National Fuel Gas Company (NYSE:NFG) Q3 2023 Earnings Call Transcript

National Fuel Gas Company (NYSE:NFG) Q3 2023 Earnings Call Transcript August 3, 2023

Operator: 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.

Brandon Haspett: 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.

David 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 optimizing the flows on our system. Earlier this week, Supply Corp. filed a rate case with FERC. The filing considers the numerous investments we’ve made in rate base, the overall increased expenses of our pipeline operations and the ongoing need for supply to invest in system modernization, including both regulatory driven and emission reductions projects. New rates will go into effect February 1, subject to refund. As you know, we have a good history of settling our pipeline rate cases.

So I’m hopeful we can reach a settlement before then. Turning to the Downstream business. In June, the Pennsylvania Utility Commission approved the settlement of our recent rate case. Under that agreement, annual base rates increased by $23 million, effective August 1. Construction season is well underway at the utility, and both jurisdictions are on track to meet their mileage replacement targets. As a reminder, we have a modernization tracker in New York that allows us to recover in near real time, the investments we make in modernization through September 2024. In Pennsylvania, we plan to increase the pace of our modernization efforts and will likely seek a similar modernization tracking mechanism to begin recovering that investment. In June, our Board of Directors approved an $0.08 per share increase to our dividend, which continues our impressive track record.

We’ve paid a dividend for 121 consecutive years and increased in each of the last 53 years. This is a streak that we’re proud of, and it’s one we plan to continue well into the future. Based on the outlook for the business, I have every confidence we’ll be able to do so. Looking to next year, midpoint to midpoint, our initial fiscal ’24 earnings per share guidance is nearly 11% higher than our updated ’23 guidance. This increase is driven by a number of factors including higher expected production and natural gas price realizations at Seneca, higher projected gathering volumes at NFG Midstream and the anticipated impact of the Pennsylvania and Supply Corp. rate cases at the regulated companies. Tim will have more on our outlook later in the call.

Consolidated capital spending next year is expected to be modestly lower than in ’23. Most of the expected decreases at Seneca, where we anticipate capital will be about 7% lower than this year. During fiscal ’24, Seneca will moderate its activity level as we transition to a maintenance to low single-digit growth rate by fiscal ’25. We also plan to focus our development program more heavily in the Eastern development area. It’s been 3 years since we completed our large Tioga County acquisition, and we recently closed on 3 additional modest acreage acquisitions in EDA that bolstered our position. Obviously, we like what we see there. Well results are outstanding, and we have more than a decade of high-quality inventory. So it makes sense to increase our focus on those assets.

Justin will have more to say on this later in the call. Capital spending at the regulated companies is expected to increase, driven in large part by continued cost inflation, coupled with the ramp-up in the Pennsylvania modernization program I referenced earlier, and the continued investment in modernization and emissions reduction projects at Supply Corp. This is a good use of free cash flow. As I’ve said on past calls, growing the regulated side of the business as a priority and investment in rate base is a great way to generate durable earnings and cash flows that support our growing dividend. In closing, we continue to see great operational results across the system. As we look to fiscal ’24 and beyond, we remain focused on the efficient allocation of capital towards investments that deliver strong returns through commodity price cycles which generates sustainable earnings and cash flows that allow us to grow our dividend, further strengthen our balance sheet and improve our overall financial flexibility.

With that, I’ll turn the call over to Justin.

Justin Loweth: 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 of winter pricing. Overall, supply/demand dynamics have begun to improve, which we expect will set up for a strong natural gas price recovery as a new wave of LNG demand ramps up in late ’24 and beyond. While the fundamentals are setting up for a more favorable longer-term pricing environment, our robust hedge book provides a significant level of downside protection at attractive prices. Over the past few quarters, we have continued to methodically layer in new hedges as the market is allowed and we currently have over 280 Bcf locked in with a combination of hedges and fixed-price firm sales for fiscal ’24.

We also have firm transportation and firm sales covering 88% of production at the midpoint of guidance. Moving to capital. We are increasing our fiscal ’23 capital guidance to a range of $575 million to $600 million. During the first half of the year, we were running 2 rigs in an intermittent top hole rig, in addition, we had a spot frac crew operating in the EDA as well as our dedicated frac crew in the WDA. Going forward, we do not have any additional top hole work planned and in late May, Seneca moved to a single dedicated electric frac crew. This crew is currently operating in the EDA, where we recently completed a 6-well pad and are now completing a 13-well pad. While overall capital spending has moderated, our water management costs have trended higher, which is now reflected in our fiscal ’23 and ’24 estimates.

Moving to fiscal ’24. Capital is forecasted to decrease by 7% versus the midpoint of our updated fiscal ’23 guidance. It’s important to note that fiscal ’24 includes a few onetime investments totaling over $35 million, which are expected to offset what would otherwise be a more pronounced capital decrease. These include a seismic shoot in Tioga, long-term investments in water infrastructure that will provide cost and efficiency benefits to our future development program and a larger land-driven budget — driven by a 2,500 acre lease in Lycoming County that we expect to close during the quarter. Regarding service costs, we’re seeing costs moderate and expect a slight tailwind next year. Tubular pricing is trending down, and both rig and frac rates seem to have peaked earlier this year and are holding steady or have decreased from those levels, though costs are still elevated compared to long-term contract pricing from a year ago.

Looking out longer term, based on current forward NYMEX prices and consistent with prior plans, we expect to moderate activity and will target maintenance to low single-digit long-term production growth in fiscal ’25 and beyond. Further, we expect to continue to transition to primarily EDA development which is supported by over a decade of highly prolific development inventory. While returns on our WDA wells are strong, the expected well productivity in the EDA is superior to that of the wells in the WDA. The transition to an EDA focused development program is expected to drive long-term capital efficiency and higher free cash flow as we continue to focus on optimizing well costs and development plans. We are fortunate to have almost entirely fee acreage in the WDA that will never expire, allowing us to prioritize the EDA where we can develop our most economic acreage now while preserving the ability to develop our WDA acreage once additional out-of-basin takeaway capacity is available, whether through peer inventory exhaustion or the construction of new interstate pipelines.

Turning to Midstream. We continue to develop opportunities to grow third-party volumes by fully utilizing our significant wholly owned gathering systems. We are having a terrific year with third-party system throughput at record levels, exceeding 16 Bcf in the third quarter. We also have significant construction underway in Tioga County as we build out infrastructure to support Seneca’s long-term development plans in the EDA. Overall, our Appalachian development program remains well positioned to generate sustained free cash flow, focusing on prudently deploying capital through commodity price cycles. By leveraging our integrated model and maintaining our focus on cost structure, while steadfastly promoting our safety culture and sustainability initiatives, we are set up for continued success in the years to come.

With that, I’ll turn the call over to Tim.

Timothy Silverstein: 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 $23 million. We’ve also agreed to a new weather normalization mechanism that will dampen volatility during the winter heating season. In New York, we are projecting an $8 million margin increase from our 2 pipeline modernization trackers. Our ability to add new investments to our original system modernization tracker ended in March. However, we are still able to recover the investments made prior to the sunset date.

That tracker was supplemented with a new system improvement tracker which allows us to recover on the investments made after March 31st of this year. Lastly, as Dave mentioned, in our Pipeline and Storage segment, we filed for a rate increase at Supply Corporation. We’d expect to have new rates in effect February of next year, and that is reflected in our initial guidance. On the O&M side, we are projecting a 5% increase in our regulated businesses versus the prior year. This is driven by ongoing increases in labor expense, expanded regulatory compliance costs, at both the state and federal levels and the inflationary impacts on the contractor and material costs. Notwithstanding these projected cost headwinds, we still expect to deliver significant regulated earnings growth.

Switching to our nonregulated segments. There are 2 major drivers behind our expected year-over-year increase in earnings. First, our fiscal 2024 guidance assumes a $3.25 per MMBtu average NYMEX natural gas price. While this represents a $0.35 decrease from this year, the value of our hedge book increases meaningfully next year. As a result, we expect our average realized natural gas price will be approximately $0.10 higher than fiscal 2023. Pricing continues to move around. So for reference, a $0.25 change in NYMEX equates to a $0.28 change in earnings per share. When coupling higher realized prices with an expected 25 Bcfe increase in natural gas production at the midpoint of our guidance, Seneca is positioned to deliver meaningful earnings growth next year.

The growth in production also accrues to the benefit of our Gathering segment. Our midpoint to midpoint revenues are expected to increase by $20 million. On the cost side of things, we are expecting Seneca’s cash unit cost to remain relative — roughly flat. On a per unit basis, modestly higher LOE is expected to be largely offset by lower other taxes related to the Pennsylvania impact fee which is based on average calendar year NYMEX prices. We also expect a $0.05 per Mcfe increase in projected DD&A expense. This is in line with our expectation of DD&A trending towards our long-term F&D rate of approximately $0.70 per Mcfe. Turning to capital. We’ve increased our 2023 guidance range by approximately $50 million at the midpoint, principally driven by the increase at Seneca that Justin discussed earlier.

The other changes are minor and are largely related to the timing of construction activity. With our fiscal year-end occurring in the middle of the pipeline construction season, many projects straddle fiscal years and the timing of capital can move around. Looking at fiscal 2024, we’ve initiated capital guidance with a range of $865 million to $975 million. This represents a 2% decrease from fiscal 2023 at the midpoint. Overall, the decrease expected in our nonregulated businesses is largely offset with anticipated increases in spending in our regulated utility and pipeline and storage segments. Given the importance of safety and reliability, and the substantial system integrity and emissions focused to requirements for these operations, we believe it is prudent to continue to invest significantly in our modernization programs in each of our jurisdictions.

We expect that this pipeline of investments funded with our internally generated cash flows will drive mid-single-digit rate base growth over the next several years, providing stable, predictable returns for our shareholders. We believe this is an attractive way to deliver value and supports our ability to continue to grow our dividend over the long term. Bringing it all together, we are now expecting this year’s cash flow from operations to exceed capital expenditures by approximately $325 million. This is more than sufficient to cover our dividend and $150 million of upstream acquisitions this fiscal year. Looking to fiscal 2024, we expect our cash from operations to exceed capital spending by $165 million. The primary reason for the decrease relative to 2023 is expected to return to more normalized levels of working capital.

As you may recall, we are projecting a large source of working capital this year given the decrease in natural gas prices. This cash flow profile will leave our balance sheet in a good spot. We’d expect to end this year with debt-to-EBITDA in the low 2x area and will likely remain in that range over the course of fiscal 2024. This gives us a great deal of flexibility and positions us well to navigate challenges or execute on potential opportunities that come our way. As we look beyond 2024, the outlook for our business remains strong. Forward prices for natural gas are around $4 per MMBtu. We continue to layer in hedges to lock in the high returns we generate at these prices. Seneca’s capital is expected to decrease. And the modernization programs in our regulated businesses provide the path towards steady, value-accretive growth for many years to come.

With this outlook, we are well positioned to increase our long-standing dividend further improve our leverage profile and deliver long-term value to our shareholders. With that, I’ll ask the operator to open the line for questions.

Q&A Session

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

Umang Choudhary: 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?

Justin Loweth: 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.

Umang Choudhary: 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?

Justin Loweth: 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.

Umang Choudhary: 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?

David Bauer: 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.

Umang Choudhary: 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. .

David Bauer: Right. Yes.

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

John Abbott: 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.

Justin Loweth: 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.

John Abbott: 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?

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

Trafford Lamar: 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.

Justin Loweth: 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.

Trafford Lamar: 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?

Justin Loweth: 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.

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

Brandon Haspett: 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.

Operator: This concludes today’s conference call. You may now disconnect.