. Net completions and wells turned to sales may be slightly higher as we have a small inventory of DUCs to draw from, as I referenced during my commentary on Q4 activity.

This 2 rig program allows us the ability to continue to grow our Texas production base.

while also setting the stage for more New Mexico asset development. When the Long Haul high-pressure line to Target is completed in Q3,

We'll begin to build volumes striving to meet our volume commitment payouts as per the terms of the sale of the Midstream asset in Q4 2025.

Both rigs have relatively short contract terms.

Allowing us to be flexible in the event market conditions, change rapidly.

We currently forecast drilling 46 to 53 gross wells, which may correspond to approximately 37 to 43 on a net basis.

Completions and wells turned to sales, maybe slightly higher, as we have a small inventory of DUCs to draw from.

as I referenced during my commentary on fourth quarter activity.

John Suter: New wells turned to sales will focus in Texas during the first half of the year and transition to New Mexico for the second half. This is predicated on New Mexico gas infrastructure being completed and ready by that time, as Bobby described. Additionally, we've been working with partners to secure sufficient water disposal for this development plan. This will increase operating expenses, which we'd see impacted later in the year, while we're also tackling initiatives elsewhere to offset this increase. Philip, I'll now turn the call back to you.

New wells turned to sales will focus in Texas during the first half of the year and transition to New Mexico for the second half.

This is predicated on New Mexico, Gaff, cast infrastructure being completed and ready by that time, as Bobby described.

Additionally, we've been working with partners to secure sufficient water disposal for this development plan.

This will increase operating expenses which we see impacted later in the year.

While we're also tackling initiatives elsewhere to offset this increase.

Philip. I'll now turn the call back to you.

Philip Riley [Chief Financial Officer and Executive Vice President: Thank you, John. I'll also cover both Q4 and full year 2025 results with a few additional notes on 2026 guidance. The company's financial results for Q4 were favorable to all guidance levels. Q4 prices after hedges were lower quarter-over-quarter across all three commodities, though total hedge revenue decreased by only $3.8 million or 3% quarter-over-quarter, benefiting from $8 million of positive hedge settlements. We experienced negative natural gas and NGL revenues after basis and fees. Like many other Permian operators who have reported this earnings cycle, pipeline maintenance constrained Permian gas egress and pressured Waha pricing during the quarter. We're monitoring the regional infrastructure build-out, which is forecast to improve by next year, absent delays.

Philip Riley: Thank you, John. I'll also cover both Q4 and full year 2025 results with a few additional notes on 2026 guidance. The company's financial results for Q4 were favorable to all guidance levels. Q4 prices after hedges were lower quarter-over-quarter across all three commodities, though total hedge revenue decreased by only $3.8 million or 3% quarter-over-quarter, benefiting from $8 million of positive hedge settlements. We experienced negative natural gas and NGL revenues after basis and fees. Like many other Permian operators who have reported this earnings cycle, pipeline maintenance constrained Permian gas egress and pressured Waha pricing during the quarter. We're monitoring the regional infrastructure build-out, which is forecast to improve by next year, absent delays.

Thank you, John.

I'll also cover both fourth quarter and full year 2025 results with a few additional notes on 2026 guidance.

The company's financial results for the fourth quarter were favorable to all guidance levels.

Fourth quarter prices after Hedges were lower quarter over quarter across all 3 Commodities though. Total hedge Revenue decreased by only 3.8 million or 3%. Quarter over quarter, benefiting from 8 million of positive hedge settlements.

We experienced negative natural gas and NGL revenues after basis and fees.

Like many other Permian operators, we have reported this earnings cycle, pipeline maintenance, constrained Permian gas egress, and pressured Waha pricing during the quarter.

Philip Riley [Chief Financial Officer and Executive Vice President: We have a material amount of Waha basis hedged next year at -$1 to Henry Hub, which, combined with higher index pricing and higher forecasted volumes, has the potential to translate to material positive revenue starting in 2027. Core cash operating costs, being LOE, production taxes, and G&A before stock compensation, decreased in total by 13% quarter-over-quarter. LOE also decreased by 13% quarter-over-quarter or by 21% on a $ per BOE basis, with cost savings across many categories. Workover expenses were the largest contributor, coming off Q3 with higher workover activity immediately following the Silverback closing. We hope to continue realizing some aspects of the cost savings, while other aspects were unique to the quarter and may not recur going forward.

Philip Riley: We have a material amount of Waha basis hedged next year at -$1 to Henry Hub, which, combined with higher index pricing and higher forecasted volumes, has the potential to translate to material positive revenue starting in 2027. Core cash operating costs, being LOE, production taxes, and G&A before stock compensation, decreased in total by 13% quarter-over-quarter. LOE also decreased by 13% quarter-over-quarter or by 21% on a $ per BOE basis, with cost savings across many categories. Workover expenses were the largest contributor, coming off Q3 with higher workover activity immediately following the Silverback closing. We hope to continue realizing some aspects of the cost savings, while other aspects were unique to the quarter and may not recur going forward.

or monitoring the regional infrastructure buildout which is forecast to improve by next year absent delays we have a material amount of waha bases hedged next year at minus 1 to Henry Hub which combined with higher index pricing and higher forecasted volumes as the potential to translate to material positive Revenue starting in 2027

Core cash. Operating costs being eloe production taxes and GNA. Before stock compensation decreased in total by 13% quarter of a quarter.

Eloe also decreased by 13% quarter of a quarter or by 21% on a dollar per Boe basis with cost savings across many categories.

Work over expenses were the largest contributor coming off the third quarter with higher work over activity. Immediately following the Silverback closing

We hope to continue realizing some aspects of the cost savings while other aspects where you need to the quarter may not recur going forward.

Philip Riley [Chief Financial Officer and Executive Vice President: G&A before stock compensation decreased by 20%, G&A inclusive of stock compensation decreased by 18%, partly on account of coming off of an unusually high Q3. A few items caused Q3 G&A to be materially higher, including the impact of a transition services agreement with Silverback immediately following the close, which was completed by the Q4. Net income increased by $69 million quarter-over-quarter, benefiting from non-recurring items such as the $72 million gain from the midstream sale and from $20 million of higher hedging gains, which were mostly non-cash, partially offset by $16 million of higher income tax expense due to the midstream sale gain. Adjusted EBITDAX increased 3% quarter-over-quarter to $66 million, as $5.8 million of lower costs more than offset lower hedge revenue, increasing margin from 59% to 63%.

Philip Riley: G&A before stock compensation decreased by 20%, G&A inclusive of stock compensation decreased by 18%, partly on account of coming off of an unusually high Q3. A few items caused Q3 G&A to be materially higher, including the impact of a transition services agreement with Silverback immediately following the close, which was completed by the Q4. Net income increased by $69 million quarter-over-quarter, benefiting from non-recurring items such as the $72 million gain from the midstream sale and from $20 million of higher hedging gains, which were mostly non-cash, partially offset by $16 million of higher income tax expense due to the midstream sale gain. Adjusted EBITDAX increased 3% quarter-over-quarter to $66 million, as $5.8 million of lower costs more than offset lower hedge revenue, increasing margin from 59% to 63%.

G&A before stock compensation decreased by 20%, and G&A inclusive of stock compensation decreased by 18%, partly on account of coming off of an unusually high third quarter.

A few items cost. Third quarter GNA to be materially higher, including the impact of a transition Services agreement with Silverback immediately following the clothes, which was completed by the fourth quarter.

Net income increased by 69 million quarter over quarter benefiting from non-recurring items such as the 72 million gain from the Midstream sale. And from 20 million of higher hedging gains which were mostly non-cash. And partially offset by 16 million dollars of higher income tax expense due to the Midstream sale gain.

Philip Riley [Chief Financial Officer and Executive Vice President: Cash flow from operations increased 2% quarter-over-quarter. Accrual capital expenditures for the quarter were $50 million compared to $18 million in Q3. The CapEx increase represented a return to more normalized upstream activity compared to an exceptionally low level in Q3 and an increase in midstream capital spend, which was ultimately reimbursed with the midstream sale. In aggregate, capital expenditures were at the low end of our Q4 guidance range, primarily due to a few new drills and smaller infrastructure projects that were deferred to 2026. We converted 27% of operating cash flow to $17 million of upstream free cash flow and $1 million of total free cash flow. Note, the proceeds of the midstream sale do not flow through total free cash flow while the CapEx does reduce free cash flow.

Philip Riley: Cash flow from operations increased 2% quarter-over-quarter. Accrual capital expenditures for the quarter were $50 million compared to $18 million in Q3. The CapEx increase represented a return to more normalized upstream activity compared to an exceptionally low level in Q3 and an increase in midstream capital spend, which was ultimately reimbursed with the midstream sale. In aggregate, capital expenditures were at the low end of our Q4 guidance range, primarily due to a few new drills and smaller infrastructure projects that were deferred to 2026. We converted 27% of operating cash flow to $17 million of upstream free cash flow and $1 million of total free cash flow. Note, the proceeds of the midstream sale do not flow through total free cash flow while the CapEx does reduce free cash flow.

Adjusted ibid tax, increased 3% quarter of a quarter to 66 million as 5.8 million of lower costs. More than offset lower, hedge Revenue, increasing margin from 59% to 63%.

Cash flow from operations increased 2% quarter over quarter.

Acral Capital expenditures for the quarter were 50 million compared to 18 million and the third quarter.

The capex increase represented a return to more normalized Upstream activity compared to an exceptionally low level in the third quarter. And an increase in Midstream Capital spend, which was ultimately reimbursed with the Midstream sale

In aggregate Capital expenditures were the low end of our fourth quarter guidance range. Primarily due to a few new drills and smaller interest infrastructure projects that were deferred to 2026.

We converted 27% of operating cash flow to 17 million dollars of Upstream free, cash flow and 1 million dollars of total free cash flow.

Philip Riley [Chief Financial Officer and Executive Vice President: I'll point out again that the midstream CapEx was reimbursed as part of the sale, so the free cash flow metric has a bit lower utility this quarter. Debt decreased by $120 million quarter-over-quarter due to proceeds from the midstream sale, resulting in a Q4 2025 balance of $255 million. As of 31 December, our credit facility was 28% utilized based on a $400 million borrowing base. Trailing debt to EBITDAX leverage was 1.0x on an as-reported EBITDAX basis, or 0.9x on a pro forma basis, including H1 2025 Silverback EBITDAX. On a full-year basis, adjusted EBITDAX and upstream free cash flow decreased by only 8% year-over-year, despite 15% lower oil prices.

Philip Riley: I'll point out again that the midstream CapEx was reimbursed as part of the sale, so the free cash flow metric has a bit lower utility this quarter. Debt decreased by $120 million quarter-over-quarter due to proceeds from the midstream sale, resulting in a Q4 2025 balance of $255 million. As of 31 December, our credit facility was 28% utilized based on a $400 million borrowing base. Trailing debt to EBITDAX leverage was 1.0x on an as-reported EBITDAX basis, or 0.9x on a pro forma basis, including H1 2025 Silverback EBITDAX. On a full-year basis, adjusted EBITDAX and upstream free cash flow decreased by only 8% year-over-year, despite 15% lower oil prices.

Note, the proceeds of the Midstream sale, do not flow through, total free cash flow while the capex does reduce free cash flow. I'll point out again that the Midstream capex was reimbursed as part of the sale, so the free cash flow metric has a bit lower utility this quarter.

Debt decreased by 120 million quarter of a quarter due to proceeds from the mo, Midstream sale resulting in a fourth quarter, 2025 balance of 255 million.

Borrowing base, trailing debt. To epodex leverage was 1.0 times on an as reported EB tax basis or 0.9 times on a pro forma basis including first half 2025 Silverback EBA tax

Philip Riley [Chief Financial Officer and Executive Vice President: Total free cash flow was 31% lower year-over-year, driven by lower prices and higher midstream spend, which of course is non-recurring. We allocated 41% of total free cash flow to dividends, up from 26% in 2024, as dividends increased and free cash flow declined. We had a very active year of acquisitions and divestitures, as you can see on our cash flow statement. Silverback is represented as the $118 million business combination. The $2.2 million of acquisitions of oil and gas properties represents a small acquisition of minerals underneath our New Mexico properties that we completed earlier in the year.

Philip Riley: Total free cash flow was 31% lower year-over-year, driven by lower prices and higher midstream spend, which of course is non-recurring. We allocated 41% of total free cash flow to dividends, up from 26% in 2024, as dividends increased and free cash flow declined. We had a very active year of acquisitions and divestitures, as you can see on our cash flow statement. Silverback is represented as the $118 million business combination. The $2.2 million of acquisitions of oil and gas properties represents a small acquisition of minerals underneath our New Mexico properties that we completed earlier in the year.

on a full year basis, adjusted eBid Dax and Upstream free cash flow decreased by only 8% year-over-year, despite 15% lower oil prices,

Total free cash flow is 31% lower year-over-year, driven by lower prices and higher midterm spend which of course is not non-recurring.

We allocated 41% of total free cash flow to dividends, up from 26% in 2024, as dividends increased and free cash flow declined.

We had a very active year of acquisitions, investors, as you can see on our cash flow statement.

Silverback is represented as the $118 million business combination.

Philip Riley [Chief Financial Officer and Executive Vice President: We also had a good amount of success in 2025 with our land ground game, reflected in a $1.3 million acquisition and effectively $3 million of new leasehold embedded in CapEx, which is labeled as the additions to oil and natural gas properties on the cash flow statement. In total, we estimate that we replaced about two-thirds of our completed locations from 2025 via new land, corresponding to a very attractive cost of entry of less than $300,000 per net undeveloped location. Moving on to 2026, we currently forecast a capital plan of $200 million corresponding to the activity that Bobby and John described.

Philip Riley: We also had a good amount of success in 2025 with our land ground game, reflected in a $1.3 million acquisition and effectively $3 million of new leasehold embedded in CapEx, which is labeled as the additions to oil and natural gas properties on the cash flow statement. In total, we estimate that we replaced about two-thirds of our completed locations from 2025 via new land, corresponding to a very attractive cost of entry of less than $300,000 per net undeveloped location. Moving on to 2026, we currently forecast a capital plan of $200 million corresponding to the activity that Bobby and John described.

The $2.2 million of acquisitions of oil and gas properties represents a small acquisition of minerals underneath our New Mexico properties that we completed earlier in the year.

We also had a good amount of success in 2025 with our land ground game, reflected in a $1.3 million acquisition. And, effectively, $3 million of new leasehold, embedded in capex, which is labeled as the additions to oil and natural gas properties on the cash flow statement.

In total, we estimate that we replaced about two-thirds of our completed locations from 2025 via new land, corresponding to a very attractive cost of entry of less than $100,000 per net undeveloped location.

Philip Riley [Chief Financial Officer and Executive Vice President: As of today, we forecast more than two-thirds of the capital spent in the first half of the year, at least on an accrual basis, with a particularly large Q2, falling in each of the Q3 and Q4, while oil volumes may rise through the year given the lag effect of investments converting to production. We see this investment benefiting not only this year, but providing a tailwind to 2027 as well. In our investor presentation, we provide a two-year outlook illustrating 2026 and 2027 spending and production levels. Overall, we forecast a materially higher allocation rate of cash flow to CapEx this year. Of course, we'll monitor markets and aim to stay flexible throughout the year. We'll protect the dividend in lower price environments.

Philip Riley: As of today, we forecast more than two-thirds of the capital spent in the first half of the year, at least on an accrual basis, with a particularly large Q2, falling in each of the Q3 and Q4, while oil volumes may rise through the year given the lag effect of investments converting to production. We see this investment benefiting not only this year, but providing a tailwind to 2027 as well. In our investor presentation, we provide a two-year outlook illustrating 2026 and 2027 spending and production levels. Overall, we forecast a materially higher allocation rate of cash flow to CapEx this year. Of course, we'll monitor markets and aim to stay flexible throughout the year. We'll protect the dividend in lower price environments.

Moving on to 2026, we currently forecast a capital plan of millions corresponding to the activity that Bobby and John described.

As of today, we forecast more than 2/3 of the capital spent in the first half of the year at least on an acral basis with a, particularly large second quarter then falling in each of the third and fourth quarters. While oil volumes may rise to the year given the lag effect of Investments converting to production.

We see this investment benefiting not only this year, but providing a tailwind to 2027 as well.

In our investor presentation, we provide a two-year outlook illustrating 2026 and 2027 spending and production levels.

Overall, we forecast a materially higher allocation rate of cash flow to capex this year.

Of course, we'll monitor markets and aim to stay flexible throughout the year.

And will protect the dividend in lower price environments.

Philip Riley [Chief Financial Officer and Executive Vice President: We entered 2026 well hedged, partially on account of the midstream capital commitment we were carrying until mid-December, partially on account of universal calls for an oil surplus and weak pricing. We've done some hedging over the past week. As of 2 March, we had approximately 70% of forecasted oil volumes at midpoint guidance, hedged at a weighted average downside price of approximately $60 per barrel, with 36% of those hedges structured as callers preserving upside participation. Thank you all for your support and attention. Operator, you may now turn it over for questions.

Philip Riley: We entered 2026 well hedged, partially on account of the midstream capital commitment we were carrying until mid-December, partially on account of universal calls for an oil surplus and weak pricing. We've done some hedging over the past week. As of 2 March, we had approximately 70% of forecasted oil volumes at midpoint guidance, hedged at a weighted average downside price of approximately $60 per barrel, with 36% of those hedges structured as callers preserving upside participation. Thank you all for your support and attention. Operator, you may now turn it over for questions.

We entered 2026 well hedged, partially on account of the Midstream Capital commitment. We are carrying until mid-December, and partially on account of universal calls for an oil surplus and weak pricing.

And we've done some hedging over the past week.

As of March 2nd, we had approximately 70% of forecasted oil volumes at midpoint guidance hedged at a weighted average downside price of approximately $60 per barrel, with 36% of those hedges structured as collars, preserving upside participation.

Operator, you may now turn it over for questions.

Operator: We will now begin the question and answer session. To ask a question, simply press star followed by 1 on your telephone keypad. Our first question will come from the line of Derrick Whitfield with Texas Capital. Please go ahead.

We will now begin the question and answer session.

To ask a question.

or followed by the

telephone.

Question will come from the line of Derek Whitfield with Texas Capitol. Please go ahead.

Derrick Whitfield: Good morning, all, and congrats on a strong year-end, and also thanks for providing the multi-period outlook as well.

Philip Riley [Chief Financial Officer and Executive Vice President: Regarding 2020-

Derrick Whitfield: Regarding 2020-

Derrick Whitfield: Great. Thank you. Regarding 2026 and 2027, while I understand there could be off-ramps in a lower price environment, could you help us shape production cadence for the year under the status quo plan as the implied average oil production for Q2 through Q4 is about 10% above the street at present. Additionally, as we kinda think about capital efficiency over this period of investment throughout 2027, would you expect it to improve in 2027 as you optimize DNC designs and get more reps in Eddy and as you back out some of the DUCs impacts in 2026?

Philip Riley: Great. Thank you.

Derrick Whitfield: Regarding 2026 and 2027, while I understand there could be off-ramps in a lower price environment, could you help us shape production cadence for the year under the status quo plan as the implied average oil production for Q2 through Q4 is about 10% above the street at present. Additionally, as we kinda think about capital efficiency over this period of investment throughout 2027, would you expect it to improve in 2027 as you optimize DNC designs and get more reps in Eddy and as you back out some of the DUCs impacts in 2026?

regarding to,

Regarding uh 2026 and 2027. Well I understand there could be off-ramps at a lower price environment. Could you help us shape production, Cadence for the year under the status quo plan as the implied average oil production for Q2 through Q4 is about 10% above the street at present.

And then, additionally, as we kind of think about capital efficiency over this period of investment throughout 2027, would you expect it to improve in 2027 as you optimize DNC designs and get more reps and EDI? And as you back out some of the duck impacts of 2026,

Philip Riley [Chief Financial Officer and Executive Vice President: Yeah, sure, Derek. This is Philip. You're gonna see the production increase each quarter this year. I guess to clarify, you're gonna see a dip in Q1 is what we're forecasting. John could follow here with a little more color, we experienced some downtime and some deferred production this quarter. We had some shut-ins from our legacy midstream partner, which caused a little bit of a dip there in Q1. We hope to achieve a nice ramp in Q2, Q3, and Q4. I hope that answered the first question. I'll go to the second and then pass to John.

Philip Riley: Yeah, sure, Derek. This is Philip. You're gonna see the production increase each quarter this year. I guess to clarify, you're gonna see a dip in Q1 is what we're forecasting. John could follow here with a little more color, we experienced some downtime and some deferred production this quarter. We had some shut-ins from our legacy midstream partner, which caused a little bit of a dip there in Q1. We hope to achieve a nice ramp in Q2, Q3, and Q4. I hope that answered the first question. I'll go to the second and then pass to John.

Yeah, sure. Derek this is Philip um,

Order. Uh,

Philip Riley [Chief Financial Officer and Executive Vice President: On 2027, yeah, depending on how you define capital efficiency, we've got a few different metrics, but yeah, you could find that next year is more efficient, and that's just the function of, you know, the delayed aspect of the investment converting to the production then. We hope to achieve another increase next year. It may not be the 25% increase like we hope to get this year, but maybe it's 10% or so based on, you know, frankly, kinda flattish CapEx is what we're showing for now. 2027 is a long way away, of course, but we did put that in there. I'm glad you appreciate it, because it does show that kind of lag effect benefit there. John, you wanna say anything else on kind of the Red Lake shut-in?

Philip Riley: On 2027, yeah, depending on how you define capital efficiency, we've got a few different metrics, but yeah, you could find that next year is more efficient, and that's just the function of, you know, the delayed aspect of the investment converting to the production then. We hope to achieve another increase next year. It may not be the 25% increase like we hope to get this year, but maybe it's 10% or so based on, you know, frankly, kinda flattish CapEx is what we're showing for now. 2027 is a long way away, of course, but we did put that in there. I'm glad you appreciate it, because it does show that kind of lag effect benefit there. John, you wanna say anything else on kind of the Red Lake shut-in?

I hope that answered the first question. I'll go to the second and then pass to John on 27. Yeah, you depending on how you define capital efficiency, uh, we've got a few different metrics. But yeah, you could find that next year's more efficient. And, and that's just the function of uh, you know, the delayed aspect of the investment, converting to the production them. So we hope to achieve another, uh, increase next year. Uh, may not be the 25% increase, like we, we hope to get this year but maybe it's 10% or so based on, you know, frankly, kind of flattish. Capex is what we're showing uh, for now 2027 is a long way away of course. But we we did put that in there. I'm glad you appreciate it. Uh, because it, it does show that kind of

John Suter: Yeah, sure. Yeah, like Philip said, we did have some downtime due to some of the heavy weather, freezing temperatures, and then, like you said, some issues with our pipeline. You know, all the more reason why we're really looking forward to Q3 when we'll have our new pipeline in place. We're excited about that. Like several of us mentioned that there'll be heavy Champions activity in the first half of the year, and then we're kind of reduced in Q3, and then in Q4, we're shifting to New Mexico. Again, we need that trunk line in place from Targa and, you know, that's on schedule to happen. Really excited about that. We'll start ramping up our completion.

Uh, lag effect benefit their John. You want to say anything else on? Kind of the red Lakes shutdown.

Yeah, sure. Um

yeah, like Philip said, we did have some uh, some downtime in the

oh, due to some of the heavy weather, uh, freezing temperatures and then um,

Like you said, some issues with our pipeline, but, you know, all the more reason why we're really looking forward to, uh, Q3 when we'll, we'll have our new, um,

New pipeline in place. We're excited about that.

like we, several, of us mentioned that there'll be

Heavy Champions activity in the first half of the year.

And then we're we're kind of uh, reduced in the third quarter, and then in the fourth quarter, we're we're shifting to New Mexico again, we need that trunk line in place from Target.

And uh, you know, that's that's on schedule to happen.

John Suter: Still won't get the full impact of it in Q4 because a lot of things are being completed then and, you know, we'll have to de-water a little bit. All the better for 2027 as we should be able to start drilling, you know, more efficiently in Denver or in New Mexico and completing those wells as we, as we go. Should be more efficient without having to wait on some water infrastructure and some gas takeaway like we are this year.

And so, really excited about that. We'll, we'll start ramping up our completions. Still won't get the full impact of it in, in Q4, because a lot of things are being completed then. And, you know, we'll have to do water a little bit but uh, all the better for 27 as we should be able to start.

Um, drilling, you know, more efficiently in Denver in New Mexico and completing those Wells as we as we go.

So uh should be uh more efficient without having to wait on some water infrastructure and some uh gas to take away like we are uh this year.

Derrick Whitfield: Great. John, maybe staying with you, in your prepared remarks, you mentioned completion optimization. Could you elaborate on some of the knobs that you're turning for completion optimization or DNC optimization and what you're seeing in well performance versus past designs?

John, maybe staying with you. Um, and your prepared remarks, you mentioned completion, optimization. Could you elaborate on some of the knobs that you're turning for completion, optimization or DNC optimization and what you're seeing in, well, performance versus past designs?

John Suter: Sure. Well, again, we've been mostly in Champions. We're trying to do zipper fracs on, you know, pad drilling, zipper fracs on everything we do. We've kind of think we found the optimal recipe there. We've reduced from, say, 700 to 800 lbs per foot down to 250 to 300 lbs per foot of sand. You know, that's a big change over time, you know, goes against what we, you know, what we hear in the shale world. We're getting a big cost savings from that. We also have found that 20/40 works better than 40/70, which is, you know, often more readily used.

Sure. Well, we

Again, we've been mostly in Champions, um,

We're trying to do zipper facts on, you know, pad drilling zipper fractions on everything we do. Uh, We've we've kind of think we found the optimal recipe there. We've, I believe, reduced from say 7 to 800 pounds per foot down to 250, to 300 pounds per foot, uh, of sand, you know. And so that's a, that's a big change over time. You know, goes against what we, you know what, we hear in the Shale world, uh, so we're getting a big.

Cost savings from from that.

Um, we also have

John Suter: The other thing is we've reduced our clusters, but still are using the same amount of sand. It reduces our water volume and, of course, less pump time, which is a cost benefit. In New Mexico, there is upside there that we have tested a little bit. We plan to test more in 2026. The Paddock layer of the Blind Bee is very similar to the San Andres over in Texas, and we would like to test more crosslink fracs there. We've done it once in 2025, I believe, and we've seen good outcome. We have a lot more testing to do, but it could provide a significant financial benefit, somewhere between a half million dollars plus per well.

Found that 2040 works better than 4070, which is, you know, um, often more readily used.

but um,

We've also, the other thing is, we've reduced our, um, clusters.

but still are using the, um,

Same amount of sand, but it reduces our water volume. And, of course, less pump time, which is a cost benefit.

Uh,

in New Mexico.

Uh there is upside there that we have uh tested a little bit. We plan to test more in 2026. The uh, The Paddock layer of the blind breeze is very similar to

Uh, the St Andrews over in Texas. And we would like to test more cross-link, fracks there. We've done it once in uh 2025 I believe and we've seen good um outcome. But we have a lot more testing to do but it could provide a significant

Financial benefit, uh, somewhere between a half million dollars.

John Suter: We're excited to do some more testing there. Again, once we have that pipeline, we'll have the freedom to do a little bit larger scale drilling.

Uh, plus per well.

pipeline will have the freedom to, uh, do a little bit larger scale, Drilling

Bobby D. Riley: Maybe, John, just to clarify on the optimization. It sounds like it's more cost, and you're getting similar performance. Is that the right way to characterize it?

Derrick Whitfield: Maybe, John, just to clarify on the optimization. It sounds like it's more cost, and you're getting similar performance. Is that the right way to characterize it?

It, maybe John just to clarify on the optimization. It sounds like it's more cost and you're getting similar performances at the right way to characterize it.

John Suter: I would say in Champions, that's probably true. Albeit, our wells are outperforming our general type curves right now. Some of that is due to, again, more child wells are being drilled in Champions because, again, we're later in the development stage there. Those wells tend to reach peak oil faster. That's another reason that's causing that in Champions.

Uh, I would, I would say, in Champions, that's probably true, albeit, um, our wells are outperforming our—

Uh, General type curves right now. Some of that is due to again. More child Wells are being drilled and champions, because, uh, again, we're we're later in the development stage there. Those Wells tend to, uh, reach peak oil faster. Uh, so that that's another, uh, reason that's causing that in Champions.

Bobby D. Riley: Terrific. Great update, guys. I'll turn it back to the operator.

Derrick Whitfield: Terrific. Great update, guys. I'll turn it back to the operator.

Terrific. Great update, guys. I'll turn it back to the operator.

Operator: Our next question will come from the line of Neal Dingmann with William Blair. Please go ahead.

Neal Dingmann: Morning, guys. Great update. Philip, maybe a question for you or Bob or John. Just, you know, again, sticking with that slide 10. I've always loved the flexibility. Again, it certainly seems like, you know, in past years, what is it, hasn't even been one rig that you've needed to have, you know, very material production growth. I'm just wondering, you know, given now today, and shoot, we're almost now back to $80 oil, you know, how flexible is this plan?

Our next question, will come from the line of nil. Dingman with William Blair. Please go ahead.

Morning guys, it's great up.

Philip maybe a question for for for your Viber John just you know against sticking with that slide 10 love. I've always loved the flexibility again. It it certain seems like, you know, in past years what is it hasn't even been 1 Rigg that you've needed to have uh you know, very material production growth that I'm just wondering, you know, given now today, I mean shoot, we're almost now back to 80 dollar oil. Um,

Neal Dingmann: You know, I know a lot of larger companies always say, Hey, we're just going to target flat and target free cash flow growth. But again, given your returns that you show on other slides, you know, would you think about trying to, you know, capture this oil upside and even potentially grow quicker than, you know? Maybe talk about the flexibility of the plan, I guess, is the best way to ask it.

You know how flexible is this plan? And, you know, I know a lot of large companies, I always say, hey, we're just going to Target flat and Target. Free cash flow growth. But but again, giving your returns that you show on on other slides. Uh, you know, would you think about trying to, you know, capture this oil upside and even potentially grow quicker than than, you know, it's just maybe talk about the flexibility of the plan. I guess is the best way to ask it.

John Suter: Yeah, I might defer some of that to Bobby for, you know, for a longer-term view of that, of increasing. Certainly, you know, we're talking about drilling what, you know, 45 to low 50s gross wells. The beauty of our wells being so shallow that compared to, you know, the Delaware is that we can knock a well out, you know, from spud to TD, you know, maybe 4 or 5 days, certainly a week by the time you get everything wrapped up. Then doing pad drilling, it's really quick. Sliding to the next one. One rig can effectively drill, you know, let's just say upper 40s to low 50s wells per year if you're able to not do, you know, a lot of regional moving.

Yeah, I might, I might defer some of that to Bobby for, uh, you know, for a longer term view of that of increasing. But certainly, um, you know, we're talking about drilling, what, you know, 45 to low 50s, gross Wells,

Um, the beauty of of our wells being so shallow that compared to, you know, the Delaware is that we can knock a a well out, you know, from Spud to TD, you know, maybe 4 or 5 days, certainly a week by the time you um, get everything wrapped up and then doing pad drilling. It's it's really quick.

Uh sliding to the next 1. So 1 1 rig can effectively drill.

John Suter: You know, it would not take much in deployment, you know, to be able to really drill quite a few wells. We have the capability and, you know, I may steer that back to Bobby to see what he thinks about drilling at a higher oil price.

Um, you know, let's just say upper 40s to low 50s Wells per year. If you're able to not, do you know, a lot of regional moving

um,

you know, so

it would not take much, uh,

In deployment, you know, to be able to really drill quite a few. Well, uh,

Bobby D. Riley: Yeah. Thank you. Thank you, Neal, for the comments you made. I'm gonna say we're probably not in a position today to be reactive to a $5 increase or $4 increase in the price of oil. I think we have a solid plan laid out for 2026 with a pretty significant D&C capital spend that really we're looking into 2027 and beyond and how that is gonna affect this company in any price environment, whether it be $55 or $85. We have the ability with the flexibility that John mentioned. We, you know, we could either shut these rigs down if we needed to or keep the rig running for the entire year. We have that option ahead of us. It's just too early, too immature to really say what we would do at this point.

Bobby Riley: Yeah. Thank you. Thank you, Neal, for the comments you made. I'm gonna say we're probably not in a position today to be reactive to a $5 increase or $4 increase in the price of oil. I think we have a solid plan laid out for 2026 with a pretty significant D&C capital spend that really we're looking into 2027 and beyond and how that is gonna affect this company in any price environment, whether it be $55 or $85. We have the ability with the flexibility that John mentioned. We, you know, we could either shut these rigs down if we needed to or keep the rig running for the entire year. We have that option ahead of us. It's just too early, too immature to really say what we would do at this point.

So we have a capability and you know, I I may stare that back to Bobby to see what he thinks about drilling it up price.

Yeah, thank you. Thank you Neil for the comments you made. Uh I'm going to say we're probably not in a position today to be reactive to uh a 5 Dollar increase or 4 dollar increase in the price of oil. I think we have a solid plan laid out for 2026 with a pretty significant DNC Capital. Spend that really, we're looking into 27 and Beyond and, and how that is going to affect this company in any price environment, whether it be 55 or 85, uh, we have the ability with the, the flexibility of like, Sean mentioned. We, you know, we we could either shut these rigs down. If we needed to or keep them. Keep the rig running for the entire year. We have that option ahead of us. It's just too early or too immature to to really

Neal Dingmann: Yeah, that makes sense, Bobby. Love the flexibility. Second question, Philip, you know, I can't help but ask on the powers, obviously is positive on that. I know I was looking at slide 16, you guys talked about, I think, knowing on the second project, it's in the final stage. Could you talk, maybe just update on that, where that second project sits? You know, have you considered, you know, even adding more power beyond project number 2? Because again, obviously, you know, I'm a fan of this, and I, again, I think as is the market would love just to hear any more plans beyond project 2.

Say what we would do at this point.

That that makes sense Bobby and love the flexibility. And uh, second question Philip, you know, I can't help but ask uh on the powers. Uh obviously is positive on that. I know I was looking at slide 16 you guys talked about I think knowing on the second project uh it's in the final stage. Could you talk maybe just update on that where that second project sits and you know, have you considered um you know, even adding more uh power beyond project number 2 because again obviously you know I'm I'm a fan of this and I again I think as is that the market would love just to hear. Any more plans to be on Project too.

Philip Riley [Chief Financial Officer and Executive Vice President: Sure. Thanks. Yeah. The second project is this merchant project we have in ERCOT, in which we take our lower cost gas and convert that to electrons to sell to the ERCOT grid. That project itself has four sites, and the first of the four sites is in the final stages of commissioning with ERCOT. That has a kinda four-week process where you're testing with ERCOT, demonstrating your ability and competency to reliably deliver that power. We're getting ready for that, and then we should be in position to enter effectively the day-ahead trading, which is the kind of power that we plan to provide and offer for the grid. It's not a long-term thing, but it's something that we then think is flexible. You can react.

Philip Riley: Sure. Thanks. Yeah. The second project is this merchant project we have in ERCOT, in which we take our lower cost gas and convert that to electrons to sell to the ERCOT grid. That project itself has four sites, and the first of the four sites is in the final stages of commissioning with ERCOT. That has a kinda four-week process where you're testing with ERCOT, demonstrating your ability and competency to reliably deliver that power. We're getting ready for that, and then we should be in position to enter effectively the day-ahead trading, which is the kind of power that we plan to provide and offer for the grid. It's not a long-term thing, but it's something that we then think is flexible. You can react.

Sure, thanks. Uh, yeah, so the second project is this Merchant, uh,

4 sites. And the first of the 4 sites is in the final stages of commissioning uh with our cot that has a kind of 4 week process where you're testing with Kai demonstrating your

Philip Riley [Chief Financial Officer and Executive Vice President: Our partner has a very active trading desk there that you can look at the dynamics, both gas and power, and make decisions on that kind of basis. You know, ultimately, this is for a few things, but one of the primary things is, frankly, to try to improve effective net backs on our gas. Now, that may not show up on our revenue, like I mentioned on our negative revenue we experienced in the Q4. Basically, it's taking that same inherent energy that's embedded in that molecule, right? Turning it into something that maybe the market would value more. We'll see. We're excited for it. We think it can make some sense.

Philip Riley: Our partner has a very active trading desk there that you can look at the dynamics, both gas and power, and make decisions on that kind of basis. You know, ultimately, this is for a few things, but one of the primary things is, frankly, to try to improve effective net backs on our gas. Now, that may not show up on our revenue, like I mentioned on our negative revenue we experienced in the Q4. Basically, it's taking that same inherent energy that's embedded in that molecule, right? Turning it into something that maybe the market would value more. We'll see. We're excited for it. We think it can make some sense.

Ability and competency to reliably deliver that power, uh, we're getting ready for that. And then we should be in position to enter, effectively the day ahead trading, which is the, the kind of power that we plan to provide and, and, and offer for the grid. Uh, it's not a long-term thing, but it's, it's something that we then think it's flexible. You can react. We, our partner has a, a very active trading desk there that you can look at the Dynamics, both gas and power and uh, make decisions on that kind of basis. Um, you know, ultimately, this is for, uh, you know, it's for a few things, but 1 of the primary things is frankly to try to improve effective.

Net backs on our gas. Now, that may not show up on our revenue like I mentioned on our negative revenue we experienced in the fourth quarter, but basically it's taking that same inherent energy that's embedded in that molecule, right? And turning it into something that maybe the market would value more.

Philip Riley [Chief Financial Officer and Executive Vice President: We've seen some other companies sign up to do something like that as they also have challenges with in-basin gas realizations. As for doing more, man, you know, look how much has changed with power in the last two years, right?

Philip Riley: We've seen some other companies sign up to do something like that as they also have challenges with in-basin gas realizations. As for doing more, man, you know, look how much has changed with power in the last two years, right?

We'll see. We're excited for it. Um, we think it can make some sense. We've seen some other companies sign up to do something like that, as they also have challenges within basis and gas realizations.

John Suter: Sounds right.

Neal Dingmann: Sounds right.

Philip Riley [Chief Financial Officer and Executive Vice President: Since we announced this. I mean, I think we'd like to see how this goes. These are very, very small sites, 10 megawatt compared to the gigawatt type of sites you're seeing now. You know, gigawatt plants and data centers are massive operations, incredibly capital intense. You got the hyperscalers now, right? You know, committed to what? $600 billion of CapEx combined with them. It's all the way up to the president, right? Who said, "Okay, you guys now need to be in charge of your own power." We're talking big, big, big scale. At the same time, that tends with that arena of infrastructure CapEx and investors tends to push down returns. I think for now we're being cautious and we're waiting to see.

Philip Riley: Since we announced this. I mean, I think we'd like to see how this goes. These are very, very small sites, 10 megawatt compared to the gigawatt type of sites you're seeing now. You know, gigawatt plants and data centers are massive operations, incredibly capital intense. You got the hyperscalers now, right? You know, committed to what? $600 billion of CapEx combined with them. It's all the way up to the president, right? Who said, "Okay, you guys now need to be in charge of your own power." We're talking big, big, big scale. At the same time, that tends with that arena of infrastructure CapEx and investors tends to push down returns. I think for now we're being cautious and we're waiting to see.

Um, as for doing more. Uh, man. You know, look how much has changed with power in the last 2 years, right? Uh, since we announced this, um, and so I, what, what I'd say is, I mean, I think we'd like to see how this goes. Um, these are very, very small sites 10 megawatt compared to the gigawatt type of sites you're seeing now. Um, you know, gigawatt plants, and data centers are massive operations. Incredibly Capital intense. You got the hyperscalers now, right? Uh, you know, committed to what 600 billion of capex combined with them, and then that's all the way up to the President, right? Who said, okay, you guys now, I need to be in charge of your own power. So, we're talking big, big, big scale, um,

Philip Riley [Chief Financial Officer and Executive Vice President: We're opportunistic. I mean, that's usually the way we treat things. I encourage you to think about it as like opportunistic projects. We did one with midstream. This is another type of project like that, is how we're thinking about it for now.

Philip Riley: We're opportunistic. I mean, that's usually the way we treat things. I encourage you to think about it as like opportunistic projects. We did one with midstream. This is another type of project like that, is how we're thinking about it for now.

John Suter: Thanks, Philip. again, fantastic deal also on the midstream project.

Neal Dingmann: Thanks, Philip. again, fantastic deal also on the midstream project.

And then at the same time that that tends with that Arena of infrastructure, capex and investors tends to push down returns and so I think for now we're being cautious and we're, we're waiting to see we're opportunistic. I mean, that's usually the way we treat things. Uh, I encourage you to think about it as like, opportunistic projects, we, we did 1 with Midstream. Uh, this is another type of project like that, uh, is how we're thinking about it for now.

Thanks, Philip. And, uh, again, fantastic deal also on the Midstream project.

Philip Riley [Chief Financial Officer and Executive Vice President: Thank you.

Philip Riley: Thank you.

Operator: Our next question will come from the line of Nicholas Pope with Roth Capital. Please go ahead.

Thank you.

Our next question will come from the line of Nicholas. Pope with Roth Capital. Please go ahead.

Nicholas Pope: Morning, everyone.

John Suter: Morning.

Morning, everyone.

Philip Riley [Chief Financial Officer and Executive Vice President: Morning.

Philip Riley: Morning.

Nicholas Pope: There were some comments made about the New Mexico operations that, I guess in Q4, maybe even earlier in Q3, you know, when the compressor system came online, kind of helped, you know, boost production on top of artificial lift, you know, just downhole work on the wells that have really kind of yielded some real nice results there in kind of maintaining the production levels without a lot of drilling. I was curious, like, where, I guess, where that New Mexico side kind of is with your taking over operations and kind of some of that field, you know, production level optimization right now. Maybe do y'all think y'all are fairly kinda through kind of integration of all those assets?

Morning.

Um,

There was a, there was some comments made about, uh, the New Mexico operations that um I guess in the fourth quarter, maybe even earlier in the third quarter. You know, when they compressor system came on live and kind of helped a you know, boost production um on top of artificial lift.

Nicholas Pope: Do you think maybe there's more of that kinda quick hit, low-hanging fruit type production work that you got going in New Mexico?

Uh you know, just downhill work on the wells that have really kind of yielded, some real nice results there um and kind of maintaining the production levels without a lot of drilling. I was curious like where um I guess where that New Mexico side kind of is with the taken over operations and kind of some of that field you know, production level optimization right now and maybe is there. Do you all think y'all are fairly kind of through kind of integration of all those those assets, or do you think maybe there's more of that kind of quick, hit low hanging fruit type, uh, production work that you got going in New Mexico,

John Suter: Yeah, I would say in related to Q4, there was a couple of early pads that we've drilled that were just outstanding performance, we're really excited about, that we've done some testing on. Certainly we have integrated the Silverback acquisition that's on the west side of our of the Red Lake asset we originally had. We have worked on a lot of integration there. We've combined our workforces, you know, got down to one office, kind of benefited from some water handling optimization, reducing some costs. Again, just numerous things. We do have that, I would say, fully integrated. There has been some strong work over performance, which is what we've concentrated on in the early stages of this.

Yeah, I would say it's related to the fourth quarter.

Uh some of the there was a, you know, a couple of uh early pads that we've drilled that were uh just outstanding performance. Uh we're really excited about that. We've done some testing on uh certainly we have integrated the uh Silverback acquisition. That's on the the the west side of our uh of the Red Lake asset. We originally had

Um, we have worked on a lot of

Integration there. We've combined our workforces, you know, got down to one office, kind of benefited from some water handling optimization, reducing some costs.

uh,

concentrated on, um,

John Suter: We found a lot of low-hanging fruit there. Wellbore, wellbore cleanouts. We've been switching from some of their artificial lift methods, even from ESP to large pumping units and doing it earlier in their life. We're saving up to $20,000 a month per installation as we've been able to find those. We're kind of working through those to. That's what's been a big contributor to, like I mentioned, you know, just kind of the outperformance in the first, you know, six months of Silverback was fantastic, kinda keeping it way flatter than we thought we would. It's from the strong work overperformance.

In the early stages of this, we found a lot of low-hanging fruit there. Uh well more well, more cleanouts uh

We've we've been switching from uh, some of their artificial lift methods. Uh, even from ESP to large pumping units and doing it earlier in their life, uh, and we're saving up to $20,000 a month per installation, uh, as we've been able to find those

So we're uh we're we're kind of working through those to uh, that's what's been a big contributor to like I mentioned, you know, just kind of the outperformance in the first, you know, 6 months of Silverback uh was fantastic, kind of keeping keeping it way flatter than we thought we would and it's it's from the strong work over performance.

Nicholas Pope: I mean, are you still finding these opportunities in that area? I mean, it didn't seem like there was a big uptick in LOE in Q4 despite kind of the positive numbers. I'm just curious, like, is that still ongoing? Is there still pretty fertile ground there to optimize?

Yeah, and, and do you think there's

I mean, are you still finding these opportunities in that area? I mean, do we think that— I mean, it didn't seem like there was a big uptick in—

Eloe in the fourth quarter, despite kind of the the positive numbers. So I'm just curious like is that still ongoing, is there still pretty fertile ground there to optimize?

John Suter: Yeah, it is. There's certainly quite a few wells. I can't remember how many horizontals they had, maybe 30-ish, if I remember right, and then a lot of verticals. Again, we're just prioritizing seeing what's the most effective way to start. Then, yeah, just working through just blocking and tackling with some of these wells we've been able to restore to near initial production. Again, it's something that, you know, there's not hundreds of them, but we're certainly taking care of them. And that's allowing us to keep that steady and holding that while we develop our what we call kind of our Artesia West on our main Red Lake asset that we've had.

Yeah, it is. There's, uh, there's certainly quite a few wells. I, I can't remember how many horizontals they had, maybe, uh,

Uh, 30-ish if I remember, right? And then a lot of verticals. But again, we're we're just prioritizing, uh, seeing what's the most effective way to start?

Um,

And then, yeah, just working through, uh, just blocking and tackling with with uh, some of these some of these Wells we've been able to restore to, uh, to near initial production. So again that's it's, it's something that, uh, you know, there's not uh,

Not, uh, hundreds of them, but we're certainly taking care of them. And that's allowing us to keep that steady, and holding that while we develop our, um,

John Suter: We'll kinda do this in phases from an inside out approach as we are trying to be effective with Targa's infrastructure they'll be laying to support this. We're excited about, you know, the large number of upside type things there are here.

What we call kind of our Artisia West, on our main Red Lake asset that we've had. Uh, so we'll kind of do this in phases from an inside-out approach. As we are trying to be effective with Target's infrastructure, they'll be laying to support this.

But we're excited about, um, you know, the large number of upside-type things there are here.

Nicholas Pope: That's great. One housekeeping item. The divestiture that y'all made, that non-Yoakum County assets, was there any production associated with that small divestiture?

That's great. Um, one house—uh, the investigator—they all made that, non Yoakum County. Um,

Assets, was there any production associated with that small destitute?

John Suter: No, it was a very, very, very small amount. That was a legacy asset that we brought in. You know, I think progress, if you going public, I don't know what the number was.

No, it was a very, very, very small amount. Uh,

Philip Riley [Chief Financial Officer and Executive Vice President: A few 100 barrels.

Philip Riley: A few 100 barrels.

John Suter: Yeah, a couple of hundred barrels.

Nicholas Pope: Okay. That's it. All right. That's all I got. I appreciate the time, guys. Thank you.

Because it was a legacy asset that we brought in. You know, I think progress—if you can go in public. I don't know what the number was. 200 barrels. Yeah. A couple hundred barrels a day, okay.

Gotcha. All right. That's all I got. I appreciate the time, guys. Thank you.

Operator: Our next question comes from the line of Noel Parks with Tuohy Brothers. Please go ahead.

Our next question comes from the line of Noah Parks with Tubby Brothers. Please go ahead.

Noel Parks: Hi. Good morning.

Hi, good morning.

Philip Riley [Chief Financial Officer and Executive Vice President: Good morning.

Philip Riley: Good morning.

Good morning.

Noel Parks: Just wanted to ask a couple. I think I sort of caught everything from the various moving parts that you were talking about, reserves and costs, you know, for the reserves for the year. I just, is there anything about the balance of in the costs incurred between what shows up as under the acquisition side versus the development side? Because the development CapEx is sequentially lower, well, lower year-over-year by a good bit, of course.

Um, just wanted to, um,

Uh, ask a couple. Um, I think I sort of caught everything from the various moving parts that you were talking about. Um,

Uh, reserves and, um, uh, and, uh, costs, um, you know, for, um,

For the reserves for the year.

But I, um,

I just, I

Is there anything? Um, about the the balance of, um,

Uh, in the classes incurred between what, uh, shows up as, um, under the acquisition side, versus the development side, because the development capex is, is sequentially.

Noel Parks: Just in doing my calculations, it just looked like the 1-year drill bit F&D came out especially low, which is a good thing, but I just wondered if there was anything sort of unusual about the bookings this year, you know, bringing new, you know, new areas onto the books and I'm sure reallocating CapEx with the SEC five-year rule and so forth. Any insight on that would be helpful.

Lower well, lower year-over-year by a good bit, of course. And, um, just in doing my calculations, it just looked like the one-year drill bit F&D came out, um, especially low, which is a good thing. But I just wondered if there was anything sort of unusual about the—

Philip Riley [Chief Financial Officer and Executive Vice President: Okay. Noel, I'll take a stab and follow up with you if you need to.

Philip Riley: Okay. Noel, I'll take a stab and follow up with you if you need to.

The bookings this year, you know, bringing new, you know, new areas onto the books. And I'm sure reallocating capex, um, with the SC five-year rule and so forth. So, um, any insight on that would be helpful.

Noel Parks: Sure.

Philip Riley [Chief Financial Officer and Executive Vice President: The direct answer is that there's nothing nuanced or new going on with regard to how we're booking. I think it's primarily the fact of what John described. We had lower activity in 25. You know, go back to April, May, Liberation Day, prices fall. At the same time, we captured that acquisition, and we tried to preserve capital for that. Had a little bit of, you know, competition for the allocation, given the midstream. We worked through the year like that. We're able to grow organically with modest activity, like he described, 16.3 net wells put online. I think a lot of it's that, combined with the cost savings on DNC. That probably translates to what you're seeing on the cash flow statement.

Philip Riley: The direct answer is that there's nothing nuanced or new going on with regard to how we're booking. I think it's primarily the fact of what John described. We had lower activity in 25. You know, go back to April, May, Liberation Day, prices fall. At the same time, we captured that acquisition, and we tried to preserve capital for that. Had a little bit of, you know, competition for the allocation, given the midstream. We worked through the year like that. We're able to grow organically with modest activity, like he described, 16.3 net wells put online. I think a lot of it's that, combined with the cost savings on DNC. That probably translates to what you're seeing on the cash flow statement.

Okay, no. I'll I'll take a stab and follow up with you if you need to. Um sure. The the direct answer is that there's nothing uh,

Philip Riley [Chief Financial Officer and Executive Vice President: When I convert that to reserves, I think we had about $13 a barrel cost to add proved developed reserves on a per barrel basis, not per barrel of oil. That was a positive. I think roughly flat with last year. On reserves, you know, just service announcement for everybody, we aim to take a pretty conservative philosophy of booking. I don't know that we booked a single PUD with Silverback, for example. Just being the public company with the SEC and the 5-year rule, as you mentioned, we just find it's, you know, easier to book as you go, at the kinda minimum. We focus on proved developed probably more so than total proved.

Philip Riley: When I convert that to reserves, I think we had about $13 a barrel cost to add proved developed reserves on a per barrel basis, not per barrel of oil. That was a positive. I think roughly flat with last year. On reserves, you know, just service announcement for everybody, we aim to take a pretty conservative philosophy of booking. I don't know that we booked a single PUD with Silverback, for example. Just being the public company with the SEC and the 5-year rule, as you mentioned, we just find it's, you know, easier to book as you go, at the kinda minimum. We focus on proved developed probably more so than total proved.

Uh I think it's primarily the fact of what John described we had lower activity in 25. Uh, you know, go back to April May Liberation day prices fall. Um, at the same time we capture that acquisition and we try to preserve capital for that at a little bit of, you know, competition for the allocation, give the Midstream. So we work through the year like that. We're able to grow uh organically with modest activity, like he described 16, uh, 3 Wells put online. Uh so I think a lot of its that, um, combined with the cost savings on DNC. Um, and so that probably translates to what you're seeing on the cash flow statement. When I convert that to reserves, I, I think we had about 13 dollars, a barrel cost to add proved developed reserves on a per barrel basis, not per barrel of oil. Um,

And so, that was a positive. I think roughly flat with last year on reserves, you know, just—

Service announcement for everybody. We

I aim to take a pretty conservative philosophy of booking. Uh, I don't know that we booked a single PUD with Silverback, for example, just being the public company with the SEC and the 5-year rule, as you mentioned. Um, we just find it's, you know, easier to book as you go, at the, at the kind of minimum. So we focus on

John Suter: Yeah, I think that's right, Philip. Just with our relatively conservative pace, you know, you could book most of Champions as a PUD if you wanted to, all but the very eastern exterior wells, but we've chosen not to do that. New Mexico, you know, until we start drilling more, we'll be able to expand our PUD base as we start developing more. We've been limited again with gas takeaway, water takeaway that now has been fixed. You know, we do pad drilling, that hurts you from being able to go out and drill 6 different areas instead of 6 wells on the same pad. You can, you can certainly book more pads if you do that.

True developed, probably more so than total proved.

Yeah, I think. That's right. Philip the, um, just with our relatively conservative pace,

You know, you could you could book most of Champions as a PUD if you wanted to, um, all. But the very East Eastern exterior Wells, but we, we've chosen not to do that. Uh, New Mexico.

John Suter: I would agree with Philip, we've taken a pretty conservative stance here, but we have a lot of optionality in the future to improve that.

You know, until we start drilling more than we'll be able to expand our uh, PUD base. As we start developing more, but we've been limited again with gas. Takeaway water takeaway that now has been fixed. Um, you know, we do do pad Drilling. And so that's that, that hurts you from being able to go out and drill 6 different areas instead of 6 Wells on the same pad you can. Uh, you can certainly book more puds if you do that. But uh, I would agree with Philip where we've taken a pretty conservative stance here, but we have a uh, a lot of optionality in the future to um,

To improve that.

Noel Parks: Great. Thanks. That does fill in a couple gaps I had in my understanding. That's great. I was thinking, just on the question before you were talking about the really nice low-hanging fruit that you have from, you know, maintenance tasks, workovers. You mentioned wellbore cleanups and so forth. I do recall, just like I think talking about both of your significant pieces of New Mexico acquisitions, especially with this, the most recent one, Silverback, that the assets being in the hands of, you know, folks who really were coming from more of a, you know, private equity sort of financing background as opposed to, you know, being sort of just your typical operators.

Great. Thanks. That does, that does fill in a a couple gaps I had in in my understanding. So that's uh, that's great. And, um, I I was thinking, uh, just on the question before you were talking about um, the the really nice low-hanging fruit um that uh you have from, you know,

Maintenance, uh, maintenance tasks, workovers, making well more cleanups, and so forth. And I, I do recall.

um,

just I think talking about both of your significant pieces of of new new meal Acquisitions, especially with this, the most recent 1 Silverback that, um, the assets being in the hands of, uh,

You know, folks who really were coming from more of a, you know, private equity sort of, uh, financing background as opposed to, um,

Noel Parks: As you look around, the other vintages of, you know, entries into the basin and into conventional plays that various parties have done over the last, you know, 5+ years or so, do you anticipate similarly, I don't know if I call them neglected, but just similar packages out there that have low-hanging fruit that's similar? I do recall you saying in the past that the issue is that there isn't really enough upside in a lot of what's been available. I just wondered if a deal something like Silverback is something that maybe over the next few years you could replicate easily.

you know, being sort of just your typical operators, um, it as you look around, um, the the other vintages of, um,

Uh, you know, entries into the base and into the conventional plays that various parties have done over the last, you know, you know, you know 5 plus years or so.

Um, do you anticipate? Similarly, um, I don't know if I call them neglected, but just, uh, uh, similar packages out there that have low hanging fruit, that's similar, um, I do recall you saying in the past that the the issue was that they're they're isn't really enough upside in a, a lot of what's, uh, been available. But um, but I just wondered if if a deal something like um, Silverback is

Something that maybe, over the next few years, you could replicate easily.

John Suter: Yeah, that's a, you know, there's a lot of different things in there. I think various companies just focus their capital on different things, whether they're trying to drill and flip or if they want to, you know, develop it as a legacy asset. I do think our team is particularly good at it. I will say that, of recognizing it and then acting on it, you know. That being said, various companies deal with that in different ways. I think that we can find a lot of fruit in most assets. Again, we, you know, we bought Silverback for the most part for all of the drilling opportunity. The, you know, it's a ton of acreage, right along trend in the Yeso play.

Yeah, that's a, you know, a

There's there's a lot of different things in there. Uh, I I think various companies just focus their capital on different things whether they're trying to

I do think our team is particularly good at it. I will say that of recognizing it and then um, acting on it, you know. But that being said

Various companies deal with that in different ways.

Um, I think I think that we can, uh, find a lot of fruit in in most assets.

but um,

uh, again we, you know, we bought silver back for the most part for

John Suter: That's why we bought it. All of this other stuff with production optimization is just bonus in my book.

Uh, all of the drilling opportunity. You know, it's a ton of acreage, right? Right along trend in the Yo play.

That's why we bought it. Uh, all of this other stuff with production optimization.

Uh, is just uh, bonus in my book.

Noel Parks: Great. Thanks a lot.

Great. Thanks a lot.

Operator: Our next question comes from the line of Jeff Robertson with Water Tower Research. Please go ahead.

Jeff Robertson [Managing Director: Thank you. Bobby, you talked about restarting the share repurchase program. Can you just talk about how that plan fits into your overall capital allocation with dividends, debt reduction, potential for acquisitions?

Jeff Robertson: Thank you. Bobby, you talked about restarting the share repurchase program. Can you just talk about how that plan fits into your overall capital allocation with dividends, debt reduction, potential for acquisitions?

Our next question comes from the line of Jeff Robertson with Water Tower Research. Please go ahead.

John Suter: Yeah. Thanks for the question, Jeff. It basically is just another tool in our tool chest, to where we look for being opportunistic. If we feel like the share price, which we do, is undervalued, it may behoove us to continue more aggressively in a share buyback. Obviously, in these accelerated prices, the returns we get on the drill bit are extremely great for us. You know, that may not lend to buyback at that particular time. The fact that we're flexible and can spend our money either in stock buyback or development, you know, that's where we wanna be. You saw from the comments and from the files, I think we averaged the buyback around $26.50 a share or something like that.

Bobby Riley: Yeah. Thanks for the question, Jeff. It basically is just another tool in our tool chest, to where we look for being opportunistic. If we feel like the share price, which we do, is undervalued, it may behoove us to continue more aggressively in a share buyback. Obviously, in these accelerated prices, the returns we get on the drill bit are extremely great for us. You know, that may not lend to buyback at that particular time. The fact that we're flexible and can spend our money either in stock buyback or development, you know, that's where we wanna be. You saw from the comments and from the files, I think we averaged the buyback around $26.50 a share or something like that.

Thank you. Uh, Bobby, you talked about restarting the share repurchase program. Can you just talk about how that plan fits into your overall capital allocation with dividends, debt reduction, and potential for acquisitions?

Yeah, uh, thanks for that, for the question, Jeff. It's basically—it's just another tool in our tool chest, uh, to where we look for being opportunistic. If we feel like the share price—which we do—is undervalued, uh,

John Suter: When the share price is out, I'm definitely buying. I don't know if I answered your question, but basically it's there and it's ready when we need it. If we feel like the return is better on the share buyback than drilling, then that's what we're gonna do.

Bobby Riley: When the share price is out, I'm definitely buying. I don't know if I answered your question, but basically it's there and it's ready when we need it. If we feel like the return is better on the share buyback than drilling, then that's what we're gonna do.

It may be behoove us to continue more aggressively in a share buyback. Obviously in these accelerated prices it returns we get on the drill bit, our our, our extremely uh, great for us. So you know, that may not lend to buy back at that particular time, but the fact that we're, we're flexible and can spend our money either in stock buyback, our development, you know, that's, that's where we want to be. Uh, you you sell from the comments from the files, I think we average the buy back to around, 26, 50 a share or something like that. Uh,

When the share price is out, I'm definitely buying, uh,

So I don't know if I answered your question but basically it's it's it's there and it's ready when we need it and if we feel like uh the return is better on the on the share buyback, then drilling then that's what we're going to do.

Jeff Robertson [Managing Director: Thank you. John, in your comments, I think you said, or maybe Philip, you said you replaced two-thirds of the 2025 drilled locations for, I wrote down less than $300,000 per location. Can you provide any color as to where those locations fit in the chart you have on slide 5, where you talk about locations by return on investment? Secondly to that, do you have a goal or an objective to how many locations you would like to replace, that you'll drill in the 2026 program?

Jeff Robertson: Thank you. John, in your comments, I think you said, or maybe Philip, you said you replaced two-thirds of the 2025 drilled locations for, I wrote down less than $300,000 per location. Can you provide any color as to where those locations fit in the chart you have on slide 5, where you talk about locations by return on investment? Secondly to that, do you have a goal or an objective to how many locations you would like to replace, that you'll drill in the 2026 program?

Thank you. Uh John in your comments. I think you said or maybe Philip you said you replaced 2/3 of the 2025 drilled locations.

For, uh, I wrote down less than $300,000 per location. Can you provide any color as to where those locations fit in the chart you have on, uh, slide 5, where you talk about locations by return on investment? And then, secondly to that, do you have a goal or an objective for how many locations you would like to replace?

Uh, that you'll drill in the 26 program.

Philip Riley [Chief Financial Officer and Executive Vice President: I will attempt to answer that. Yeah. The locations, I'd say they fall in kind of the middle of the 2 to 3x DROI. You're looking at just referencing page 5 of our presentation. Right third, we've got a chart in there. The Lower tier there just for the benefit is a small section kind of on the perimeters of Red Lake, but most of our stuff is great and we're excited about it. This that we got was we think nice down the fairway type of locations just under a dozen there, so we're thrilled to do that. Yeah, this might be a Bobby answer, but I'll attempt it. You know, look, our goal is to replace as much as we can. If we could replace 100%, then that's fantastic, right?

Philip Riley: I will attempt to answer that. Yeah. The locations, I'd say they fall in kind of the middle of the 2 to 3x DROI. You're looking at just referencing page 5 of our presentation. Right third, we've got a chart in there. The Lower tier there just for the benefit is a small section kind of on the perimeters of Red Lake, but most of our stuff is great and we're excited about it. This that we got was we think nice down the fairway type of locations just under a dozen there, so we're thrilled to do that. Yeah, this might be a Bobby answer, but I'll attempt it. You know, look, our goal is to replace as much as we can. If we could replace 100%, then that's fantastic, right?

Philip Riley [Chief Financial Officer and Executive Vice President: In a depletion business, you've got to have something like that to some degree. The closer you can get to 1x or 100%, that's great. We're thrilled with 60% last year. Of course, it was easier coming off of putting on 18 wells versus 40. We're always out there looking for things. You've seen us have an active A&D, you know, track record so far. We'll do the best we can.

Philip Riley: In a depletion business, you've got to have something like that to some degree. The closer you can get to 1x or 100%, that's great. We're thrilled with 60% last year. Of course, it was easier coming off of putting on 18 wells versus 40. We're always out there looking for things. You've seen us have an active A&D, you know, track record so far. We'll do the best we can.

That this might be a Bobby answer, but, uh, I'll attempt it and I'll look where our goal is to replace as much as we can, if we could replace a 100 percent, and that's fantastic. Alright, and in a depletion business, you've got to have something like that, to some degree. Uh, the closer, you can get to 1x or 100%, that's, that's great. Uh, so we're thrilled with with, uh, 60% last year. Now, of course, it was easier coming off of putting on 18, Wells versus 40. But, uh, we're always out there looking for things. You've seen us have an active, A, and D. Um,

John Suter: Yeah. Let me add a little bit to that. We're focusing this year with our land group, where we've kind of restructured it to one of our key focuses is gonna be what we call the ground game, which is this is not going out and buying a competitor. This is actually just digging in and adding acreage in and around our existing footprint. The goal would be to replace 100% of what we drill every year or more. I think we have that opportunity in New Mexico. We're executing a few of those opportunities in our legacy Yoakum asset this month as we speak. We're a little bit more limited there on where we think the rock creates a opportunity than we are in New Mexico.

You know, track record so far, um, we'll do the best we can. Yeah, let let me add a little bit to that. Um,

We were focusing this year, with our Land Group, where we've kind of restructured it to—one of our key focuses is going to be what we call the ground game, which is, this is not going out and buying a competitor. This is actually just digging in and adding acreage in and around our existing footprint.

John Suter: That's one of our big focuses this year is gonna be, what we call the ground game and executing that and replacing our drilling inventory at least 100% with bolt-ons.

Uh, and and the goal would be to replace 100% of what we drill every year or more. And I think we have that opportunity uh, in New Mexico. We're executing a few of those opportunities and, and our Legacy Yoakam asset this month. As we speak, uh, we're a little bit more limited there on where we think the The Rock creates, uh, opportunity than we are in New Mexico. But that that's 1 of our big focuses. This year is going to be what we call the ground game and and executing that and replacing it.

Our drilling inventory, at least 100%, with, uh, with—

The bolt-ons.

Jeff Robertson [Managing Director: Thank you. Philip, Riley signed an agreement with WaterBridge, which I believe takes effect in September 2026. Will that agreement with respect to saltwater disposal lower your costs? Will it just improve efficiencies in the Red Lake area? How do you characterize that, the benefit of that?

Jeff Robertson: Thank you. Philip, Riley signed an agreement with WaterBridge, which I believe takes effect in September 2026. Will that agreement with respect to saltwater disposal lower your costs? Will it just improve efficiencies in the Red Lake area? How do you characterize that, the benefit of that?

Thank you, and and Philip. So you all saw or Riley signed an agreement with Waterbridge, which I believe takes effect in September of 2026.

Will that agreement with respect to saltwater disposal lower your costs? Will it just improve efficiencies in the Red Lake area or—

How do you — how should — how do you characterize that benefit of that?

John Suter: Yeah, this is John. It's going to increase our cost. What it does is allows for full-scale development the rest of the way for this field. You know, we did an agreement, I would say, at industry standard rates. We're really pleased with it. More than any kind of minor efficiency, it's just like the Targa is for gas. It's to allow full field development without having to worry if there's any capacity somewhere.

yeah, this is John uh,

It's going to increase our cost.

Um,

but what it does is it allows for full-scale development.

um, the rest of the way for this field,

So it's, uh, you know, we did an agreement, I would say at industry standard rates, um,

And we're, we're really pleased with it. But uh,

More than any kind of minor efficiency. It's, uh,

Philip Riley [Chief Financial Officer and Executive Vice President: Let me just add on in that what we hope to achieve is that we're managing the costs over time and that we achieve at the same time, as some of those WaterBridge costs are impacting us, we get overall efficiencies just with the scale as a larger percentage of the Red Lake production becomes horizontal, which is much higher margin, lower cost, versus right now you've got some component of that that's just, frankly, the vertical that was holding the land. It's how we got it from a seller. Right?

Philip Riley: Let me just add on in that what we hope to achieve is that we're managing the costs over time and that we achieve at the same time, as some of those WaterBridge costs are impacting us, we get overall efficiencies just with the scale as a larger percentage of the Red Lake production becomes horizontal, which is much higher margin, lower cost, versus right now you've got some component of that that's just, frankly, the vertical that was holding the land. It's how we got it from a seller. Right?

It's just like the target is for gas. It's to allow full field development, uh, without uh, without having to worry if there's any capacity somewhere. And and let me just add on in that I I what we hope to achieve is that we're managing the costs over time and that we achieve at the same time, uh, as as some of those Water Bridge.

John Suter: Right. you know, we do have a lot of undedicated acreage at this point, so we still have flexibility for future options as well.

Are impacting us. We get overall efficiencies just with the scale as a larger percentage of the Red Lake production becomes horizontal, which is much higher margin, lower cost versus right now. You've got some component of that that just frankly the the vertical that was holding the land that it's it's how we got it from a seller, right, right. And uh, you know, we we do have a lot of Undead acreage at this point. So we still have uh, flexibility for for future options as well.

Jeff Robertson [Managing Director: Lastly, Philip, you spoke about hedges for 2026. Given the shape of the curve today, where you've got for 2027 prices, I think are for oil are in the mid-sixties. Can you just provide any color on how you're thinking about hedging in a volatile market?

Jeff Robertson: Lastly, Philip, you spoke about hedges for 2026. Given the shape of the curve today, where you've got for 2027 prices, I think are for oil are in the mid-sixties. Can you just provide any color on how you're thinking about hedging in a volatile market?

And lastly, Philip you spoke about hedges for 2026. Given the shape of the curve today, where you've got, we're 2027.

Prices I think are for oil are in the mid-60s. Can you just provide any color on how you're thinking about?

Uh, hedging in the in a volatile Market.

Philip Riley [Chief Financial Officer and Executive Vice President: Yeah. We talk about it approximately 27 times a day and then think about it through the night. You know, we've been through 5 years of volatility, right? We're trying to position ourselves and protect the program ahead. You know, our philosophy historically is when we've got higher capital obligations and debt loads, then we might benefit from the hedging. We had that as of December. We don't now, since you hedge in advance, you know, absent liquidating some of those, we have those on the books. You know, and I mentioned this in my prepared remarks, we also entered the year with, you know, everybody calling for a surplus and you know, $50 or $55 WTI. We're happy with where we are.

Philip Riley: Yeah. We talk about it approximately 27 times a day and then think about it through the night. You know, we've been through 5 years of volatility, right? We're trying to position ourselves and protect the program ahead. You know, our philosophy historically is when we've got higher capital obligations and debt loads, then we might benefit from the hedging. We had that as of December. We don't now, since you hedge in advance, you know, absent liquidating some of those, we have those on the books. You know, and I mentioned this in my prepared remarks, we also entered the year with, you know, everybody calling for a surplus and you know, $50 or $55 WTI. We're happy with where we are.

Yeah, so we talked about it approximately 27 times a day and then think about it through the night. Uh, you know, we've been through 5 years of volatility, right? Um, we're trying to position ourselves and protect the program ahead. Um, you know, our philosophy historically is, when we've got higher capital obligations and debt loads, then we might benefit from the hedging. Uh, we had that as of December—um, we don't now, but since you hedge in advance, you know, in absent liquidating some of those, uh,

Philip Riley [Chief Financial Officer and Executive Vice President: You know, we'll be happy to write a check to the hedge counterparties if oil is at $70 for many months. We're not holding our breath, and we don't need that to execute on our plan. Like I said, 2/3 of the hedges this year are in the form of swaps, with the balance in collars. The collars kinda have a range of weighted average, I'd call it $58 to 72. We feel good about that. There's plenty of room in there to make some margin. We, you know, last thing I'll say is we remember what it was like coming out of COVID in 2020 or coming out in 2021 with the prices rising, and we enjoyed that, seeing the daylight and getting that.

Philip Riley: You know, we'll be happy to write a check to the hedge counterparties if oil is at $70 for many months. We're not holding our breath, and we don't need that to execute on our plan. Like I said, 2/3 of the hedges this year are in the form of swaps, with the balance in collars. The collars kinda have a range of weighted average, I'd call it $58 to 72. We feel good about that. There's plenty of room in there to make some margin. We, you know, last thing I'll say is we remember what it was like coming out of COVID in 2020 or coming out in 2021 with the prices rising, and we enjoyed that, seeing the daylight and getting that.

Like I said, two-thirds of the hedges this year are in the form of swaps, with the balance in collars. The collars kind of have a range of weighted average—I call it $58 to $72.

And so we feel good about that. There's plenty of room in there to to make some margin. Um,

Philip Riley [Chief Financial Officer and Executive Vice President: We have to be careful to hedge too much as we monitor the cost environment. John's group has to, you know, react to potentially changing service costs. Now, I think we're in a different environment, and we don't hope to see the same type of inflation across the board like we did then, which I think was also related to the Fed printing money and so forth. Anyway, that's kind of a long answer of saying, you know, we're quite hedged. We feel fine about it. We've got a lot of volumes to work with. We can always do more, we could do less. Feeling good on the setup for now.

Philip Riley: We have to be careful to hedge too much as we monitor the cost environment. John's group has to, you know, react to potentially changing service costs. Now, I think we're in a different environment, and we don't hope to see the same type of inflation across the board like we did then, which I think was also related to the Fed printing money and so forth. Anyway, that's kind of a long answer of saying, you know, we're quite hedged. We feel fine about it. We've got a lot of volumes to work with. We can always do more, we could do less. Feeling good on the setup for now.

we you know last thing I'll say is we we remember what it was like coming out of coid in 2020 or coming out in 2021 with the prices rising. And we enjoyed that seeing the daylight and uh and getting that. But we have to be careful uh to hedge too much as we monitor the cost environment and John's group has to, you know, react to potentially changing service costs. Now, I think we're in a different environment and we don't hope to see the same type of of inflation across the board. Like we did then, which I think was also related to the FED printing money and and so forth. But um, anyway, that's kind of a long answer of of saying, you know, we're we're quite hedge. We feel fine about it. Um, we got a lot of volumes to work with. Uh, we can always do more, we could do less, um, but feeling feeling good on the setup for now.

[Company Representative] (Riley Exploration Permian): Thank you.

Jeff Robertson: Thank you.

Bobby D. Riley: Jeff Robertson, this is Bobby Riley. Let me follow up just to give you a little bit more color on your question on our kind of our ground game and our inventory. One of the things that we're doing here with our subsurface team is really looking at the way our completions in New Mexico through microseismic, through different tracer surveys to where we optimize what our wine rack looks like, so to speak. I mean, right now, we have a very conservative approach of about five wells, three in one bench and two in another bench.

Bobby Riley: Jeff Robertson, this is Bobby Riley. Let me follow up just to give you a little bit more color on your question on our kind of our ground game and our inventory. One of the things that we're doing here with our subsurface team is really looking at the way our completions in New Mexico through microseismic, through different tracer surveys to where we optimize what our wine rack looks like, so to speak. I mean, right now, we have a very conservative approach of about five wells, three in one bench and two in another bench.

Bobby D. Riley: We're kind of going to where we're gonna add a whole another bench in the San Andres and some of our acreage, and then modifying possibly by adding a well or two per section in the wine rack that we have right now. That's gonna organically increase our well count considerably when we get to finalizing that. I do know there will be an increase. I don't know just how impactful it will be, but it will move the needle there.

Bobby Riley: We're kind of going to where we're gonna add a whole another bench in the San Andres and some of our acreage, and then modifying possibly by adding a well or two per section in the wine rack that we have right now. That's gonna organically increase our well count considerably when we get to finalizing that. I do know there will be an increase. I don't know just how impactful it will be, but it will move the needle there.

Thank you, Jeff. Let me this is Bobby. Let me follow up. Just to give you a little bit more color on your question, on our kind of our ground game and our inventory, uh, 1 of the things that we're doing here. With our, our subsurface team is really looking at, uh, the way, our completions in New Mexico, through Microsoft, make through different Tracer, surveys to where we optimize what our our wine rack looks like, so, to speak. I mean, right now, uh, we have a very conservative approach of about 5 5 Wells, 3 in 1 bench and 2 in another bench. Uh, but we're, we're, we're kind of

Philip Riley [Chief Financial Officer and Executive Vice President: Yeah. That spacing you were mentioning is per 320.

John Suter: Yeah. That spacing you were mentioning is per 320.

Going to where we're going to add a whole another bench in the San Andreas and some of our acreage and then modifying possibly by adding a well or 2 uh per section in the uh the the the wine rack that we have right now. Uh so that's going to organically increase our our well count considerably. When we get to finalizing that I don't I do know, there will be an increase. I don't know, just how impactful it will be but it will, it will move the needle there.

Bobby D. Riley: Yeah. Okay. Yeah.

Bobby Riley: Yeah. Okay. Yeah.

Yeah, and that space that you were mentioning is for 320. Yeah, okay.

[Company Representative] (Riley Exploration Permian): Those would be locations added on existing acreage, so there's really no incremental cost.

Jeff Robertson: Those would be locations added on existing acreage, so there's really no incremental cost.

Those would be locations added on existing in.

Existing Acres of there's really no incremental cost.

Bobby D. Riley: No incremental cost in the acreage. That's correct.

Bobby Riley: No incremental cost in the acreage. That's correct.

[Company Representative] (Riley Exploration Permian): Thank you.

Jeff Robertson: Thank you.

No incremental cost in the acreage. That's correct.

Thank you.

Operator: This concludes the question and answer session and our call today. Thank you all for joining. You may now disconnect.

and this concludes,

Question and answer session and our call today. Thank you all for joining. You may now disconnect.

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