Hello, and welcome to the National Fuel Gas Company Q2 Fiscal 2025 Earnings Conference Call. My name is Alex, and I'll be coordinating the call today. I’ll now hand it over to your host, Natalie Fischer, Director of Investor Relations. Please go ahead.

Thank you, Alex, 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 2025 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 would 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 great second quarter with earnings increasing more than 30% compared to last year. We continue to build on our positive momentum across each of our businesses, which drove the strong results for the quarter. At Seneca, we continue to see outstanding well results from our Utica program in Elliott County. Since the start of the fiscal year, we’ve brought online 12 wells across two pads. These wells are the best we’ve turned in line since the inception of our Utica program and were the main contributor to our 8% sequential growth in production. Also, as we mentioned last quarter, we recently brought online our best WDA Utica pad to date, and those wells continue to exceed our initial expectations. Given the performance of these wells, we are increasingly confident in the long-term outlook of our Appalachian development program. We have great inventory across the EDA and WDA with two decades of development locations that are economic at NYMEX prices below $2.25 an MMBtu. As we continue to optimize our well-designed facilities, we expect further enhancements in both productivity and inventory life. Add to that the benefits of owning and operating our gathering facilities, and we see the ability to deliver still further improvements in capital efficiency. Switching to our regulated businesses, our utility had a particularly good quarter with earnings per share increasing by $0.22. The biggest driver behind the increase was the rate settlement approved by the New York PSC in December. This settlement will be a tailwind for the remainder of this year and given its multiyear nature will drive additional earnings growth through fiscal 2027. In Pennsylvania, we’re starting to see the initial uplift from our modernization tracker. While the impact in the second quarter was small, we expect this to grow over the next two fiscal years until we hit the approximately $7 million annual cap on that program. In our FERC regulated pipeline and storage business, Supply Corporation’s 2024 rate settlement continues to benefit earnings. Rates went into effect last February, so this quarter reflects the full benefit of that rate increase. At Empire Pipeline, in January, we reached an agreement with our shippers to amend our 2019 rate settlement. As you may recall, we had a mandatory comeback provision in that settlement that required us to file a rate case by May one of this year. We began conversations with our shippers in the fall and were able to reach an agreement, which FERC approved this quarter. This is a good outcome for both us and our shippers. We agreed to a modest roughly $500,000 rate decrease, which will go into effect in November. In exchange, we were able to extend some key contracts with major shippers, which limits near-term re-contracting risk. The settlement also gives us the ability to stay out of a rate case for another six years, but we are allowed to file as early as 2027 should we need to. Separately, we continue to make progress on our Tioga Pathway Project. As a reminder, this project will provide Seneca with an outlet for 190 million a day of Tioga County production and will add $15 million in annual expansion revenue for our pipeline business. In February, FERC issued its environmental assessment of the project with no significant issues noted. The project’s next milestone is the 7C certificate, which is still on track for later this summer. Over the past three months, sentiment in Washington has clearly shifted towards more practical energy solutions. Many of the executive orders and early actions at agencies like EPA, DOE and others have certainly been encouraging. But at the end of the day, building significant energy infrastructure projects still takes far too long and carries substantial regulatory and litigation risk. And it’s not just natural gas facilities. Wind, solar, and electric transmission projects all face similar hurdles. I’m hopeful the new administration will work with Congress to achieve the permitting reform that’s so desperately needed in this country. Moving to the broader pricing environment, the outlook for natural gas remains strong with demand increasing rapidly. The industry has line of sight on significant LNG export growth over the next few years and still further growth potential beyond that. The Woodside announcement earlier this week of reaching FID on their $17.5 million Louisiana LNG project is a strong indication the LNG growth story is not over. In addition, domestic energy demand is robust with positive momentum from data centers, industrial growth, and the ongoing electrification of certain parts of the economy. As it’s becoming increasingly obvious, this demand growth can’t be met with renewables alone. Natural gas and its ability to provide reliable, cost-effective baseload generation is critical to meet the growing demand for energy. National Fuel, with our integrated mix of businesses, is well positioned to play an important role in meeting this growing demand. Seneca has clear visibility on incremental firm sales and additional pipeline takeaway capacity that should allow it to continue growing production. We are in the unique position of high grading our development while other operators are moving down the inventory quality spectrum or focusing on other basins. This should naturally lead to a moderation of activity levels in Appalachia and allow Seneca to capture market share, particularly with capacity originating in the EDA. We also continue to see growing interest from data center developers and IPPs that seek reliable, cost-effective energy and timeliness to market. The depth of resource, cooler weather, and the significant amount of existing pipeline infrastructure makes Appalachia an attractive place for the next wave of data center development. National Fuel is uniquely positioned to offer solutions to meet this growing demand. Whether it’s utilizing our existing pipeline infrastructure to provide transportation capacity, building a short lateral to bring gas to an IPP, or contracting for a long-term gas supply agreement, we are seeing increased desires from counterparties to work with National Fuel to meet their needs. While a lot of these conversations are still in the early stages, they are ramping up, and we are optimistic they will lead to new opportunities for us in the coming years. Putting it all together, National Fuel’s underlying fundamentals remain very strong and position us well to deliver continued value to shareholders. Our deep inventory of economic wells, low-cost operations, and the strong outlook for natural gas prices should deliver continued growth at Seneca and NFG Midstream. At the same time, we expect the ongoing expansion and modernization of our pipeline and utility infrastructure to provide rate base and earnings growth in our regulated subsidiaries, all of which should drive significant free cash flow generation in fiscal 2025 and beyond. With that, I’ll turn the call over to Tim.

Thanks, Dave, and good morning, everyone. Across the company, we are continuing our track record of strong execution. Combine that with the tailwind of higher natural gas prices and adjusted operating results increased 32% for the quarter. David on the high points, so I’ll focus on the outlook for the business. Starting with natural gas prices, we have seen a structural improvement since the beginning of the year. With colder than normal weather, along with a faster than expected ramp in LNG export demand, we saw storage levels shift from a 5% surplus to a 10% deficit compared to the five-year average. With the evolving supply demand fundamentals, we saw an opportunity to layer in a number of favorable hedges. Specifically, for fiscal '26 and '27, we added 76 Bcf of swaps and collars. Our swaps were executed at an average price of over $4 while our collars had an average floor of $4 and an average cap of $5.50. These hedges are in the money today and if prices were to run, we retain significant upside exposure to our portfolio of collars and unhedged production. Turning to earnings guidance, we continue to use a NYMEX price of $3.50 per MMBtu as our base case assumption for the remainder of the year. At this price level, our guidance for adjusted operating results is now in a range of $6.75 to $7.05 per share. At the midpoint, this represents a $0.15 per share increase from our prior guidance. Higher natural gas prices during the second quarter combined with the approved cost structure outlook are the main contributors to this increase, partially offsetting these is an expectation for increasing basis differentials. While the forward markets are projecting this widening, we are optimistic that increased regional power generation demand and lower storage levels, particularly in the East Region, which sit at 27% below last year’s levels, will provide support and lead to tighter basis differentials as the summer cooling season arrives. Given the potential for continued volatility, we’ve provided earnings per share guidance ranges at various NYMEX gas prices. Switching to capital, we are holding our guidance ranges the same as last quarter. We are seeing some tailwinds across the company, but given that we are just moving into the warmer weather months and increasing levels of capital spend activity, we will wait until next quarter to provide an update. One other item I wanted to address on the cost side relates to global tariffs. To date, we are seeing a minimal effect from both U.S. tariffs on imports and related retaliatory tariffs. We’ve been proactive in procuring critical equipment to have certainty of supply and maintain a stable cost structure throughout the course of the year. Further, almost all our steel products are produced domestically. While certain larger items such as engines used in our compressor packages are manufactured in Canada, those needed for near-term development in our gathering business are already stateside. We are seeing some indirect cost increases in certain other goods and materials that have components manufactured internationally. But in aggregate, these increases have been very modest. On the revenue side of the equation, the recent tariff activity is not impacting us. All our gas is sold domestically, typically under firm sales agreements where title is transferred at the interconnect between our gathering system and the interstate pipelines. Where we could see a modest impact is if Canada were to impose retaliatory tariffs on energy, which has not yet occurred. Although Seneca does not have any contractual arrangements in place to physically transport gas into Canada, a limited portion of Seneca’s production is sold through marketing counterparties, approximately 5%, which may be exposed to Canadian tariffs. Switching gears, you’ll note that we pulled back the pace of repurchases during the quarter. While we remain highly confident in the outlook for the business, we deemed it prudent to reduce our buyback activity amid the broader macroeconomic uncertainty. As things stabilize, we plan to resume our prior cadence such that we are targeting to complete the original $200 million authorization by the end of calendar 2025. With our balance sheet on a path towards 2x debt to EBITDA by the end of the year and the outlook for free cash flow remaining strong, we are in a great position to return to buying back shares and retain significant flexibility on our capital allocation strategy going forward. We also took a big step to reduce near-term refinancing risk. Taking advantage of a strong execution window and with an eye toward removing the risk of increasing economic volatility, in February, we issued $1 billion in new notes, split evenly across five and ten-year tranches. This was the largest bond issuance in the company’s history and with strong demand, our issuance was nearly seven times oversubscribed. We achieved record low credit spreads for National Fuel debt. More importantly, this managed all our fixed income liabilities through early next year. Also, ahead of this transaction, we discharged our legacy 1974 indenture and are no longer subject to those covenants. In summary, National Fuel’s outlook is exceptionally strong. The supply and demand fundamentals are driving a constructive long-term outlook for natural gas prices. We are also seeing strong capital efficiency tailwinds in our non-regulated businesses and strong earnings growth potential in our regulated businesses. We expect both of those trends to continue for the foreseeable future, driving growing free cash flow. Our balance sheet is already in great shape and with key refinancings behind us, we are in a position to deploy this free cash flow in the most opportunistic way to create value for our shareholders. With that, I’ll turn the call over to Justin.

Thanks, Tim, and good morning, everyone. Positive momentum at Seneca and NFG Midstream continued in the second quarter with record production and throughput. Production increased 8% from the prior quarter to almost 106 Bcf, which helped drive all-time high gathering volumes of nearly 130 Bcf. Our EDA focused development program, strong operational planning and execution, and enhanced well designs are driving significant capital efficiency gains. The performance of recent Utica pads incorporating our Gen three ell design has been our best to date, both in terms of initial production rates and EURs. In aggregate, these two pads are producing 300 million per day, which is the same rate I noted three months ago on our last earnings call. The most recent pad achieved $495 million to $550 million. As planned, we recently picked up a second rig and commenced seasonal construction activities, building roads, pads, and infrastructure projects, which will increase our level of spending in the second half of the year. Longer term, we intend to maintain a one to two rig development program and dedicated frac spread. Turning to the outlook for natural gas prices, we believe that supply and demand fundamentals remain firmly supportive of our development plans, particularly as we look out to 2026. Demand has been strong year to date with record natural gas-fired power generation and a faster than expected ramp-up in LNG feed gas volumes. On the supply side, overall levels of gas production have moved up slightly, likely due to producers turning in line remaining DUCs and deferred drills to capture strong winter demand and pricing. As this flush production rolls over, we anticipate flat or even declining production in the coming months. That trend, combined with the potential for decreased associated gas growth from the Permian Basin due to low oil prices, sets the stage for a bullish gas market as we approach next winter. Overall, we are well positioned both physically and financially for this backdrop. Financially, we have an excellent portfolio of swaps, fixed price deals, and collars stretching out across the remainder of fiscal '25 and into fiscal '26 and beyond. These instruments provide us with appropriate downside protection allowing us to capture significant upside should our bullish gas thesis prove accurate. On the physical side, almost 90% of Seneca’s remaining expected fiscal 2025 production is secured through firm sales and firm transportation. These agreements provide access to premium markets as well as mitigate exposure to in-basin pricing fluctuations. Pivoting to NFG Midstream, we continue to grow Seneca gathered volumes and plan for new third-party production. As Seneca’s EDA production ramps, NFG Midstream is expanding existing stations and building centralized facilities at multiple locations to enable future growth. For example, we recently began the installation of compression at our Keeneyville facility in Northwest Tioga County to support current producing wells and we also commenced engineering design to accommodate Seneca’s increasing well productivity and deliverability. Turning to our third-party activity, I’m pleased to share that we recently executed a new interconnect agreement with a Tioga County producer. While our primary focus in energy midstream is to serve Seneca’s increasing production volumes, we remain engaged with third-party shippers to leverage and more fully utilize our significant gathering infrastructure and associated facilities. In closing, our focus on operational excellence and continued capital efficiency gains is yielding outstanding results. Amongst our peers, Seneca stands out as one of the few companies poised to achieve both increasing production and decreasing capital over the three-year period ended in 2025. We expect this positive capital efficiency trajectory, growing production while driving capital lower, will continue beyond fiscal '25 as we develop our Gen 3 Tioga Utica wells and pursue operational efficiencies. This trend, combined with our unique integrated business model and more decades of inventory at PV-ten breakeven prices below $2.25 NYMEX, position Seneca and NFG Midstream extremely well to thrive in the years to come. With that, I’ll ask the operator to open the line for questions.

Our first question for today comes from Zach Parham of JPMorgan. Your line is now open. Please go ahead.

First, could you talk a little bit more about how you’re thinking about the buyback? The stock’s been very strong year to date, both absolute and relative. It’s hit new all-time highs. How does stock price factor in? How you’re thinking about buying back shares? And I know you moved back the target date by a quarter here. But if the stock remains strong, do you think about pushing out the buyback even further?

I don’t see any change in our thinking right now about our buyback program. I mean, price is a factor, but overall, when we look at capital allocation, once our balance sheet is in the place we want it to be, which it is, our first preference is going to be to grow the company either organically or through M&A. But absent that, our plan would be to return capital to shareholders. So we’re still committed to this buyback program. As you point out, it can take a couple of months longer to get it done, but we fully intend to.

My follow-up, I just wanted to ask about infrastructure build in general. I mean, there’s been some rumblings out there about the Constitution pipeline potentially coming back. Any thoughts on if that pipe could happen? And maybe just your broader thoughts on what the new administration could do to encourage more pipes to get built out of Appalachia to get more gas out of the basin?

With respect to Constitution, I think the biggest roadblock there is New York State, much more so than the market or FERC or anything. So we’ll see where that goes, but I think it would change it would require a big change in thinking out of New York to get that one over the finish line. In terms of what the new administration could do, to me, the two biggies would be tackling the Clean Water Act and sort of doing away with or preventing the states from using it in the ways that they have over the years, whether it’s with respect to the Constitution or what they tried to do with our Northern Access project. And then looking at the judicial review process to try to get it so that projects don’t stretch out so long and have as much litigation and delays.

Our next question comes from Noah Hungness of Bank of America. Your line is now open. Please go ahead.

Justin, I think I have two questions for you. The first one here is, could you maybe give us some additional color on what leading edge EUR per 1,000 foot is for the recent EDA tills that you all have seen? And if the wells haven’t been flowing long enough to give us to have an EUR in mind, maybe could you just talk about the pressure declines that you have seen?

Yes, sure, Noah. Thanks. We’ve got now a number of tightly spaced Utica pads online, but only really the last one to two pads where we’ve kind of been employing fully and had a chance to see this M3 design and what it can deliver. I mean, the punch line is last quarter I spoke about EUR moving up to an expectation of 2.5 Bcf per 1,000 feet. Certainly, the productivity we’re seeing out of these wells and it is early. We’re kind of maybe five to six months on one of the pads and maybe closer to four to three to four on the other one. So we have data. We have good history. The pressure declines are exceeding our expectations. The pressure drop is low. I just spoke about the fact that we expect to see a number of these wells maintain sustained rates at 25 million to 30 million a day for nine to 12 months. So that kind of informs what that means from a productivity perspective. So the bias right now is upside to the EUR, but we feel really good about what we put out to date and we feel really good about what we’re seeing out of these wells. I’ll have more color and more commentary in the coming quarters as we have more data.

And then for my second question, the Gen 3 well design seems to be a success here. But, could we see like a Gen 4 design? And if so, could you maybe talk a little bit on what that looks like?

Sure. So definitely, we’ve made an evolution. I think where we’ve arrived at was probably with the Gen 3 design has been a big step forward for us. We’ve already begun the process of testing certain variables that would be an expansion, if you will, upon the Gen 3 design. So kind of alluding to that Gen 4 or Gen 3 plus whatever you want to call it for now. The punch line is the places where I think we’ll potentially find the most gains are going to be related to continued adjustments on the inner well spacing and then profit loading, looking to test completions that are larger than the 2,200 pound design and whether that’s stepping up to more like 3,000 or even 3,700, 3,800 pounds per foot. We think that there’s an opportunity. We’re kind of in a spot where we’ve got a very prolific resource, a lot of gas in place and we’re looking for the right kind of mix of invested capital to drive productivity, but also balancing kind of the sweet spot between the returns you’re getting as you deploy more capital into a more intensive design. So I think we’re striving towards that. I think we’re making great gains with the team looking at that. I do think as time goes on, we will be talking about some additional tweaks to our overall well design.

Our next question comes from Greta Drefke of Goldman Sachs. Your line is now open. Please go ahead.

I was wondering if you could speak to your views on current outlook for growing in basin demand where conversations currently sit on power-related agreements and what components of your integrated business model have you found to be the most attractive for potential counterparties?

Well, I’ll hit the first one and then Dave or Tim may hit on a little bit of the second there. But just as it relates to kind of the opportunity for more in-basin demand, I would talk about a couple of things. One that we’ve been speaking to and have seen success with is almost more about the opportunity for other producers maybe investing less capital and that kind of frees up capacity for us to fill. And whether that’s through taking new firm transport that’s been released or restructured, whether that’s through new firm sales with counterparties or just purely attrition. The backdrop to that, the positive against even that kind of attrition we’ve spoken to is the corollary to more in-basin demand. It’s absolute that there are opportunities to see continued growth, more industrial development and frankly just running the existing power generation assets that are in the basin today, they could run harder and increase the capacity or the throughput going into those plants and put more power out. So we see a lot of kind of, I’ll call it, green shoots and tailwinds as it relates to how we’re able to continue to grow our production. And we have a lot of different avenues on that and then continue to see continued in-basin demand incrementally happening over the coming months and years.

I’d add to the second part of your question, but it’s likely the pipeline business that’s, call it, the lowest hanging fruit. A lot of these hyperscalers and developers are really value-seeking to market. And so to the extent we can provide a pipeline solution in a timely way is likely the nearest term type opportunities.

And then for my second question, I’m just wondering how you would characterize the outlook for regulated M&A at this point in time? In the current macro environment, does your disposition towards or the opportunity set for acquisitions change meaningfully or if at all?

Yes. It’s something we’re still focused on. I’d like to gain scale across the business. And I think the regulated side of the business is the place to do it. That’s not to rule out upstream M&A, but I think that would be more of a focus on bolt-on type acquisitions as we’ve done in the past. And I guess I won’t comment on any specific assets that may or may not come to market, but we’ll just leave with you that we’re still interested in it and are optimistic things will come to market that will be a good fit for us.

Our next question comes from John Freeman of Raymond James. Your line is now open. Please go ahead.

You all had an active and consistent hedging program for years, I realize that’s just part of the DNA of the company. And I think, Justin, when you were sort of outlining your bullish outlook on gas, which we obviously share, I’m curious if that constructive outlook would potentially have you all move maybe directionally more toward collars versus swaps in the future to kind of give you the opportunity to realize maybe more upside?

Yes, I think you’re absolutely right. We’re constructive, but philosophically, we’re still big believers in hedges. But given where our balance sheet sits today, we definitely would skew more towards collars as long as there is skew available on those collars where it makes sense. A great example is the collars we put on over the last few months here with $4 floors and $5.50 average caps. Those are sort of no-brainer hedges in our mind, where we protect the downside at a really fantastic price but retain meaningful upside in case the strip runs. So I don’t see us changing our hedging philosophy, but definitely skewing more towards collars, especially once we have the baseload layer of hedges on that give us that downside protection.

And then my follow-up question, you slightly lowered the utility O&M expense guidance for the full year. And you’ve got a slide in the back of the presentation that kind of goes through the moving parts. So you’ve got the higher personnel costs and then being offset by some of the rate case adjustments. And I did see that that O&M expense went up during the quarter. So I’m just trying to understand maybe the moving parts involved, maybe the lag effect of some of the rate case adjustments on what sort of drove the full year guide lower?

I think it’s just as we go through the year, we’re very good, and you’ve probably seen this historically, in terms of keeping our cost structure down at the utility business and the pipeline business, really frankly across the company. And so we moved the O&M guidance down a little bit. And while the slide references O&M increases, that’s year-over-year increases. So some of those actually are tailwinds relative to our original guidance outlook for the business. But this is just something you should expect from us over time is the continued focus on maintaining costs, especially once we have set rates. It’s really important for us to maintain that cost structure so that we can earn an acceptable return in that business.

Our next question comes from Geoff Jay of Daniel Energy Partners. Your line is now open. Please go ahead.

Just curious about how you think about CapEx cadence beyond 2025. Obviously, your well productivity is improving as you move into the ADA more. But there are also some puts and takes, it seems to me, where if you do increase profit, maybe that adds to costs. And not sure kind of where you think you are in terms of gaining even more efficiencies. Kind of just curious if sort of a baseline expectation as to sort of say flattish from here 2026 and beyond, barring any changes.

Yes. Thanks, Geoff. I want to I had some information here in my prepared remarks also to kind of at least point toward the trends that we see. But look from '23 to the midpoint of guidance at '25, we will have taken capital down from $588 million to $505 million. So we’ve made a dramatic decrease. I anticipate fully anticipate that as we move forward into '26, '27, et cetera, we will find additional ways to drive that lower. The rate of change may shallow some, but we fully expect we will be able to move capital downward. The investments we would make related to say an enhanced well design would also lead to enhanced well productivity. And so we wouldn’t be making those if we weren’t seeing that. And we would expect that to show through with perhaps you need less wells or less activity to achieve the same level of production growth. So we’re very much this trend is not a two, three-year trend for us. This is a multiyear trend that should extend beyond ’25 and ’26 plus. And you should anticipate continued gains in terms of reductions of capital and kind of that mid-single-digit production growth that we’ve been on over the last three years. We see that continuing over the next few years.

And then just as a follow-up on the LOE side, are those improvements largely a function of better-than-expected volumes or is there something else going on there?

I would say it’s really cost, just a detailed cost focus. The team kind of has done a pretty deep dive relook at all the areas where we’re investing money across the, I’ll call it the controllable element of our LOE. Since so much of LOE we’re just paying to our sister company and a fee midstream. But of the controllable piece, they’ve done a great job of looking for areas where we can minimize those expenses. And so the beat we had here in kind of the first half of the year is translating to our ability to bring down the full year guidance. And then just overall, I mean, there is some seasonality to the work we do. We certainly have we'll do more work over and well repair work and maintenance work during summer months when the weather is more favorable for some of those activities.

Our next question comes from Timothy Winter of Gabelli. Your line is now open. Please go ahead.

I have two questions. First, Dave, I was wondering if you could clarify that I heard you correctly that on the M&A focus, it’s going to be more on regulated bolt-ons. Is that what you said? And does that mean pipes? Or does that mean regulated utilities?

No, the bolt-on was in reference to the E&P side of the business. On the regulated side, we’d be thinking bigger than just bolt-on. LDCs would be the most likely candidate.

And then just big picture, talking more, I guess, the state of Pennsylvania than nationally. I’m curious what the long-term infrastructure potential is of the state? I’m listening to conference calls, PPL yesterday, talking about 50 gigawatts of data centers in its service area and tremendous over in Ohio as well. What is the long-term infrastructure potential of the state to serve that kind of demand both from a pipe network? And I forgot to mention Homer City gas plant, 3.5 gigawatts also being developed. Is the infrastructure there to support all of this?

Yes, I think to an extent. But certainly, if the amount of generation that’s being contemplated gets built, we’re going to need more of it. I think that Pennsylvania is obviously a pro-energy state. And so I don’t think you’d see the hurdles to getting that built that you would in other states. But the potential is certainly there. We’ll just see how it plays out.

At this time, we currently have no further questions. So I’ll hand back to Natalie Fischer for any further remarks.

Thank you, Alex. We’d like to thank everyone for taking the time to be with us today. A replay of this call will be available this afternoon on both our website and by telephone and will run through the close of business on Thursday, May 8. 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.

Thank you all for joining today’s call. You may now disconnect your lines.