National Fuel Gas Co Q2 FY2026 Earnings Call

Hello, everyone. Thank you for joining us, and welcome to the National Fuel Gas Company Second Quarter Fiscal 2026 Earnings Call. The operator provided instructions to participants on how to use the conference call lines. I will now hand the conference over to Natalie Fischer, Director of Investor Relations. Please go ahead.

Thank you, Karina, and good morning. We appreciate you joining us on today's conference call for a discussion of last evening's earnings release. With us on the call from National Fuel Gas Company are Dave Bauer, President and Chief Executive Officer; Tim Silverstein, Treasurer and Chief Financial Officer; and Justin Loweth, President of Seneca Resources and National Fuel Midstream. At the end of today's prepared remarks, we will open the discussion to questions. The second quarter fiscal 2026 earnings release and April investor presentation have been posted on our Investor Relations website. We may refer to these materials during today's call. We'd like to remind you that today's teleconference will contain forward-looking statements. While National Fuel's expectations, beliefs and projections are made in good faith and are believed to have a reasonable basis, actual results may differ materially. These statements speak only as of the date on which they are made, and you may refer to last evening's earnings release for a listing of certain specific risk factors. With that, I'll turn it over to Dave 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. 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. 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 timeline 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.

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.

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. 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. 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 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 deeper than many peers 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.

We now turn the line open for questions.

The operator provided instructions to participants for the question-and-answer session. Your first question comes from the line of Zach Parham with JPMorgan.

First, I wanted to ask on curtailments. Tim, I think you mentioned in your prepared remarks that National Fuel 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-basin where you think about shutting in some volumes and maybe where about is that price level?

Zach, we have approximately 30 Bcf exposed to the spot market. As we've said in prior years, we do not disclose a specific price at which we would curtail volumes. Historically, prices north of $2 per MMBtu generally support continuing to flow gas. Prices well below $1 are levels where we have definitely curtailed in the past. We don't provide an exact threshold, but again, our spot exposure is limited and each day that passes we are continuing to flow gas at current prices.

My follow-up is 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?

A couple of things. Regarding the sustained period, we'll need to do more work and monitor these wells, but we expect cumulative production to scale relatively linearly compared to wells produced at 30 million per day. If you flow at 40 million versus 25 or 30 million, the high-rate period will be somewhat shorter, but it pulls more value forward. We're aiming to reach a design that allows us to flow at those higher rates using the same production facility cost that we have today, potentially even less as we continue to optimize. The balance we're optimizing for is overall returns between flowing higher rates for a shorter period and the cost of surface equipment and infrastructure. For pads with fewer, longer-lateral wells—recently we've completed casing on wells approaching 20,000-foot total lateral length—the opportunity to flow at a higher rate can pull significant value forward. We're encouraged by the results and the pressure available in the reservoir. The decision will be guided by overall integrated economics, including gathering infrastructure and capital allocation. This test was an inexpensive and straightforward validation for us, and it was successful.

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

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 when do you think the team might be comfortable just using the Gen 4 design as your standard recipe going forward?

These wells were on the western side of our core development area. Several factors contributed. We acquired this area in 2023 and did not yet have the benefit of the 3D seismic data and the integrated subsurface model we have today. When we drilled these wells, we were earlier in our development of well designs and were using Gen 2 designs in that sequence of testing as we moved toward Gen 3 and Gen 4. The pad also served to hold a valuable lease package of roughly 20,000 acres. If we could go back, these would be drilled to Gen 3 or Gen 4 designs. The Upper Utica well and the Gen 4 well on the pad are performing in line with expectations, while the four older Gen 2 wells underperformed. We now have much more data and better understanding across our acreage, which is informing our current decisions. We're trending toward a Gen 4-centered approach, but we'll continue to evaluate whether a Gen 3 or intermediate design may provide better overall returns when factoring in gathering costs and capital. We are led by integrated economics between upstream and gathering to get the most gas for the least amount of capital.

That's a great detailed answer. As my follow-up, I was curious to learn more about the long-term expansion opportunities for Supply Corp. You highlighted a third project with the Line N upgrade. How many projects are out there? How do you decide which to pursue? And you mentioned potentially more to do with Line N's incremental expansions. Can you talk more about the likelihood that you can capture that?

We've had a strong run of expansions on Line N over the years, and given its location, I expect many more opportunities in the future. Our current focus in the Line N area is supporting power generation, both behind-the-meter projects like Shippingport and broader generation that would feed into PJM. Developer dialogues have been productive. For example, the Shippingport project initially starts at 200 million a day and could grow to as much as 800 million a day if fully built out, which would be a significant opportunity. We're also evaluating other potential expansions along Empire, which runs from Tioga County north into New York and connects to Canada. The region is generally short on electric generation. In PJM we see shortage indicators in auctions, and in New York there has been underinvestment in energy infrastructure. Over time, we believe more baseload generation will be needed, and natural gas is the practical choice to provide that reliability. Our pipelines, including Empire, are well suited to serve that new generation.

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

First question for Justin: you touched on some of the headwinds on the CapEx side from diesel prices and similar impacts. Could you give any more color on supply chain factors beyond diesel? Are you seeing real supply chain disruptions or other service cost pressures?

The primary element we're seeing is higher diesel, which impacts haul-intensive activities and can lead to surcharges in many vendor contracts. We have been talking to counterparties and have not seen material supply chain disruptions at this point. We've considered potential impacts such as restrictions on explosives or other defense-related items, but we aren't observing those issues now. The situation is early and we don't have visibility on its duration, so we're evaluating and monitoring it. We also have longer-term contracts for drilling and completions—frac providers and rig contracts are typically 12 to 18 months—so that provides some insulation from short-term shocks. For now, it's more of a pricing headwind than a supply chain availability issue.

Dave, a follow-up: it seems over the last several quarters you're increasingly focused on behind-the-meter projects like Shippingport. How do you see the opportunity set playing out over the next several years between behind-the-meter and traditional grid-based solutions?

The focus is shifting more toward broader generation within PJM. There is still interest in behind-the-meter generation, which tends to be better received by some policymakers, but the practical need is for more generation capacity in the region. Building new gas-fired generation will be necessary to meet baseload and reliability needs, and we'll be well positioned to support that development.

Your next question comes from the line of Neil Mehta with Goldman Sachs.

Yes.

Can you hear me okay? My first question is on the gas macro. We've seen a softening relative to earlier in the year, which could be seasonal or due to production beats. As you think about the balance of this year and the setup for the October exit, how do you view the market and how is that shaping your approach to activity and hedging?

Nothing has really changed fundamentally in our view. We built the portfolio to handle both high and low price environments. The volatility from a February settle near $7.50 to a May settle around $2.56 is significant, which is why we hedge thoughtfully. We use collars to capture upside and maintain a marketing portfolio designed to access premium markets while minimizing in-basin exposure. Nationally, more gas is coming from areas such as the Permian as new pipeline projects come online, and the Haynesville remains a wildcard for how it moves through the year. For Appalachia specifically, we see more disciplined production behavior relative to several years ago. Producers are recognizing storage and demand constraints, and the market is generally more balanced with reasonable differentials to NYMEX Henry Hub. Our longer-term view for Henry Hub is a range between $3 and $5, with short periods above or below. That view is constructive for our business: those price levels support strong free cash flow and earnings, and as capital efficiency improves, that generates more cash flow.

Certainly volatile. My follow-up is on maximizing Gulf Coast exposure and any opportunities to secure more firm takeaway into premium end markets. How big could this opportunity be over the next couple of years?

We've been focused for several years on expanding takeaway capacity via firm transportation to premium markets. When we quantified the strength of the Utica resource, it was clear we needed to protect our pathway to growth by securing firm transport. We recently gained access to 50 million cubic feet per day to the Gulf Coast, and during the quarter we executed another 50 million per day contract along the same route that will come into service over the next few years, giving us roughly 100 million per day to the Gulf over time. Our overall firm transport portfolio is balanced across Gulf Coast, Mid-Atlantic markets and premium Pennsylvania markets where power generation demand is strong. We also have the Tioga Pathway and EGT Project Stratum coming into service. Over the next several years we expect total firm transport capacity to grow about 50% to more than 1.5 Bcf per day. We've made huge strides and will continue to look for opportunities to expand capacity to premium markets as they arise.

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

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.

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