Q2 2025 Coterra Energy Inc Earnings Call

John (Conference Operator): Thank you for standing by. My name is John, and I will be your conference operator today. At this time, I would like to welcome everyone to the Coterra Energy's second quarter 2025 earnings 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 followed by the number one on your telephone keypad. To withdraw your question, simply press star one again. I would now like to turn the call over to Daniel Guffey, VP of Finance, Investor Relations, and Treasurer. Please go ahead.

Shannon Young: Thank you, John. Good morning, and thank you for joining Coterra Energy's second quarter 2025 earnings conference call. Today's prepared remarks will include an overview from Thomas Jordan, Chairman, CEO, and President; Shannon Young, Executive Vice President and CFO; Blake Sirgo, Executive Vice President of Operations; and Michael DeShazer, Executive Vice President of Business Units, is also in the room to answer questions. Following our prepared remarks, we will take your questions during our Q&A session. As a reminder, on today's call, we will make forward-looking statements based on our current expectations. Additionally, some of our comments will reference non-GAAP financial measures. Forward-looking statements and other disclaimers, as well as reconciliations to the most directly comparable GAAP financial measures, were provided in our earnings release and updated investor presentation, both of which can be found on our website. With that, I'll turn the call over to Thomas.

Thank you for sending by my name is John and I will be your conference operator. Today at this time I would like to welcome everyone to the Cotera energy second quarter 2025 earnings. 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 followed by the number 1 on your telephone keypad. To withdraw, your questions simply press star 1. Again, I would now like to turn the call over to then Gaffey VP of Finance, investor relations and Treasurer. Please go ahead.

Thomas Jorden: Thank you, Dan, and thank you, all of you, for joining us on the call this morning. I will provide an overview before handing it over to Shannon for financial results and an operational update from Blake. Coterra had an excellent second quarter. We exceeded the high end of our guidance range for natural gas and total barrel of oil equivalent production and came in well above our midpoint on oil volumes. Our revenues for the quarter were nicely balanced between oil and natural gas, inclusive of natural gas liquids. We generated outstanding returns on capital and are on track to finish the year investing approximately 50% of our cash flow. A low reinvestment rate is one of the primary measures of asset quality, and Coterra remains top tier in our ability to deliver consistent, profitable growth with high capital efficiency.

Thank you, John, good morning, and thank you for joining. Kotor energies second quarter 2025 earnings conference. Call today's prepared, remarks will include an overview from Tom Jordan chairman CEO and president Shane Young Executive, Vice President and CFO Blake Sergo Executive Vice President of Operations. Michael dazer, Executive Vice President of business units is also in the room to answer questions. Following our prepared remarks, we will take your questions during our Q&A session. As a reminder, on today's call, we will make forward-looking statements based on our current expectations. Additionally, some of our comments will reference non-gaap Financial measures, forward-looking statements, and other disclaimers as well as reconciliations to the most directly comparable, gaap Financial measures or provided in our earnings release and updated investor presentations, both of which can be found on our website with that. I'll

Turn the call over to Tom.

Thank you, Dan, and thank you all for joining us on the call this morning.

I I will provide an overview before handing it over to Shane for financial results and an operational update from Blake.

Cotera had an excellent second quarter. We exceeded the high end of our guidance range for natural gas and total barrel of oil equivalent production and came in well above our midpoint on oil volumes.

Our revenues for the quarter were nicely, balanced between oil and natural, gas inclusive of Natural Gas Liquids.

We generated outstanding Returns on Capital and are on track to finish the year investing. Approximately 50% of our cash flow,

Thomas Jorden: I would like to provide an update on our Culbertson-Harkey program. We are on track with our efforts to address the issues that cropped up in our Wyndham-Harkey flowbacks last quarter. We have additional evidence that strongly indicates that the issues we encountered are localized around the Wyndham development and not widespread to our Culbertson assets. Blake will give you more details around six new Harkey wells recently brought online that are in the immediate vicinity of the Wyndham Row. We're making meaningful progress and expect the Harkey to be a solid contributor to our program for years to come. We have seen some weakening in natural gas prices over the past quarter, and the recent announcement of the cessation of the OPEC Plus curtailments has led to a softening of oil markets. We live in an environment of perpetual commodity uncertainty.

A low reinvestment rate is one of the primary measures of asset quality, and Coterra remains top-tier in our ability to deliver consistent, profitable growth with high capital efficiency.

I would like to provide an update on our Co hierarchy program.

We are on track with our efforts to address the issues that cropped up in our Windom Parky flow backs. Last quarter, we have additional evidence, that strongly indicates, that the issues we encountered are localized around the Windom development and not widespread through our Cobra and assets.

Blake will give you more details around 6, new hierarchy, Wells recently brought online that are in the immediate vicinity of the Windham row.

We're making meaningful progress and expect the harky to be a solid contributor to our program for years to come

We have seen some weakening in natural gas prices over the past quarter, and the recent announcement of the cessation of the OPEC+ curtailment has led to a softening of oil markets.

Thomas Jorden: Coterra's assets and capital allocation discipline allow us to maintain a steady operational cadence across modest peaks and valleys. Last quarter, during the uncertainty around the impact of terrorists, the Iranian enrichment response, the broader Middle East conflicts, and the potential impact of these and other forces on the world economic outlook, we discussed the plan to lay down activity. As we've seen this macro situation stabilize, we have decided to keep nine rigs deployed in the Permian, two rigs in the Marseles, and one to two rigs in the Anadarko. These decisions in aggregate will maintain consistent activity through the second half of 2025 and put us on solid footing for 2026. We look forward to updating our three-year outlook in February. As always, our outlook will be underwritten by steady cash flow, outstanding assets, and investment returns that help to accomplish our mission of consistent, profitable growth.

We live in an environment of Perpetual commodity uncertainty.

Cotter's assets and capital? Allocation discipline allow us to maintain a steady operational, Cadence across modest Peaks and valleys.

A world economic Outlook, we discussed the plan to lay down activity.

As we've seen this macro situation stabilized, we have decided to keep 9 rigs deployed in the Parian 2 rigs in the Marcellus and 1 to 2 rigs in the Anadarko. These decisions in aggregate will maintain consistent activity through the second half of 20125, and put us on solid footing for 2026.

We look forward to updating our 3 year outlook in February.

Thomas Jorden: We seek to grow our free cash flow and demonstrate its durability. We see the quality and durability of our free cash flow as one of Coterra's differentiating features. Volume growth is an output, not an input. We are bullish on the long-term prospects for our industry and for Coterra in particular. Recently, there has been discussion about the industry being in the final chapter of Tier 1 inventory. To that, we would like to make two comments. First, although it is inevitable, it will happen to different companies at different times. With our deep inventory of low-cost assets, Coterra is best positioned to maintain its strong capital efficiency for many years to come. Second, a decline in Tier 1 inventory will ultimately lead to an increase in cost structure and an increase in the clearing price for incremental volumes.

As always, our Outlook will be underwritten by Steady cash flow outstanding assets and investment returns that help to accomplish our mission of consistent profitable growth.

We seek to grow our free cash flow and demonstrated its durability.

We see the quality and durability of our free cash flow as 1 of kotter's differentiating features. Volume growth is an output not an input.

We are bullish on the long-term prospects, for our industry. And for coera in particular,

Recently, there has been discussion about the industry being in the final chapter of Tier 1 inventory.

To that we would like to make 2 comments.

First, although it is inevitable, it will happen to different companies at different times. With our deep inventory of low-cost assets Cotera is best positioned to maintain its strong Capital efficiency for many years to come.

Thomas Jorden: A logical consequence will be commodity price increases necessary for our industry to keep pace with demand. These consequences will materialize differently for oil than for natural gas, furthering our thesis of having meaningful exposure to both commodities. And one final thought: our industry will indeed face headwinds, but if we have learned one lesson in the past 20 years, it is to never underestimate the ingenuity, adaptability, and creativity of the American oil and gas producer. Our industry will find a way forward, and Coterra will be there to help. With that, I will turn the call over to Shannon.

Second a decline in Tier 1 inventory, will ultimately lead to an increased in cost structure and an increase in the clearing price for incremental volumes.

A logical consequence will be commodity price increases necessary for our industry to keep Pace with demand.

These consequences will materialize differently for oil than for natural gas, furthering our thesis of having meaningful exposure to both commodities.

And 1 final thought our industry will indeed face headwinds. But if we have learned 1 lesson in the past 20 years, it is to never underestimate the Ingenuity adaptability and creativity of the American Oil. And Gas producer. Our industry will find a way forward and Kotor will be there to help with that. I will turn to call over to Shane.

Shannon Young: Thank you, Thom, and thank you, everyone, for joining us on this morning's call. Today, I'd like to cover three topics. First, I'll quickly summarize the important takeaways from our second quarter financial results. Then, I'll provide an update on our guidance, including the third quarter as well as the full year 2025. Finally, I'll provide an update on our balance sheet and our cash flow priorities for the remainder of the year, turning to our strong performance during the quarter. During the second quarter, Coterra's oil production came in 2% above the midpoint of our guidance, while natural gas was above the high end of the guidance range due to outperformance in all three business units. BOEs were also above the high end of the guidance range, with strong NGL volumes as we were in ethane recovery for most of the quarter.

Thank you, Tom, and thank you everyone for joining us on this morning's call.

Today, I'd like to cover 3 topics. First, I'll quickly summarize the important takeaways from our second quarter Financial results.

Then I'll provide an update on our guidance, including the third quarter as well as the full year 2025.

Finally, I'll provide an update on our balance sheet and our cash flow priorities for the remainder of the year.

Turning to our strong, uh, sorry turning to our strong performance during the quarter.

During the second quarter, cotter's oil production came in 2% of the midpoint of our guidance. While natural gas, was above the high end of the guidance range due to outperformance in all 3 business units.

Shannon Young: The Permian had 49 net turn-in lines during the quarter, and the Anadarko and Marseles had net turn-in lines of nine and three, respectively. We expect tills for the year in all areas to continue to be in line with our annual guidance. Pre-hedge oil and gas revenues came in at $1.7 billion, with 52% of revenues coming from oil production. There's a 7% increase in oil contribution quarter over quarter, driven by higher oil volumes, and is consistent with our balanced commodity strategy. Cash operating costs totaled $9.34 per BOE, down 6% quarter over quarter on higher volumes and in line with our annual guidance midpoint. We reported net income of $511 million, or 67 cents per share, and adjusted net income of $367 million, or 48 cents per share for the quarter.

Boies were also above the high end of the guidance range with strong NGL volumes, uh, as they as their as we were in ethane recovery for most of the quarter.

The puran had 49 turn net turn in lines during the quarter and the Anadarko and Marcellus had net turn in lines of 9 and 3 respectively.

We expect tills for the year in all areas to continue to be in line with our annual guidance.

Free Edge oil and gas revenues came in at 1.7 billion dollars with 52% of revenues coming from oil production.

There's a 7% increase in oil contribution quarter over quarter driven by higher oil volumes and is consistent with our balance commodity strategy.

Cash operating costs total $9.34 per Boe down 6%. Quarter over quarter on higher volumes and in line with our annual guidance midpoint,

we reported net income of 511 million or 67 cents per share and adjusted net income of 367 million or 48 cents per share for the quarter.

Shannon Young: Capital expenditures in the second quarter were 44 million less, or 7% below the midpoint and slightly below the low end of our guidance range. This was driven primarily by timing and, to a lesser extent, additional cost savings relative to expectations. Discretionary cash flow for the quarter was $949 million, and free cash flow was $329 million after cash capital expenditures. Looking ahead to the third quarter and full year 2025, during the third quarter of 2025, we expect total production to average between 740 and 790 MBOE per day. Oil is expected to be between 158 and 168 MBO per day, and natural gas is expected to be between 2.75 and 2.9 BCF per day. We expect capital for the quarter to be $650 million at the midpoint of guidance, and we anticipate that this will be the high quarter for capital for the year.

Capital expenditures in the second quarter were 44 million less or 7% below the midpoint and slightly below the low end of our guidance range.

This was driven primarily by timing and to a lesser extent additional cost savings relative to expectations

Discretionary cash flow for the quarter was 949 million in free. Cash. Flow was 329 million After Cash, Capital expenditures.

looking ahead to the third quarter and full year 2025

The average between 740 and 790 mboe per day.

Oils expected to be between 158 and 168 MBO per day and natural gas is expected to be between 2.75 and 2.9 BCF per day.

Shannon Young: This quarter-on-quarter increase is driven largely by an increase in the Anadarko, where we plan to continuously run a frac crew during the quarter. For the full year 2025, we are increasing annual MBOE per day production guidance midpoint by 4% from 740 to 768. We are maintaining the oil guidance midpoint while tightening the guidance range slightly. Importantly, we're increasing our natural gas volume guidance midpoint 5% from 2.78 to 2.9 BCF per day. As previously indicated, we expect full-year capital to be about $2.3 billion, or a reinvestment rate of around 50% of 2025 cash flow. This level of spend maintains consistent activity in all three business units during the second half of 2025, which we believe gives us good momentum going into 2026.

We expect capital for the quarter to be 650 million at the midpoint of guidance. And we anticipate that this will be the high quarter for capital for the year.

This quarter on quarter, increase is driven largely by an increase in the anteed Darko where we plan to continuously, run a Frac crew during the quarter.

For the full year. 2025 we are increasing. Annual mboe per day, production guidance, midpoint, by 4%, from 740 to 768.

We are maintaining the oil guidance midpoint while tightening the guidance range slightly.

Importantly, we're increasing our natural, gas, volume guidance, midpoint 5% from 2.78 to 2.9 BCF per day.

As previously indicated, we expect full year Capital to be about 2.3 billion or reinvestment rate of around 50% of 2025 cash flow.

This level of spin maintains consistent activity in all 3 business units during the second half of 2025, which we believe gives us good momentum going into 2026.

Shannon Young: As a result of recent US tax law changes, we now expect our current tax percentage of total tax expense for the full year of 2025 to be between 40 and 60%. As a result, we expect minimal current taxes in the second half of the year. Looking forward, we would expect the current tax percentage to move closer to 70 to 90% of total tax expense. With regard to our three-year outlook provided in February, we remain highly confident. This outlook is underpinned with a low reinvestment rate, improving capital efficiency, and we believe delivers attractive value with modest production growth. Turning to shareholder returns and the balance sheet, yesterday, we announced a 22 cent per share dividend for the quarter.

As a result of recent uh us tax law changes. We now expect our current tax percentage of total tax expense for the full year of 2025 to be between 40 and 60%.

As a result, we expect minimal current taxes in the second half of the year.

looking forward, we would expect the current tax percentage to move closer to 70 to 90% of total tax, expense

With regard to our 3 year outlook provided in February February, we remain highly confident. This Outlook is underpinned with a low reinvestment rate improving Capital efficiency and we've been believed delivers attractive value with modest production growth.

Turning the shareholder returns in the balance sheet.

Shannon Young: This is one of the highest yielding base dividends in the industry at over 3.5%, and we remain committed to reviewing increases to the base dividend on an annual basis. During the second quarter, we repaid an additional $100 million of our outstanding term loans that were used as part of the financing of our acquisitions earlier this year. This brings our total term loan paydown to $350 million in the first half of 2025. In addition, we returned $191 million directly to shareholders through our base dividend and share repurchases, or 58% of our free cash flow. We ended the quarter with an undrawn $2 billion credit facility and total liquidity, including cash, of $2.2 billion. We expect to continue prioritizing deleveraging, and in the current environment, we expect to fully repay the remaining $650 million of term loans during 2025.

Yesterday, we announced a 22 Cent per share dividend for the quarter.

This is 1 of the highest yielding based dividends in the industry at over 3.5%, and we remain committed to reviewing increases to the base dividend on an annual basis.

During the second quarter, we repaid an additional hundred million dollars of our outstanding term loans that were used as part of the financing of our Acquisitions earlier this year.

This brings our total term loan. Pay down to 350 million in the first half of 2025.

In addition, we returned 191 million directly to shareholders through our base dividend and share repurchases or 58% of our free cash flow.

We ended the quarter with an undrawn 2 billion credit facility in total liquidity, including cash of 2.2 billion.

Shannon Young: We are quickly executing on getting our leverage back to home to around 0.5 times net debt to EBIT. At the same time, as previously indicated, we expect our share repurchase activity to be weighted towards the back half of the year, particularly in light of current share price. Coterra is committed to maintaining a fortress balance sheet that is strong in all phases of the commodity cycle, enabling us to take advantage of market opportunities and protecting our shareholder return goals. In summary, Coterra's team delivered another quarter of high-quality results, both operationally and financially, across all three business units. For 2025, we continue to expect consistent oil production growth throughout the year, substantial free cash flow generation at over $2 billion, and rapid deleveraging. With that, I'll hand the call over to Blake to provide additional color and detail on our operations. Blake.

We expect to continue prioritizing deleveraging and in the current environment, we expect to fully repay, the remaining 650 million of term loans during 2025

We are quickly executing on getting our leverage, back to home to around 0.5 times, net debt to IBA.

At the same time as previously indicated, we expect our share repurchase activity to be weighted towards the back half of the year.

Particularly in light of current share price.

Cutter is committed to maintaining a fortress balance sheet that is strong in All Phases, of the commodity cycle and a enabling us to take advantage of Market opportunities and protecting our shareholder return goals.

In summary Gutierrez team delivered, another quarter of high-quality results, both operationally and financially across all 3 business units.

For 2025, we continue to expect consistent oil production growth throughout the year.

Substantial free cash flow generation at over 2 billion dollars and rapid deleveraging.

Michael DeShazer: Thanks, Shannon. On the activity front, we are focused on consistency, which in turn helps optimize our dollar per foot costs and project economics. We expect to maintain nine rigs in the Permian in the second half of the year, which is one rig less than we originally guided to in February. Our current plan allows us to consistently run three frac crews in the Permian, including our Culbertson-Simul frac fleet for the remainder of '25 and into '26. In the Marseles, we have elected to take our second on-ramp and keep two rigs running throughout the year. This activity pushes Marseles capital up $100 million from our original guidance. In aggregate, we expect full-year capital to be approximately $2.3 billion. Our consistent activity in the second half of '25 positions Coterra for a highly capital-efficient 2026.

With that, I'll hand the call over to Blake provide additional color and detail on our operations. Blake

Thanks Shane.

On the activity front, we are focused on consistency which in turn helps optimize our dollar per foot costs and project economics.

We expect to maintain 9 rigs in the puran in the second half of the year which is 1. Rig less than we originally got it to in February.

Our current plan allows us to consistently Run 3, fracc Crews and Parian, including our Culbertson SEMO Frac Fleet for the remainder of 25 and into 26.

To take our second on-ramp and keep 2 rigs running throughout the year.

This activity pushes marcela's Capital up 100 million dollars from our original guidance.

In aggregate, we expect full year Capital to be approximately 2.3 billion.

Michael DeShazer: With the first half of 2025 behind us, we are realizing some wins in the field that are beginning to impact our costs. In the Permian, we are currently projecting an all-in cost of $940 per foot, which is down 2% from the first of the year and down 12% year-over-year. These cost reductions are driven by a continued focus on drilling and completion efficiencies, as well as some reductions in our market rates for the second half of the year. We are seeing an increase in rig and frac availability, which is leading to competitive pricing in our bids. Our 2025 program is delivering the strong capital efficiency that we have come to expect from our Permian assets.

Our consistent activity in the second half of 25 positions Cotera for a highly Capital efficient 2026.

With the first half of 2025 behind us, we are realizing some wins in the field that are beginning to impact our costs.

In the Permian we are currently projecting an all-in cost of 940 per foot, which is down 2% from the first of the year and down 12% year-over-year.

Cost reductions are driven by a continued focus on drilling and completion efficiencies, as well as some reductions in our market rates for the second half of the year.

We are seeing an increase in rig and frac availability, which is leading to competitive pricing in our bids.

Michael DeShazer: Integration of the Franklin and Avon assets is complete, and results continue to beat expectations as we continue to lower our cost structure and delineate new landing zones across the northern Delaware. We remain on track to hit our annual oil guide. Turning to Culbertson County, the Wolf Camp wells at Wyndham Row continue to exceed expectations, with a projected PVI 10 north of 2.3 at strip pricing and an all-in cost of $894 per foot, an exceptional outcome across the row, remediation efforts on the Wyndham-Harkey wells are almost complete. We're seeing improved pressure drawdown, declining water cuts, and a modest oil response. However, in aggregate, the remediated wells are not yet contributing material incremental oil volumes. As such, we do not expect Wyndham-Harkey to impact our current full-year 2025 oil guidance.

Our 2025 program is delivering the strong Capital efficiency that we have come to expect from our permanent assets.

Integration of the Franklin and Avon assets is complete and results continue to beat expectations. As we continue to lower our cost structure and delineate new Landing zones across the northern Delaware.

We remain on track to hit our annual oil guide.

Turning to culverson County.

The wolf Camp Wells at Windom Road continue to exceed expectations with a projected pvi 10, north of 2.3 at strip pricing and an all-in cost of 894 per foot.

An exceptional outcome across the road.

Remediation efforts on the Windham, harky Wells are almost complete.

We're seeing improved pressure. Drawdown, declining, water cuts and a modest oil response.

However, in aggregate, the remediated wells are not yet contributing material incremental oil volumes.

Michael DeShazer: The water introduced from the shallow disposal zone will take time to recover, and although we expect to see gradual oil recovery over time, we may not fully achieve our original pre-drill volumes. Importantly, during the quarter, we brought six new Harkey wells online in Culbertson County that were immediately adjacent to Wyndham Row. These wells are in flight while we were bringing on Wyndham Row Harkey wells, and we were able to adjust the wellbore designs to ensure mechanical isolation. These wells have come on strong and are meeting or exceeding expectations. This gives us confidence that the mechanical issues we encountered on Wyndham Row were localized and have been addressed. Across the basin, our broader Harkey program continues to perform well. The success of the six new wells in Culbertson County reinforces our confidence in the long-term potential of the Harkey interval across the asset.

As such, we do not expect Windham, harky to impact our current full year 2025 oil guidance.

The water introduced from the shallow disposal zone will take time to recover. Although we expect to see gradual oil recovery over time, we may not fully achieve our original pre-drill volumes.

Importantly, during the quarter, we brought 6 new harky Wells online in Culbertson County, that were immediately adjacent to Windham row.

These Wells are in-flight while we were bringing on Windham row, harky Wells, and we were able to adjust the well board designs to ensure mechanical isolation.

These Wells have come on strong in our meeting or exceeding expectations. This gives us confidence that the mechanical issues. We encountered on Windham Road were localized and have been addressed.

Across the Basin, our broader harky program continues to perform well.

Michael DeShazer: Outside Culbertson, we drilled 21 gross Harkey wells in 2024 and plan to drill 10 to 20 gross wells annually from 2025 to 2027, driven by consistently strong returns. We continue to view Harkey as a valuable target across the basin for Coterra and other Delaware Basin operators. Results in the Marseles continue to be strong. As Shannon noted, we significantly beat our natural gas forecast during the quarter. A large component of this beat was the outperformance in our Marseles production, with significant contribution from the box wells that came on last winter. The 11 wells we turned online in the box in December 2024 have been the most productive wells in our Marseles history, with a peak 30-day rate of 450 million cubic feet per day across the 11 wells. Coterra is back to consistent work in the Marseles, with two rigs drilling and one frac crew.

The success of the 6 new wells and culverson County reinforces our confidence in the long-term potential of the harky interval across the asset.

Outside Culbertson, we drilled 21, Grouse harky wells in 2024 and plan to drill 10 to 20, gross Wells, annually from 2025 to 2027 driven by consistently strong returns.

We continue to view Harky as a valuable target, the Basin for Coterra and other Delaware Basin operators.

Results in the Marcellus continue to be strong. As Shane noted, we significantly beat our natural gas forecast during the quarter.

A large component of this beat was the outperformance in our Marcellus production, with significant contribution from the box, wells that came on last winter.

The 11 wells we turned online in the Box in December 2024 have been the most productive wells in our Marcellus history. With a peak 30-day rate of 450 million cubic feet per day across the 11 wells,

Michael DeShazer: We plan to bring on 7 to 12 more tills between now and the end of the year, with more completions in early 2026, giving us a nice ramp throughout winter. Our focus in the Marseles continues to be improving capital efficiency through cost reductions and extended laterals. We currently expect an average lateral length of 17,000 feet across the program, which is helping to drive our go-forward cost structure of $800 per foot. Our Anadarko program continues to bring in strong results, with the Roberts pad coming online in Q2 with stellar results. This nine-well project achieved a 30-day equivalent IP of 173 million cubic feet per day. This productivity, paired with strong NGL yields, makes this one of the best gas projects in our portfolio.

Cotera is back to consistent work in the Marcellus with 2 rigs Drilling and 1 fat crew.

We plan to bring on 7 to 12 more tills between now and the end of the year with more completions in early 2026, giving us a nice ramp throughout winter.

Our focus in the Marcellus continues to be improving Capital efficiency through cost reductions and extended laterals.

We currently expect an average lateral length of 17,000 ft across the programme, which is helping to drive our go forward cost structure of 800 per foot.

Our Anadarko program continues to bring in strong results with the Roberts pad coming online in Q2 with Stellar results.

This 9 World project achieved a 30-day equivalent IP of 173 million cubic feet per day.

Michael DeShazer: We continue to gain efficiencies in our Anadarko program, with our first three-mile project coming online later this year with an impressive all-in cost of $923 per foot. Our Anadarko team is laser-focused on driving capital efficiency and extending our laterals across the asset. Lastly, an update on our gas marketing portfolio. We are excited to announce our new power net bag deal in the Permian with a 50,000 MMBTU per day long-term sale to competitive power ventures, New Basin Ranch Power Plant in Ward County, Texas. This deal is the culmination of a multi-year collaboration between Coterra's marketing team and CPV to deliver a differentiated in-basin project that not only delivers a firm fuel supply to CPV's new facility, but also adds additional power net bag exposure to Coterra's gas sales portfolio.

This productivity paired with strong. Mgl yields makes this 1 of the best gas projects in our portfolio.

Impressive all-in cost of 923 per foot.

Our Anadarko team is laser focused on driving Capital efficiency, and extending our laterals across the asset.

Lastly, an update on our Gas marketing portfolio.

We are excited to announce our new power. Net bag deal in the Parian with with a 50,000 mmbtu per day, long-term sale to competitive power. Ventures, new Basin Ranch power plant. In Ward County, Texas.

Michael DeShazer: Similar to our recent LNG transactions, Coterra continues to execute on our strategy of pursuing differentiated gas sales across all of our three basins. We are not interested in making additional investments and commitments in markets that we already have ready access to. We will continue to focus our execution on sales that bring diversity and price enhancement to our portfolio. And with that, I'll turn it back to the operator for Q&A.

This deal is the culmination of a multi-year collaboration between kotas marketing team and CTV to deliver a differentiated in-base in project that not only delivers a firm fuel supply to cpv's, new facility, but also adds additional power net back, exposure to cot's gas sales portfolio.

Similar to our recent LG transactions, Cotera continues to execute on our strategy of pursuing differentiated gas sales across all of our 3 basins.

We are not interested in making additional Investments and commitments in markets that we already have ready access to. We will continue to focus our execution on sales that bring diversity and price enhancement to our portfolio.

And with that, I'll turn it back to the operator for Q&A.

John (Conference Operator): Thank you. Ladies and gentlemen, we will now begin the question and answer session. As a reminder, if you have dialed in and would like to ask a question, please press star followed by the number one on your telephone keypad. And if you would like to withdraw your question, simply press star one again. We kindly ask everyone to limit themselves to one question and one follow-up only to accommodate everyone. Thank you. Your first question comes from the line of field method with Goldman Sachs. Please go ahead.

Neil Mehta: Yeah, thanks so much, Tom and team. I just want to start off on Harkey and just, you know, round out this point. It sounds like you feel like you've gone through it. So can you just give us a level set of, you know, how much conviction you have that you've worked through this issue, the timeline, and when do you see production really being at optimal level?

Thank you, ladies and gentlemen, we will now begin the question and answer session as a reminder, if you have dialed in and would like to ask a question, please press star, followed by the number 1 on your telephone keypad. And if you would like to withdraw your question, simply press star 1, again we kindly ask everyone to limit themselves to 1 question and 1 follow-up. Only to accommodate everyone. Thank you. Your first question comes from the line of heel method with Goldman Sachs. Please go ahead.

Thomas Jorden: Yeah, Neil, thank you for that question. You know, as Blake said, you know, our remediation efforts look like they're highly successful, both shutting off water flow on existing wells, but also, you know, we did change our wellbore design, and I think that's really the key point here. These wells are in the immediate vicinity, would have been exposed to the same phenomena, and they're flowing back pretty as pink. And so that's exactly what we hope for. You know, as Blake said, go forward, it's going to take, you know, we put a lot of water in this formation, and it's going to take a while to dewater this. So we're being very conservative in our go-forward oil forecast from Wyndham Row. But we are full steam ahead on Harkey and really do look forward to getting this problem behind us.

Yeah, thanks so much Tom and team. I I just want to start off on on hard key and just uh you know, round round out this this point, um it sounds like you feel like you you've gotten through through it. So can you just give us a level set of you know how much conviction you have? Um, that you've worked through this issue the timeline and and uh when do you see production really being at optimal level?

Yeah, the Neil thank you for that question. You know, as Blake said, uh, you know, remediation efforts look like they're highly successful, both shutting off water flow on existing Wells, but also, you know, we did change our world board design and I think that's really the the key Point here. These Wells are in the immediate vicinity would have been exposed to the same phenomena and they're flowing back.

Neil Mehta: Yeah, thanks, Tom. And then just the $100 million of activity that you had for the Marseles and the rig ad, can you talk about that? There's been a big debate in the investment community about whether we're overproducing with some of these scrapes kind of around 108 bees right now, which is probably one to two bees higher than most of us thought we would be. Does this feel like the optimal time to be leaning into the gas program? And how do you think about, you know, the risk of if the leaders are adding supply before the demand and inventory signals are there?

Uh, prettiest pink and so that's exactly what we hope for. Um, you know, as Blake said, go forward, it's going to take, you know, we we put a lot of water in this formation and it's going to take a while to dewater this. So we're being very conservative in our go forward. All forecast from wind and row but we are full steam ahead on hierarchy and really do look forward to getting this problem behind us.

Thomas Jorden: Well, we see, you know, we do see growing demand with LNG exports. Of course, this whole power story is going to be ramping up. If we could pick optimum timing, we'd be, you know, we'd stand alone in our industry if we could do that. I can tell you that when we look at our forecast of current pricing, our Marseles program is our best returns right now. And that's because of the quality of these wells and the costs that we're bringing this supply on. Blake, you want to comment on that?

Yeah, thank thanks Tom and then just the the hundred million dollars of activity that you add to the Marcellus um, in the rig. Add can you talk about that? There's been a big debate in the investment Community about whether we're overproducing with some of these scrapes kind of around 108 BS right now, which is probably 1 to 2 beats higher than most of us thought we would be. Does this feel like the optimal time to be leaning into the gas program? And how, how do you think about, you know, the risk of the if the leaders are adding Supply before the demand and inventory signals are there?

well, we see, you know, we do see growing Demand with LNG exports, of course, this, this whole power story is going to be ramping up, uh, if if, if we could take off to on timing, we'd be um, you know,

We'd stand alone in our industry. If we could do that. I I can tell you that when we look at our forecast of current pricing,

Michael DeShazer: Yeah, I'll just say that, you know, picking the market is a very difficult thing to do with a giant DNC machine. And so we're pretty focused on consistent activity. We've really lowered our cost structure in the Marseles, which has lowered our breakevens, and that gives us confidence when we go through these modest cycles. And so we feel really good about the projects we have coming online between now and the end of the year.

Thomas Jorden: And Neil, I think, you know, it's important to note that this activity this year comes off zero. I mean, we sort of went to zero last year and kind of held that till April and now it picked up. And this level of activity we're talking about is very akin to kind of a maintenance level for what we're doing up in the Northeast.

Our Marcellus program is our best returns right now. And that's because the quality of these Wells and the costs that we're bringing this Supply on Blake. You want to comment on that? Yeah, I'll just say the, you know, picking the market is uh, very difficult thing to do with a giant DNC machine. So we're we're pretty focused on consistent activity. We've really lowered our cost structure in the Marcellus which is lowered, our break evens and that gives us confidence. When we go through these uh, modest cycles. And so uh we feel really good about the projects we have coming online between now and the end of the year and Neil. I think you know it's important to note that this activity this year comes off zero. I mean, we sort of went to zero last year and kind of held that till April and now I've picked up and and this level of activity, we're talking about is is uh very akin to kind of a maintenance level for, for what we're doing up in the Northeast.

John (Conference Operator): Your next question comes from the line of Arun Jayaram with JP Morgan. Please go ahead.

Arun Jayaram: Yeah, good morning. John, I was wondering if you could talk a little bit about the trajectory of your oil growth expectations in the back half of the year. Obviously, you've given a third quarter guide. By our math, you'd have to average about 172,000 barrels in the second half to hit the midpoint of your oil guide or 160. You know, given Blake's commentary on consistent activity levels, talk to us about, you know, confidence level at the midpoint and how you expect to kind of achieve that fourth quarter run rate, which would assume kind of an oil trajectory approaching 180,000 barrels a day.

Thomas Jorden: Yeah, Arun, high confidence on our part. And I'll just say we've spent a lot of time on this data, and it's simple arithmetic. It's not necessarily a balance of operational things, all of which need to go right. This is simple arithmetic. We have the blessing of having a lot of high working interest projects coming online in the fourth quarter, and that's just sort of a statistical anomaly. These are projects that we understand. Their names are well known to us. And as we review the on-ramp, some of these are already producing and building as we speak. So we have a high degree of confidence in our forecast. It is simple arithmetic. It does not require operational gymnastics. It's, you know, solid. We're going to deliver it. Blake, anything you want to add?

Yeah, good morning. Um, gentlemen. I was wondering if you could, uh, talk a little bit about the trajectory of your oil, uh, growth expectations, uh, in the back half of the Year, obviously, you given a third quarter guide by our math. You you'd have to average about 172,000 barrels and the second half to hit the midpoint of your uh, oil guide or 160, you know, given Blake's commentary on consistent activity levels. Talk to us about, you know, confidence level at the midpoint and and how you expect to kind of achieve that fourth quarter run rate, which would assume kind of an oil trajectory approaching 180,000 barrels a day.

Yeah, a rune, um, high confidence on our part, and I'll just say we've, um, spent a lot of time on this data and it's simple arithmetic. Uh, it's not, it's not necessarily a balance of operational things, all of which need to go, right? This is simple arithmetic. We have, uh, the blessing of having a lot of high working interest projects coming online in the fourth quarter and that's just sort of a statistical, anomaly. Uh, these are projects that we understand their names are well known to us. And as we review the on-ramps, some of these are already producing and building as we speak. So we have a high degree of confidence in our forecast. It is simple arithmetic.

Michael DeShazer: Yeah, I'll just say the only operational cadence is not changing in any of our programs. It's very consistent. It's just a matter of really high working interest DSUs coming on relatively close together. And I'll just mention we are thrilled to have the high working interest in these DSUs.

Thomas Jorden: Yeah, and I think since we started guiding for the year, we've really tried to point the market towards a bit of a stairstep over the course of the year and the trajectory being consistent, not necessarily a flat production over the course of that period.

It does not require operational gymnastics it's um, you know, solid we're going to deliver it Blake. Anything you want to add? Yeah, I'll just say this. The only the operational Cadence is not changing in any of our programs. It's very consistent. Um, it's just a matter of really high working interest dsus coming on, uh, relatively close together. And uh, I'll just mention. We are thrilled to have the high working interest in these dsus.

I think since we started guiding for the year, we've really tried to point the market towards a bit of a stair step over the course of the year and and the trajectory being consistent, not necessarily a flat production over over the course of that period.

Arun Jayaram: Fair enough. And my follow-up question is, Tom, thoughts on, you know, you announced that you believe that you have a new wellbore design, which has fixed maybe some of the issues experienced in the Harkey in the 1Q conference call. But do you have enough confidence now to co-develop the zones, you know, in Culbertson County?

Uh, fair enough in my, uh, follow-up question is, is Tom thoughts on, you know, you announced that you you believe that you uh, have a, a new well board design, which is fixed. Maybe some of the, the issues experienced, um, in the hierarchy, uh, and and, and, and the 1. But do you have enough confidence now to co-develop the zones um, uh, you know, in Culbertson County.

Thomas Jorden: Well, yes. You know, as we said in our last call, we don't think this is a co-development issue. So my answer to that is yes.

Yeah, well yes. This this you know, as we said in our last call we we don't think this is a code development issue. So so my answer to that is yes.

John (Conference Operator): Your next question comes from the line of Doug DeGatte with Wolf Research. Please go ahead.

Your next question comes from the line of dog negative. It will research. Please go ahead.

Doug Leggate: Well, good morning. I almost didn't recognize your name there. Good morning, Tom. How are you doing?

Thomas Jorden: Very well.

Doug Leggate: Tom, I wonder if I could ask a kind of a high-level question. Forgive me for this, but you're, you know, you're a leader in the industry, and I think your perspective on this could be worth everybody listening to. And it's really in that the industry, you know, often justifies at the individual company level drilling wells on the basis of wellhead returns because it's the right thing for the company. But collectively, the industry ends up destroying price. So it's another way of asking why, I mean, you have the option to not spend $100 million in Marseles. Is this a desire to maintain production? Because the risk, obviously, to the commodity, as it was Neil pointed out, production's been surprisingly upside, and the biggest part of that has been the Marseles. So I guess I'm asking if you might be part of the problem on the commodity.

Well, good morning. I almost didn't recognize your name there. Good morning, Tom, how are you doing? Um, very well Tom. I I I wonder if I could ask uh, I kind of a high level question. Forgive me for this. Um, you're

You're a leader in the industry. Um, and I, I think your prospective on, this could be, could be worth everybody listening to it. And it's really that

the the industry, you know, often justifies that the individual company level

Drilling Wells, on the basis of Wellhead returns, because it's the right thing for the company. But collectively, the industry ends up destroying price.

So it's another way of asking why. Um, I mean, you have the option to to not spend $100 million in Marcellus, is this a, a desire to maintain production? Because the risk obviously to the commodity, as it was new pointed out,

Productions. Been surprising in the upside and the biggest part of that has been the marcelis. So I I'm I guess I'm asking if you might be part of the problem on the commodity

Thomas Jorden: Well, Doug, the problem with our business is we don't manage it with a spreadsheet. And so we make decisions sometimes, depending on the project, it can be 12 or 18 months in advance. And, you know, if we had had this conversation six months ago, I think our conversation would have been very different on gas prices. So I'll just tell you that at Coterra, one of the things that keeps us whole through this challenge, as you lay out, is having a very low cost of supply. And we run our CapEx down to very draconian pricings. I mean, in the case of oil, we'll run at sub-50 oil as if that's the only price that well will ever see through its life. In the case of natural gas, we'll even go sub-$2. And these investments we're making are really, really profitable even at that.

well Doug the problem with our business is we don't manage it with a spreadsheet and so we make decisions sometimes depending on the project it can be 12 or 18 months in advance and um you know if if if we had had this conversation 6 months ago, I think our our

Thomas Jorden: Our long-term goal, as I said, isn't production. It's generating free cash flow and demonstrating to the market that we have durability there. And so one of the things that our asset complexion and our mixture gives us the luxury of is having stable cash flow and the ability to ride through the cycles. And I'm going to make one final point, Doug. We recently did some analysis. You know, we've talked a lot about our look back, our look back on our own program. And we go back 20 years and look at every investment we've ever made, and we tear it apart. And that analysis, we looked at our behavior in the troughs.

As if that's the only price that will will ever see through its life and the case of natural gas will even go sub 2 dollars and these Investments we're making are really, really profitable. Even at that our, our long-term goal, as I said isn't production it's generating free cash flow and demonstrating to the market that we have durability there. And so 1 of the things that our asset complexion and our our mixture gives us luxury of is having stable cash flow and the ability to

Thomas Jorden: And because of that lag time, our conclusion is that not only were the investments we made in the troughs some of our most profitable in our history, but it really told us that a steady cadence of activity is the best way to manage a cyclic commodity business. So I take your question. You know, I'll let others describe if we're part of the problem, but we think our behavior is a representative of the strength of Coterra.

Ride through the cycles. And I'm going to make 1 final Point. Doug we, we recently did some analysis, you know, we've talked a lot about our look back, our look back on our own program and we we go back, 20 years and look at every investment we've ever made and we tear it apart. And then analysis, we, we looked at our behavior in the troughs.

And because of that lag time,

Uh, our conclusion is that not only were the Investments. We made in the troughs, some of our most profitable in our history, but it really told us that a steady Cadence of activity, is the best way to manage a cyclic commodity business. So I, I, I, I take your question, you know, I'll let others describe if we're part of the problem, but we think

Doug Leggate: I appreciate the answer. And Tom, I was going to go in a different direction, but I'm going to, if you don't mind, I'm going to ask a follow-up on this because another aspect of having that low cost of supply and a stellar balance sheet, frankly, is that some of your large pure play gas peers have used that as a crux for managing their tills, almost like seasonally managing their production, shutting it in production in the trough, bringing it on into winter, and so on. So I guess my question is, is that a consideration for your gas strategy? If not, why not?

Our behaviors, our representative of the strength of Cotera.

I appreciate the answer and Tom I was going to go in a different direction, but I'm going to ask. If you don't mind, I'm going to ask a follow-up on this because another, um, aspect of of having that low cost of supply, and and a stellar balance sheet, frankly, is that some of your large Pure Play Gas peers have used that as a Crux for managing their tills almost like, seasonally managing the production shutting in production in the trough bringing it on into winter and so on. So I guess my question is is that a consideration for your, your gas strategy? If not why not

Thomas Jorden: Blake, why don't you handle that one?

Michael DeShazer: Yeah, Doug, you know, I'd say that's absolutely in our toolkit. We have used that before. It really comes down to our sales portfolio. So we have long-term sales that are anchored to really good deals that are much better than we get in basin, but we do have in basin cash sales also. And so we really look at that as the incremental molecule. And so you've seen us manage production. You've seen rolling curtailments, and you would see delayed completions and things like that if necessary. So those are tools we have in our toolkit, but it really has to be done in harmony with the long-term sales portfolio. It's really important.

Thomas Jorden: Yeah, Doug, based on our behavior over the last year, I think anybody looking at us would know that we have the wherewithal to shut production in if pricing gets too hostile.

Like, why don't you hang on that 1? Yeah. Doug, you know, I I'd say that's absolutely in our tool kit. We we have used that before, uh, it really comes down to our sales portfolio. So we have long-term sales that are, uh, anchored to a really good deals that are much better than we get in Basin, but we do have in basing cash sales also. And so, we really look at that as the incremental molecule. And so, you've seen us manage production, you've seen rolling curtailment, um, and you would see delay completions and things like that if necessary. So, those are tools we have in our toolkit, but it really has to be done in harmony with the uh long-term sales portfolio. It's really important.

Yeah, Doug based on our Behavior over the last year. I I think anybody looking at us would know that we have the wherewithal to shut production in if price price gets too hostile.

John (Conference Operator): Your next question comes from the line of Betty Jiang with Barclays. Please go ahead.

Your next question comes from the line of Betty Jiang with Barclays. Please go ahead.

Betty Jiang: Good morning. Thank you for taking my question. Shannon, I want to ask about cash taxes. Thank you for the color you provided earlier. Could you just give us a bit more detail around why the 2025 cash taxes are going down more? And then moving forward, you gave the range of 70 to 90%. How should we be thinking about that range over time? Thanks.

Good morning. Thank you for taking my question. Um I'm saying I want to ask about cash taxes. Um thank you for the caller you provided earlier. Um

Thomas Jorden: Yeah, Betty, thank you for the question. So look, we are benefiting from two primary things. There's a lot in the bill, but the two primary things are, one, a return to 100% bonus depreciation, where we can expense things in the year incurred, and two, it's a return of some of the R&D expenses that we're able to do. And really, by nature, you know, those are more timing elements. And so in other words, we'll get them this year, but over time, those will sort of normalize. And so as we get out over the next two, three, four years, you know, we will get back to where we are.

Could you just give us a bit more detail around why the 2025 cash tax is going down more? And then, moving forward, you gave the range of 70% to 90%. How should we be thinking about that range over time? Thanks.

Yeah, buddy. Thank you for the the questions. So, look, we we are benefiting from 2, uh, primary things. There's a lot in the bill, but the 2 primary things are 1 a return to 100% bonus depreciation. Uh where we can expense things in the year, incurred and 2 to the return of some of the R&D expenses that that we're able to do. And and really by Nature, you know those are more timing elements. Uh and so in other words we we'll get them this year but over time those will sort of normalize. And so as we get out over the next

Thomas Jorden: The other thing I would point out on tax and, you know, a little bit of this, particularly when you combine it with the bonus depreciation comment I made earlier, is the deals that we did earlier this year all got step-ups in basis. So it really sort of changed the profile and complexion and sort of our ability to offset some taxable income. But when you combine that with the bonus depreciation element on some of the fixed facilities and assets that we have, you know, it really gives us an advantage in 2025. So again, I would say it's early days. As we sort of get through, you know, we'll refine our guidance a little bit more, but we knew that would be an important question for this call.

Thomas Jorden: So we wanted to be really, really dialed in on '25 and have a very, you know, a range, but a very educated range on a go-forward basis.

Betty Jiang: So this 80%, can we use that for the next going forward, that three, five years?

Days as we sort of get through. Uh, you know, we'll, we'll refine our guidance a little bit more, but we knew that would be an important question for this call. So we wanted to be really, really, uh, dialed in on 25 and have a very, uh, you know, a range, but a very educated range on a go forward basis.

So this 80% can we use that for the next?

Going forward, like 3 to 5 years.

Thomas Jorden: You know, I'd say over the next several years, that's a good place to be. Over time, again, most of this is a question of timing, whether it's the R&D expenses or whether it's bonus depreciation, and things will level out again when you get out past three, four years.

You know, I say over the next several years that that's a good place to be over time. Again, most of this is is a question of timing, whether it's the R&D expenses or or whether it's bonus depreciation and things will level out again, uh, when you get out past 3 or 4 years,

Betty Jiang: Yes. My follow-up is on the buyback is with the incremental free cash flow now the business is generating. Should we expect once the pay-it-turn loan is paid off, you will start accelerating on the buyback again? And could we see it going back to that 100% cash return level towards later this year and into next year?

Thomas Jorden: Yeah, that's a really, really fair question. I mean, in 2024, we were about 90% of free cash flow in payout. In 2023, we were probably closer to 76%. So we've been at some really elevated levels when we weren't in debt reduction mode. You know, as we look at the back half of the year, and this is all dependent on sort of the actual conditions, but based on sort of what we see today, you know, we envision being able to pay off the last 650 of the term loans and at the same time being able to balance that with some buybacks over the course. Now, when we get paid off, so let's say we look into 2026, you know, I think you're, you know, I think you're spot on that the focus can move back towards buybacks and direct shareholder returns.

On the, on the buyback, um, is as, uh, with the incremental, uh, free cash flow. Now, the business is generating, um, should we expect once to pay it Term? Loan is paid off, it will start. Um, accelerating on the buyback again, and could we see it going back to that 100% cash return level, um, towards later this year and the into next year?

Thomas Jorden: You know, that being said, you know, towards the end of '26, we do have a $250 million maturity. So we'll have to figure out sort of how that fits into our free cash flow profile in that year. Nothing's been decided yet. But yes, absolutely. I think if you look at the behavior over the last few years in sort of that 75 to 100% range that we've been at, I think when we're out of that debt paydown mode, you know, that's a place that, although things being equal, you should expect to see more buybacks.

Yeah, that's a really, really fair question. I mean, in in 2024, we were about 90% of free cash flow in payout. And 2023, we're probably closer to 76. So we've been at some really elevated levels when we weren't in debt reduction mode, you know, as we look at the back half of the year and this is all dependent on sort of the actual conditions, but based on sort of what we see today. You know, we, we envision being able to pay off the last 650 of the term loans. And at the same time, uh, being able to balance that with with some BuyBacks over the course, now when we get paid off. So let's say we look into 2026, you know, I think you're, you know, I think you're spot on that that the focus can move back towards uh, BuyBacks and and and and, and direct shareholder returns. Uh, you know, that being said, you know, towards the end of of 26, we do have a 250 million maturity. So we'll have to figure out sort of how that fits into our our free cash flow profile and that year, nothing's been decided yet. But, but yes,

Betty Jiang: Great. Sounds great. Thank you.

Absolutely. I think if you look at the, the behavior over the last few years, uh, in sort of that 75 to 100% range that we've been at, um, I think when we're out of that Debt, Pay down mode. You know, that that's a place that all other things being equal, uh, you should expect to see more BuyBacks.

Great sounds great. Thank you.

John (Conference Operator): Your next question comes from the line of JP Kumar with Mizuho. Please go ahead.

Doug Leggate: Hey, good morning, guys. Thanks for taking my questions. Tom, I want to maybe follow up to Arun's question. You have a pretty strong ramp-up in activity in oil volumes for the rest of this year. Historically, just given your focus on bigger projects, a big ramp-up has, you know, been followed by maybe a little bit weaker or decline, but you're also adding activity or at least retaining activity this year without increasing your guidance. I'm not asking for guidance for 2026, but how do you see the trajectory sort of beyond fourth quarter? Do you expect a bit more ratable oil volumes in 2026?

Your next question comes from the line of sleeping Kumar with mizuho. Please go ahead.

Thomas Jorden: Yeah, and thank you for that. Look, fourth quarter is going to be a bit of a flush. We don't anticipate first quarter being up from fourth quarter. But you know, I'm going to sound like a broken record here. We really don't worry about quarter to quarter as much as we do just the trend upward to the right on an annual basis. So we're going to have quarter to quarter fluctuations because of a lot of things. And you know, we mentioned working interest. Well, it just so happens that in the fourth quarter, a lot of the contribution is high working interest. So, you know, we're steady as she goes, constant level of activity. But you know, these kind of quarter to quarter fluctuations are just going to be part of the business.

Hey, good morning guys, thanks for taking my questions. Um, Tom, I want to maybe follow up to our own question. Um, you have a pretty strong ramp up in activity, in in oil volumes, uh, for the rest of this year. Historically, just given your focus on bigger projects, a big ramp up has, um, you know, been followed by, um, maybe a little bit weaker or, or, or, or decline, but you're alling activity or at least retaining activity this year without increasing your guidance. So I'm not asking for guidance for 2026. But how do you see the trajectory sort of Beyond fourth quarter? Um, do you expect expect, expect a bit more readable oil volumes in 2026?

Yeah and then thank you for that. Uh look fourth quarter is going to be a bit of a flush. We don't anticipate first quarter being up from fourth quarter but you know, as I'm going to sound like a broken record here. We really don't worry about quarter to quarter as much as we do, just the trend upward to the right on annual basis. So we're going to have quarter to quarter fluctuations because of a lot of things and you know, we've mentioned working interest. Uh, we're just just so happens that in the fourth quarter, a lot of the contribution is high working interest. So,

Thomas Jorden: But you know, we want to consistently grow, generate a growing free cash flow over the duration.

Um, you know, we're we're study as she goes, constant level of activity and, but, you know, these kind of core to core fluctuations are are just going to be part of the business. But, you know, we want to consistently grow.

Generate a growing free, cash flow over the duration.

Doug Leggate: Great. Great. Thanks for the call there, Tom. My follow-up is on the gas marketing side. And maybe, Blake, looking at slide 18, I think 31% or so of your current gas volumes are sold in basin across the three operating areas. You mentioned the LNG contracts, and you mentioned you announced this Powerdale. So on our math, it's roughly 8% or 9% of your total corporate gas volumes. Should we expect that these new volumes will be really met by sort of a reallocation of in basin? And part B is, as you think about the longer-term mix for your gas marketing.Portfolio,

Great, great, thanks for the color there Tom uh my follow-up is on the Gas marketing side and and maybe Blake, um uh looking at slide 18, I think 31% or so of your current gas volume is so sold in Basin across the 3. Operating areas you mentioned the LNG contracts and you mentioned, um, your announced this power deal. So on our mats roughly 8 or 9% of your total corporate, gas volumes. Um,

Be.

John (Conference Operator): is there an advantage of keeping some molecules priced in basin as well?

Blake Sirgo: Oh, that's a good question, and I'll answer the first part. Yes, I think of these as reallocation of existing sales. You know, we've been on a mission for a while now to diversify away from Waha, and that's why we love this power deal so much. It's real in basin demand, but it's not indexed to the local gas price. We actually get access now to the power strip, and that's something we really value in our portfolio. So, we like those deals. We're looking at more of those deals all the time, but it has to truly either give us diversity in pricing, and then it has to give us enhancement, some sort of enhancement to value over the long run. So, that's really how we look at it.

Is, as you think about the longer term mix for your Gas marketing? Portfolio, is there an advantage of keeping some molecules priced in Basin as well?

No, that's a that's a good question and I'll answer the first part. Um yes I I think of these as reallocation of existing sales, you know we've we've been on a mission for a while now to diversify away from waha and that, that's why we love this power deal so much. It's real in Basin demand but it's not indexed to the local gas price. We we actually get access now to the, the power strip and that's something we really value in our portfolio. So we like those deals. We're looking at more of those deals all the time, but it has to truly either give us diversity in pricing. Um, and then it has to give us uh, enhancement some sort of enhancement to Value over the long run. Um, so that, that's really how we look at it.

Conference Center Operator: Your next question comes from the line of Scott Gruber with Citigroup. Please go ahead.

Your next question comes from the line of Scott Gruber with City Group, please go ahead.

John (Conference Operator): Yeah, good morning. A lot of discussion on the gas strategy. I wanted to come back to the oil strategy. There's been some comments around, you know, a preference for operational consistency. You know, if we do see the macro shift again and oil dips, you know, back to the high 50s, you know, would the preference be to maintain those nine rigs in the Permian, you know, for that operational consistency? And I assume there's, you know, been some good benefit from lower service costs, or would you look to pivot back, you know, to a lower rate count?

Yeah, good morning. Um a lot of discussion on the the gas strategy, 1 of the to come back to the oil strategy because there's been some comments around, you know, preference for operational consistency. You know, if we do see the the macro shift again and oil dips, you know, back to the high 50s, you know, with the preference speed to, to maintain those 9 rigs in the, in the Permian, you know, for that opportunity.

operational consistency and I assume there's, you know, been some good benefit from lower service costs or or would you look to Pivot back you know, to a lower rate count

Blake Sirgo: Yeah, I mean, this goes back to what Tom was discussing earlier. This is the reason we stress test our projects to very low crude prices, and they're very resilient in the face of that. And our operational cadence is important to us. As you mentioned, when those things happen, we tend to get lower service costs. And so, you know, assuming we're in a $50 world and not a COVID world, then yeah, I would expect some consistent activity.

Thomas Jorden: Yeah, Scott, let me just add to that. Our business has changed. We still talk about rig numbers, and that's really not the way we think about it. It's how many completion crews can we keep running consistently? That completion now is the majority of our capital expenditure, and the biggest disruption we can have is if we have to, you know, release completion crews and then bring them back in. So, we really think about this in terms of completion crews. We may talk about rigs, but that's the driver of completion crews.

John (Conference Operator): I think also reinvestment rate is an advantage part of our story and our strategy. And I think, you know, right now we're hovering around 50%, and we've got some headroom if prices move down to absorb a little bit more reinvestment rate without having to cap capital.

Yeah. I mean this this goes back to what Tom was discussing earlier. We this is the reason we stress test our projects to very low uh crude prices and they're they're very resilient in the face of that. Um and our our operational Cadence is important to us. As you mentioned, when those things happen, we tend to get lower service costs and so, um, you know, assuming we're in a $50 world and not a coid world. Then, yeah, I I would expect some uh, consistent activity. Yeah, Scott, let me let me just add to that. Our business has changed. We know we still talk about rigged numbers and and that's really not the way we think about it. It's how many completion Crews can we keep running consistently? Uh, that completion now is the majority of our capital expenditure and the biggest disruption we can have is if we have to, you know, release completion Crews and then bring it back in. So we really think about this, in terms of the completion Crews, we may talk about rigs but that's the driver of completion Crews.

I think also reinvestment rate is an advantage part of our story and our our strategy. And I think you know, right now we're hovering around 50% and and we've got some Headroom with prices moved down to to absorb a little bit more reinvestment rate without having to catch capital.

Thomas Jorden: I appreciate that. And then coming back to the Harkey wells, the new well design you made on the incremental Harkey wells on Windham Row, how much did that cost? And you mentioned, you know, that the water issue doesn't appear to be an issue across, you know, the broader Culbertson County. But are you thinking about applying that well design, the new enhanced well design across Culbertson out of an abundance of caution, or is that not really necessary?

I appreciate that. Um and then coming back uh to the harky Wells. Um the new well-designed you made on the incremental, harky Wells on wind and Road. How much did that cost?

And you mentioned, you know that the water issue doesn't appear to be a an issue across you know the the broader call for some County. Um but are you thinking about applying that well-designed the new enhanced well-designed across, Culbertson out of an abundance of caution or is that not really necessary?

Blake Sirgo: Yeah, Scott, I'd say in general, we're very focused on making sure we always have great mechanical isolation across any disposal zone. And so, you know, for these wells we were talking about today, that was a change in cement design, but we're also looking at casing designs, casing set points, things like that. And then, you know, we have to be very specific about where we are in the field and where isolation points are. So, we're very focused on that, but the goal is simple: make sure we have great mechanical isolation no matter where we put a well in the ground.

Yes, Scott, I'd say in general. We're we're very focused on making sure. We always have great mechanical isolation across any disposal Zone and so um you know for these Wells we were talking about today that was a change in semen design but we're also looking at casing designs case, set points, things like that. Um and then it you know, we have to be very specific about where we are in the field and where isolation points are so we're we're very focused on that but the goal is simple. Make sure we have great mechanical isolation, no matter where we put a well on the ground.

Conference Center Operator: Your next question comes from the line of Calle Aquino with Bank of America. Please go ahead.

Shannon Young: Hey, good morning, guys. This first question is on use of gas. You kind of touched on this in your opening remarks that the term loan is a near-term priority. The argument for a more aggressive buyback, however, is that your share price is currently at a discount and that you don't have a balance sheet problem. You're actually in really good shape. So, why not shift priorities and focus more on the buyback?

Your next question comes from the line of Cali aamina with Bank of America. Please go ahead.

Hey, good morning guys. Uh, this first question is on use of cash. You kind of touched on this in your opening remarks, but the term loan is that the near-term priority, the argument for a more aggressive buyback? Whoever is that your share price is currently at a discount and that you don't have a balance sheet problem, you're actually in really good shape. So, why not ship priority is in focus more on the buyback?

John (Conference Operator): Well, look, I'll hit that one. But listen, number one, you know, we've been consistent about the priority and what it's, you know, look, it's part of our culture is to have a conservative financial profile and credit profile. But I think more importantly, to your question, we see repaying these term loans, getting back to home, as we call it, is really a facilitator for more, one, taking volatility out of the system, which we think benefits our shareholders, and then two, facilitating a return to a more robust and consistent buyback phase, sort of along the lines of what we were discussing with Betty earlier. So, we see actually debt paydown is consistent with long-term buyback strategy and getting there as quickly as we can. Now, that being said, you know, we've talked about having some back-end weighted repurchases in this year if cash flow holds up.

John (Conference Operator): Year-to-date, cash flow has held up, and so that's good. And to your point, at current prices, that relative attractiveness, it's not lost on us. So, yes, I wouldn't be surprised if the pace of buybacks picks up relative to what it's been in the first half of the year.

Shannon Young: Thanks, Shannon. I appreciate that perspective. My second question is on federal lease sales in New Mexico. Following the Big Beautiful Bill, I think those lease sales tend to become more frequent. How do you think about using those lease sales to add to your position? Do you see it becoming a more material part of your capital budget plan, Gordon?

Facilitator for more 1, taking volatility out of the system, which we think benefits our shareholders and, and then 2 facilitating a return to a more robust and consistent buyback, phase sort of along the lines of what, what we were discussing with, with, Betty earlier. So, so we, we see actually, uh, Debt Pay down is consistent with long-term buyback strategy and getting there as quickly as we can. Now, that being said, you know, we we we've talked about having some back-end weighted, uh, repurchases in this year. Uh, if if cash flow holds up year to date cash flow has held up and so that, that that's good and to your point at current prices, uh, that that relative attractiveness, um, it it's not lost on us, so yeah, so I wouldn't be surprised if the pace of BuyBacks picks up relative to what it's been the first half of the year.

Thomas Jorden: We hope so. You know, there was a day not too many years ago when federal lease sales were a really important part of the calendar, and over the last few years, there's been, you know, a complete absence of them or near complete absence of them. They're going to be competitive. You're going to see some headline prices for acreage. Federal leases are highly desirable leases, but we're going to be in that game, and we're going to be competitive.

Thanks, and I appreciate that perspective. Um, my second question is on federal lease sales in New Mexico, following me the big beautiful bill. I think those lease sales tend to become more frequent. How do you think about using those lease sales to add your position? Do you see it becoming a more material part of your capital budget point for it?

We hope so. Uh, you know, there was a day not too many years ago when Federal lease sales were a really important part of the calendar. And over the last few years, there's been uh, you know, a complete absence of them or near complete absence of them. They're going to be competitive, you're going to see some headline prices for acreage Federal. Leases are highly desirable leases, but we're, we're going to be in that game, and, and we're going to be competitive.

Conference Center Operator: Your next question comes from the line of David Deckelbaum with TD Cowan. Please go ahead.

Your next question comes from the line of David Deco, bomb with TD cabin, please go ahead.

Thomas Jorden: Thanks for taking my questions, guys. Just was curious on just, you know, how you're thinking about the midcon in terms of demanding capital over the next couple of years, particularly just given the move into more three-milers this year. How quickly can like a three-miler program become part of the midcon go forward?

Thomas Jorden: You know, I'm going to throw that one to Michael DeShazer, who's, you know, over our business units.

Thanks for taking my questions guys. Um, this was was curious on just, you know, how you're thinking about the midcon, uh, in terms of demand and capital over the next couple of years, particularly just given the uh the movement to more 3 Mi is this year. Uh how quickly can like a 3 Mile or program become part of the uh the mid-con go forward.

Michael DeShazer: Thank you, David. Yes, the three-mile projects are unique in that a lot of the developments are already in place in Kane Field, where we operate, you know, our three different areas of Lone Rock, Updip, and Downdip. So, we are going through all of our inventory right now and understanding where can we extend three-mile laterals because we've seen the profitability increase of those in all of our basins. The project that's scheduled to come on in Q4 was an opportunity where we could easily add on that third-mile lateral, and we were excited to do that. But I think it will be a longer-term transition, and we will have, because of the way the units have been set up as two miles in the past, we won't be able to move all of that program to three miles over time.

You know, I'm going to throw that with Michael Chaser, who is over our business units.

Thank you, David? Yes. Uh, the 3-mile projects are unique in that, uh, a lot of the developments already in place in Cana field where we operate, you know, our 3 different areas of the Lone Rock up dip and down dip. So we are going through all of our inventory right now and understanding, where can we extend 3 Mile laterals because we we've seen the the profitability increase of those and all of our basins. Uh, the project that's that's

Scheduled to come on in Q4 uh, was an opportunity where we, we could easily add on that third mile lateral. And we were excited to do that, but I I I think it will be a longer term transition and we will have because of the way the units have been set up as 2 miles

in the past we we won't be able to move all of that program to 3 miles over time.

Thomas Jorden: I appreciate the color there, Michael. And maybe just, you know, Blake, on the remaining Harkey wells, that were the 22 that are dewatering, do you guys have an anticipated timeline on how long these wells would take to dewater before looking to go back and remediate and return the sales?

Blake Sirgo: No, I mean, that's why we really, you know, we covered in the remarks, we mentioned the gradual build over time, and that's really what we're expecting. And that's also why we're not using it to add to our oil guide this year. We do think it's just going to be a slow, gradual build over time. And so, we've de-risked those volumes this year, and we'll see how they clean up through time.

Appreciate the color there, um, Michael and maybe just, you know, Blake on, on the remaining hockey Wells, uh, or the 22 that are deep watering, uh, do you guys have an anticipated timeline on? You know how long these Wells would take to dewater before looking to go back and remediate and return the sales?

No, I mean that's why we really, you know, we covered in the remarks. We we mentioned the gradual build over time and that's really what we're expecting. Uh and that's also why we're we're not using it to add to our oil guide. This year is we we do think it's just going to be a slow gradual build over time. And so uh, We've digressed those volumes this year and we'll we'll see how they clean up through time.

Conference Center Operator: Your next question comes from the line of Derek Whitfield with Texas Capital. Please go ahead.

Your next question comes from the line of Derek Whitfield with Texas Capitol. Please go ahead.

Neil Mehta: Thanks. Good morning all. Congrats on your update. With my first question, I wanted to lean in on the power gym opportunity for Coterra and the success you've experienced in achieving power sales agreements. As this has been an elusive feat for many of your Permian peers, how would you characterize what's leading to your success and how you're positioning Coterra as a partner?

Um, thanks. Good morning all, congrats on your update.

With my uh, thank you sir.

With my first question, I wanted to lean in on the power jet opportunity for guitar and the success of experiencing power sales agreements.

As this has been an elusive feat for many of your premium peers, how would you characterize what's leading to your success? And how are you positioning Katara as a partner?

Blake Sirgo: Yeah, thanks, Derek. A lot of really hard work is really the only answer to that question. Our marketing team started as I've talked to lots of folks. We talked to folks all over the country, but this opportunity is years in the making. We had to find a wonderful partner in CPV, who frankly just really understood the market for what it was. The Permian has a disadvantaged gas price and a strong power demand. It's a great place to build power plants. But for us, we have to have something differentiated also. We can't just sell gas at Waha. We already have that opportunity every day. And so, those two things came together over lots and lots of negotiations, and we were able to find a deal that worked great for both parties.

Yeah, thanks Derek. Um, a lot of really hard work. It's really the only answer to that question. Our marketing team started as as talks to lots of folks, we talked to folks all over the country, but this opportunity is years in the making, um, we had to find a wonderful partner and cpv who frankly just really understood the market for what it was. There's the permanent has a disadvantage gas price and a strong power demand. It's a great place to build power plants.

Blake Sirgo: And so, those tend to be more the exception than the rule, or we would be announcing a lot more of them, but our team knows exactly what we're looking for, and we're very diligent. We stay at it.

Thomas Jorden: You know, let me add to that. Our experience, whether it's power or dealing with some of our LNG purchasers, if you don't have an investment-grade balance sheet and a good reputation, you don't get past the initial conversation. So, that's certainly been an asset for us. And then as far as this power deal, we're really thrilled to have it from a pricing standpoint. But you know, another element of this that hopefully is not lost is the access to power. You know, in addition to the pricing, we have the ability to purchase additional power, and availability of power is a growing concern in the Permian Basin. So, it really ticks both those boxes.

Can't just sell gas at waha. We already have that opportunity every day and so those 2 things came together, over lots and lots of negotiations. And we were able to find a deal that worked great for both parties. And so um, those tend to be more the exception than the rule or we would be announcing a lot more of them. But our, our team knows exactly what we're looking for. And uh, we're very diligent. We stay at it. You know what? Let me add to that, our our experience, whether it's um, Power or dealing with some of our

Uh LNG purchasers if you don't have an investment grade balance sheet and a good reputation. You, you don't, you don't get past the initial conversation. So that's certainly been an asset for us.

Blake Sirgo: Yeah, I'll just, just as a reminder, we have two great power deals in the Marcellus. So, this is now our third power deal. We now have access to PJM power pricing and ERCOT power pricing, which we love having in our portfolio.

And then as far as this power deal, we're really thrilled to have it from a pricing standpoint but you know another element of this that hopefully is not lost is the access to power you know, in addition to the pricing we have the ability to purchase additional power and availability of power is a is a growing concern and the and the peryam Basin so that it really ticks both those boxes.

Yeah, I'll just just as a reminder, we we have 2. Great power deals in the Marcellus. So this is now our third power deal. We now have access to a pjm power pricing and our cop power pricing which we love having in our portfolio.

Neil Mehta: Great. And then pretty much follow up, I wanted to focus on the Anadarko. While capital costs are down 18% per foot year over year, Anadarko DNC is the highest among your three assets. If we were to think about a greater capital allocation and/or longer wells in general, how much further could you compress costs if you were to lean into that asset, given the constructive gas backdrop we have?

Great. And then for my follow-up, I wanted to focus on the antidote. While Capital costs are down 18% per foot year-over-year.

And a dark. Oh DNC is the highest among your 3 assets.

If we were to think about a greater Capital allocation Andor longer wells in general, how much further could you compress cost if you were to lean into that asset, given the constructive gas backdrop. We have

Michael DeShazer: Yeah, thanks for that question, Derek. I think the Anadarko has some huge advantages. One, it's a pressured basin with really highly productive wells. But that can be a negative on the cost side because they are more expensive to drill, as you've pointed out. The lateral linked extensions that you see on our upcoming projects will definitely help drive that cost down, as well as all of our technology that we're deploying from the Permian and the Marcellus in terms of getting our facilities costs and our completion costs down. As we continue to run our frac fleet through this two and three-mile project that we're on right now, we're excited to see where that could go if we had that consistent frac crew. But in the Anadarko, with the scale of where we're at right now, we don't have a consistent crew.

Michael DeShazer: And I think that's another piece of that puzzle that's missing compared to, let's say, the Permian, where we have three active frac fleets.

John (Conference Operator): And I would say, yeah, while it may have the highest per foot cost, it also generally over the course of the year has the best price realizations on the gas side for us and the NGL side for us.

Yeah, thank you for that question Derek. I think the the inner Darko is it has some huge advantages 1. It's a pressured Basin with really highly productive Wells. But that can be a negative on the cost side because they are more expensive that expensive to drill as you've pointed out. The lateral linked extensions that you see on our, our upcoming projects will definitely help drive that cost down as well as all of our technology that we're deploying from the puran. And the Marcellus, in terms of getting our facilities costs and our completion cost down as we continue to run our Frac Fleet uh through this 2 and 3 Mile project that we're on right now we're we're excited to see where that could go if we had that consistent track crew but in the end of Darko with the scale of where we're at right now we don't have a consistent crew and I think that's another piece of that puzzle that's missing uh compared to let's say the furion where we have 3 active, Frac fleets.

Michael DeShazer: Ultimately, we always look at returns of these assets, and we think that the returns, even at these higher dollar per foot values you see, compete heads up with the other basins.

And I would say you know, while it may have the highest per foot cost, it also generally over the course of a year has the best price realizations for on the gas side for us and the in jail side for us.

Ultimately, we always look at the returns of these assets, and we think that the returns, even at these higher dollar per foot values, compete heads up with the other basins.

Conference Center Operator: Your next question comes from the line of Matt Portillo with TPH. Please go ahead.

Your next question comes from the line of Matt partiel with tph. Please go ahead.

Shannon Young: Good morning all. You've had some phenomenal success and results in the Dimmitz box. I was just curious if you might be able to provide some color on how many additional locations you see in the area and maybe timing of development for those pads moving forward.

Good morning, all. Um, you've had some phenomenal success and results in the Demick Box. I was just curious, uh, if you might be able to provide some color on how many additional locations you see in the area, and maybe the timing of development for those pads moving forward.

Thomas Jorden: Yeah, we're, you know, I'll just answer it this way, Matt. We'll be drilling Dimmitz box wells here for the next year or two. You know, we're not prepared to give well counts, but they are phenomenal wells. They're truly phenomenal wells. And you know, the other thing I'll say is just from a community standpoint, we're really happy that a lot of royalty owners and landowners that hadn't been able to participate in the royalties are fully participating. And it's just nice. It's nice for the community. So, we'll be drilling in the Dimmitz box here for the next year or two.

Yeah, we're um, you know I'll just answer it this way. Matt, we'll be, we'll be drilling dimmick box Wells here for the next year or 2. Uh, you know, we're not prepared to give well counts but they are phenomenal. Well, so they're, they're truly phenomenal. Well and you know, the other thing I'll say is just from a from a

Community standpoint. We're really happy that a lot of royalty owners, and land owners that hadn't been able to participate in the royalties are fully participating and it's just nice. It's nice for the community. So we'll we'll be drilling uh, in the demick Box here for the next year or 2.

Shannon Young: That's great. And then maybe just to follow up on the Northeast, I was curious if you might be able to talk about your views specifically in Northeast PA on the opportunity set around power demand growth. A lot of your peers in Southwest PA have provided context in terms of their opportunity set. And then in addition to that, I was curious if you might be able to talk about your updated views on infrastructure opportunities in the region and the ability to potentially market gas further away from the field.

That's great. And then maybe just a follow-up on the Northeast. I was curious if you might be able to talk about your views, specifically in Northeast PA, on the opportunity set around power demand growth. A lot of your peers in Southwest PA provided context in terms of their opportunity set. In addition to that, I was curious if you might be able to talk about your updated views on infrastructure opportunities in the region and the ability to potentially market gas further away from the field.

Thomas Jorden: Well, I'll tee that up. Blake will comment. You know, the opportunity set is rapidly evolving. Now, you know, others have said, and we will also say that a long-term commitment at in-base in pricing is not very interesting to us. We have access to in-base in pricing without making long-term commitment. So, if we're going to make a long-term commitment to generation, you know, power generation, we'd really like to have some kind of price structure that underwrites that investment. You know, as far as infrastructure, you know, there's a lot of movement of infrastructure in the Northeast. We are optimistic, but again, we're going to need to have customers that are willing to make a commitment for the product. We're just not interested in committing to long-haul transportation without purchasers on the terminus of that that are willing to, you know, have a price that's constructive.

You know, others have said, and we will also say that a long-term commitment at in Basin pricing is not very interesting to us. We have, we have access to Invasion pricing without making long-term commitment. So if we're going to make long-term commitment to generation, you know, power generation, we'd really like to have some kind of price structure that underwrites that investment, you know, as far as infrastructure. Uh, you know, there there's a lot of movement of infrastructure in the Northeast. We are optimistic. But again, um,

Thomas Jorden: Blake, you want to add anything to that?

Blake Sirgo: I just, you know, on the power side, what's going on in Pennsylvania is very exciting. We're seeing lots of movement, and all the right players are coming to the table on these things. So, the power growth looks real, but I'd just, you know, echo what Tom said. It still has to be differentiated for Coterra. We can't just sign up for long-term in-base in sales. And really, the long-haul projects are the exact same math. You know, if we're going to move gas out of basin and take on those commitments, we need to have either a differentiated price, a different market that we really believe in, or we need to have a price structure that really helps underwrite those investments that are ultimately going to fill those pipes.

We're going to need to have customers that are willing to make a commitment for the, the, the product. We're, we're, we're just not interested in committing to Long Haul transportation, without purchasers on the Terminus of that, that are willing to, you know, have a price. That's constructive Blake. You know what, anything to that. I, I just, you know, on the power side, what's going on in? Pennsylvania is very exciting. We're seeing lots of movement, um, and there's all the right players are coming to the table on these things. Uh, and so, the power growth looks real, but I just, you know, Echo what, Tom said, it still has to be differentiated for Cotera. We, we can't just sign up for long term in Basin sales and really the uh, the Long Haul projects or the exact same math. You know, we, if we're going to move, gas out of basin, uh, and take on those commitments, we need to have either a differentiated price.

Uh, different market that we really believe in, or we need to have a price structure that really helps underwrite those investments that are ultimately going to fill those pipes.

Conference Center Operator: Your next question comes from the line of Philip Jungwirth with BMO Capital Markets. Please go ahead.

Your next question comes from the line of Philip Young, who works with BMO Capital Markets. Please go ahead.

Shannon Young: Thanks. Good morning. Can you expand more on the comment about delineation of zones across the avant acreage? What you've de-risked to date or could by year-end, and then how does this compare to the acquisition underwriting on the upper end of locations?

Michael DeShazer: Yeah, this is Michael. Obviously, the Northern Delaware Basin, the main intervals that operators have historically attacked have been in the third bone spring sand and the second bone spring sand. And what we've seen is a lot of operators have focused that drilling activity in those two intervals. We're excited to see that some of the shallower intervals in the first bone spring and Avalon have shown tremendous results as you move north. And so, that's, but it's more geologically driven. In those reservoirs, you have to be more specific about where you're drilling. It's not a blanket play. We think that plays to our strengths of being highly geologically driven and that attention to detail of where we place our laterals, what spacing looks like, what frac design looks like. And so, that's what we're seeing in terms of results there.

Thanks, uh, good morning. Uh, can can you expand more on the comment about delineation of zones across the Avant acreage? Um, what you do is to date or could by year end. And then, how does this compare to the the acquisition underwriting on, on the upper end of locations?

Yeah, this is Michael obviously the northern Delaware Basin the main intervals, that that operators of historically attacked have been in the third bone, spring sand and the second bone spring sand. And what we've seen is a lot of operators, have focused that drilling activity in those 2 intervals, we're excited to see that the sum of the shallower intervals in the first bone spring. And Avalon have shown tremendous results As you move north.

Michael DeShazer: That's about as much detail as we want to get into in terms of what additional ideas we have. Obviously, the first and first bone spring and Avalon are well known at this point, but we're also excited about other intervals that we see that we're trying to attack up there as well.

And so that's, but it's more geologically driven in those reservoirs. You have to be more specific about where you're drilling. It's not a blanket play. We think that plays to our strengths of being highly geologically driven and that attention to detail of where we place our laterals, what spacing looks like, and what Frac design looks like. And so that's what we're seeing in terms of results there. That's about as much detail as we want to get into.

Terms of of of what additional ideas we have. Obviously, the first and first bone spring and Avalon are are well known at this point, but we're also excited about other intervals that we see that. We're trying to attack up there as well.

Shannon Young: Okay, great. And then maybe more specifically on Appalachian marketing, Williams did discuss a new agreement for Northeast supply enhancement, which would add 400 million a day to North Jersey and New York markets. More indirectly, but would you see this benefiting Coterra? And then would something like this make Constitution less attractive from a producer standpoint?

Okay, great. And then, uh, maybe more specifically on Appalachian marketing. Uh, William Williams did discuss a new agreement for Northeast Supply enhancement, uh, which would add 400 million a day to North Jersey, New York markets, uh, what more indirectly? But um, would you see this benefiting Cotera? And then with, with something like this, make uh make Constitution uh less attractive from a producer standpoint.

Blake Sirgo: Yeah, I mean, we're very involved in all those discussions. You know, I just kind of, whether it's Constitution or NESE or whatever FT deal is, it's the same math we've been talking about. It's got to provide us either diversity or price enhancement over and above what we can get in the current portfolio. And we're excited about these deals because that's bringing new markets to the table, and that's how we can possibly get some price enhancement in the portfolio. So, we'll see where they go.

Thomas Jorden: Yeah, you know, NESE and Constitution are both top-of-mind items for a lot of people. It makes sense the way it's been prioritized is NESE has kind of been prioritized above Constitution. And the reason for that is NESE has more immediate access to a market. There are fewer dominoes that have to fall for NESE to make sense. So, we're, you know, we're watching both those with great interest.

Uh, yeah. I mean, we're we're very involved in all those discussions, you know, I just kind of whether it's Constitution or Nessie, or whatever ft deal is. It's it's the same math we've been talking about, it's got to provide us either diversity or Price enhancement over and above what we can get in the current portfolio. And uh, we're excited about these deals because that that's bringing new markets to the table. And that's how we can possibly um get some price enhancement in the portfolio. So we'll we'll see where they go.

Yeah, you know um Nessie and Constitution are both top of Mind items for a lot of people. Uh, it's makes sense. The, the the way it's been prioritized is Nessie, has kind of been prioritized above Constitution and and the reason for that is Nessie has more immediate access to a market. You, there are fewer dominoes that have to fall for Nessie to make sense.

Uh, so we're, you know, we're watching both those with great interest.

Conference Center Operator: Your next question comes from the line of Paul Cheng with Scotiabank. Please go ahead.

Arun Jayaram: Hey guys, good morning. Two quick questions. First, based on the comment that you guys made earlier, does that mean that Anadarko could be an area of interest for M&A?

Yeah, next question comes from the line of Paul Chang with SCA Bank. Please go ahead.

Hey guys, good morning. Um, two quick questions. Uh, first, um,

And the DOE could be an aerial interest for M&A.

Thomas Jorden: Well, look, Anadarko has some great net backs. You know, we're bringing on a project now we've talked about in the past that is phenomenally productive from a gas standpoint. You also have natural gas liquids, and you know, the profitability is great. You know, we're in a competitive environment. We're not going to comment on M&A in any particular area, but we have a great position, great inventory in Anadarko, and it really is a solid part of our portfolio.

Well, look, look. Um

Anna Darko has some great in that backs. Uh, you know it's it. Bring on a project. Now we've talked about in the past that that is phenomenally productive from a gas standpoint. You also have natural gas liquids and um and you know the profitability is great. You know we're in a competitive environment. We're we're not going to comment on m&a and then any particular area but we have a we have a great position, great inventory in the ad Darko and and it really is a solid part of our portfolio.

Arun Jayaram: And Tom, on the, it looks like that you guys like the power netback contracts. Is there a target in terms of percent of your gas volume you would like to be in that type of contracts? Or do you think that higher is better?

Thomas Jorden: Well, let me bounce past that to Blake. We do like power contracts, but Blake.

And Tom on the uh it look like that. You guys like the power in that bag. Uh contracts. Um, is there a Target in terms of percent of your gas warning? You would like to be in uh that type of contracts or that do you think that the higher is better?

Blake Sirgo: Yeah, I wouldn't say we have a specific target. Really, what we're always doing with our entire sales portfolio is we're looking at long-term sales we can take on to give us diversity and price enhancement. And then we're balancing that with long-term growth plans and how many future volumes we want to commit to these deals. And so, that's a very dynamic thing that moves through time. And you've seen us step into that more and more, and a lot of that's underwritten just in the confidence of our assets. We can deliver these volumes over the long haul.

Well, let me let me bounce past that to Blake. We, we do like power contracts but Blake. Yeah, I wouldn't say we have a specific Target. Um really what we're always doing with our entire sales. Portfolio is we're looking at a long-term sales we can take on to give us diversity and price enhancement. And then we're balancing that with long-term growth plans and how many

Future volumes. We want to commit to these deals and so that's a very Dynamic thing that moves through time. Um and you've seen us step into that more and more and a lot of that's underwritten just in the confidence of our assets and we can deliver these volumes over the Long Haul.

Arun Jayaram: I see. Okay, we do. Thank you.

See. Okay, we do. Thank you.

Conference Center Operator: Your next question comes from the line of Leo Mariani with Roth Capital Partners. Please go ahead.

Your next question comes from the line of Leo Marani with Roth Capital Partners. Please go ahead.

Shannon Young: Yeah, hi. I wanted to see if you can provide a little bit more color on the Franklin Mountain and Avant acquisitions here. You've mentioned earlier comment they've been kind of fully integrated. Can you speak and maybe quantify some of the recent results? You talked about testing some other zones there, which sounds encouraging, but can you kind of provide a little bit more of an update on how results have maybe trended on the wells versus the prior operator and how costs have trended versus the prior operator?

Michael DeShazer: Hey Neil, thanks for that question. Yeah, when we said that the Franklin Mountain and Avant assets are now integrated, what we were really thinking about there is that our field operations, our safety procedures, our rigs and frac crews, and everyone's on the same team now. And that's really important anytime you acquire assets or a company is getting that culture all the way through that new acquisition asset. In the case of the individual well results, obviously we had an expectation for all of the wells that were in progress before the acquisition, and all of those wells are meeting those expectations. It's really about right now where Coterra has been able to put their stamp on all of the well results going forward because we're getting to choose well spacing and frac design from here on out.

Yeah. Hi. I want to see if you can provide a little bit more color on the Franklin mountain in e-vent. Uh, you know, Acquisitions here. Many earlier comments, they've been kind of fully integrated, can you speak? And maybe quantify some of the recent results, you talked about, uh, testing some some other zones there which sounds encouraging but can you kind of provide a little bit more of an update on how results? So maybe trended uh on the wells versus uh the prior operator and how costs of trying to diverse the prior operator.

Hey Neil, thanks for that question. Yeah, when we said that the Franklin mountain and Avant assets are now integrated, what we were really thinking about there is that our our field operations our safety procedures, our uh, Rigs and Frack Crews and everyone's on the same team now, and that's really important. Anytime you acquire assets or a company, is getting that culture all the way through, um, that that new new acquisition asset, in the case of the, the individual well results. Obviously, we had an expectation for all the wells that were in progress.

Michael DeShazer: And so, our message is that the expectations we had entering into the acquisition, all of those wells that were in progress were meeting or exceeding those expectations. And from here on out, you should expect Coterra results.

Before we, you know, before the acquisition and all of those wells are meeting those expectations, it's really about right now where Coterra has been able to put their stamp on all of the well results going forward because we're getting to choose, you know, well spacing and frac design from here on out. And so, our message is that the expectations we had entering into the acquisition, all of those wells that were in progress were meeting or exceeding those expectations. And from here on out, you should expect Coterra results.

Thomas Jorden: Thanks.

Thanks.

Conference Center Operator: And that is the end of the question and answer session. I would now like to pass the call over to Tom Jordan for closing remarks.

Thomas Jorden: Yeah, I just want to thank everybody for joining us. And in closing, you know, we're working on delivering what we promised, as always. And when we say consistent profitable growth, you've heard us say loud and clear, the growth we're going to deliver is growth and free cash flow. And we want Coterra to be known as a free cash flow machine with great durability. With that, thank you very much.

And that is the end of the question and answer session. I would not like to pass the call over to Tom Jordan for closing remarks.

yeah, I just want to thank everybody for joining us and in closing, uh, you know, we're

on delivering what we promised as always. And when we say consistent profitable growth, you've heard us say loud and clear, the growth. We're going to deliver is growth in free, cash flow and we want cotero to be known as free cash flow machine with great durability with that. Thank you very much.

Conference Center Operator: This concludes today's conference call. You may now disconnect your lives. Have a pleasant day, everyone.

This concludes today's conference call, you may now disconnect your lines have a pleasant day, everyone.