Ladies and gentlemen, thank you for standing by and welcome to the National Fuel Gas Company Q4 2019 Earnings Conference Call. At this time all participants are in listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. [Operator Instructions] I would now like to hand your conference over to your speaker today Ken Webster, Director of Investor Relations. Please go ahead sir.

Thank you, Marcella, 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 fourth quarter fiscal 2019 earnings release and October 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.

Thank you, Ken, and good morning, everyone. National Fuel ended its fiscal year with a strong fourth quarter. Record production at Seneca and its corresponding impact on our Gathering segment offset the impact of lower realized natural gas prices and contributed to a 10% increase in year-over-year consolidated operating results. Operationally, we had a really good quarter across the system. Seneca brought on two new pads, one each in the EDA and WDA. Both pads exceeded our expectations. Cash unit costs were down meaningfully year-over-year, a trend we expect will continue as Seneca's base of production grows. Seneca is currently operating 3 rigs in Pennsylvania. As I said on last quarter's call, we plan to release one of those rigs once it's done drilling a 6-well pad in Tioga County, which should be some time in the middle of our second fiscal quarter. I expect we'll stay at that reduced level of activity for the near future. Even at a 2-rig program, Seneca will see production growth of nearly 15% next year and single-digits the following year. Any further activity changes will obviously be dependent on pricing. As we move through the winter season, we will continue to watch prices and reassess our activity level for 2021 and beyond. Seneca's operational success continues to directly benefit our Gathering segment, which, on the strength of record throughput, saw revenue growth of approximately 18% over last year. We expect future Gathering throughput will grow in lockstep with Seneca's production, which should translate into annual revenue growth of approximately 10% on average in the near term. Owning 100% of the Gathering infrastructure that supports Seneca's operations gives us a significant economic advantage. We have attempted to highlight that in the updated IR deck that's available on our website. In it, you'll see that…

Thanks Dave and good morning, everyone. Seneca had a strong fourth quarter. We produced 59.1 Bcfe, an increase of around 25% compared to last year's fourth quarter. Total annual net production came in towards the high end of our guidance at 211.8 Bcfe. Again, a new high for Seneca and around a 19% increase year-over-year. As of fiscal 2019, we have now produced over 1 Tcf of gas from our shale acreage in Pennsylvania. For the year, capital expenditures and expenses on a per unit basis were all within our guidance ranges. Proved reserves increased by almost 600 Bcfe or 23% to 3.1 Tcfe. Our proved developed reserves now make up approximately 67% of our total reserves. And we continue to reduce our three-year average F&D cost, now at $0.56 per Mcfe. We have posted an updated Marcellus and Utica type curves for all of our production areas in our Q4 investor deck, including an updated WDA Utica development type curve on Page 20. As a reminder, our initial Utica type curve was based on our first five appraisal wells in the CRV area. Our updated development type curve is based on results to date for all 26 wells online in this area. This type curve ranges between 1.6 Bcf to 1.7 Bcf per 1,000 foot and assumes all wells going forward are bounded and spaced around 1,200 feet apart. Our latest Utica pad, located to the Southeast in Rich Valley, has now been online for over three months. Four out of the five wells on this pad are performing above our type curve and on a per-well average is our best to date in the WDA. Including this pad, we are now producing from 11 wells along the southern boundary of the CRV area, with 10 of these wells…

Thank you, John, and good morning, everyone. Last night, National Fuel reported fourth quarter adjusted operating results of $0.54 per share, an increase of $0.05 or 10% over last year. The majority of the earnings growth was driven by our nonregulated operations, where the 12 Bcfe year-over-year increase in Seneca's production and the associated Gathering throughput more than offset lower realized natural gas prices. Like any quarter, there were a number of smaller moving pieces, but the earnings release does a good job describing those drivers. The one item worth noting is our effective tax rate for the quarter, which came in at 19.4%, which was below our expectations. The fourth quarter can see some movement year-over-year on our effective rate as we true-up some annual accounting estimates. This year was no different. While I'm at subject of taxes, as a reminder, the enhanced oil recovery credits phased out at the end of fiscal 2019. And as a result, our effective tax rate is expected to increase to approximately 25% for fiscal 2020. Looking to next year, we are revising our fiscal 2020 earnings guidance down to a range of $3 to $3.30 per share. This is principally driven by three main factors. First, we are reducing our natural gas price assumption to $2.40 per MMBtu, down $0.15 from our preliminary guidance. This drop is partially offset by the incremental hedges that we added during the quarter. While our price deck is generally in line with the future strip, for reference, every $0.10 change in NYMEX is approximately $0.05 in earnings per share for the year. We are also revising our expected Midway Sunset oil price premium from 108% to 106% of WTI based on recent realizations in California. The second main item relates to an expected increase in operating…

[Operator Instructions] Your first question comes from the line of Holly Stewart from Scotia Howard Weil. Your line is open.

Good morning.

Hi, Holly.

Maybe the first one, just high level, either Dave or John, just kind of thinking about the comments around having the flexibility to reduce capital spending to Seneca on pricing or related to pricing, if need be. Just can you give us a little color around that comment? I guess, given the hedge book, do you – is this a multiyear lookout? Like, how do you think about the weakness in pricing and your reaction to that?

Thanks, Holly. Our current plan is to drop a rig during the fiscal second quarter. Obviously, that's being driven to reduce our spot exposure at the current script. That rig is currently drilling Utica wells in Tioga. And as we move into the winter season here, we're going to continue to watch and see how prices go. If we're successful in layering in additional firm sales, then that may postpone the chance or the potential drop in that second rig. But at this stage, I think we'll just wait to get to the winter season and then reevaluate at that point whether or not it makes sense to drop another rig.

Okay. And then maybe a follow-on to that, John, would be do you have a level of spending, I guess, that you would think about as kind of maintenance capital? And then is there an associated rig count or well count that we would think about then to kind of hold production flat?

Yes. For us to hold production flat, we've calculated and looked at this before. It's between a 1-rig to 2-rig case, a spend about $250 million to $300 million a year. So at 1 rig, I don't think we'd be able to hold it flat. But certainly, if we're back and forth between 1 to 2 rigs, we can do that.

Okay. That’s super helpful. And then maybe just, John, any incremental color you could provide on the CRV Utica EUR? It looked like it modestly went down even though the laterals appear to have increased?

Yes. It modestly went down on a per foot basis. But honestly, we expected that. Our first five wells were unbounded appraisal wells. Now we’re drilling – each pad that we go to, we’re drilling multiple development wells. Our spacing is about 1,200 foot. So we expected to see a little bit of a decrease now that all of these wells are bounded. So it really wasn’t that big of a surprise to have a slight deduction.

Okay. That’s great. Thanks, guys.

Your next question comes from the line of Tim Winter from Gabelli. Your line is open.

Good morning, and thanks for taking my question. I have sort of a big picture strategic question that follows up on that first one. So the Utility had a nice year, $0.70 a share earnings. And if you look small gas utilities trade 25x earnings, which gets you about $18. Pipeline and storage, Gathering earned $1.52. If you just conservatively put a 15 multiple on that, you’re at about $23. So summed up, you’re at $41. And with NFG at $44, it seems like you’re not getting full value or much value at all for Seneca, but the capital budget of $800 million has about 60% allocated to Seneca. I’m just wondering if you guys are considered buying more regulated assets, like maybe even into the electric or water distribution business?

Yes. Hi Tim, our focus in the near term is on our natural gas opportunities and that’s across the value chain, right? So we’ve got the opportunity to grow the pipeline business in a meaningful way and our existing utility in a, I'll call it, more of a modest way. The returns on the wells that we're drilling, as I said in my remarks, are quite good when you look at it on a consolidated basis. So we feel good about our program. When we think longer term and bigger picture about other directions we might take, I mean, certainly, acquiring other regulated assets, whether they be electric, water or gas are certainly avenues that we could pursue amongst many different ones. As with anything, we got to compare our return potential for what we buy with what we already have. And these are things that we routinely evaluate and discuss with the Board.

Okay, great. Thank you

Your next question comes from the line of Gordon Loy from Raymond James. Your line is open.

Good morning and thanks for taking my question. So I was just looking at Slide 58, kind of where you guys give all the Seneca economics. And I recall in the last – around this time last quarter when we were having the call that the two rigs that are remaining will be located in the WDA. And I was trying to reconcile, just trying to figure out if there's any other factors that you guys had in terms of choosing to allocate the remaining rigs in the drilling program going forward to the WDA instead of to the EDA?

Yes. Sure. Honestly, a rig in the EDA with continued activity there would generate volumes that would have to be sold in the spot market. And at the spot market if prices are poor, obviously, that just wouldn't make a whole lot of sense. Our spot pricing at our receipt point and the WDA has historically ranged between $0.10 to $0.30 better than we see at the EDA sales points at TGP Zone 4 and also in Leidy. And almost all of our activity in the WDA is focused currently on return trips to existing pads with existing infrastructure, which significantly enhances our consolidated economics. We also view a 2-rig program there will allow us to grow into our FM100 Leidy South commitment, which is currently scheduled to come online late in 2021. So that's really the driver of why we have the two rigs from the WDA.

Okay. That's extremely helpful. And I guess, my one follow-up and just kind of a simple clarification question. The return metrics located on Slide 58, they all include factoring in the NRI for the EDA, right?

Absolutely.

Okay. That’s all I had. Thanks for taking my question.

Your next question comes from the line of Chris Sighinolfi [Jefferies LLC]. Your line is open.

Hey, good morning everyone.

Hey, Chris.

Hey. I appreciate all the color this morning as always. I think I have a question for each of you, if I could. Karen, I guess, to start, I appreciate the color on the drivers of earnings tax impacts in 4Q and the change from 2019 to 2020. I'm curious if you have an anticipated cash tax rate you could share? I think the initial expectation a while ago was for modest refunds in fiscal 2019 and 2020, given some ATM usage or credit usage, but I don't know with the passage of time any updates to your plan if that's still a good base.

Yes. So we're still in that position.

Okay. I guess, you had said net financing, you thought, would be $200 million. So I guess I could just back into what that implies, but it was implying a positive number for me. So I just wanted to confirm that.

Yes. That’s very correct.

Okay, thanks for that. And then John, if I could switch and follow up on just the last questioner to better understand the calculation that you've embedded in those consolidated IRRs for Seneca, including Gathering. You note in the footnotes there that Gathering CapEx included is for expected remaining return trip locations. I guess I have an impression of what that means, but I think safer just to ask you what that means. What does that mean? I guess what is included versus excluded in regard to Gathering CapEx?

Yes. It’s all in there. Chris, it's all included.

Okay.

I think it's – all of the Gathering is included in those economics on our return trip actually for all of it.

Okay. So, this – I guess, the sunk cost if you're going to reuse Gathering infrastructure that was predicated for the Marcellus development originally and it gets reused or recycled for Utica development now, how – I guess, is that viewed in the sunk cost and therefore not applicable in the calculation, because it's looking forward? Or do you carve that up and share?

Yes. Now, we look at it on a point-forward basis.

Okay, understood. And that’s what I wanted to make sure. Okay. And then finally, I guess, Dave, for you, there's heightened media focus on utilities and the environment. I mean, if we look at what's going on in – with PG&E in California and the drama between national grid and the PSE and Governor Cuomo here in New York, I'm just curious, with the CLCPA passed earlier this year, what things NFG can do or is doing to prepare for the impacts of that, recognizing, of course, the targeted goals of some years in the future.

Yes, sure. What we're really in the early stages, so it's a little early to say what the exact impact is going to be. This is a process that's going to play out over a few years. The first step is the appointment of a Climate Action Council by January of next year. And then after that, there's four years of process to get any sort of regulation in place. We intend to be an active participant. Donna DeCarolis, who you know is the President of our Utility, was appointed to the Climate Action Council, which is the main committee that will be overseeing the process. So we'll have a seat at the table and be able to keep everyone up to speed as we move through time. But I think, long run, there's definitely going to be a role for an LDC in our service territory. When you just consider a few facts, we serve 95% of the heating load of the customers in our service territory. Our reliability is better than 99.99% or a cold climate better than 75% of the days have temperatures below 30 degrees, and heating with electricity is pretty expensive, as much as four times as expensive is with natural gas in our service territory. So when you overlay this so that we're not necessarily a rich community. The median income in the city of Buffalo is less than $40,000. I think it's pretty hard to see the LDC going away if cost and reliability are factors that will ultimately enter the equation.

And that's part of the Climate Action Committee's mandate is to consider those items as well. I mean, it's my hope, but I'm asking.

Yes. As I understand, the cost benefit is a definite factor. You got to understand, Chris, that this was – if you read the legislation, it basically sets targets and then says, we’re going to – they’re going to set up committees to figure out how we’re going to reach those targets. There’s not…

That is what I noticed. So it’s just – and it feels like having read Governor Cuomo’s letter to PSC about the supply shortage that national grid is talking about. I mean, it’s just – it feels like the Utility is saying we wouldn’t have this problem if you had approved the pipeline, and the Governor’s saying, you have a problem that you didn’t plan for, and it’s your fault. And so, I guess, when you contrast that or compare that against legislation that has defined goals but no defined path, I just worry about anybody getting caught up in that. That’s what sort of prompted the question. And I saw a release you guys put out a couple of days ago about Niagara Falls for zero-net energy home, which you had a role to play in. And I’m just curious like things like that, are they scalable? Is that how NFG distribution sort of fits into the pie?

Yes. I mean, those are all things that we’re exploring. And again, I think the – when you consider the reliability and you consider the cost savings from natural gas, it’s really hard to see how electrification of heating loads in Western New York makes sense for the consumer.

Yes. Okay. All right. Thanks a lot for the color this morning. I appreciate it.

You bet.

[Operator Instructions] Your next question comes from the line of Sam Monnier from G Research. Your line is open.

Hi. Good morning. Thanks for taking my question.

Good morning.

I’m new on following the Appalachian E&P names and of course your company. Can you walk me to the economics of a well? First, how much it costs a drill when completed? And then secondly, using the net gas prices at the current strip, what's the return of the well, just the well, excluding the gathering system?

Yes. If you go to our slide deck on Page 58, all of that information is on there. And as far as the Seneca standalone, our economics are on the footnote on that exact same slide. So it'll go through the costs, the average costs across each of our producing areas. It will give you an average EUR per 1,000 foot and it also will show you our economics both on a standalone and also on a consolidated basis.

Okay. I mean, since you provide CapEx on per 1,000 foot. What’s the average foot per well?

If you also look at that slide, it gives you the average completed lateral length for each of those producing areas.

I see. Okay. I see it now. Okay. Great. Then as my follow-up, you mentioned about dropping one rig next year due to low gas prices. I think you touched on this with Holly earlier. I just want to make sure I understand it. Just a lot of drilling that you do on your own land and not on land held by production. How do you think about trading off between drilling at current prices and holding off and waiting for higher gas prices?

Well, we're pretty well hedged going into next year – actually, we're in this year. We're at 60% hedged. We've already sold 87% of our gas. And as I said with Holly's question, as we go through the winter season, we'll keep an eye on prices, especially strip prices over the next year or two. And at that point, we'll decide does it make sense to continue with the two rig case or is it time to make a change.

Okay. I see. And then I would like to sneak one more question in. I just want to clarify this. The unit cash cost, the $1.25 per Mcfe, is that the all your all-in cash operating cost at the wellhead?

Yes.

Okay. And then since every company seems to define cost differently the cash cost differently, you mentioned LOE and transportation, does that unit cost include SG&A, financing and taxes?

Yes. It does.

Okay. Great. Thank you.

Thank you.

There are no other questions at this time. I'll turn the call back over to Ken Webster for closing remarks.

Thank you, Marcella. We'd like to thank everyone for taking the time to be with us today. A replay of this call will be available at approximately 3 p.m. Eastern Time on both our website and by telephone, and will run through the close of business on Friday, November 8th. To access the replay online, please visit our Investor Relations website at investor.nationalfuelgas.com and to access by telephone, call 1800-585-8367 and enter conference ID number 4581569. This concludes our conference call for today. Thank you, and goodbye.