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Good morning, everyone, and welcome to BKV Corporation's fourth quarter and full year 2025 earnings conference call. As a reminder, today's call is being recorded. A brief question-and-answer session will follow the formal presentation. I would now like to turn the call over to Mr. Michael Hall, Vice President of Investor Relations. Please go ahead.

Thank you, Operator, and good morning, everyone. Thank you for joining BKV Corporation's fourth quarter and full year 2025 earnings conference call. With me today are Christopher Kalnin, Chief Executive Officer; Eric Jacobsen, President of Upstream; and David Tameron, Chief Financial Officer. Before we provide our prepared remarks, I would like to remind all participants that our comments today will include forward-looking statements, which are subject to certain risks, uncertainties, and assumptions. Actual results could differ materially from those in any forward-looking statements. In addition, we may refer to non-GAAP measures. For a more detailed discussion of the risks and uncertainties that could cause actual results to differ materially from any forward-looking statements, including those associated with the recently completed power JV transaction or the integration of recently acquired upstream assets, as well as the reconciliations of non-GAAP financial measures, please see the company's public filings included in the Form 8-Ks filed today. I would also point listeners to the updated investor presentation posted this morning on our Investor Relations website. We encourage everyone listening to review those slides and our forthcoming annual report to be filed with the SEC for further information on our business, operations, results from the quarter and full year, and details on our 2026 guidance. I will now turn the call over to our CEO, Christopher Kalnin.

Thank you, Michael, and thank you, everyone, for joining us to discuss our fourth quarter and full year 2025 results. As we close out 2025, I am proud to report that BKV Corporation delivered a transformational year that exemplifies our “said-did” culture and positions the company for sustained, long-term profitable growth. We generated strong earnings, maintained a fortress balance sheet, and delivered strong growth. 2025 marked our first full year as a public company, and we executed across each pillar of our closed-loop strategy. Our business lines of upstream natural gas, natural gas midstream, carbon capture, and power deliver premium, low-carbon energy solutions that are increasingly sought after in today's energy markets. In our upstream business, we exceeded expectations throughout the year, and our performance across the Barnett and Northeast Pennsylvania showcased the depth, durability, and competitiveness of our upstream assets with approximately 8% exit-to-exit organic production growth on upstream development capital well within cash flow and with top-tier F&D costs. The successful close of the Bedrock acquisition in the third quarter was executed in line with our plans. The transaction materially expanded our footprint in the Fort Worth Basin and added high-quality assets. We added more than 100 MMcfe/d of production and nearly 1 Tcfe of proved reserves to our leading position in the basin. Our upstream business remains foundational to our growth strategy. We believe we have built a scalable, repeatable, and disciplined operating model for extracting value from mid-tenured shale basins. Our team is at the forefront of driving efficiency by leveraging technology, data, and AI to optimize development and performance across our portfolio. This is a model that we believe wins in mid-tenured gas basins over the long term. In our carbon capture business, we had meaningful progress in 2025. Earlier in the year, we secured a transformative partnership with Copenhagen Infrastructure Partners (CIP), who committed up to $500 million for joint investment in carbon capture opportunities. We are working hand in hand with their team to scale this business profitably. Our flagship Barnett

Thanks, Chris. 2025 was an outstanding year for our operations, capped by a strong fourth quarter that highlighted the depth and quality of our asset base, the strength of our team, and the disciplined, efficient approach we apply across the business. For the full year 2025, our upstream business delivered, and in many cases exceeded, the targets we previously set, including the following highlights. We delivered robust organic production growth of 8% exit-to-exit while spending well within upstream cash flow and driving continued cost efficiencies. We beat and raised our full year legacy production guidance twice in the year, by 4% at midyear and then by another 1%, all within our initial development capex and while maintaining LOE at the midpoint of guidance. We achieved a step change in completions efficiency, setting multiple internal records above 22 horsepower-hours per day. We drilled several company-record laterals, including the longest well in the history of the Barnett Shale. We delivered top-tier performing new Barnett wells, with three ranking among the highest in the entire history of the basin based on first-month production. We lowered D&C cost per lateral foot to a gas peer-leading $545 per foot. We achieved consistent and sustained positive offset well, or POW, production, a unique advantage in the Barnett, which we discuss further in our investor presentation. We delivered the lowest base decline amongst our peers, supported by our extensive dataset and application of AI technology. We seamlessly integrated our recently acquired Bedrock assets, adding scale and inventory to our leading Barnett position. And we ended the year with approximately 6 Tcfe of 1P reserves valued at 10% of $3.1 billion. The fourth quarter was a continuation of the results we had seen all year. We again outperformed guidance across key metrics, punctuated by zero reportable safety incidents; production that outperformed the upper end of our guidance range at 940 MMcfe/d; we delivered our first NEPA well to production for the year and drilled three additional wells with completions expected in 2026; and we had over $6 million invested in rapidly progressing Bedrock development, landing full year 2025 development capital spend at $245 million. To note, we invested $319 million all-in corporate capex, which was below the initial low end of full year guidance. And we executed our first post-acquisition completions on the Bedrock assets, including two DUCs and two refracs, with strong results. One more example of Barnett competitiveness and an important proof point in the continued optimization of the Barnett development is what we refer to as positive offset wells, or POW. In addition to new wells outperforming type curve expectations, we are consistently observing a material and sustained uplift in parent well performance across our DSUs following new completions. Based on early analysis across approximately 30 new wells and their offsets, we have seen an approximate 22% uplift above type curve on average through the first 150 days of production. Roughly half of this outperformance is due to POW. Whether POW, peer-leading D&C cost, structurally lowered operating costs, or applying big data and AI, these and more combined validate our comprehensive operating approach of delivering durable value over the long term. And there are more innings yet to go. It is a model that we believe wins in every mid-tenured gas basin. We are applying that model to our Bedrock acquisition, which has proven to be everything we anticipated and more, with integration progressing ahead of pace. The assets fit seamlessly with our existing acreage position, creating further opportunities for lateral extensions, inventory additions, and multiple optimization levers. As an example of further accreting value, or what we call torque, we are actively evaluating over 60 equivalent 10,000-foot Tier 1 locations compared to 50 underwritten, and over 100 refrac candidates compared to 80 underwritten. Importantly, value creation from the acquisition is exceeding our underwriting assumptions in development counts, early-time performance, day-one LOE reductions, and other areas, reflecting our ability to apply torque to the asset and unlock incremental synergies and value. These assets complement our low base decline, attractive economics, and highly competitive and accretive inventory opportunities, which are all trademarks of our dominant Barnett position. Our performance throughout 2025 confirms that the Barnett is not only alive and well, but highly attractive and ideally positioned relative to other shale plays with advantaged access to the heart of the Gulf Coast gas market. Looking ahead to 2026, we expect continued strong performance from our upstream operations enhanced by the full integration of our Bedrock assets. While the impacts of Winter Storm Fern resulted in significant and unanticipated downtime, we still expect strong production in the range of 900 to 930 MMcfe/d during Q1. Development capex spend in the first quarter, we anticipate to be in a range of $70 to $100 million. For the full year 2026, we are guiding to 935 MMcfe/d of production on $240 million of development capital spend, right in line with our 2025 development program. Our upstream business continues to serve as the backbone of our closed-loop operations model, generating the cash flow that enables growth across all our business lines while maintaining operational excellence and capital efficiency. Turning to carbon capture, 2025 was a year of strong, accelerating momentum for the business. Against the backdrop of growing market demand and supportive policy tailwinds, we advanced multiple projects across our portfolio, progressing them through critical stages of evaluation, development, and execution. Key highlights from the continued expansion and maturation of our development pipeline include our Eagle Ford and Cotton Cove projects, which continue to progress as planned with commencement of operations at both locations on track. At our East Texas project, where we are working with the same large midstream company as we are in the Eagle Ford, we have reached internal FID and are currently scheduled to begin drilling the injection well in the first half of this year. And we also plan to drill our High West stratigraphic test well in the first half of the year. In addition, as Chris mentioned, we have recently executed definitive agreements with Comstock to add CCUS to their Bethel and Marquet facilities in the western Haynesville play in East Texas. We continue to advance discussions on additional CCUS opportunities with new partners and emitters, with a focus on larger projects that offer greater economies of scale. Several of these opportunities are referenced in our updated investor presentation, and we look forward to providing updates as appropriate. Our flagship Barnett

Thank you, Eric. 2025 was a year of meaningful progress for BKV Corporation as we continued to execute and deliver on our promises. We had significant transactions in upstream, power, and CCUS. We strengthened our balance sheet and improved our capital structure, issuing our first-ever bond while also increasing float and improving liquidity in our stock. We entered 2026 with significant momentum and are well positioned to capitalize on our strategic initiatives. In our power business, we delivered consistent performance throughout 2025, with the Temple Energy Complex maintaining high availability factors, minimal unplanned downtime, and strong operational execution. The Temple plants achieved a combined average capacity factor of 57% during the fourth quarter of 2025 and 59% for full year 2025, generating over 7,600 gigawatt-hours. During the fourth quarter, power prices averaged $49.69 per MWh, with natural gas costs averaging $3.55 per MMBtu. This resulted in an average quarterly spark spread of $24.54 per MWh. For the full year, power prices averaged $48.86 per MWh with natural gas costs averaging $3.31 per MMBtu. This resulted in an average full-year spark spread of $25.36, underscoring the growing power demand in ERCOT. Average spark spreads for the full year were up over 15% versus the prior year. Power JV adjusted EBITDA was $31 million for the fourth quarter and $127 million for the full year, of which BKV Corporation had a 50% interest. Reflecting our new controlling ownership stake, beginning with our first-quarter 2026 results, we will consolidate the power JV. For the first quarter, we expect gross power JV EBITDA of $25 to $35 million, reflecting typical seasonal patterns, capture of storm-related power pricing, and strong operational performance thus far in the quarter. Importantly, we weathered Winter Storm Fern without any related downtime. This is an important proof point for the reliability of our Temple assets as we engage in PPA offtaker discussions. For full year 2026, we are guiding to a power JV EBITDA range of $135 to $175 million. This outlook reflects the strength of the platform we built, continued operational execution, and confidence in the earning power of our Temple assets. Turning to our 2025 corporate financial performance, these results clearly demonstrate our team's relentless focus on execution and ability to consistently deliver. Combined adjusted EBITDAX attributable to BKV Corporation was $109 million in the fourth quarter and $390 million for the full year. This represented a 19% increase quarter over quarter and a 47% increase year on year. For the fourth quarter, adjusted net income was $27 million, or $0.29 per diluted share. For full year 2025, adjusted net income totaled $120 million, or $1.40 per diluted share. Capital expenditures totaled $102 million for the fourth quarter and $319 million for the full year. This full year result is below the low end of our original guidance, reflecting highly competitive capital efficiency and our ongoing attention to capital discipline and cost optimization. Importantly, after fully funding all capital investments across our business lines, and excluding any cash contribution from our power JV, we generated positive free cash flow for the entire year, and we did this while further strengthening our balance sheet and improving our liquidity. At year-end, total debt was $500 million, with the only debt outstanding reflecting our recently issued senior notes. Net leverage ratio was 0.9x. Cash and cash equivalents totaled $199 million, and total liquidity stood at $984 million, more than double the prior year. Looking ahead, our 2026 capital investment program is structured to lay the foundation for a multiyear phase of disciplined growth. There are three key components of this program. First, total gross capital expenditures of $410 to $560 million, including an anticipated $135 million of gross strategic power capital. This power investment reflects the constructive conversations we are having with multiple potential PPA offtakers. Second, on a net basis and excluding our power growth capital, we are targeting a net capital investment midpoint of $324 million, effectively flat year on year. Third, and importantly, based on current strip pricing and just as we did in 2025, we expect our total full year net capital expenditures to be fully funded within cash flow. This approach reinforces our commitment to disciplined capital allocation while positioning the company for sustainable, long-term value creation. Regarding hedging, our program continues to provide downside protection while allowing participation in favorable market conditions. In our upstream business, our total 2026 hedge position protects just over 60% of forecasted production, with gas hedged at $3.85 per MMBtu and NGLs hedged at $22 per barrel. In our power business for 2026, we have hedged 40% of our ERCOT generation capacity through heat-rate call options, or HERCOs. These HERCOs include substantial premium revenues that help mitigate annual earnings volatility. We have also locked in fixed spark spreads on roughly 100 megawatts, while retaining meaningful merchant exposure across the balance of the platform. For the remainder of our 2026 guidance, please refer to our complete schedule, which can be found both in the press release and our latest investor deck. With that, I will turn the call back to Chris for his closing remarks.

Thanks, David. As we conclude our discussion of 2025 and look ahead to 2026, I want to highlight what truly differentiates BKV Corporation. We have built a distinctive, winning strategy connecting natural gas production, power generation, and carbon capture into a virtual closed-loop platform uniquely positioned to serve the evolving needs of the energy market. This strategy is operating today, delivering results, and positions us to shape solutions for the evolving needs of hyperscalers, data center developers, and industrial customers. Looking ahead to 2026, we see clear growth vectors. Increased control of our power JV is expected to enhance earnings and cash flow while enabling tangible strides towards executing a PPA. Our CCUS business is accelerating momentum, with additional projects coming online soon and with an increasingly high-graded portfolio of attractive projects in development. Our upstream business remains a reliable, repeatable cash engine with leading corporate decline rates and F&D metrics. Finally, I want to thank our exceptional BKV Corporation team for their commitment to our values, our safety culture, and their focus on the execution of our strategy. We enter 2026 with strong momentum, clear line of sight to growth, and confidence in our ability to create long-term, risk-adjusted shareholder value. Operator, we are now ready to take questions.

Thank you. We will now be conducting a question-and-answer session. If you would like to ask a question, please press 1 on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. You may press 2 if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star key. We ask that analysts limit themselves to one question and a follow-up so that others have the opportunity to do so as well. One moment, please, while we poll for questions. Our first question comes from Betty Jiang with Barclays. Please proceed with your question.

Hi. Good morning. Team, congrats on just strong execution across all segments in your first year. I want to start with a question on the strategic power growth capex. Can you, Chris, speak to what specifically is that spending on? Clearly, it is not maintenance, and it is aligned with the progress in the conversation that you are seeing. So can you just give us a bit more color on is it spending ahead of contract that you are expected to sign later this year or early next year? Thanks.

Yes. Hey, Betty, thanks for the question. So you are correct. The power investments are strategic. As you can imagine right now, as you discuss long-term offtake agreements with potential customers, those designs are going to be in a private use network type setup. That is the assumption here. And so as part of a private use network, you need to invest in transformers, switches, power lines, generation equipment, earthworks, pipelines, water. And that infrastructure then gets recovered over the life of a contract. Right? And so what we are guiding here is that we have got designs and/or investments that need to be made to enable this, and that is really where you see that capital. When you think about the existing Temple 1, Temple 2 capex, you can imagine historically that has been in that sort of $5 million-ish per year level, and we expect that to continue. So the vast majority of what we are guiding here to is really for establishment of a private use network type setup, and that is, again, we think incredibly important to accreting value in a very capital-efficient manner for BKV Corporation.

Yes, Betty, just if I could tack on one thing. Just keep in mind that all this is going to be funded within cash flow. Our entire 2026 program, including strategic power capital, is going to be within cash flow for 2026.

Got it. And it also sounds like you recover this capex in that PPA contract down the line as well.

Exactly. It works just like a lease, Betty. If you invest and a landlord puts in infrastructure, then they recover it in the rent. It is the same concept. In a PPA, you basically amortize the cost of your capital over the life of a contract as part of the investments you make.

Got it. That makes sense. My follow-up is on the CCS business. It is really good to see that million-ton-per-annum target getting raised to 1.5. Clearly, momentum on that asset. Can you speak to the financial implication of that business going forward? Maybe help us with maybe dollar-per-ton margin on that business. And what are you seeing in the market to drive that confidence to raise that long-term target?

Hi. Good morning, Betty. This is Eric. Thanks for the question on CCUS. It is a good one, and we have signaled before, on the back of the passage of the One Big Beautiful Bill Act, some expanded commercial interest. We continue to see that, and that commercial interest and the subsequent projects like Comstock that we were excited to announce definitive agreements reached upon, in total, has given us the confidence to raise that target to 1.5 million tons run rate within 2028. So we are stair-stepping into that already this year with two more projects coming on in the first half. We will be drilling another injection well, a High West stratigraphic well, and then advancing these commercial agreements like Comstock towards FID. You can think about the economics of these projects in the kind of $48-per-ton EBITDA range, and those are the kind of solid economics we use as we march forward towards that 1.5 million tons.

That is great. Thank you.

You bet.

Our next question comes from Scott Gruber with Citigroup. Please proceed with your question.

Yes. Good morning, and I will echo the congrats on a strong performance last year. Given multiple vectors of growth here, Chris, I wanted to come back to power. You are investing in a private use network. It sounds like that is separate from the grid, so just wanted to confirm that. And then there are discussions happening at ERCOT around alterations to their grid connect approval process. How is that impacting your discussions with potential customers for a longer-term PPA?

Hey, Scott. Thanks. Good questions. On the private use network, the setup would be ultimately to connect it back into the grid. So you can imagine it is a behind-the-meter setup. You would hypothetically connect into a data center directly from your generation assets, but then you would have a switching yard that would feed a substation which is grid-connected. And those timelines may not match up one-to-one, and so, as we have mentioned, this is probably where you are going to see the market move with co-located power generation over the next few years. The reason for that is manyfold, but a lot of it has to do with transmission congestion. One of the biggest constraints in the market—this will get to your second question—is the ability to move electrons in sizable form in and out of localized areas. Having co-located power in a private use network setup really does solve a lot of the issues associated with that. It optimizes the amount of capex that needs to be incorporated in the grid. That is really where we see the market going. In terms of the regulation specific for Texas and ERCOT, I think it is overall bullish. Texas is going big on data center infrastructure. It is open for business. There is a very strong feeling here in the state to promote investments in the power grid. We think Texas is one of the states that is really going to figure this out quickly, and BKV Corporation is taking a leadership position in power in Texas. With regards to the regulations themselves, the major concerns of the grid operators are: one, we want to ensure grid reliability—so how are you considering that; two, we want to make sure rates are fair and equitable to existing customers across the state; and three, we need to make sure that new investments are built into the system or are encouraged. The regulations are orienting towards large load—that is the SB 6 regulation that everyone is talking about here—and we think it is incredibly constructive because what they are doing is creating a framework to high-grade projects that address all those three things: grid reliability, ability to ensure equitable rates to existing customers in the state, and then adding grid generation assets. Our designs that we have been describing, including the capex I mentioned, address those three key points. We think this is going to high-grade the projects that are real, that have real customers, that have real funding behind them, and weed out those projects which are speculative and not as real. Overall, we are active with the regulators and the stakeholders here in the state, and we think that Texas figures this out very quickly. A lot of customers have that same view.

I appreciate all the color. I also want to turn to the Comstock deal. Good to see that across the finish line. Can you walk through the injection ramp at those facilities, as well as the timing of the associated capex? And is there capex associated with those projects in the second half of this year, for instance? Just some color there would be great.

Yes. Thanks, Scott. It is a good question. I appreciate Jay and his team really working with us on this project. If you think about what we have guided to, we are expecting to be injecting in 2028. So that is when we are going to commercialize these projects. We did not guide to a volume ramp. Obviously, that is something that we are working with Comstock and we will figure out. You can think about the volume as multiples of our current injection amounts, so it is a significant amount of injection volume. If you think about the spend curve, most of these projects follow a typical construction S-curve. So within the last 12 months before injection, that is when you see a majority of the capex get spent. We have historically guided to a couple hundred dollars per ton of capital that has to go into investment. That is not a bad way to think about it. You should expect that spend to be more back-end loaded, and then the volumes themselves to be multiples of what we are currently injecting.

Great. Exciting. I appreciate the color. Thank you.

Thank you. Thanks, Scott.

Our next question comes from Jonathan Martini with KeyBanc Capital Markets. Please proceed with your question.

Hi. Good morning. Thank you for taking our questions. On power, on slide seven, you referenced a potential PPA execution on 4.5 terawatt-hours of unutilized capacity. Can you just clarify whether this implies a PPA covering just a portion of the Temple plants' capacity, with the remainder being sold into merchant markets? Or just how you are seeing the structure of a PPA shaping up based on your latest discussions?

Yes. Jonathan, it is Chris here. It is a good question. When you look at Temple today, we have two identical power plants in Temple 1 and 2, each 750 megawatts. Today, we hedge roughly half of the complex—so one power plant–equivalent worth of power. There are several reasons you do that. Oftentimes, you can sequence your maintenance to be down on one plant and be fulfilling your power obligations off the other, and so we see a PPA in a similar type structure. A PPA effectively is a long-term hedge on power prices. You could imagine that you are going to always be looking at about half your capacity being contracted and the other half being floated so that you can manage around your maintenance schedules and have resiliency as well. The balance of the volumes that are not contracted, you are absolutely right, from a behind-the-meter setup, you would be able to feed that into the grid and sell that, and you are able to load balance. If you have additional power that the customer is not using, you would theoretically sell that additional power into the grid as well. When you think about these agreements, they are structured like long-term offtake agreements that you would see potentially even for an LNG contract. They are substantive. You can imagine something like 750 megawatts over 10 to 20 years with a structured price, which is somewhat a capacity payment blended with an energy payment, and at a price that is typically about strip. These are the structures that we see in the market today and are good reference points. You are starting to see the announcements on the gas side for these. That is how you can envision something like this coming together.

Okay. That is great context. Appreciate that. Just moving on to CCUS, on the sequestration outlook for a 1.5 million ton annual run rate by 2028, it is an increase from the prior 1.0 million tons you saw by 2027. Just on that gradual ramp, can you help us understand how you see those volumes scaling throughout 2030?

Sure. Hey, good morning, John. Eric here. For the ramp through 2030, I will start with the ramp into 2028—the 1.0 million tons, as you referenced, we have updated and upgraded that on the back of a lot of commercial interest, as I mentioned earlier, following the One Big Beautiful Bill. We have taken that commercial interest and translated it into projects like the Comstock project and others in the making that we are progressing towards FID. As I mentioned, we have the two this year, we are drilling some more wells, and we are really excited about this steady cadence of capex to get us to that 1.5 million tons by 2028. Then, as we ramp from there into 2030, the volumes start to ramp significantly on the back of some of this commercial interest in bigger projects that we are navigating now. On the back of the seven Class VI permits that we filed—six of which are in Louisiana, all of which are progressing nicely—you will remember in Louisiana, our High West project is surrounded by 30 million tons of CO2 emissions within a 30-mile radius. You can see the size and magnitude of projects that help us start to scale this business dramatically past 2028 on the back of these existing Class VI permits, roughly 50,000 acres we have under pore space lease, and a really nice platform to grow post-2028 as we deliver on the 1.5 million tons run rate within that year.

Understood. Appreciate the context. I will leave it there.

Our next question comes from Michael Furrow with Pickering Energy Partners. Please proceed with your question.

Hello, good morning. Thanks for taking my questions. It seems like the company's willingness to develop the Temple 3 plant, if it is underpinned by an offtake agreement, is a positive indicator for your outlook on the PPA market as a whole. So would you say that your confidence level has improved in signing a quality PPA, and therefore, the potential for a Temple 3 plant has improved?

Yes. Hey, Michael, good question. Absolutely right. If you look at what I have just described in terms of the way the regulators are thinking about the large load applications and the overall SB 6 process, having additional generation assets co-located with additional data center infrastructure is, in our minds, very critical. You need to be able to show that you are going to not only take power from the grid, but you are also going to contribute power to the grid and add to grid resiliency. That enters the concept of Temple 3. We believe that Temple 3 does contribute to that. It adds additional resiliency to the Temple Energy Complex. Originally, Temple was designed for three power plants. There is sufficient space, water, gas infrastructure, etc. It makes a lot of sense that as you start to design a private use network, you would include the construction and development of additional generation assets in the form of a, hypothetically, Temple 3. We are excited about that. Again, it would be backed by commercial arrangements. In the same vein as the capital we are spending on the power side, you are looking for a return on that capital as part of an agreement, and we would not move forward without those agreements in place. As you have highlighted, the optimism around what is happening in Texas and the overall amount of data center infrastructure that we expect to be built is, I would say, really accelerating, and BKV Corporation is at the forefront of that.

I appreciate that detail. As a follow-up, I would like to hear on the Upper Barnett appraisal program that is targeted for this year. The breakeven costs appear higher than the core Lower Barnett position. So what are the company's ultimate goals here with this program? And maybe you can provide us with a well count that the company plans to test this year.

Yes, sure. Hi, Michael, it is Eric. Thanks for the good question on the Upper Barnett. We are excited about the future of the Upper Barnett as included in our inventory counts. We will be testing one well at least this year, possibly two. At the moment, our breakevens are slightly higher than our average for the Lower Barnett. But on the back of the success we have had in Lower Barnett—dramatically lowering dollar-per-foot cost by 30% over the last three years; enhancing and advancing completions; negotiating gathering, compression, processing, transport for the Upper Barnett; and our ability to execute—we have proven to execute in the high $0.40s per Mcfe F&D cost. We will translate all those learnings into the Upper Barnett this year. We will drill the one well, we will evaluate it, and we may drill a second by the end of the year. Then we will have a steady dose of Upper Barnett wells as part of our program going forward. We absolutely expect to delineate and confirm those 100 wells this year. We are excited about those on the back of the older vertical wells and some refracs we have had in the area. We really think the Upper Barnett is prospective, and we look forward to sharing some more results by midyear to the second half of the year. Thanks for your time.

Our next question comes from Jacob Roberts with TPH and Company. Please proceed with your question.

Good morning. I wanted to start by circling back to the power capital, and I guess my question is maybe in context of slide 25. When we think about that guidance, is that a function of the number of potential PPAs? Is it a function of the scale of the agreement or even maybe the geographical distance from Temple?

Morning, Jake. Yes. Thanks, Jake. Good question. I think the slide is meant to show the activity around Temple. If you think about where people are building massive amounts of data center infrastructure, they are looking for a few things. One is the ability to add generation assets and grid interconnect—that is critical. Number two, they are looking for proximity to existing fiber lines and/or data center clusters that are already in existence. Number three, they are looking for a buildable, friendly environment where licensing, contracting, and regulations are streamlined. Temple sits right between the Dallas–Fort Worth area and the San Antonio cluster, and this slide is meant to show the amount of activity in Temple. The city of Temple itself has been astronomical in the last, especially 24 months, around that, and it is for the reasons that I just mentioned. It is flat land, it is buildable, it is Texas, it is grid-connected, there are three 345 kV lines. That is the intention. In terms of how you would actually design, the closer to the generation assets, the better, as you build. You are going to see more and more of this co-located power design that I am describing here. That is critical because of what I mentioned around grid congestion. If you are pulling huge amounts of megawatts, the more localized you can match that demand and supply, the less taxing amount of infrastructure you rely on the grid. That is where you are seeing loads in the past in that 200 to 300 megawatt level for data centers—now folks are talking about gigawatt plus. When you are talking about a gigawatt interconnection, you really do need localized generation support. You can imagine the closer you are to generation assets, you optimize your capex more and you get better bang for buck in terms of the overall design. That is where this goes, and you are seeing that in this slide here on ’25 with 1.5 gigawatts of generation capacity.

Thanks, Chris. That is helpful. And then maybe taking a longer-term view on the gas marketing side of things, could you remind us on how your Barnett takeaway contracts are currently structured? And maybe in terms of the ability to eventually shift more of those volumes toward what could become more valuable hubs, specifically Katy and Ship Channel.

Yes. Sure, Jake, this is Eric. Thanks for the question on the contractual nature of our marketing. As we show in our slide deck, right now from the Barnett anyway, roughly 40% of our gas goes to Houston Ship Channel, 30% to Katy, and 30% to Transco. We receive a very nice uplift from the Transco Station 85 on a typical run-rate basis. Over time, a lot of firm contracts are expiring over the next two or three years, enabling us opportunities to sell the gas into multiple markets, and this is exactly why we are so very excited to be positioned in the Gulf Coast. We can sell to our own power plants or other power plants. We can sell locally to the DFW area. We can expand some of our contracts to these existing hubs, directly to industrials in the Gulf Coast corridor, and then, of course, the big boom of all, the LNG expansion that is hitting to the tune of, in our estimation, multiple Bcf over the next four or five years. Being positioned in the Gulf Coast, having access to multiple points and hubs, as well as infrastructure that was built to handle far more than the Barnett is producing today as a basin, and the contractual nature of our expiries that allow us the flexibility, we are very excited for margin enhancement—what we call alpha margin—as a result of our marketing coming out of the Barnett and really increasing the commercial generation of cash flow and margin from our company.

Yes, Jake, it is David. It is something we are actively managing. We spend a lot of time on that internally. You have heard Chris talk about it. At the end of the day, we want to be the highest dollar-per-molecule provider out there, and this is part of that. You will see us over the next six to nine months offer more color around our marketing efforts, and I think it will be well received by you and the Street.

Thanks, Eric. I appreciate your time.

As a reminder, if you would like to ask a question, please press star 1 on your telephone keypad. Our next question comes from Fu Fang with Roth Capital Partners. Please proceed with your question.

So I just have a question about the East Texas project. In the last quarter, you said that the target FID was going to be in first half 2026, but this quarter, you said it is going to be in the internal FID in December. So is that project still waiting for FID, or is it ready? That is one question.

Yes. Thank you. This is Eric. Thank you for the question, Fu, about our East Texas project where we reached internal FID. Yes, we are very excited about that. That is stage one in our trajectory towards our final investment decision, which we have not put out a timeline on just yet. What I can say is we are progressing that project with the same major midstream operator for which we are doing the Eagle Ford project about to start. All of the documents and agreements are in place. We will be drilling the injection well this year, with an anticipated start-up sometime in 2027, as we have signaled. FID is forthcoming on that. We will be drilling the well. We are very excited for that here in the first half of the year, and we look at that as a continuation of our kind of sweet spot so far in these Class II natural gas processing projects, generating that $48 per ton in EBITDA margin and stair-stepping into additional projects in our ramp to 1.5 million tons.

Thank you. And just my second question about the M&A. After Bedrock acquisitions, what are the constraints on the M&A right now?

Yes, Fu, it is Chris here. I think we have shown this is a company that knows how to do M&A. The Bedrock acquisition is going incredibly well in terms of just being able to integrate those assets and really absorb them into the Barnett. The Barnett remains our core M&A target. There is a natural roll-up on the upstream side. There are a number of players that we have shown in the past. There is over a Bcf of M&A opportunities in the basin, and we will continue to prioritize those. More broadly speaking, we are always looking in the M&A markets. We think this business model for mid-tenured gas basins is ideally positioned, and we really are mastering it. We manage some of the oldest shale wells in the entire country, and we understand how to manage them really, really well, and we have demonstrated that. As we look in the Gulf Coast at basins and evaluate the rise, we will be active evaluating and analyzing opportunities and looking for accretive, risk-adjusted transactions so that BKV Corporation can continue to scale our business model in line with the winning formula of gas, power, and carbon capture.

Thank you. We have reached the end of our question-and-answer session. I would now like to turn the floor back over to Christopher Kalnin for closing comments.

Thank you, everyone. I appreciate your time. BKV Corporation is positioned for growth along all our three vectors. We are very excited about 2026, and we look forward to future announcements around that. Thank you, everyone.