National Fuel Gas Company [NFG] Conference call transcript for 2021 q4
2022-02-04 15:57:05
Fiscal: 2022 q1
Operator: Good day. Thank you for standing by, and welcome to the First Quarter 2022 National Fuel Gas Company Earnings Conference Call. At this time all participants are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. Please be advised that today's conference is being recorded. I would now like to hand the conference over to Brandon Haspett, Director of Investor Relations. Thank you. Please go ahead.
Brandon Haspett: Thank you, Blue, 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; Karen Camiolo, Treasurer and Principal Financial Officer; and Justin Loweth, President of Seneca Resources. At the end of the prepared remarks, we will open the discussion to questions. The first quarter fiscal 2022 earnings release and February 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.
Dave Bauer: Thank you, Brandon, and good morning, everyone. National Fuel had an excellent start to the fiscal year with adjusted operating results of $1.48 per share, an increase of 40% from last year. Higher commodity prices and an increase in Appalachia natural gas production drove the strong results. On the production side, we leveraged our integrated upstream and gathering operations to bring several wells online a few weeks earlier than our initial expectations, which allowed us to take advantage of the strong pricing at the start of the winter. This is largely a matter of timing. Moving the pads forward in the schedule does not have a material impact on our overall production expectations for the year. However, capturing higher prices at peak initial production rates obviously enhances the return profile for those wells. As noted in last night's press release, at the midpoint, we're increasing Seneca's fiscal 2022 capital spending guidance by about $38 million or 9%. Roughly half of that increase is driven by incremental cost inflation beyond what was included in our initial guidance range. This should come as no surprise given the persistent supply chain issues across the economy. The other half is incremental capital designed to further optimize the production from our two rig program, which we think is a good use of capital given the strength of natural gas prices and the depth of our drilling inventory. In particular, we plan to more frequently incorporate a top hole rig in our operations, which allows us to reduce drilling time and complete a few more wells each year. We also plan to use tighter stage spacing on a number of wells throughout the year. Obviously, this isn't a step change in activity level, but it should improve our growth rate going forward. We've previously talked about maintenance to low growth at Seneca, but with these tweaks to our development approach, we now expect the growth trajectory in the mid to high single digits area, on average, over the next few years, which should enhance our cash flow generation at not just Seneca, but also our gathering business. Justin will provide more details on Seneca's updated production and capital plans later on the call. Turning to our Pipeline and Storage business. In December, we placed our FM100 project in service on time and substantially under budget. Total project costs are expected to be $230 million, more than 15% under our initial cost estimate of $280 million. As I've said in the past, this project in conjunction with Transco's companion Leidy South project provides a great outlet for 330 million a day of Seneca's production and is the perfect example of the benefit of our integrated business model. FM100 was the largest project in our company's history and wouldn't have been possible without the hard work and dedication of the many employees and contractors who worked on it. And I'd like to say thank you to everyone who made it a reality. Looking to the remainder of fiscal 2022 and into fiscal 2023, our focus on our regulated pipeline business will be on system maintenance and modernization. On an annual basis, we expect to spend about $50 million on maintenance and another $25 million to $50 million per year on average on modernization efforts, including our emission reduction initiatives. At this level, I expect rate base will grow modestly, stay in the low single-digit area. However, at this level of spending, we do expect significant free cash flow from this business in the $100 million per year area on average. We will continue to pursue expansions of our system though in the near term those will likely be the smaller variety on our Line N and Empire systems. The anti-natural gas sentiment of the current administrations in Albany, D.C. and elsewhere is certainly making larger-scale expansion projects challenging. But I firmly believe new pipeline infrastructure will be needed if the country is serious about achieving its emission reduction goals. All too often, policymakers pass up actionable projects that can make a real difference today. There are dozens of electric plants in the Midwest that use coal and millions of homes and buildings in the Northeast that heat with fuel oil, all of which could be easily converted to natural gas. And doing so would not just lower emissions by 30% to 50%, but would also reduce energy bills. Investing in natural gas infrastructure would also improve electric reliability. Many believe we ought to electrify everything, but adding electric demand, while under investing in baseload generation and hoping intermittent renewables will be there to save the day, is slowly eroding the reliability of the electric grid. The European Union, which is several years ahead of the U.S. in its efforts to decarbonize its economy, clearly recognizes the importance of natural gas. So much so that it's committing to new pipelines and even proposing to add natural gas to its taxonomy of "green energy." I'm optimistic the U.S. will one day reach that same conclusion. And when it does, National Fuel and the rest of the pipeline industry will be there to build the much needed infrastructure. Moving on to our Utility business. The weather in the first quarter was warmer than it's been in quite a while, 24% warmer than normal. But January has been a different story with weather that's been significantly colder than ever – than normal. Nevertheless, despite the recent bout of cold weather on balance we expect the full year will be warmer than normal, which will cause our utility margin in Pennsylvania to be a little lower than was reflected in our prior guidance. On the cost side of things, like many companies and industries, we are seeing some general inflationary pressures. Costs for materials and services, including contractors, are all contributing to higher-than-anticipated costs at our utility and pipeline businesses. We now expect O&M costs at those operations will be about 4% to 5% higher compared to last year. We expect to see similar increases in the cost of our capital projects. Labor shortages have plagued the broader economy, but our team has done a great job lining up contractors, and as such, we don't have any concerns with our planned construction schedules. Switching gears. Most of you know that New York State has enacted significant climate legislation with its Climate Leadership and Community Protection Act that was passed in 2019. This past December, the Climate Action Council published for comments a draft scoping plan that describes how the state will go about achieving its aggressive emission reduction goals. The full document, including exhibits, totals about 800 pages, but the message can be summed up rather succinctly: electrify everything at any cost, transportation, heating, cooking, commercial and industrial processes, all of it. Putting aside the cost to consumers, which is an incredibly important consideration that the draft scoping plan largely ignores, what's particularly concerning is the recommendation to begin phasing out affordable, reliable fuels like natural gas, almost immediately, well before the grid itself is green and more importantly, well before it's clear that the electric grid can actually support the added electric demand that would result. The scoping plan readily acknowledges that even after an unprecedented build-out of renewable generation and battery storage, by 2040, there still remains a shortfall of 15 to 25 gigawatts of peak day generation that cannot be met with existing renewable technology. And that is a startling amount of generation. It's greater than the total amount of electricity that's being generated in the state as we speak today. If we electrify all of the state's heating load, the electric peak day will almost certainly shift to the winter. So it's almost certain that the shortfall in generation would occur when we need it the most, on the coldest days of the winter. In a state where winners can be brutal, especially in our service territory where peak day temperatures can be 50% colder than downstate New York, it makes little sense to put all our energy eggs in one basket, particularly if there are holes in that basket that need to be plugged in order to ensure reliability. Perhaps one day, the holes will be filled, but in the meantime, and all of the above emissions reduction strategy like the one we proposed in our pathways to a low carbon future report makes a lot more sense. Through a combination of energy efficiency, selective electrification, hybrid heating solution and the deployment of low and no carbon fuels like green hydrogen and renewable natural gas, we can leverage existing utility infrastructure to achieve significant decarbonization that meets – that not only meets the state's emissions goals, but also preserves access to low-cost, reliable and resilient energy for consumers. In closing, the underlying fundamentals of National Fuel are very strong. Our deep inventory of economic wells, low-cost operations and strong outlook for natural gas prices, positioning us to deliver continued growth at Seneca and Energy Midstream. At the same time, the completion of FM100 and ongoing modernization of our infrastructure will provide rate base and earnings growth in our regulated subsidiaries, all of which will lead to significant free cash flow generation in fiscal 2022 and beyond. With that, I'll turn the call over to Justin.
Justin Loweth: Thanks, Dave, and good morning, everyone. Seneca kicked off fiscal 2022 with a strong first quarter. The start-up of our 330 million per day of capacity on the Leidy South project provides a valuable long-term outlet for our Appalachian production. With good visibility on project timing, we began ramping up completion activity last year, allowing us to turn in line 24 new wells during the quarter, nearly all of which came online earlier than projected. In addition, operational curtailments came in lower than forecasted as our team found innovative ways to keep our gas flowing. For example, we were able to avoid shut-ins during station maintenance using temporary compression and bypass loops. This truly coordinated effort between our upstream and gathering teams, allowed us to maximize production and enhance returns during the time of very favorable pricing. These efforts drove production to 85 Bcfe for the quarter, a 7% increase sequentially and allowed us to maximize the value of our Leidy South capacity from day one. With our growing base of production, we remain focused on reducing risk while retaining upside through optimization of our marketing and hedging portfolio. Our focus over the past few months has been on layering in financial hedges for the near-term while adding firm sales, mostly fixed price, over the longer term. Given recent natural gas price volatility and favorable SKU, our hedging strategy included adding 75 Bcf of costless collars with floors of $3.20, mostly targeting our fiscal 2023 and 2024 production. We've also added roughly 75 Bcf of long-term fixed price firm sales contracts for fiscal 2024 and well beyond, bolstering our existing firm transportation portfolio and locking in strong economics as we move towards modest growth. Regarding our overall activity levels, as Dave mentioned, we're maintaining our two rig program, but have increased our top-hole rig work, allowing us to accelerate development within our Tioga acreage and further enhancing expected consolidated returns. Our top-hole rig program will reduce drill times by 3 to 5 days per well, allowing us to drill and complete more wells per year while also lowering our drilling costs on a per foot basis. We are also planning enhanced completion designs for some of our pads, tightening stage spacing from 200 feet to 150 feet. This incremental investment generates extremely attractive returns at payback in a matter of months. Overall, these activities further optimize our development program, increasing our ability to generate long-term sustainable free cash flow. The additional top-hole rig activity and completion enhancements are expected to drive roughly half of our fiscal 2022 capital increase, and we expect to see the majority of the production benefit in fiscal 2023 with growth in the 10% area compared to this year's forecasted production. Also driving our capital guidance modestly higher is inflation. We talked previously about overall inflation in the context of mid to high single digits, which we expected to largely mitigate through operational efficiencies. While we are fully realizing those efficiencies, costs for certain services and materials have risen beyond our prior estimates and our continuing headwind. We now expect our overall drilling and completion expenses to be up 10% to 15% from the prior year, though our operational efficiencies reduce this impact to the mid to high single digits. While we've locked in our rigs for longer-term contracts, costs for labor, trucking, completion spreads and certain materials like tubulars are still rising. Despite these challenges, our procurement team has done a tremendous job tempering cost increases where possible in ensuring we have material and service availability to keep our operations on schedule. Putting these items together, we've increased the midpoint of our capital guidance by $37.5 million to a range of $425 million to $500 million. Moving to production cadence for the remainder of fiscal 2022, the bulk of our new wells coming online are scheduled for the spring. As a result, we expect our fiscal second quarter to be relatively flat to slightly up compared to the first quarter. From there, output is expected to ramp into the third quarter and then level out just shy of 1 Bcfe per day. We've modestly increased our production guidance to a range of 340 to 365 Bcfe to account for this revised cadence and incorporating the strong results of our first quarter. At the midpoint of our updated guidance, we have hedges and fixed-price firm sales in place for nearly 80% of our expected remaining fiscal 2022 natural gas production. We have another 13% with basis protection that is not hedged, which leaves less than 10% of expected production exposed to in-basin pricing. We've been opportunistic with our marketing portfolio over the past few months when prices rally, locking in favorable basis differentials and creating price end at great prices. As I discussed last quarter, we've adjusted our development plans to increase activity within our Tioga County footprint. We recently brought online a four well Utica pad in Tract 007, which included laterals that extended into the acquired acreage. Our newly combined contiguous acreage position allowed us to optimize our well spacing and lateral lengths and the results speak for themselves. This pad has been producing at almost 80 million a day since late November. We have two additional development pads in Tioga expected to come online this spring: a five well Utica pad in the Northwest and a six well Marcellus pad in the Southeast. Developing these pads, including modifications to existing gathering infrastructure, less than 18 months after we closed the acquisition is a testament to the outstanding job our upstream and gathering teams are doing. And we have well over a decade of development running room on this prolific acreage. While our operations are moving along really well, we've also taken great strides in our sustainability initiatives. Starting with our California operations, our new South Midway Sunset solar plant is expected to go in service very soon and will offset 30% of the field's power needs. We are also moving full speed ahead with a new plant at South Lost Hills and target in-service later this year. And our team has adjusted and refocused our steaming operations, resulting in approximately 15% less steam fuel consumption with dual benefits of lower LOE and reduced CO2 emissions with minimal impact to production, a true win-win. Moving to our Pennsylvania sustainability efforts. Earlier this month, we achieved certification of 100% of our Appalachian production under Equitable Origin's EO100 Standard for Responsible Energy Development. As a reminder, this framework has a series of rigorous environmental, social and governance performance targets. Achieving certification is a validation of our longstanding culture of environmental stewardship and community engagement and allows us to differentiate our responsibly sourced gas in the marketplace. Additionally, we are working with Project Canary to certify 121 wells, which produced approximately 300 million per day under the TrustWell certification. In November, we deployed Project Canary continuous monitoring devices on three producing pads, and we expect to complete this certification process in the next few weeks. These efforts with Equitable Origin and Project Canary are not only important to us from a sustainability perspective, but we believe they will also benefit our long-term marketing efforts. In the near-term, we think our responsibly sourced gas designation will give us a competitive advantage and allow us to create value by selling some of our production at a modest premium. Longer term, we think that many buyers, be it utilities or otherwise, will require this certification from producers to meet their own sustainability initiatives. Finally, we've completed our comprehensive emission study on emissions associated with various types of completion equipment. This study done in conjunction with NexTier and U.S. Well Services has two key takeaways. First, it confirmed that increasing utilization of natural gas in place of diesel fuel significantly lowers GHG emissions intensity, with 100% natural gas reciprocating engines being the clear winner of the equipment tested. Second, as we displace more and more diesel consumption with natural gas, the fuel costs of our completions are expected to be substantially lower. For example, moving from 100% diesel to 100% natural gas fuel completions would reduce annual fuel costs by more than 60% for each frac spread. This emission study, along with our assessment of equipment reliability and cost will guide our decision-making going forward. On the heels of this study, we are redoubling our efforts to increase the use of natural gas to fuel our drilling and completion operations. National Fuel is uniquely positioned to do this more efficiently than many of our peers, given our focus on consolidated upstream and gathering development. Our teams have worked in lockstep to accelerate the development of key gathering infrastructure to ensure we can utilize field gas in nearly all of our operations. We will continue seeing the benefit of increased diesel substitution in our overall emissions intensity in the years to come. This is just one of the many examples of the National Fuel team collaborating to stay on the leading edge of emissions reduction initiatives. In closing, as we look out over the next few years, Seneca is in a great position. The completion of Leidy South and execution of additional long-term firm sales contracts supports the next leg of growth for Seneca and gathering. With a strong natural gas price backdrop and additional takeaway capacity, we are moving forward to take advantage of our deep inventory of high-quality acreage by modestly toggling up activity. This added growth, now expected to be in the mid to high single digits over the next several years, enhances our capital efficiency and long-term free cash flow generation. That coupled with our laser focus on sustainability, positions Seneca for continued success. And with that, I'll turn it over to Karen.
Karen Camiolo: Thanks, Justin, and good morning everyone. As Dave mentioned, National Fuel's adjusted operating results for the quarter were $1.48 per share, an increase of 40% from the prior year. The increase was primarily in our E&P and Gathering segments, driven by both higher commodity price realizations and increased Appalachian production. As it relates to the former, tightening supply-demand fundamentals have strengthened commodity prices. As a result, our natural gas price realizations were up 18% from last year, while crude oil realizations were up over 25%. Combining this with a 7% increase in total production, which has a corresponding benefit to our gathering throughput, earnings between these two segments were up $0.43 per share. In our Regulated segment, earnings were flat compared to last year. As FM100 commenced service in December, we started to see the benefit of the project show up in our results, recognizing just under $3 million of revenue during the quarter. As a reminder, the expansion portion of this project is expected to generate annualized revenues of $35 million. In addition, we have a $15 million per year of revenues commencing in April related to the modernization component of the project. At the utility, we continue to see the growing benefits of our system modernization tracker in New York, adding about $1 million to margin during the quarter. Going the other direction was the approximately $2 million impact of warmer weather in our utilities Pennsylvania jurisdiction where we do not have the benefit of a weather normalization clause. Temperatures on average were 8% warmer than last year and 24% warmer than normal in Pennsylvania. As we look to the remainder of the year, we are increasing our earnings guidance to a range of $5.20 to $5.50 per share, an increase of $0.10 per share at the midpoint. There are a couple of key drivers worth noting. First, we are truing up our commodity price assumptions to better align with the current forward strip. Our NYMEX natural gas price has been revised to $4.50 per MMBtu. We previously were guiding to $5.50 from January to March and $3.75 for the last six months of the fiscal year. Pricing has had a healthy dose of volatility as of late. For reference, our earnings will move up by $0.06 for every $0.25 change in pricing for the remainder of the year. We've also moved our WTI price assumption to $80 per barrel, up $5 from our previous guidance, a $5 change in oil impacts earnings by $0.02. The other two notable changes are on the cost side of things. First, at Seneca, we are reducing our LOE guidance by $0.02 per Mcfe, now projecting a range of $0.81 to $0.84. This is largely a function of lower steam fuel costs in California that Justin referenced earlier. On the regulated businesses, Dave discussed some of the inflationary headwinds we are facing. We now expect O&M costs to be up approximately 4% to 5% versus last year. Just to remind everyone, we had a one-time favorable benefit of about $4 million to Pipeline and Storage O&M in fiscal 2021 that will not recur this year. Outside of this dynamic as well as the costs to operate FM100, underlying O&M costs are expected to be up approximately 3.5%. Moving to capital. Given the dynamics Dave and Justin discussed earlier, we have revised our consolidated capital expenditure guidance to a range of $665 million to $810 million, an increase of $37.5 million or 5% at the midpoint. Bringing this all together, the balance sheet is in great shape and our cash flow projections remain strong. We previously discussed funds from operations exceeding capital spending by $300 million to $350 million. In spite of the increase in our capital guidance, we still anticipate being in that range, generating free cash flow well in excess of our dividend. This level of free cash flow will continue to improve our leverage metrics. For the 12 months ended December 2021, we were approximately 2.5x levered from a debt-to-EBITDA perspective. As our EBITDA grows and we continue to generate free cash flow, we expect this to trend closer to 2.25x over the next 12 months. While there are no hard and fast rules with the rating agencies, we are well positioned to work our way toward mid-BBB metrics over the course of the next year or so, depending on how commodity prices play out. In closing, despite the inflationary and weather headwinds, the first quarter was a strong one. National Fuel is projecting to generate meaningful free cash flow, which will further strengthen our investment-grade balance sheet and positions us well for the future. With that, I’ll ask the operator to open the line for questions.
Operator: Thank you. Your first question comes from the line of Zach Parham with JPMorgan. Your line is now open.
Zach Parham: Hey, thanks for taking my question. First off, we’ve seen a delay on a new pipe out of Appalachia and production numbers for the basin seem to climb in year end, Seneca is part of that. I know you all mostly locked in near-term volumes, but just curious on your view on local basis. It looks like you’re assuming $0.85 of NYMEX in your guidance for Appalachia spot, but just any worries on that wide being out further for even the industry potentially getting into a situation where some producers had to shut in volumes similar to what we saw a couple of years ago? Just general thoughts on basis really.
Justin Loweth: Sure, Zach. We have much locked in at least as much of our in-basin exposure as we feel comfortable with. So we’re less than 10% exposed to any sort of massive blowout in basin. And that’s in part with our new Leidy South capacity, and it’s in part due to some of our efforts along marketing to protect that. It’s hard to say exactly what will happen with basis this summer, so it depends where we end, of course, the winter and what storage levels look like, and some of it will depend, frankly, on what other producers are doing. In terms of our overall activity levels, we’re really anticipating production is pretty similar to where we were before at least through this year. Longer term, I think the story is the same. It’s going to depend on how people – how our peers in Appalachia, how they handle their overall production levels if they stick to kind of more the maintenance or if they decide to grow. But what we’ve done is we’ve insulated that risk well beyond 2022. So with our existing firm transport and firm sales portfolio, that gives us a minimal amount of exposure to that in-basin long term because I think we view it as a risk we’re not really willing to take. And as we’ve said consistently, we’re not going to grow just to grow. We want to grow knowing we have a good home for our gas, and that is not in-basin.
Zach Parham: Got it. Thanks for that color. I guess maybe just 1 follow-up. You mentioned in your prepared remarks the RSG certification and potentially getting a premium on some of that gas. Can you talk a little bit about what the market for RSU looks like? And what kind of premium you could potentially get for that gas?
Justin Loweth: Sure. So I’d say it’s – the market is developing. And what we think – we absolutely think we’ll be successful at selling some of our gas at a modest premium. The premium is not going to be nickels, dimes and quarters. It’s more likely pennies. And I think we’re kind of settling in on what the right number is. And just for commercial purposes, I’d rather not speak specifically to that, but at least order of magnitude, that should help guide you on what we’re expecting. We’re definitely seeing a lot of interest. Interestingly, a lot of our gas, we can get it to Canada. And in Canada, they, in particular, are very interested in the Equi-Origin certified gas. So we think there’s a great opportunity for us there as well as into other markets. And we think it will keep developing, particularly at the utility level, as Public Utility Commission get on board with not just asking their utilities to reduce their emissions intensity and move towards sustainability but will allow them to recover the cost of buying RSG from a producer like Seneca. And our hope is that we’ll – that discussion will continue and we’ll ultimately get there in the months and years to come.
Zach Parham: Thanks for the color. That's all for me.
Operator: Your next question comes from the line of Holly Stewart from Scotia Howard Weil. Your line is now open.
Holly Stewart: Good morning, gentlemen, Karen.
Karen Camiolo: Hi.
Dave Bauer: Good morning.
Holly Stewart: Dave, maybe I’ll start off on a bigger picture question because you talked a lot about electrification and the reliability of the overall grid. And it looks like a few weeks ago, a Pennsylvania Senator invited NFG to relocate its headquarters to the state of Pennsylvania versus New York. It’s actually a very interesting move given that New York has made a lot of let’s just say, anti-fossil fuel claims over the last few years. So maybe just curious as to your thoughts around this and sort of how the company and you are thinking about this offer?
Dave Bauer: Yes. Sure. We’ve been getting the question a fair amount. I’m not ready to give up on New York just yet. I think we’re solidly in the political phase of climate legislation and the next phase is going to be the more practical implementation. And I think when you start bringing things like costs into play and electric reliability into play, the state may come to its senses and decide that if not all that smart to move at the pace that is currently being contemplated. So we’re not ready to give up on New York just yet and plan to keep our headquarters here.
Holly Stewart: Great. Just thought it was an interesting move out of that senator. Maybe just moving on, you highlighted a lot of free cash flow generation in this year and beyond. I thought maybe we could get your updated thoughts on that capital allocation. It looks like maybe there’s a small maturity that’s at a little bit of a higher rate that you could take out. But other than that, not – doesn’t appear to be a lot to do on the balance sheet side of things. So just maybe any updated thoughts you can give us.
Dave Bauer: Yes. Our – as we talked in the past, the first priority is going to be to delever a bit, and delevering not just in a lower debt-to-EBITDA number where – that’s driven by higher EBITDA, but also reducing absolute leverage on our balance sheet. Because as you know, our capital structure plays into our rate setting process, and so lowering absolute debt makes a lot of sense if rate cases are on the horizon. So we’ve got our next maturity in February of 2023, I think it is, that’s in the $500 million range. So we’ll likely use some of our excess free cash flow to pay down that maturity and do a smaller issuance. Then longer term, certainly, free cash flow will grow in 2023 as we have all of the revenues from FM100 and we have lower capital. Really no change in our thinking. We’d really like to continue growing the company and find opportunities either organically or through acquisitions. But if those don’t arise, return capital to shareholders in some way.
Holly Stewart: Okay. That’s great. Maybe flipping to Justin. And Justin, pardon me if I missed the comment. I know you’re talking about a few more pads and kind of enhancing that, I guess, completion design and just some of your spacing and whatnot. Can you just give us maybe what you had in plan for TILs for 2022, which – and then that updated number now today with the new capital in terms of those TILs for 2022?
Justin Loweth: Sure, Holly. So we brought on 24 wells in the first quarter. Our TILs on the – for the balance of the year don’t really change. The incremental kind of completion in top-hole that I spoke about, so on the completion side, it’s more about more enhanced design where we’re doing tighter stage spacing. And we’ve got a lot of data and a lot of history through our kind of development over time and optimization. And where prices are today and what we see out there, the returns on investing that incremental capital over the balance of the fiscal year, payout, I mean we’re talking, for the most part, these are 100% plus IRRs on that incremental capital and payouts that are just – you can count the months on your hand. So that’s more of a, I’ll call it, an optimization enhancement of our plan. And we’ll really see the – we might see a little bit of that benefit towards the very tail end of the year. There’s one pad in particular, but most of that will spill into fiscal 2023. Similarly, on the top-hole, we’re just going to employ our top-hole rig more frequently and likely top-hole really all of our pads. And that – what that does is it’s – that has kind of the impact of accelerating how quickly we can bring wells on in the sense that you drill incrementally three, four, five, six, maybe four to seven incremental wells per year with our two larger rigs. It just speeds those up and has the benefit of lowering our costs. Again, that mostly will spill into fiscal 2023 benefits from a production perspective.
Holly Stewart: Okay. And sorry, I don’t have that number at my fingertips in terms of just the total TILs expected for the year.
Justin Loweth: I don’t have that number right off the – top of my head, but we can follow up.
Holly Stewart: Okay. I can follow up on that. Okay, great. And then, Justin, sorry, I’ll stop here. But last one and a little bit maybe more in the weeds. It looks like from a Midstream perspective, the ratio of sort of gathered volume to Seneca volume has been rising and particularly the last two quarters and maybe the fee of seceding a bit. So I’m sure that’s just based on mix or gross versus net or I’m not sure how to think about it. So I guess that’s my question is what’s driving that? And then should we think about that trend here going forward in the forecast?
Justin Loweth: Sure. So it’s a couple of things driving it, and you’re kind of dialing in on them. So one is just simply the difference between the gross and the net of Seneca for throughput – the other one is exciting in the sense that we now have added meaningful volume – third-party volumes and third-party revenues through our gathering systems. Some of we’ve been working on for a long time. And this quarter was the first quarter where some of that started to show up. And you should absolutely anticipate those benefits continuing through the balance of the year and into the future.
Holly Stewart: Okay. Great. Thank you all.
Operator: Your next question comes from the line of John Abbott from Bank of America. Your line is now open.
John Abbott: Good morning. Thank you for taking our questions.
Dave Bauer: Hey, John.
John Abbott: Hey. So our first question is on maintenance CapEx. I mean, David, you addressed some of this in your opening remarks, but you are seeing cost inflation. And granted you are going to grow over the next several years, it sounds like. But when you think over a multiyear period of time, what are your latest thoughts on maintenance CapEx across your various segments?
Dave Bauer: Yes. On the pipeline side, like I said, it was in the $50 million range, and that would take into account the cost inflation that we’ve seen at least to date. On the Utility side, I would say in the, let’s say, $60 million to $70 million range for true maintenance, right, so excluding modernization and replacement of older pipe. And then on the Gathering side, it’s very, very small, given the age of the system. It’s more preventative maintenance and the like, which falls into O&M. And then Justin, you want to hit Seneca?
Justin Loweth: Sure. So in at Seneca, our plans aren’t quite maintenance, so I’ll baseline you on what they look like. So going into next year, we’d expect capital to come down. It will still be it will come down, say, in the 400 to 450. But then as we think about long term, if we just continue at that mid-high single digits, it’s probably more closer to 400. And if you think about just maintenance off of that, you’d subtract another $50 million to $75 million per year, if we went to truly just flat production.
John Abbott: That is very helpful. And then the second question, it was touched on earlier about basis differentials. But when you saw, you’ve been adding marketing contracts. When you think about Appalachia post 2023, how are you thinking about your long-term differential in Appalachia? I mean the majority of our gas is being sold out of basin, but how are you thinking about that long-term differential at this time?
Justin Loweth: So in terms of gas that would be exposed to in-basin pricing, it depends a lot on where NYMEX is, which will drive overall activity levels and gas supply. But I would say it’s in a range of kind of $0.70 to $1. And I know that’s pretty wide, but it will be highly variable depending on how much production is growing or not growing within the basin. There’s certainly – other than MVP, which is – had some setbacks recently, there are no large infrastructure projects with gas getting out of the basin. So unless you have a great firm transportation portfolio and augment it with some firm sales on top of that. I think people are going to have to generally stay keep their production in check, and that will result in kind of that range I’m talking about long term, kind of $0.70 to $1 off of NYMEX.
John Abbott: And that’s for in-basin correct? When you play on your marketing – when you layer in your marketing contracts, where do you see the differential sort of potentially shaking out for you long term?
Justin Loweth: So I guess what I would point you to is in our slide deck, we have – we show what our long-term basis looks like. It’s Slide 29 of our deck. And if you take a look at fiscal 2023, where we just show an average, that would give you a pretty good assessment. If you look at our NYMEX contracts, our Don contracts, our other contracts that go through, Transco and into some of the Northern New York Empire markets, that gives you a really good flavor in some more specifics. I would expect us to be in those general ranges, and it will just evolve over time. But all – what I’m describing there are realizations that are better than what we would see if we were in basin overall and in some cases, meaningfully better.
John Abbott: That is very helpful. And if I could squeeze one more in here? So with inflationary pressures, just for the regulated businesses, how does this influence the timing of potentially a rate case for those businesses? How does that sort of factor in the inflation? And maybe how does that work?
Dave Bauer: Yes. I mean it certainly is a driver of rate cases. On the Pipeline side of things, we have a stay out in both pipes for at least another year. On the Utility side of the business, we can file – I think we can file in both jurisdictions now. We’re earning good returns, but obviously, inflation eats into that. And I think we’re likely approaching the point where you’ll see us file a rate case in the next year or two.
John Abbott: Very helpful. Thank you for taking our questions.
Dave Bauer: You bet.
Operator: Your next question comes from the line of Trafford Lamar with Raymond James. Your line is now open.
Trafford Lamar: Great. Thank you guys for taking my question. The first one has to do with 2023 production growth. And given the additional growth capital for CapEx this year, should we expect kind of a proportionate increase in midstream spend in 2023? Is that a fair assumption to make?
Dave Bauer: Not necessarily. There might – we likely will have a few more wells that we’re able – we will have a few more wells we’re able to turn in line during fiscal 2023, which will likely result in a very modest move or an incremental piece of pipe we need to put in the ground, et cetera, but not a material step-up. The other thing, just to make sure I was clear in stating earlier is that I would see capital – even with our revised plans to this kind of mid- to high single-digit growth, I would see Seneca capital and Gathering capital shifting down from this year to next year. And by 2024 kind of the Seneca side of that falling into Appalachian capital in the ballpark $400 million with this growth that we’re talking about.
Trafford Lamar: Okay. Perfect. Thank you. And then last question. It kind of revolves around the recent and current winter storms. I just want to know if you all have experienced any production shut-ins or if it’s at any in the effect on 2Q production and any if any, effect on midstream as well?
Justin Loweth: Yes. So fortunately, at Seneca and Gathering, we’ve really – the team has done a fantastic job of keeping our production flowing. We’ve had very, very minimal freeze-offs or other issues associated with the weather.
Dave Bauer: And on the Regulated and Pipeline side of the business, no issues.
Trafford Lamar: Okay. That’s great news. Thank you guys.
Dave Bauer: Yes.
Operator: Your next question comes from the line of Umang Choudhary from Goldman Sachs.
Umang Choudhary: Thank you for taking my questions. I had just one. I wanted to circle back on the RSG certification. Are you seeing more engagement from policymakers to support future development as you get certified by independent auditors? And like you mentioned, the carbon intensity of natural gas is much lower than coal and fuel oil at is much more reliable. So do you see potential to kind of increase that engagement in the coming quarters? And maybe you can also touch on the outlook on pipeline growth and pipeline demand across the Appalachia basin as well. Thank you.
Justin Loweth: So certainly, as it relates to what we’re doing from a sustainability front, we’re very engaged in speaking with policymakers in D.C. as well as at a state level. And I think that just holistically, I’ll speak to that slightly to say whether it’s the responsible source gas or just overall the sustainability initiatives that the industry is taking, we’re kind of in the catch-up education phase of how far we’ve come and just how quickly we’ve come to this place and where we’re going and seems to be good receptivity to that. How that ultimately finds its way into the state-level public utility commissions and their ability to actually pass on an incremental cost of buying responsibly sourced gas to their consumers, I think it just takes time, like anything else for that education process certainly from a producer perspective is ongoing. And I think speaking for us and other companies – peer companies, we’re very engaged in making sure we’re kind of informing the key stakeholders on what we’re doing and why it matters.
Dave Bauer: I think you asked about pipeline expansion opportunities, right? Did I hear that part right?
Umang Choudhary: That’s absolutely right. Any expansion opportunities in Appalachia in your existing systems and the timing around it?
Dave Bauer: Yes. I think we will have the opportunity to continue to expand our system. I don’t think it’s going to be quite as large as, say our FM100 project. But I think there are projects that can get done. So for example, on our Empire line, we built our Empire North project in 2020 that was a compression-only project that boosted throughput. I think we’ve got the opportunity to add – to do another expansion there or we add another compressor station and boost volumes. Similarly, on the Line N system, there’s a lot of petrochemical development that’s going on there that can be served by our pipeline. I think it would be interesting for us to see if we can connect our system with the Rover system that isn’t very far from our Line N. And I think those types of things will lead to further expansions. We – in terms of timing, we’re pursuing these things. I wouldn’t expect anything to be built further in 2022. But our hope is that as we get into 2023 and 2024, some of these projects will come to fruition.
Umang Choudhary: Okay. That’s great. Thank you.
Dave Bauer: Yes.
Operator: There are no further questions at this time. I will now turn the call over back to Brandon Haspett.
Brandon Haspett: Thank you, Blue. 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 Friday, February 11. To access the replay online, please visit our Investor Relations website at investor.nationalfuelgas.com, and to access by telephone, call 1 (800) 585-8367 and enter conference ID number 837-5065. This concludes our conference call for today. Thank you, and goodbye.
Operator: Ladies and gentlemen, this concludes today’s conference call. Thank you for participating. You may now disconnect.
