Ladies and gentlemen, thank you for standing by, and welcome to the Q1 2021 National Fuel Gas Company Earnings Conference Call. [Operator Instructions]. I would now like to hand the conference over to your speaker today, Ken Webster, Director of Investor Relations. Thank you. Please go ahead, sir.

Thank you, Ditamara, 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 John McGinnis, President of Seneca Resources. At the end of the prepared remarks, we will open the discussion to questions. The first quarter fiscal 2021 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 would like to remind you that today's teleconference will contain forward-looking statements. While National Fuel's expectations, beliefs and projections are made in good faith and are believed to have a reasonable basis, actual results may differ materially. These statements speak only as of the date on which they are made, and you may refer to last evening's earnings release for a listing of certain specific risk factors. With that, I'll turn it over to Dave Bauer.

Thanks, Ken. Good morning, everyone. National Fuel's first quarter was a great start to our fiscal year, with operating results up 5% year-over-year. Operationally, we had a really strong quarter, particularly at Seneca and NFG Midstream, where in spite of 4 Bcf of pricing-related curtailments, production and the associated gathering throughput was up 36% over last year. Most of that growth was the result of last year's Tioga County acquisition, which continues to trend better than our initial expectations. The team has been focused on high-grading our consolidated development program, optimizing our firm sales and transportation portfolio and driving down unit costs. You can see our success in Seneca's updated guidance. We increased the midpoint of our production range and lowered our forecasted unit costs, all while holding our capital range constant. Seneca added a second drilling rig in January, with first production permit scheduled to come online in early fiscal 2022. The goal is to fill our Leidy South capacity as soon after it goes in service, and thereby, capture the premium winter pricing in the East Coast markets. The second rig will focus principally on Tioga County. We're at $2 netback prices, our consolidated returns on Utica wells are north of 65%. Looking beyond fiscal '22, absent new firm takeaway capacity, Seneca's program will likely average between 1.5 and 2 rigs, which will keep our production flat to slightly growing. Our focus will be on generating free cash flow. As you can see from our updated slide deck at a $2.75 NYMEX price, we expect our Upstream and Gathering businesses will generate approximately $115 million to $125 million in free cash flow in 2021. As our production grows in '22 and '23, we expect this level of free cash flow to similarly increase. Obviously, our ability to generate…

Thanks, Dave, and good morning, everyone. Seneca had a strong first quarter. We produced a company record, 79.5 Bcfe, despite approximately 4 Bcf of price-related curtailments in October and early November. Our nearly 40% production increase in Appalachia was largely due to the company's fourth quarter fiscal 2020 acquisition of upstream assets in Tioga County as well as production from our ongoing development program. We continue to see the benefits of our recent acquisition, with increased scale and operational synergies driving a collective $0.10 per Mcfe decrease in G&A and LOE expenses from the prior year's first quarter. With about 6 months of operations now under our belt, we are seeing additional cost reductions above our initial expectations. As an example, LOE reductions of over $50,000 a month have been realized by releasing unneeded equipment rentals and contract services on the acquired assets. Additionally, we achieved between $300,000 to $500,000 per well in reduced water cost on our recent Tioga 007 pad completions through the use of acquired water withdrawal points and storage facilities. In line with our plans discussed on last quarter's call, we added a second drill rig in early January, which will focus on our EDA assets, including the deep inventory of acquired Utica locations in Tioga. This activity will allow Seneca to bring online additional volumes in early fiscal '22, commensurate with the expected availability of our capacity on the Leidy South project, reaching premium markets during the winter heating season. We expect Seneca's other rig to remain focused in the WDA, maintaining relatively balanced activity between these 2 operating areas longer term. Although pricing in fiscal '21 has not been as strong as we initially projected during this winter, the supply and demand fundamentals, whether notwithstanding, remain constructive over the next 12 to 18 months.…

Thank you, John, and good morning, everyone. National Fuel's first quarter GAAP earnings were $0.85 per share when you back out items impacting comparability, including a ceiling test charge and the impact of a gain related to the sale of our timber properties, operating results were $1.06 per share. This increase of 5% over last year was on the strength of our Pipeline & Storage segment results as well as the impact of the Upstream and Gathering acquisition in Appalachia. Dave and John already hit on the high-level drivers, so I'll focus on a few other details from the quarter and discuss our outlook for the remainder of the year. First, in line with our expectations, we closed on the sale of our timber properties in December, receiving net proceeds of $105 million after closing adjustments. As a result, we recorded an after-tax gain of $37 million. We made the decision to divest substantially all of these properties to fund a portion of our Appalachian acquisition. The timing of the sale allowed us to structure the transaction as a like kind of exchange, which defers a relatively sizable tax gain over the life of the Appalachian reserves that we acquired last year. The other large item impacting comparability during the quarter was the $55 million after-tax noncash ceiling test charge. Given where prices are today, we would not expect to record another ceiling test impairment in the fiscal year. Moving to operating results for the quarter. John and Dave hit the high points in our Upstream and Pipeline businesses, so let me touch briefly on earnings at the Utility, which were down $3.5 million versus last year's first quarter. Warmer weather, particularly in our Pennsylvania service territory and an additional accrual for bad debt, likely to result from the pandemic,…

[Operator Instructions]. Your first response is from Brian Singer of Goldman Sachs.

I wanted to start on FM100, but really more from an E&P perspective. As FM100 ramps up at the end of this year, can you talk a little bit more about what goes into the picture from a DUC rig count and ultimately production perspective? You added a second rig in the Eastern development area, how do the DUCs and rigs evolve over the year? And then importantly, should we expect that production will go up, cubic foot per cubic foot, for the new capacity?

John, you want to take that?

Yes, I'll take that. You'll see the production increase. If you go to one of the slides in our deck, let me pull it up. Yes, if you go to Slides 27 and 28, you sort of get a sense for what we're looking at as we go through the remainder of this year into next year. The majority of the production will certainly come out of the WDA. We're drilling around 25 wells there this year completing, I think, around 30. So most of it will come out of the WDA, but we will have additional available volumes if we need them in Lycoming and also in Tioga. We have around 100 million a day on the Dominion line that will connect us to Leidy South. And if necessary, we can certainly utilize the production coming out of Tioga as well. But as far as the growth profile, if you take a look at those 2 slides, you'll get a pretty good feel for how we look.

Great. And then my follow-up is with regard to some of the comments that you made on lower carbon ventures and efficiencies. One is, you mentioned in your comments on convincing customers to use less, which is something that's been embraced on the New York side. What do you see as the range of potential impact of customer efficiency or demand reduction in gas, whether it's in your service areas or more broadly in the Northeast? And then you talked on slide, I think, 48 or so, on renewable natural gas, which you also mentioned in your opening comments. And I wondered if you could just talk about what your key objectives are this year to promote, not only this, but the other low carbon ventures and low carbon resources initiatives that you talked about?

Sure. With respect to efficiency gains, I think over time, it's -- a lot is going to depend on technology from a, call it, a heating equipment perspective. And then how willingly customers are to embrace further insulation and, call it, tightening of the envelope. And our team is busy calculating what those impacts could be. And I don't want to throw out a number of where we think we could get to without getting to them, but it is a meaningful reduction, particularly on the tightening of the envelope side. And when you look at some of the technologies that are coming out, whether it's a gas-fired heat pump or hybrid type system that uses air source heat pump with supplemental gas heat, the potential for meaningful reduction in usage is there. And you point out in New York, we have a revenue decoupling mechanism. So we're largely indifferent to -- well, not largely, we are indifferent to our customers' usage. With respect to RNG, I guess, in the near term, since we really are early innings on it, is first getting RNG plants hooked up to our system so that we're able to take the gas and use it. And then second, working with the commission to allow for our gas purchasing department to include RNG in our overall supply mix. Those would be the two near-term objectives. And then obviously, as we go through time and the industry becomes more mature, it will go from there.

Your next response is from Asit Sen with Bank of America.

I just wanted to follow up on Brian's question on carbon. And Dave, I appreciate all the comments on reducing carbon intensity. And as we await more clarity on energy policy, thanks for sharing those details. But if I'm thinking about broadly as we find out where carbon policies evolve, near term, if I'm thinking about it, it's conservation, and you also mentioned modernization. You gave details on conservation, but is there more -- further opportunities on modernization that could help reducing carbon intensity? And thinking about technology, you said RNG, would hydrogen be a much longer-term aspiration also?

Yes. Well, hydrogen, certainly, long term, would be an opportunity to reduce emissions. And when you look longer term, the best renewable generation sites happen to be very near our service territory. And so it's certainly possible that the -- any excess generation from them could go towards a hydrogen type production facility. In terms of modernization, on the Utility side, we've been -- well, both the Utility and the Pipeline side, we've been at it for a couple of decades in modernizing our system. I think we still have room to go. And at the end of the day, on the Utility side, can certainly get to an 80% reduction relative to 1990 levels. On the Pipeline side, it's a little bit more challenging because we have stack emissions from our compressor stations that we've got to address. But I'm confident over time, we'll find a solution, whether it's new technologies, offsets or something else that hasn't even been thought of.

Got it. And how do you view California and potential ramifications with the changes in energy policy?

John, you want to take that?

Yes. I mean, certainly, California has a larger environmental footprint than our natural gas assets do, but we recognize that. And we actually now have a slide in our deck as well that we're looking to replace some of our power needs through building solar plants out there. And we've done that at North Midway a few years ago. It's proven to be very successful. And we actually hooked up our office to solar power as well, and we'll be moving forward with the plant in South Midway Sunset, which is another key operations or production operations area for us.

John, appreciate -- or congrats on your retirement and appreciate the comments that you made on improvement in cost savings and efficiency post-acquisition last year. Could you comment a little bit on what you're seeing in terms of decline rate on a combined basis? You mentioned earlier that potential improvement. And also, any thoughts on service cost for the balance of this year that you're witnessing?

And you're talking decline rates in Pennsylvania or?

Yes, Pennsylvania.

Okay. Yes. And it pretty much remains the same. Quarter-over-quarter, we don't see a huge difference, but it's in that 20%, 23% range, maybe a little bit lower, some quarters depending on how recently we brought on new pads, but around 20% decline range is what we see across our Pennsylvania assets. And in terms of service costs, honestly, I think they'll remain relatively flat over the next 6 to 12 months. I don't see them going down, especially with where gas prices tend to be going and oil prices. But I think we're -- at least with respect to Seneca, we'll be able to keep our service costs pretty much flat.

Our next response is from Holly Stewart of Scotia Howard Weil.

Maybe first start off by a big congrats to John. John, good luck in your retirement. We are all jealous. And it's definitely been a pleasure working with you all these years.

Thank you, Holly. I appreciate that.

I'll start off with you. On the CapEx, I think, for the first quarter, I mean, really kind of light across the board as you sort of extrapolate it to the full year guidance, but maybe focusing on Upstream specifically, how should we think about that progression of spend throughout the next couple of quarters, assuming we should see quite a bit of jump up in 2Q given the rig add? But just kind of wanted to walk through those thoughts with you.

Yes, that's exactly right. I -- you'll see an increase in our second quarter and then it should remain -- second to third quarters, should remain relatively consistent. But as we step into our fourth quarter and even first quarter of next fiscal year, you'll begin to see that ramp up. As -- because we're deferring some of our completion activity, flowback activity, as a result of waiting for the turn on date of Leidy South, we'll begin to ramp up those -- that activity level pretty much in our fourth quarter is what we see right now.

Sorry, I kind of got confused there. So a ramp-up in spending in 2Q, flat in 3Q and then fourth quarter would decline?

No, we'll see even a further ramp-up. Yes, yes, because there'll be a number of wells that we're going to look to complete in our fourth quarter of this fiscal year and first quarter in next fiscal year, depending on the turn on date of Leidy South, obviously.

Okay. Ramping into that pipe.

Yes.

Okay. Got it. Understood. And then maybe it appears that the free cash flow generation numbers actually went up pretty nicely. I was kind of honing in on that $2.75 type of price, even though you decreased your gas price overall in the guidance. So any sort of color on those -- on what drove kind of that free cash flow increase?

Well, certainly, the increase in production, having the Tioga assets for the entire quarter producing. Our Gathering, obviously, that goes into 100% into our Gathering business, and so that was a big plus. And we had -- as you just pointed out, we had a low CapEx quarter in terms of Seneca as a stand-alone, we will not be generating the same free cash flow because we added that second rig as we go forward. But on a consolidated basis, we will continue to do so.

Sure, sure. And I guess one more for me, if I could, and this is either for John or for Dave. You guys obviously just completed your largest acquisition to date with the Shell deal, but there appears to be sort of more Northeast PA assets that are being talked about on the market. Curious as to your appetite right now for additional M&A?

Yes. I think, as we've said on prior calls, Holly, that we would certainly be interested in adding acreage in the areas that would be adjacent to areas where we're currently active, and in particular, like Lycoming County. Ideally, the -- what we buy would be near us and have a gathering opportunity, and either come with FT or be able to be sold into FT that we have already. So to the extent that stuff comes on the market like that, we definitely would be interested.

[Operator Instructions]. Our next response is from Gordon Loy of Raymond James.

Congratulations to John on your upcoming retirement. So my first question is for John, with kind of the current ship above $50 until about 2023 or so, have there been kind of any discussions regarding increasing spending in California from the $10 million and maybe getting back to the $30 million? And then on top of that, with what does kind of a maintenance level program in California look like?

Okay. Yes, we are already talking about adding development dollars back into California. As we've seen over the last few months, prices continue to improve. I think recently, we're in the mid 50 level, mid-50-plus. And we do have projects out there that make sense in that dollar range. Our struggle right now, and which I don't think or hopefully won't last, as looking in fiscal '22 and beyond, it's still fairly low. I think last I looked it was around $50. So we're looking for that $55 to $60 range, both this year and next year, and then we'll begin to add dollars back into California. I do not see only $10 million in spending on an annual basis out in California. I would prefer to get back up to that to $20 million to $30 million range because we do have 2 or 3 new farming opportunities out there, that so far have been fairly successful, and we would like to get back developing those assets. As far as maintenance mode out in California, our decline rate out there is fairly low. You're looking at anywhere from 6 -- around 6%, plus or minus a couple. Having said that, our -- typically, that $20 million a year is what's really needed to sort of keep our production flat out there. So I would say $20 million, plus or minus a couple of million.

Got it. That makes sense. And then my follow-up, I was looking at the Pipeline & Storage CapEx with the guidance between $250 million to $300 million, is that kind of $50 million delta? How much of that is down to the timing of the start of construction of FM100? And how much of it is just down to kind of other kind of maintenance CapEx type spending?

Yes. So most of it probably is due to the FM100 project and the timing of when those costs hit.

At this time, there are no further questions in the queue. I'd like to turn the conference call back over to Ken Webster for closing remarks.

Thank you, Ditamara. 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 12. 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# 9363257. 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.