Thank you for standing by. My name is Kayla Baker, and I will be your conference operator today. At this time, I would like to welcome everyone to the National Fuel Gas Company Q3 Fiscal 2023 Earnings Conference Call. [Operator Instructions]. I would now like to turn the call over to Director of Investor Relations, Brandon Haspett, you may begin.

Thank you, Kayla, 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 Principal Financial Officer; and Justin Loweth, President of Seneca Resources and National Fuel Midstream. At the end of the prepared remarks, we will open the discussion to questions. The third quarter fiscal 2023 earnings release and August 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 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 the call over to Dave Bauer.

Thanks, Brandon, and good morning, everyone. Last night, we reported adjusted operating results for the quarter of $1.01 per share. While generally in line with our expectations, earnings were down compared to last year. Appalachian production was up 6 Bcf versus last year, despite the impact of over 5 Bcf of curtailments during the quarter. But this was more than offset by the loss of earnings related to our California properties that were sold last June and sharply lower natural gas prices. You'll recall that during last year's third quarter, NYMEX averaged about $7 a dekatherm as compared to about this year. Operationally, it was a good quarter across the company. Seneca continues to see excellent results from its development program, which has driven production to record levels. Cash unit operating costs were very much in line with expectations. Pricing, as I just said, was obviously a headwind for the quarter and will likely continue to be volatile through the fall. But our robust marketing and hedging portfolio minimized the impact to low in-basin pricing and limited the amount of voluntary curtailments during the quarter. Longer term, we're constructive by natural gas prices as increasing LNG export capacity that starts ramping up in the next 12 to 24 months should drive increased natural gas demand. Over time, our deep inventory of high-quality drilling locations positions us well to take advantage of higher pricing. Our Midstream businesses had strong operational quarters as well. On the nonregulated gathering side, NFG Midstream saw a record gathering throughput from both Seneca and third-party producers. And our FERC-regulated pipelines, we're able to capitalize on strong interest in short-term transportation services. Over the past few months, volatility in locational pricing basis has created opportunities for our shippers and our marketing department has done a great job…

Thanks, Dave, and good morning, everyone. Seneca and NFG Midstream wrapped up another strong operational quarter with record production and throughput. Seneca reported third quarter production of 94.8 Bcfe, an increase of 2% over the second quarter and 7% above last year's third quarter Appalachian production. Notwithstanding the over 5 Bcf impact of third-party pipeline downtime and voluntary pricing-related curtailments. Looking to the balance of the fiscal year. We are revising our fiscal '23 production guidance range to 370 to 380 Bcfe. Seneca is moving forward with its plan to push back the online timing of 2 pads to early fiscal '24 to take advantage of higher expected winter pricing. As a result, we expect fourth quarter production will be slightly down relative to the third quarter. Through multiple pricing cycles over the last decade, we have maintained a philosophy of curtailing production when spot pricing is depressed, and our experience and detailed analysis still support this approach. Our reservoir characteristics and coordinated marketing and operations teams allow us to ramp production up and down through volatile periods like the one we're experiencing. Given our expectation that in-basin pricing will continue to be depressed over the next several months, we've locked in additional firm sales for July and August, leaving us with minimal exposure to in-basin pricing for the remainder of the year. I will note, however, that our guidance as usual does not account for the potential impact of further voluntary pricing-related curtailments. Moving to fiscal '24 production guidance. We anticipate a 7% increase to a range of 390 to 410 Bcfe. We are targeting 19 wells to be turned in line during November and December and additional pads in January and February, which are expected to drive production higher in late Q1 and into Q2 to take advantage…

Thanks, Justin, and good morning, everyone. Yesterday, National Fuel reported third quarter GAAP earnings of $1 per share. Excluding some minor items relating to unrealized gains that impact comparability, our adjusted operating results were $1.01 per share, a decrease of $0.53 from last year's third quarter. Dave hit on the major drivers, but I did want to note that last year's third quarter reflected approximately $0.15 per share of earnings related to our California assets. We closed our net sale in June 2022, so this will be the last quarter where we see a year-over-year impact. The remainder of the results for the quarter were relatively straightforward and discussed in detail on last night's earnings release. Given that, I'll spend some time talking about our outlook for the remainder of this year and for fiscal 2024. Starting with this year, we've narrowed our earnings guidance to a range of $5.15 to $5.25 per share. This reflects the price-related curtailments Justin discussed and modest tweaks to some of our other guidance assumptions. We are well hedged for the remainder of the year with approximately 80% of our production protected from pricing changes. Additionally, we have firm sales in place for approximately 95% of our expected remaining production. This leaves us with minimal exposure to in-basin pricing, limiting the risk of near-term price-related curtailments. As we look to fiscal 2024, the outlook is strong across the company for each of our segments is expected to see meaningful earnings growth. We are initiating earnings guidance with a range of $5.50 to $6.00 per share, an increase of 11% at the midpoint. Starting with our regulated businesses, we are anticipating significant earnings growth, primarily driven by top line revenue increases. In Pennsylvania, our recent rate case settlement is expected to increase annual margin by…

[Operator Instructions]. We'll take our first question from Umang Choudhary with Goldman Sachs.

My first question was on this high grading, which you're doing towards the eastern development program. You have this onetime impact of $35 million next year. But as you think about the program from a multiyear basis, can you talk us through what kind of efficiency gains we should expect from the outlook? And then also, just on the near term, any color you can provide in terms of why the CapEx increase for FY '23?

Sure. I'll start with the near term, just kind of some of the increase we've seen here late. Really, the drivers behind fiscal '23 going up is, the first half of the year, we had a significant amount of -- a significant program going on with, in particular, spot completion activity and that was at a time when rates were quite high. So our capital is running a little bit high. But ultimately, as we work through the second half of the year, we've been seeing additional costs, particularly related to what I noted on the water management, mostly related to increased water hauling as we continue to have more operations in the EDA on some elevated trucking rates. These costs, we view them as transitory and evolving over time. So kind of pivoting into the longer-term plan and how the move to the EDA will really benefit our long-term efficiency gains and capital levels over time. We have significantly better well productivity in our EDA Utica in particular, where we have a very deep inventory following the acquisitions we've completed over the last few years. And we've really validated the well performance there and the quality of our position and what we should expect going forward. So moving to an area with more well productivity, both in terms of the deliverability of the wells early in their life, holding flat at restricted rates of 15 million to 20 million a day for many months and higher EURs will really benefit us over time. And we'll be shifting a good chunk of our activity and development into the EDA here over the next year to 2 as that ramps up. There are some onetime costs associated with doing that and largely related to the continued build-out of infrastructure that will benefit us for many years to come, so mentioned water-related infrastructure project. And then also, I've been talking about some of the projects at our Gathering business where we're investing in things like centralized compression and dehydration, which have some of initial upfront capital but really benefit O&M over time. So big picture, putting it all together, we would expect increased capital efficiency as a result of this. And as we move into more of a maintenance, then we would expect capital -- overall capital levels for Seneca and Gathering to shift down to $50 million to $150 million below fiscal '23 levels.

And just to be sure, that excluding the $35 million of onetime charges, right, so $50 million to $55 million taking out the $35 million as well, which is onetime in nature in '24?

Yes. So '24 will be down relative to '23, it would have been down even more had it not been for those onetimes. When I talk about kind of a long-range view on capital, I'm referencing off '23 as an initial point. So definitely down quite a bit off what we see here in '23 between Seneca and Gathering.

Very helpful. And then would love your thoughts around M&A and M&A opportunities outside the upstream space more on the regulated side, anything which you are seeing, which is interesting for the company? And how are you thinking about balancing the portfolio between the regulated business and the nonregulated business longer term?

Yes. So I've said on past calls that growing the regulated side of our business is a priority. When you look at our organic capital spend, that will, as Tim said, keep us in kind of that mid-single digits growth area, but getting more balance quickly would likely come through M&A and those deals tend to come every once in a while, and we keep our eye out for what's out there. And hopefully, we'll see a deal happen.

Got you. And in the meantime, you have this modernization spend and the rate cases, which will help grow the regulated business in the -- over the next year. .

Right. Yes.

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

Just going back to the E&P business and understanding the shift from your Western Development Area to Eastern Development Area. I mean you just mentioned that you expect CapEx to decline by about $50 million to $100 million versus what you expect in 2023. Can you just sort of provide any additional color on the underlying decline rates between the areas and just sort of how that underlying decline rate changes between the 2 areas as you share.

Sure. So John, just to make sure level setting on the capital. The -- relative to '23, I would expect Seneca plus Gathering to a decline by $50 million to $150 million per annum over time as we shift to a true maintenance. And some of that's driven by the capital efficiencies we'll see as a result of the better well productivity. Over time, we currently are in the low 20% range on our overall decline rate, I would not anticipate that meaningfully changing. I think we'll still remain as one of the operators in Appalachia with a shallow overall decline. And so no meaningful shifts in that overall rate over multiple years that I'm foreseeing.

Appreciate it. And the second question, I missed part of the opening remarks here. And this question would be for Tim. But Tim, just with the regulated business, that range that you gave for next year, how do you think about that CapEx level over a multiyear horizon?

Yes. It's a good question, John. I think as Dave alluded to, with the goal of trying to continue to grow the regulated businesses organically, I'd expect to see the pipeline business in the $100 million to $150 million area really focused on the modernization efforts and emission reduction efforts. And that, I think, generates rate base growth in the, call it, low to mid-single-digit area. On the utility side, I would say it's a flatter capital trend, so $125 million to $150 million area, continuing to grow the Pennsylvania side in terms of our modernization program given the availability of the disc mechanism there and continuing to replace 110 miles or so in New York each year. And so that translates into about $125 million to $150 million per annum.

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

I appreciate the color on CapEx. I guess for Justin, I was going to ask kind of how should we view production cadence in '24? I think you mentioned a 13-well pad expansion up. Just trying to get any color would be great on that.

Sure. So as we kind of inter '24, so call it, when October comes around, I would say we're not really quite ramping. That should be part of the shoulder month. So really, our plans are designed around ramping into the winter pricing. So in that kind of November, December timeframe. So we'll see -- our expectation is right now, we will see production meaningfully start going up as we get into November and then throughout December and continuing to increase in January and February, and then over the balance of the year, that will trend. So you'll have a lot of growth kind of going into Q2 and then over the balance of the year, that kind of flattening out and then declining again into the end of the year. We really try to sculpt and as best we can manage our development plans to really take advantage of the seasonal pricing. That's one of the few things in gas prices you can somewhat rely on. And so we really try to work hard to sculpt our development plans around that.

Great. Yes, that makes sense. And then for '24 with activity shifting to the EDA. You mentioned slightly higher cost per lateral foot via water management. I was going to see if you all could provide kind of a benchmark number for cost per foot for '24? And then any color on what that kind of looks like once that transition is completed, assuming, let's just say, flat OFS?

Yes. So our Tioga Utica wells are kind of unique. When you think about most Northeast producers, they're developing Marcellus wells. We're developing these deeper Utica wells, more akin to what you see over in, say, the Ohio kind of deep Southern Utica play, and that's the kind of cost structure that we see, kind of in terms of an overall well cost ballpark, that's in the $1,400 to $1,600 per foot. That's an all-in number, which is somewhat comparable to what you'd see for operators kind of in that same ZIP code over there. And the reason those are the balance to that is kind of what you see out of these wells. And so you get a generally a very, very high pressure, and you're able to flow these wells at sustained rates for many months before beginning to decline in EURs that are in excess of 2 Bs per 1,000. And we're drilling on average, these are north of 10,000 foot TLL. So in the 11,000 to 13,000 foot is kind of an average round number. So that's where we expect to be. And then over time, as we transition more and more of our activity into the EDA, we would expect that to begin trending down those overall well cost per foot.

And there are no further questions at this time. Mr. Haspett, I'll turn the call back over to you.

Thank you, Kayla. 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, August 11. To access the replay online, please visit our Investor Relations website at investor.nationalfuelgas.com. and access by telephone, call 1-800-770-2030, provide access code 47961. This concludes our conference call for today. Thank you. Goodbye.

This concludes today's conference call. You may now disconnect.