National Fuel Gas NFG Q2 2026 Earnings Transcript

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DATE

Thursday, April 30, 2026 at 9:00 a.m. ET

CALL PARTICIPANTS

• President & Chief Executive Officer — David Bauer
• Chief Financial Officer — Timothy Silverstein
• President, Seneca Resources Corporation — Justin Loweth
• Manager, Investor Relations — Natalie Fischer

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TAKEAWAYS

• Adjusted EPS -- $2.71, up 13% year over year, continuing double-digit EPS growth and in line with the multiyear 10%-plus annual growth target.
• Free Cash Flow -- Approximately $160 million generated, providing coverage for the dividend and capacity to reduce leverage before the Ohio LDC acquisition closes.
• Production Guidance -- Reduced by 3% at the midpoint to 425-440 Bcfe for the full year, reflecting weather-driven operational delays and underperformance on four older design wells.
• Natural Gas Price Realizations -- Up by more than $0.50 per Mcf or nearly 20%, attributed to portfolio positioning and market tailwinds during winter volatility.
• Pipeline & Storage Developments -- Line N system upgrade announced, adding 94,000 dekatherms/day of contracted incremental capacity; project capital cost estimated at $93 million with 70% allocated to modernization, expected in service by late 2028.
• FERC Rate Case -- New filing seeks a $95 million increase in cost of service and includes a proposed modernization tracker; settlement targeted for fall with new rates later in the year.
• Utility Business Rate Plans -- New York is in year 2 of a 3-year plan through fiscal 2027; Pennsylvania has requested a $20 million rate increase with settlement discussions expected by fall.
• Ohio LDC Acquisition -- Closing remains on track for calendar Q4, with regulatory processes completed or progressing as expected, and $1 billion in permanent financing required at closing.
• Capital Expenditure Guidance -- Maintained at $560 million-$610 million, with upward pressure from drilling efficiencies and diesel price increases attributed to the conflict in Iran, trending toward the upper end.
• Contracted Firm Transport Capacity -- Portfolio expected to increase by approximately 50% to more than 1.5 Bcf/d, including new Gulf Coast exposure doubling in coming years.
• Debt Metrics -- Expectation to finish the year below 2x debt-to-EBITDA, with FFO to debt approaching 50%.
• Gathering O&M Outlook -- Full-year gathering O&M now forecasted at $0.12 per Mcf (up $0.01), offset by lower upstream LOE, resulting in no net impact on total cost structure.
• Record EBITDA in Upstream & Gathering -- Segment delivered more than $300 million EBITDA, driven by net production of 102 Bcf and elevated winter prices.

SUMMARY

The company highlighted a sequential milestone in its pipeline expansion strategy, executing a precedent agreement for the Line N upgrade that secured all incremental capacity under a long-term contract with an investment-grade counterparty. Natural gas price volatility during the winter enabled higher realized prices, which management credited as a key driver of record quarterly EPS and pronounced free cash flow. Management reiterated completion timelines for the Shippingport Lateral and Tioga Pathway expansions, affirming alignment with planned November 2026 in-service dates. Portfolio hedging remains disciplined, with approximately 75% of anticipated production hedged for the remainder of the year, chiefly through swaps and fixed price sales. Management described ongoing improvements in well design, with Gen 4 and Upper Utica completions performing in line with expectations and contributing to higher deliverability on recent pads.

• David Bauer said, "Collectively, between the rate case and two expansion projects, fiscal 2027 should be a period of significant growth in our Pipeline and Storage business."
• Timothy Silverstein emphasized the company's "unique combination of EPS growth and significant free cash flow generation" relative to industry peers.
• Justin Loweth stated, "Our inventory depth in Northeast Pennsylvania, which is arguably deeper than any peer in the region, positions us well to be a disciplined acquirer of transportation capacity as it becomes available."
• Management noted firm transport agreements initiated in Q2 will double Gulf Coast exposure over time and provide flexibility to serve premium end markets.

INDUSTRY GLOSSARY

• Gen 4 Well Design: The company's most recent generation of well completion methodology, incorporating updated spacing, proppant loading, and tailored designs to maximize productivity in the Utica formation.
• Upper Utica: The stratigraphic upper portion of the Utica Shale targeted by NFG for natural gas and liquids production.
• Firm Transport (FT) Capacity: Contracted, guaranteed pipeline space for moving natural gas from the production basin to demand markets, regardless of spot market congestion.
• Modernization Tracker: A rate mechanism proposed in regulated utility filings to allow timely recovery of capital invested in infrastructure modernization projects.
• FFO to Debt: A leverage metric representing the ratio of funds from operations to total outstanding debt.
• LOE (Lease Operating Expense): Ongoing operating costs required to maintain production from existing oil and gas wells.
• PJM: Interconnection, LLC, a regional transmission organization coordinating the movement of wholesale electricity in parts of the Eastern U.S., including NFG's core markets.
• Bcfe: Billion cubic feet equivalent, a standardized unit combining volumes of natural gas, oil, and natural gas liquids.
• Dekatherm: A unit of energy equal to ten therms or one million British thermal units (MMBtu), used to measure natural gas transportation volumes.

Full Conference Call Transcript

David Bauer: Thank you, Natalie, and good morning, everyone. National Fuel had a solid second quarter with adjusted earnings per share of $2.71, an increase of 13% from last year. This continues our streak of double-digit EPS growth and keeps us on track to achieve our multiyear 10% plus average annual growth target. I'm also happy to report that during the quarter, we achieved additional milestones across the system that further bolster our long-term earnings outlook. Our second quarter was a prime example of the strong operational resiliency of our natural gas assets, particularly during severe weather events.

In January and February, we experienced an extended cold snap across our operating footprint, where daily low temperatures in some of our regions were below freezing for 19 straight days. A big thank you to our dedicated workforce and contractors who worked through the elements to ensure that the gas continued to flow during this critical time. Overall, our systems held up extremely well with no notable issues at our Utility and Pipeline and Storage businesses. On the nonregulated side, our production and gathering facilities performed very well with limited freeze-offs. This allowed us to take advantage of some of the strong prices we saw on the coldest days.

We did, however, experience some regional road closures over multiple days due to heavy snowfall. During this stretch of weather, we slowed the pace of completions and delayed the flowback of a new pad, which had a modest impact on our production for the quarter and will similarly impact full year production. On the drilling and completion side, we continue to focus on the optimization of our integrated development program. We've made substantial progress on the testing of both our Gen 4 well designs and our Upper Utica locations and are seeing continued success, which further enhances our long-term outlook.

With decades of core inventory locations, a growing marketing portfolio and ongoing improvements in capital efficiency, our Integrated Upstream & Gathering business is positioned to deliver meaningful production and free cash flow growth for years to come. Justin will provide additional details later in the call. Our outlook for the regulated businesses is also strong. Starting with the Pipeline and Storage segment, we continue to develop new expansion opportunities on our Line N system, which is well positioned to support both behind-the-meter generation that's co-located with data centers and the broader need for electric generation within PJM. Last week, we executed a precedent agreement on a new expansion opportunity that we're calling the Line N system upgrade project.

And this project has a dual benefit for us. First, it adds 94,000 dekatherms a day of incremental transportation capacity, all of which was subscribed under a long-term contract with an investment-grade counterparty. And second, the project allows us to modernize a key 6-mile portion of pipe, ensuring the continued reliability and integrity of that part of our system. The project has an estimated capital cost of $93 million, approximately 70% of which relates to the modernization component of the project, and it's expected to go in service in late calendar 2028. Also this quarter, construction commenced on our Shippingport Lateral and Tioga Pathway expansion projects, both of which are on track to meet their November 2026 target in-service dates.

Lastly, today, Supply Corporation is filing a new rate case with FERC that seeks an approximately $95 million increase to our cost of service. In addition, our filing proposes a modernization tracker to support the ongoing investment in the safety and reliability of the system. We expect this proceeding to play out along the typical time line and hope to reach a settlement sometime this fall with new rates going into effect late in the calendar year. Collectively, between the rate case and two expansion projects, fiscal 2027 should be a period of significant growth in our Pipeline and Storage business. Moving to the Utility.

Customer affordability remains top of mind, and we continue to work closely with our regulators to ensure we can continue to invest in the modernization of our system while keeping rates reasonable. Our delivery rates are the lowest in both states, and we're doing our best to keep it that way. In New York, we're in year 2 of our 3-year rate plan, which runs through the end of fiscal 2027. As we look beyond 2027, we have over a decade of remaining modernization investments at our current replacement pace. Over the coming months, we'll be proactively working on a solution to recover these important future investments. In Pennsylvania, our rate case is progressing as expected.

Testimony from staff and other intervening parties was filed a few weeks ago. We'll file rebuttal testimony in May and then expect to commence settlement discussions over the summer. Given our modest rate increase request, we're optimistic we'll reach a settlement by the fall. I expect discussions will be constructive. As I said, our rates are the lowest in the state and would continue to be the lowest even if we receive the full $20 million increase we've requested. Turning to Ohio. The CenterPoint acquisition is on track for a calendar fourth quarter closing. In January, we made our HSR filing and the required waiting period has since passed, completing that regulatory process.

In addition, we've given notice of the acquisition to the Public Utilities Commission of Ohio and expect an order from the commission in late spring or early summer. Tim will have more on the acquisition later in the call. Before closing, a quick word on energy policy in New York State, where we continue to see a growing recognition of the practical role natural gas must play in the state's energy future. While New York remains committed to its long-term climate objectives, recent proposals from Governor Hochul and the adoption of the state energy plan reflect a more balanced common sense approach.

Policymakers are increasingly focused on maintaining reliability, protecting affordability for customers and ensuring the system can perform during peak demand periods, particularly during winter weather events. Those discussions underscore what we've long believed. The existing natural gas system remains essential to serving homes and businesses and supporting electric grid reliability and will continue to be a critical part of New York's energy mix for decades. In closing, National Fuel is well positioned to deliver steady growth in earnings and cash flow in the years ahead. We have a great set of Integrated Upstream and Gathering assets with multiple decades of high-quality development inventory.

Our midstream infrastructure is strategically located to provide key support to the significant growth in natural gas-fired electric generation expected in the region. And we have a growing base of utility earnings that will be further enhanced with the completion of our pending Ohio LDC acquisition. Taken together, the National value proposition is as strong as it's ever been. With that, I'll turn the call over to Tim.

Timothy Silverstein: Thanks, Dave, and good morning, everyone. National Fuel had record earnings per share in the second quarter, driven in large part by the strength of our natural gas marketing and hedging portfolio. We've intentionally positioned this portfolio to capture meaningful upside from higher winter prices, and we saw that come to fruition in late January and February. Combining this with the steady growth of our regulated businesses, National Fuel's adjusted earnings per share increased 13% for the quarter. We also generated approximately $160 million in free cash flow. This unique combination of EPS growth and significant free cash flow generation differentiates National Fuel from many of our peers. Diving a bit deeper into the results for the quarter.

First, in the Integrated Upstream and Gathering segment, price realizations were up more than $0.50 per Mcf or nearly 20%. While we convert a lot of our marketing portfolio to NYMEX-linked prices, we maintain a bit more exposure in the winter months to markets that have the potential for premium prices as demand spikes. That exposure provided a great tailwind during the quarter. Pairing that with the skew towards collars in the winter months, we were able to capture a nice benefit during the extended cold snap. On the production side, results came in slightly below expectations. As Dave mentioned, the system held up well during the challenging weather.

However, road closures impacted our operations, which reduced production for the quarter. Overall, this had a 5 Bcf impact in the quarter. Lastly, our per unit gathering O&M came in slightly above expectations. This was a result of a new preventative maintenance strategy we deployed on several compressors. In the normal course, we take compressors out of service to perform maintenance. However, in certain instances, it is more beneficial to swap in a new engine to minimize downtime and upgrade the technology. There is minimal cost to doing this, but the accounting rules require us to write down the remaining net book value of the unit being replaced. As a result, we recorded a larger-than-normal expense during the quarter.

We now expect gathering O&M to be $0.01 higher at $0.12 per Mcf for the full year. But going the other direction, upstream LOE is expected to be $0.01 lower. On a combined basis, we don't see any impact on our cost structure. On the regulated side of the business, results were ahead of expectations as we continue to see strong execution across the board. Turning to guidance. The biggest change for the remainder of the year relates to our NYMEX price assumption, which we are now projecting to be $3 per MMBtu, down from $3.75.

With the lower pricing, we are also seeing modestly tighter basis differentials over that same period, which we now project to be $0.80 below NYMEX. We are approximately 75% hedged for the rest of the year, with the bulk of that in the form of swaps and fixed price sales. This provides price certainty, which lessens the impact of the lower expected pricing on our earnings guidance, which we now project to be in the range of $7.45 to $7.75 per share. At the midpoint, this represents a 10% increase over last year. Embedded in our assumptions are a few other changes, including production guidance, which we now expect to be 425 to 440 Bcfe for the full year.

This is down 3% from our prior guidance range, but at the midpoint is still expected to be up relative to last year. Longer term, our outlook for production growth remains intact. As a reminder, our guidance does not assume any price-related curtailments. Thus far since winter, we haven't curtailed any volumes. But to the extent we see material in-basin pricing declines, we may decide to do so. At the midpoint of guidance, our spot exposure is limited to approximately 30 Bcf, which minimizes the potential impact on earnings and cash flows for the year. Lastly, on our fiscal 2026 outlook, we've increased our guidance for Pipeline and Storage segment revenues.

During the quarter, as colder weather settled in, we were able to take advantage of the increased demand. We also saw higher revenues tied to a tracker on electric costs, but those are fully offset in O&M. There were a couple of additional tweaks to a few guidance assumptions, all of which are highlighted in our earnings release and IR presentation. Switching to capital. Our guidance remains the same. However, we are trending towards the higher end of those ranges. In the regulated subsidiaries, we have had great success with our modernization programs and are ahead of schedule on our plans for the year. With our pending rate proceedings, we expect to obtain timely recovery for this spending.

Our two pipeline expansion projects are on track as well, both from a timing and budget perspective. The bulk of construction season is still ahead of us, so things may move around a bit as we work through the rest of the fiscal year. Justin will have more on nonregulated spending in a minute. Overall, our balance sheet is in great shape. We still anticipate generating a significant amount of free cash flow, more than enough to cover our growing dividend and reduce absolute leverage before closing our Ohio LDC acquisition. We expect to end the year below 2x debt-to-EBITDA and approach 50% FFO to debt.

This leaves us in a comfortable position to achieve our target of mid-2x debt-to-EBITDA after the first full year post closing. Sticking with the acquisition, things are moving along well. With the HSR process behind us, our focus is on the notice filing in Ohio. We've had several discussions with commission staff over the past few months, and we expect to complete this process well in advance of closing. Our teams are also working diligently to prepare for an efficient transition of the business, and we are confident that it will be a smooth process for customers. We are also taking the necessary steps to position ourselves to complete the remaining permanent financing prior to closing.

We are working to finalize the necessary pro forma financial statements, which we anticipate wrapping up shortly. Once those are ready, we will start to evaluate the market to find the right window to raise the remaining $1 billion we need at closing. We also plan to refinance our $300 million October maturity and term out a portion of the term loan that we temporarily repaid with the proceeds from our equity issuance completed last December. All told, we expect to raise up to $1.5 billion across multiple tranches. We also recently upsized our committed credit facility, which now provides $1.3 billion of borrowing capacity to support our growing operations.

This was well supported by our bank group and provides us with additional financial flexibility in the future. In conclusion, we expect 2026 to be a key inflection point for National Fuel. We are leveraging our interstate pipeline assets and commercial relationships to significantly expand the FERC-regulated businesses. We have two critical expansion projects under construction and another expansion announced yesterday. Our Ohio LDC acquisition will provide a further avenue for stable, regulated growth. Lastly, our strong balance sheet and significant free cash flow generated by our nonregulated businesses provides the foundation upon which we can deliver further growth.

Combining this with our commitment to consistently return an increasing amount of cash to shareholders, National Fuel is positioned to create value for years to come. With that, I'll turn the call over to Justin.

Justin Loweth: Thanks, Tim, and good morning, everyone. Our Integrated Upstream and Gathering segment had a solid second quarter, delivering record EBITDA of more than $300 million, driven by net production of 102 Bcf and higher natural gas prices during Winter Storm Fern. Through the severe weather conditions, our team and Integrated Upstream and Gathering facilities performed exceptionally well with minimal downtime due to freeze-offs. That said, the heavy snowfall and extreme cold in January and February closed roads, which slowed completions and delayed flowback on a new pad. These weather-driven factors modestly impacted production during the quarter and are expected to have a similar effect on fiscal year production as volumes shift into future periods.

In addition, last fall, we turned in line a 6-well pad in Northwest Tioga and a separate fault block, which included an Upper Utica well and a Lower Utica Gen 4 test, along with 4 older design wells. The 4 wells with older style designs are underperforming our projections. This pad was strategically drilled about 18 months ago in part to hold an almost 20,000-acre parcel of land, but prior to our 3D seismic shoot and incorporation of that data into our broader subsurface model. Today, we have the benefit of an integrated subsurface model and significant other attributes across the vast majority of our core development area, which we expect will lead to superior outcomes going forward.

Going the other way, the Gen 4 and Upper Utica wells on the pad are demonstrating strong productivity in line with our expectations. While the older design wells will modestly impact our production estimate for the balance of fiscal '26, the Gen 4 and Upper Utica results, along with our deep understanding of the subsurface, reinforce our confidence in this area and optimal future well design. Overall, we are reducing fiscal '26 production guidance by 3% at the midpoint to a range of 425 to 440 Bcf to account for the expected impact of these items. Despite this modest adjustment, we remain confident in durable mid-single-digit production growth over the next several years.

Across our operations, we remain focused on continuous improvement and are advancing our testing program to further optimize well design and understand productivity drivers across our core area. During the quarter, our two best-performing Tioga Utica pads to date, Bauer and Taft, reached cumulative production of 130 Bcf. The 12 wells across these pads, 10 of which incorporated Gen 3 and Gen 4 designs and two of which are Upper Utica wells were turned in line in late 2024 and produced at rate-constrained levels of 25 million to 30 million per day for an extended period. We estimate they will deliver about 900 million per 1,000 foot in 18 months, among the best results in the basin.

Turning to development activity during Q2. We turned in line our first Tioga co-development pad with 3 Upper and 3 Lower Utica wells, and we have another pad planned to come online toward the end of the fiscal year. On this pad, we also utilized production facilities that allowed us to flow a single Tioga Utica well rate constrained at 40 million per day, well above the 25 million to 30 million per day we held on Bauer and Taft. It's early, but this is an encouraging data point. And the team is doing a great job expanding what we believe is possible on well deliverability.

Finally, at the very end of the quarter, we began flowing back our first fully bounded Lower Utica Gen 4 pad with a total of 5 wells. Expanding the capacity of our surface equipment, understanding co-development influences and building confidence in optimal well design are key components of our continuous improvement focus. Pulling it all together, these data points inform our long-term development planning, and we'll remain deliberate in testing variables and applying what we learned to further optimize the program over time. Turning to capital. We're maintaining our prior guidance of $560 million to $610 million. Our drilling team is driving efficiencies that may result in more wells being drilled this year.

While this is very positive and reduces our cost per foot, it has the potential to bring forward capital. On the land side, we've been extremely active, making a number of strategic moves to further bolster our acreage position given our confidence in the Utica resource. We are also seeing emerging cost headwinds tied to the conflict in Iran, particularly higher oil and diesel prices flowing through drilling, completions and logistics, especially long-haul intensive activities. Altogether, these items have us trending towards the high end of the range. In our gathering operations, construction activities are well underway with seasonal pipeline and infrastructure construction expected to continue into the summer months.

Near-term activity continues to support Seneca's production growth while advancing opportunities for incremental third-party volumes in Tioga County. We have multiple projects underway to expand pipeline and compression capacity in our core area. And throughput continues to track Seneca's production closely with third-party volumes steady and in line with our full year projections. Turning to the broader natural gas outlook. We are bullish on the long-term setup and see fundamentals supportive of higher prices over time. LNG exports are near record levels of around 20 Bcf per day with additional capacity coming online. And recent global events continue to highlight the value of reliable, low-cost U.S. natural gas.

Domestically, demand is building in the Northeast and the Mid-Atlantic regions, driven by gas-fired power generation, data centers and AI-related load growth. At the same time, producer discipline is keeping supply growth in check, particularly in Appalachia, where pure curtailments are effectively limiting near-term volumes in excess of demand. Overall, we expect a more balanced market and improving long-term price realizations for high-quality Appalachian supply, especially for operators with strong market access and flexibility like Seneca. Against this backdrop, we're executing our multiyear marketing strategy to reach premium markets and added flexibility, both in-basin and out of basin. Over the next few years, we expect total firm transport capacity to grow approximately 50% to more than 1.5 Bcf per day.

Just this month, we gained access to our new 50 million per day of firm transportation that reaches the Gulf Coast. During the second quarter, we added another 50 million per day of long-term firm capacity along the same route that will go in service over the next few years, doubling our Gulf Coast exposure over time on similarly attractive terms. Our inventory depth in Northeast Pennsylvania, which is arguably deeper than any peer in the region, positions us well to be a disciplined acquirer of transportation capacity as it becomes available.

With increasing access to the Gulf, the soon-to-go in service Tioga Pathway project and the EGT Project Stratum, which reaches premium markets in Western Pennsylvania and Leidy Hub, we're taking strategic steps to support long-term growth through valuable pipeline capacity contracts. We see additional opportunities ahead and remain confident in our ability to deliver growth at premium price realizations over time. In closing, the underlying strength of our asset base is clear. Our testing program continues to validate acreage depth and quality and will help optimize development for years to come. We've remained disciplined on capital despite emerging headwinds and our recent marketing and midstream investments support future growth and greater access to premium markets.

Overall, we remain well positioned to deliver durable production growth, increasing free cash flow and long-term value for our stakeholders. With that, I'll turn it back to the operator to open the line for questions.

Natalie Fischer: We now turn the line open for questions.

Operator: [Operator Instructions] Your first question comes from the line of Zach Parham with JPMorgan.

Zachary Parham: First wanted to ask on curtailments. Tim, I think you mentioned in your prepared remarks that NFG didn't have any curtailments in the current guide. Another Appalachian producer talked about some curtailments in 2Q. I know you've got the large majority of your volume hedged, but can you talk about how you're thinking about curtailments? Is there a price level in the in-basin where you think about shutting in some volumes and maybe what -- where about is that price level?

Timothy Silverstein: Zach. Like I said, we have approximately about 30 Bcf exposed into the spot market. And as we've said in years past, especially when we've seen lower prices, we don't specifically talk about the price level at which we curtail. I think what we've said historically is that prices north of $2, we're still flowing gas. Prices well below $1, we're definitely curtailing somewhere in there is where we typically make the decision. So we don't give that specific price. But again, we're very limited exposure and each day that passes, we're continuing to flow gas right now.

Zachary Parham: Then my follow-up is maybe for Justin. You talked about flowing one of the new wells at 40 million a day versus the 25 million to 30 million that I think you flowed in some of the older wells. Can you talk about, one, your expectations on how long these wells can hold that plateau period at the higher rate? And two, how having the equipment in place to flow at a higher rate impacts both cost and potential returns from pulling forward some volumes?

Justin Loweth: Yes. Sure, Zach. So a couple of things. I mean, one, in terms of the ultimate sustained period, we're going to have to do more work and look at it, but it should be relatively linear with wells that we produce at 30 million. We would expect to get some sort of cume in total drawdown over a period of time. Of course, if you're flowing at 40 million versus 25 million or 30 million, that period of time will be a little bit shorter. But it also brings forward value.

And so one of the things we're really looking for and trying to optimize on, and I think this goes back to your cost question, is that we believe that we're close on a design where we'll be able to flow at those higher rates and do it at the exact same production facility cost that we have today, potentially even less as we continue to optimize and improve those designs.

And what we're really balancing is that particularly if we have a pad with less overall wells, let's say, it's 4 or 5 wells on that pad, and they're very long laterals, which we've been moving towards recently, we're actually -- recently here just finished casing some wells that will be approaching 20,000-foot TLL. With wells like that, the opportunity to flow at a higher rate restricted rate, even if it's for ultimately a little shorter period can pull a lot of value forward. And so we're trying to understand kind of what that relative balance is and what the overall deliverability makes sense. But look, we're encouraged by it.

We know from the wells we've drilled that there's plenty of pressure and plenty of opportunity to do more. It's just going to be this balancing act. And the other thing that we, of course, factor into all of this is our gathering infrastructure and what makes the most sense from an integrated investment and capital allocation decision. So those are the kind of guiding principles that we're looking at in it. But this was a great opportunity to just have a well where we could pretty easily and inexpensively really validate this test for ourselves, and it was successful.

Operator: Your next question comes from the line of Tim Rezvan with KeyBanc Capital Markets.

Timothy Rezvan: I wanted to follow up on upstream. The release highlighted the 6-well pad and in comments, it sounds like 4 wells underperformed expectations with an older completion design. I was curious if you could provide more insight on what happened. Was it simply under stimulation? Was there a downhole issue? And kind of where I'm going with this is, when do you think the team might be comfortable just using the Gen 4 design as your standard recipe going forward?

Justin Loweth: Tim, thanks for your question. These wells, you said it right, it was a 6-well pad. It's kind of on the western side of our core development area. Several factors here that play into it. The first one is we have a lot of 3D seismic coverage across our acreage. This area, though, was one we had acquired in 2023, and we're in the process of capturing that 3D seismic and then ultimately processing that and integrate it into our broader subsurface model. So at the time when we were drilling these wells, we didn't have the benefit of that knowledge. Today, we have all of that, and we have tremendous understanding and visibility into this area.

And so when they were drilled, which was also tied to holding a very important lease that captured about 20,000 acres of land, when they were drilled, we had a -- we were earlier in our days. We were still drilling both well design in terms of interwell spacing as well as proppant loading. We were still testing and doing our Gen 2 designs and then working towards our Gen 3 and Gen 4 designs. If I could go back in time, these would all be Gen 3, Gen 4 because the Upper Utica well in the pad and the Gen 4 design in the pad are very strong performers, right in line with our expectations.

These 4 wells, though, that were older Gen 2 designs, just have underperformed. And so we've got a lot better understanding in this area. Like I said, I mean, we've got now -- we've got a lot of wells across our broader portfolio, a lot more information, a lot better understanding, and that's informing the decisions we're making today. So as part of that, the idea of going all the way to a Gen 4 design we're trending in that direction.

But what I'll tell you is we are going to continue to challenge ourselves between Gen 4 and Gen 3 or any other future generation design to really optimize for the best overall return between our upstream and gathering business. And a Gen 4 design is a little bit more expensive than a Gen 3 design, and we want to see additional results from these Gen 4s that we're drilling, including I mentioned at the very end of this Q2, we brought online our first 5-well fully bounded Gen 4 design pad.

We want that kind of data to really help inform us on if we're moving all the way towards the Gen 4 design or something in between that could be even better. But ultimately, we're going to be led by the economics between our Integrated Upstream and Gathering, getting the most gas for the least amount of overall capital.

Timothy Rezvan: That's a great detailed answer. And as my follow-up, I was curious to learn kind of if you all could give more color on the long-term expansion opportunities for Supply Corp. You highlighted a third project with the Line N upgrade. How many projects are out there? And how do you decide which to pursue? And then on top of that, you mentioned in the slide deck, there's potentially more to do with Line N's potential incremental expansions. And can you talk more about the likelihood that you think you can capture that?

David Bauer: Sure. Yes, we've had a great run of doing expansions on Line N over the years. And given its location, I think that we're going to have lots more opportunities in the future. Our current focus right now, if you will, in the Line N area is on power gen, both with behind-the-meter type projects like with our Shippingport project as well as other, call it, just power gen that would go into PJM. And there's a lot of opportunities there. The dialogues that we've had with developers has been productive.

As you may know, the Shippingport project, which is initially starting at 200 million a day, could grow to as much as 800 million a day if the project developer was successful in fully building it out. So that certainly would be a big opportunity. And then other opportunities along the line are sizable as well, right? Our plants use a lot of gas. And Line N isn't the only spot that we're looking at. Our Empire line that goes from Tioga County north into New York and then ultimately connecting to Canada is another area that we could expand. I think the region is just generally short electric generation. Certainly, in PJM, we see the results of their auctions.

But in New York, where there's been such underinvestment in energy infrastructure, at some point, I really believe that we're going to need more generation within the state. And as much as policymakers would like that to be wind and solar, those just don't work for baseload power. And I think we're looking at needing more baseload power and natural gas is the logical choice for that. And our pipelines, particularly the Empire is really well suited for serving that new generation.

Operator: Your next question comes from the line of John Freeman with Raymond James.

John Freeman: First question, Justin, you touched on some of the maybe headwinds that you're seeing on the CapEx side on the diesel prices and things like that. Could you give just any more kind of color just on a leading-edge basis outside of like diesel prices, if you're seeing anything that's either supply chain type factors as a result of what's going on and then just any potential pressure on the service cost side?

Justin Loweth: Yes. Sure, John. Thanks for the question. The short answer is you're hitting at kind of the main element, which is more diesel, which obviously haul-intensive activities are going to be impacted by that and various surcharges that are baked into a lot of contracts that us as well as many other operators across the country have with their various vendors. In terms of real supply chain issues, we've actually been talking to all of our counterparties, digging into this, trying to ensure that there's no war-impacted challenges. At this point, we don't believe there are.

One, we've looked kind of potentially across like, for example, charges to the extent you have more explosives that potentially could get hung up and tied into Defense Production Act or otherwise needs. And we're just not seeing it. So we think we're pretty well insulated from, I'll call it, the same shocks that a lot of people went through back coming out of COVID, where you had an inability of the supply chain to deliver what you need. It's much more about some pricing headwinds. And the reality is we don't -- it's so early in this conflict and don't have a lot of visibility when it's going to end and how that works.

So we're evaluating it and working on it. And we're not seeing anything specific as it relates to drilling or completions. I would just note that those generally are longer-term contracts for us. We have a long-term frac provider. And similarly, we generally contract our rigs for 12 to 18 months at a time when we're bringing them in.

John Freeman: And then, Dave, I wanted to follow up on some comments you made previously. It seems like over the last couple of quarters, increasingly, we're hearing more and more of a focus on kind of the behind-the-meter kind of projects like what you have done with Shippingport. And I'm just curious, when you look out like at the opportunity set over the next several years and we sort of think about the opportunities behind the meter versus kind of the traditional grid-based solutions, kind of how you see that mix playing out?

David Bauer: I think the focus is switching more towards broader generation within PJM. I mean there still certainly is interest in behind-the-meter generation. I think that tends to go over better with the policymakers. But from a practical standpoint, having -- like I said just a minute ago, having more generation just generally in the region is going to require the build-out of new gas-fired generation, and we're going to be there to support it.

Operator: [Operator Instructions] Your next question comes from the line of Neil Mehta with Goldman Sachs.

Neil Mehta: Can you hear me okay?

David Bauer: Yes.

Neil Mehta: Sorry about that. So just your perspective on the gas macro would be terrific. I mean we've obviously seen a softening relative to where we were when we connected a couple of months ago and part of that could be the shoulder. Part of it seems like it's just production beats. I mean just your perspective on -- as you think about the balance of this year, we set up for exits in October. How do you think about the setup here? And how is that shaping the way you're approaching activity and hedging?

Justin Loweth: Thanks, Neil. I mean, just big picture, nothing has really changed fundamentally about our views. Tim spoke to some of this in his remarks. We've really built the portfolio to go through periods of both high and low prices. And as you're alluding to, that's exactly what we've seen. To go from a February settle of almost 750 and then the settle we just saw here from May of 256 is pretty tremendous volatility. We hedge. We've always hedged. We're methodical about that and thoughtful about it. We use collars to capture the upside. And then we have a marketing portfolio that's designed to capture premium markets at the end, but also minimize in-basin exposure.

And so Look, I think across the country, we're going to have more gas coming out of the Permian, particularly as these new pipeline projects go in service. Haynesville, a bit of a wildcard, exactly how that moves and exits through the year. But coming back closer to home for us and what really matters are the flows coming out of Appalachia and the relative demand. And I think our view is that, generally speaking, there's just a lot more discipline these days than there has been if you go back several years ago. And by discipline, what I'm referring to is just producers in Appalachia understanding that we have a specific amount of storage.

We have a specific amount of demand that will fluctuate based upon winter and summer temperatures, of course. But generally, the market stays more balanced and maintains, I'll call it, reasonable differentials to NYMEX Henry Hub. And then look, longer term, Henry Hub, I'll just hit at that briefly. We're still very much in the camp that we're -- we've entered a market where, generally speaking, we're going to see Henry Hub prices between $3 and $5. And we would expect that there will be short periods of time that could be above or below that level. And that's really our fundamental view.

What's great is that with those kind of prices, with the longer-term $3 to $5, we do fantastic. We generate a lot of free cash flow, a lot of earnings. And as we continue to make forward progress on our capital efficiency trends, that's just going to translate to more and more cash flow. So yes, I mean, very constructive with air pockets along the way, both highs and lows along the way.

Neil Mehta: Yes, certainly volatile. I appreciate that. And then just your thoughts around maximizing Gulf Coast exposure and any firm takeaway opportunities down to premium end markets would be good. I mean we saw that you layered in a little bit more here. But how big could that opportunity set be for you guys as you look out over the next couple of years?

Justin Loweth: So I mean, we've been at it now for a few years, really trying to further bolster our takeaway capacity in the form of new firm transportation. When we saw the depth and quality of this Utica resource that we have, it was clear to us we needed to protect the pathway to grow and do that through finding our way into premium markets. I spoke about some of those today. We've got the Tioga Pathway service -- coming in service later this year. We've got the EGT Project Stratum coming in, in a few years. And then what we've been able to selectively grab are these Gulf Coast new capacity contracts that you're alluding to.

Getting that first 50 million, getting that first olive out of the jar took a long time. We've been working on that for 18 months. And then we were successful here this last quarter at executing a contract to pick up another 50 million. And so over time, we'll have about 100 million going there. And then a lot of our overall FT portfolio, when you think about the $1.5 billion, it gets pretty balanced. We've got a nice chunk that's going to Gulf Coast or to, I'll call it, the Mid-Atlantic markets down as far as Z4, which would be in Alabama, but also Z5 South.

We've got some great capacity that gets us into kind of the New York, non-New York markets. And then we've got some access to some premium PA markets where we see continued, in particular, power gen. There's going to be a lot -- there are a lot of plants under development right now and PJM is short power, and we strongly believe that where we're moving this gas is going to be moving right to it. And then through the northern markets, whether that's Canada or Northern New York. So we really like the portfolio setup. We're going to keep chipping away. I'm confident we'll find more ways to continue to expand it. If that's Gulf Coast, awesome.

If it's something else, that's great, too. And we're -- but I'm confident we'll keep chipping away. But we've made huge strides. I mean, growing our portfolio by 50% over the last few years in terms of how much capacity we'll have as we get out to 2029.

Operator: There are no further questions at this time. I will now turn the call back to Natalie for closing remarks.

Natalie Fischer: Thank you, Karina. We'd like to thank everyone for taking the time to be with us today. A replay of the call will be available on the website later today. Please feel free to reach out if you have any follow-up questions. Otherwise, we look forward to speaking with you again next quarter. Thank you, and have a nice day.

Operator: This concludes today's call. Thank you for attending. You may now disconnect.

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