Ladies and gentlemen, thank you for standing by. And welcome to Q2 2022 National Fuel Gas Company Earnings Conference Call. At this time, all participant lines are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. [Operator Instructions] Please be advised that today's conference is being recorded. [Operator Instructions]. I would now like to hand the conference over to your first speaker today, Brandon Haspett, Director of Investor Relations. Please go ahead.

Thank you, RJ, 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 Lowe, President of Seneca Resources and National Fuel Midstream. At the end of the prepared remarks, we'll open the discussion to questions. The second quarter fiscal 2022 earnings release and May 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 in earnings release for a listing of certain specific risk factors. With that, I'll turn it over to Dave Bauer.

Thanks, Brandon. Good morning, everyone. National Fuel had a great second quarter. Adjusted operating results were $1.68 per share, up 25% year-over-year with each of our four major reporting segments contributing to the increase. Seneca had an outstanding quarter, both operationally and financially. Production for the quarter was up sequentially and relative to last year. Net increase, combined with the ongoing rise in commodity prices caused earnings to grow by 50% over last year. As we announced in last night's release, Seneca has entered into an agreement to sell our California operations to Sentinel Peak for $280 million in cash and $30 million in contingent consideration. Just as the spring of 2020 was a great time for us to acquire natural gas assets, we think the current oil price environment is the right time for us to sell our California properties. These have been great assets for us. Since 2010, generating over $1 billion in cash flow that funded a good amount of our upstream and midstream growth in Appalachia. But the regulatory environment in California makes it difficult to grow those operations. Plus as our Appalachian businesses have grown our California assets were increasingly non-core. Sentinel Peak will be a great owner of these assets. They're an established operator in California with an excellent track record. Justin will have more details on the transaction, but before moving on, I want to personally thank the California team for their hard work and dedication to the company. We expect the June 30 closing date for the transaction. Net proceeds from the sale should be approximately $175 million to $200 million after accounting for taxes, the April 1 effective date and the unwinding of out-of-the-money hedges that will not be transferring to the new owner. Turning to Seneca's capital budget. We're revising…

Thanks, Dave, and good morning, everyone. Before I get into the details of the quarter and future outlook, I want to touch briefly on the sale of our California properties. First and foremost, I want to add my sincere gratitude to the Seneca West Division team. The employees in our West division, many of whom have been with Seneca for multiple decades, have been tremendous stewards of these assets and are managing the transition to a new owner with the utmost professionalism. This is no surprise and is what we've come to know from such a hard-working, dedicated group of employees. To the team, I just want to say thank you for all that you've given to Seneca over the years, and I wish you all the best in the future. They've already hit on the high points of the transaction, so I'll touch briefly on a few of the details. We've agreed to sell the properties to Sentinel Peak Resources for total potential consideration of $310 million, with an expected closing date of June 30. This consists of $280 million in cash at closing, subject to purchase price adjustments and contingent payments with potential value of $30 million. The contingent payments are up to $10 million per calendar year from 2023 to 2025, and are based upon the average Brent price for each year. For each $1 per barrel that Brent averages over $95, Sentinel Peak will pay Seneca $1 million with a contingent payment capped at an average Brent price of $105 per barrel. For those who are not familiar with Sentinel Peak, they acquired Freeport-McMoran's onshore California assets in 2017 and operate approximately 25,000 BOE per day. We believe they have both the scale and financial strength to be long-term sound stewards of these assets. We have…

Thanks, Justin, and good morning, everyone. National Fuel's GAAP earnings were $1.82 per share, while adjusted operating results for the quarter were $1.68, an increase of 25% from the prior year. The primary difference between our GAAP earnings and operating results was the impact of a onetime non-cash benefit of $0.16 per share. This was related to an approved tariff filing in our Utilities Pennsylvania jurisdiction we've previously discussed that permitted us to stop collecting post-employment benefit costs due to the overfunded nature of these plans. The order approved several items, including the unwinding of a previously recorded regulatory liability, leading to the onetime non-cash $18.5 million benefit recorded this quarter. On an ongoing basis, we also expect a reduction to margin of approximately $10 million annually and a corresponding decrease to EBITDA. This drop is fully offset by the elimination of the associated OPEB expense most of which is nonservice costs sitting below operating income. As a result, we expect no direct earnings impact in our Pennsylvania jurisdiction. We also agreed to refund a portion of the remaining regulatory liability through onetime and ongoing bill credits starting last October and extending over a period of five years. These credits will be funded by money previously set aside in the trust for the full benefit of rate payers, resulting in no impact to operating cash flows. Switching back to our ongoing operations, I'll focus mostly on the outlook for the coming quarters since results for the quarter were relatively straightforward. Starting with earnings guidance. We've revised our range, which is now expected to be $5.70 to $6 per share. This reflects several changes to our assumptions. First, we've increased our natural gas price forecast to average $7.25 per MMBtu for the remainder of the year with basis differentials averaging dollar.…

Thank you. [Operator Instructions] Your first question comes from the line of Neil Mehta with Goldman Sachs. Your line is open.

Good morning, team. And thanks for all the perspective here, and congrats on the recent sale. The first question I had is just talking through your hedging strategy. You gave some good sensitivities around your natural gas sensitivity for 2022, but talk about your hedge position in '23. And how sensitive you are to movements in Henry Hub?

Good morning. And thanks for the question. We'll guide out our exact production for -- expect to guide out our production for fiscal '23 likely at our next call. But within our disclosures, you can see that generally speaking, are -- we have a number of hedges that kind of roll off. So our relative percent covered will be lower, and therefore, the exposure to upward prices will be quite a bit higher. And then I guess, overall, I would tell you that the strategy we have remains intact. And we've got a lot of flexibility within our policy, but we've also moved more recently towards collared approaches to try to retain a lot of upside and frankly, take advantage of the positive skew in the market.

Look for more clarity there. And then talk about what can drive longer-term earnings growth. Any debottlenecking opportunities in Appalachia or incremental growth projects that will drive the vector of earnings growth higher?

Yeah. I think -- this is Dave. I think we've got a great opportunity to continue growing the company. On the upstream side, through firm sales, we're able to grow our production kind of in that mid to high single digits area for at least the next few years, which for us is a decent percentage, but relative to the total market isn't a huge amount of volumes that will be coming to the market. So I don't see us really moving prices. And then on the regulated side, we've got really two things. One is the continued modernization of our systems. So if you look at our past history, we've been spending in the $100 million to $110 million range on the utility. Most of that's modernization that has a nice upward trend on rate base growth. Similarly, on the pipeline side, we spend in, call it, the $50 million to $70 million area on modernization that also helps with rate base growth. On top of that, I do think we can continue to do expansions on our pipeline system. We just recently did an open season on our line in and are sorting through the service request that we got there. We're optimistic that we can have a project that rough order of magnitude could be in the $100 million to $200 million per day type size. And then Empire North, we expanded last year. And I think we've got the ability to add a third compressor to that project, and we're chasing that. So is it going to be double-digit growth? No. But will it be modest, call it, mid-single digits growth, I guess.

Great color. Thanks color.

Yep.

Your next question comes from the line of Holly Stewart with Scotiabank. Your line is open.

Good morning, Dave, Karen.

Good morning.

Dave, Karen, I'm not sure which one you want to take this one. But Karen, I know you talked a lot about accelerating the debt reduction program and sort of what's what you're targeting. But maybe from a capital allocation standpoint, is -- maybe the first question would be, is there a targeted absolute debt level or maybe even a normalized leverage target, assuming kind of a longer term commodity deck maybe that we should be thinking about? And then, I guess, the bolt-on to that would be kind of after you get to these targets is bumping the dividend more than you historically have or maybe even a special dividend, something that you would consider.

Yeah. From an overall target, I think we'd like our, call it, our equity to cap ratio to be in the, call it, low mid-50s area, which is helpful in rate case proceedings. In terms of capital allocation, once we get beyond that, certainly, I'd like to continue growing the company. So our first priority is going to be to try to do that. But beyond -- if there's -- the opportunities just aren't there, a return of capital is certainly something that we would consider whether it's a dividend or a buyback, we'll determine when we get there.

Okay, Dave. And then maybe a follow-on to that would be with -- obviously, with gas prices doing what they're doing, you're skewing to the non-regulated side of things in terms of kind of your balance. Is there a thought process of keeping that more level? Like how do you think of those growth opportunities, whether they're internal or external?

Yeah. I just the previous question went through kind of the internal opportunities that we see. I'd like to continue to grow the regulated side of the business. We've been active in looking at some of the assets that have been on the market. And I think given the environment, there's a good chance that additional regulated properties will be on the market, and we'll be looking at those as well.

Okay. That's great. And then maybe, Justin, just one for you. You've kind of kept the two-rig program in place accelerating those completions in order to take advantage of the higher commodity price environment. I guess, maybe how are you thinking about the '23 program? Any kind of new factors that you're thinking through or weighing into that activity set, whether that's outlining ‘23 or even ‘24 at this point?

Yeah. So I'd say, I mean, the team is just executing very well. So we're getting our wells drilled right in line with what I felt were pretty aggressive assumptions. And so that's kind of set us up for this opportunity where we can get after some completions a little bit earlier than maybe we previously had thought. And then even with -- in spite of this tight service environment that everyone is in we've been successful at getting a crew to do a pretty significant amount of work for us starting at some point this summer. So that -- really, a lot of this activity is a combination of a little bit of bump to what previously we thought our production could be in fiscal '23, but it's also about shaping. And so when I talk about that, what I'm really referring to is trying to move production that we might have seen next summer, and get as much of that into the winter as possible. The strip keeps moving so much these days, so it's hard to keep up. But generally, it's 300 to 350 higher to sell gas in, say, January versus April. And so to the extent we can do some things and overall, maybe increase our volumes a little bit, but even almost as importantly, bring some of that activity in the winter it's meaningfully accretive to us to do so. So that's the driver. And long term, absolutely, what we've been stating is very much our focus here. We've got mid to high-single digit production growth. Of course, that will drive growth through the midstream business as well. And our program with two rigs and using a top hole rig and is really designed to achieve that, and we're protecting that future production through executing firm sales in excess of our firm transportation portfolio. So again, aligning to what we've always said, which is not growing just to grow, but growing into markets that we can get great prices in. So that's I think it's just kind of a continuation of things we've been talking about with a little bit of modulation and the focus to '23 to really take advantage of the strong winter pricing.

Yeah. Okay, that’s great. Thank you, guys.

You bet.

Your next question comes from the line of John Abbott with Bank of America.

Good morning. And thank you for taking our questions. Karen, I think this question is going to be for you. It's going to be on rate cases with utility business and growth in the utility business. So I listened to your opening remarks. It didn't sound like there was any change in the growth outlook for the utility business, but guidance for the utility business was sort of slightly reduced even though you had a feat it looks like based on colder weather. So trying to understand it because my initial impression that might have been driven by the reduction in the site reduction in the rate case in PA. But what's driving that difference in growth of the utility business.

No. Yeah, I don't think that we're anticipating much change to our growth in the utility business. I mean, we've always kind of talked at low-single digit growth, where we've got some small addition of customers. We've got the system modernization tracker in New York that continues to allow us to grow rate base there. Yeah, I guess I'm not seeing that we're expecting a change in what we had projected.

Yeah. I thought the high end of the growth range previously was 4%. It just looked like it dropped down a little bit to 3%. So I was just trying to understand that.

And then It's pretty much -- yeah, go ahead. Sorry. John.

And then the other, I guess, -- and so again, this is actually a continuation of the first question. I've got a second question on the pipeline. But -- so I guess it's probably the standard procedure, but just given inflation, I mean the PA moved to reduce the rate case here because of -- you don't need to recover for the retirement benefit. I mean, does that give you any sort of concern going into a rate case because you are experiencing inflation. So why do the lowering now?

Well, I think prior to that was just kind of in response to pandemic. The commissions had been asking utilities to find ways to reduce the impact of rates on customers. And this was something that we had developed over the years. This this overfunded OPEB liability, and it really just gave us the opportunity to pass those back to the customers. We're also able to lower our rates there. So then when we go in for a rate case, it's going to -- we'll be more likely to be able to get good response from the commission to increase our rates for things like inflation.

And John, one thing to keep in mind on the OPEB reduction, those dollars were -- and expense were fully tracked and reconciled to rate recovery, right? So we could only use those OPEB dollars for OPEB expense, right? So we couldn't use it to offset inflation, for example. Does that make sense? So the dollars just sat and trust, and we're now giving them back.

That helps out quite a bit there. And then the other question, again, this could be on the pipeline and storage segment, is that there was an increase in percentage for OEM. It looks like you're expected to be up 8% year-over-year versus 5% prior. You described that as pipeline integrity and fuel costs. I mean, what's the risk that that actually goes even higher, sort of looking into 2023? How do we sort of think about that?

Yeah. We're not expecting there to be a huge impact from inflation there at this point.

All right. Very much appreciated. Thank you for taking our questions.

You bet. Thanks.

[Operator Instructions] Your next question comes from the line of Trafford Lamar with Raymond James. Your line is open.

Thank you. Guys, thanks for taking my question. My first question, you already answered it was about ‘23 production growth. But a follow-up it revolves around RSG -- you all achieved -- you have already achieved 100% certification under EO at 30% certified under Project Canary. I guess with regards to kind of the premium markets, what are you all seeing currently? And kind of what are your thoughts on premium market similar to net zero oil over the year and midterm?

Sure. So what I would share with you is that we have been successful at selling responsibly sourced gas certified gas at a premium. The market is going to evolve in our assessment. I mean the market is going to evolve a lot over the balance of this year and into the future. The premiums that you can achieve today, and I think I've mentioned this maybe in the past, but it's pennies. It's not nickels and dimes and quarters for that matter. It's pennies. But I think there's a lot of opportunity as it develops to see that improve. It somewhat depends on what happens at utility commissions among various states and if they want to embrace that part of decarbonizing and reducing overall emissions means differentiating natural gas paying premiums, specifically to natural gas that has a very low methane intensity associated with it. We could see that premium expand. I think there's also an opportunity, as you think about carbon credits and so forth that Appalachian natural gas is really the lowest methane intensity out there. It's way better than everything else. And so to the extent there's a way to kind of capture that more and define it and certify it better, I think there's an opportunity that can develop around that. We're still in very early innings. And we've been, as I mentioned, successful to date at selling some responsible source gas, but I think we're early and it will keep evolving.

Perfect. Appreciate the color.

Your next question comes from the line of Zach Parham with JPMorgan. Your line is open.

Hey, thanks for taking my question. I guess first one for Justin. Can you talk a little bit more about what you're seeing on cost inflation, specifically what services where you're seeing the most inflation? And maybe give us a little color on how contracted you are on your rigs and other services that you're using going forward?

Sure. So I'll start with how contract we are. So I mean we have contracts that extend out through this year, even into next year for both of our big ridge high-spec rigs. There's not a whole lot of near term change in any of that. Similarly, we have a long-term contract for our main frac crew that extends out through the end of the year. And we continue to have discussions with them about extending that. So if you think of the real big line items, I mean those are two of them. The places where the other services, not so much, I mean, very in contract terms. The price inflation, I mean, the biggest probably single item that absolutely everyone is looking at relates to steel costs. And so tubulars have gone up massively. And perhaps someone bought enough inventory to get through a certain period of time, a number of months. But the reality is every single person in our industry is facing increased steel costs and they're massively increased. Fortunately, in Appalachia, our overall steel costs are a little bit less than other plays. But nonetheless, that's a big one. Frac sand has tightened up very much the spot crew market on -- frac space has gone up significantly from the prices that we saw last year. And it goes without saying to anyone in any business that things like diesel fuel and labor have gone up as well. So I think generally speaking, this is across the board. And we're just trying to be very transparent about exactly what we're seeing and get out ahead of it and make sure that as we've always done, we try to be transparent with our guidance and with our commentary on all of this. And this is what -- we're just calling it as we see it. And so that's what's ahead of us. We've also baked in definitely what we've experienced of late and seeing existing contracts as well as trying to think about where we see the market going. So that we capture it more holistically. So I mean that's really the punchline on inflation.

That's helpful color. I guess maybe just following up on that, on a cost per foot basis, where are your costs running now on the wells that you're drilling?

Yeah. So I'm happy to follow up with some more detail on that. But what I will tell you is that we're actually below on a $1 per foot, we're below our cost of 2021. And but that's largely because we've been able to move to areas where we are drilling longer laterals. And so the velocity and the overall spend is higher, but through our operational efficiencies through the flexibility we have through our highly contiguous large WDA acreage and our meaningfully expanded position in Tioga, where we can drill much longer laterals than perhaps we could before. On a dollar per foot basis, we're actually kind of neutral to down from last year, but we're just getting more TLL.

Got it. That make sense. That’s all for me. Thanks.

There are no further questions over the phone line at this time. I would now like to turn the call back to Brandon for any additional and closing remarks.

Thank you, RJ. 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, May 13. To access the replay line, 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 4564187. This concludes our conference call for today. Thank you, and goodbye.

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.