Good morning. My name is James and I will be your conference operator today. At this time, I’d like to welcome everyone to the Q4 2018 National Fuel Gas Company Earnings Conference Call. All lines have been placed on mute to prevent any background noise. And after the speaker’s remarks, there will be a question-and-answer session. [Operator Instructions] I’d now like to turn the call over to the Director of Investor Relations, Ken Webster. Mr. Webster, please go ahead.

Thank you, James, 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 Ron Tanski, President and Chief Executive Officer; Dave Bauer, 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 2018 earnings release and November 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. National Fuel will be participating in the Jefferies Energy Conference, later this month. If you plan on attending, please contact me or the conference planners to schedule a meeting with the management team. With that, I’ll turn it over to Ron Tanski.

Thanks, Ken. Good morning, everyone. We finished our 2018 fiscal year with a strong quarter; and looking forward, we expect fiscal 2019 will be a good year too. We’ve got a lot to keep us busy, and I’ll give some thoughts on the various activities in our major operating segments, and how they fit within our overall plans for the future. Dave Bauer and John McGinnis will also provide some more color on the financial results detailed in last evening’s earnings release, before we open it up for questions. More than half of our capital expenditures in fiscal 2019 will be directed toward our upstream exploration and production business where we will continue to keep three drilling rigs active. Well results in Seneca’s Utica drilling program continue to meet our initial projections, and those results were instrumental in increasing our proved reserves to 2.5 trillion cubic feet equivalent. We are continuing to look at fine-tuning some of our well designs to maximize the per well reserves while keeping within our drilling budgets. While 2.5 trillion cubic feet equivalent is the highest level of year-end reserves that Seneca has ever reported, what’s equally impressive is that 70% of those reserves are proved developed reserves with only 30% in the proved undeveloped category. The three rig drilling program that is now focusing on 100% Seneca-owned wells is bearing fruit in terms of growing both, production and cash flow. In addition we’ve got a lot of running room with plenty of well locations across our large acreage position in Pennsylvania. Since the bulk of that acreage is owned in fee with no lease expirations to contend with, we’ve taken the conservative approach to drill it only when we have a line of sight to pipeline capacity that is available to get our production…

Thanks, Ron. Good morning, everyone. Seneca produced 47.3 Bcfe during the fourth quarter compared to 40.4 Bcfe in last year’s fourth quarter. Total annual net production was 178.1 Bcfe, a new annual high for Seneca and about a 2.5% increase year-over-year. In the East, we produced 43.2 Bcfe during the fourth quarter compared to 35.6 last year, a 21.5% increase. In California, we produced 682,000 BOEs, down around 14% from last year’s fourth quarter. And this decrease was largely driven by the sale of Sespe earlier this year and natural decline at several of our fields. Capital expenditures for the year were at $356 million, just under the midpoint of our guidance. Expenses on a per unit basis were all within guidance. For the year, our proved reserves increased by 369 Bcfe or 17% to just over 2.5 trillion cubic feet equivalent. Utica reserves, driven primarily within the WDA, more than doubled year-over-year and now account for nearly 20% of our total reserves. As we move forward over the next few years, in conjunction with our increased WDA production, this percent will continue to grow. And finally, we continue to drive down our three-year average F&D costs, now at around $0.74 per Mcfe. So, moving to fiscal 2019 guidance. We are now forecasting capital expenditures to come in a bit lower, now ranging between 460 to $495 million. California is expected to be around $25 million and Pennsylvania between 435 to $470 million. Net production is expected to range between 210 to 230 Bcfe, a forecasted increase of around 24% year-over-year at the midpoint. As stated last quarter, we will continue with the three-rig program, two rigs active in the WDA, drilling mostly Utica wells on existing CRV pads, and a single rig in the EDA, drilling Utica wells in…

Thanks, John. Good morning, everyone. Last night, National Fuel reported fourth quarter operating results of $0.49 per share. Though a little below Street consensus, these results were right in line with the guidance we provided last quarter. Our E&P and gathering businesses had good quarters. On a combined basis, the operating income of these businesses increased by $1 million over last year. As John mentioned earlier, Seneca’s production was up 17% compared to the prior year and its operating expenses were all in line with our expectations. In addition to benefiting Seneca, this production growth drove a 14% increase in gathering revenues during the quarter. Unfortunately, as in the first three quarters, the expiration of favorable hedge contracts caused a $0.46 drop in realized natural gas prices which offset the benefit from higher production. Going forward, quarter-over-quarter comparisons of realized natural gas prices should be much more muted, given our strong marketing, portfolio and hedge position. At the pipeline business, O&M spending increased by $2.8 million over last year. As I discussed on last quarter’s call, in the near term, we expect to see significant increases in our compressor maintenance and pipeline integrity spending due to cyclically higher than normal required levels of activity. Some of that activity started in the fourth quarter of fiscal 2018, leading to the increase in O&M spending. This maintenance spending offset what was otherwise a good quarter for the pipeline business where revenues were up $2.6 million or nearly 4%, as a result of both our Line D Expansion that went in service last November and our storage acquisition that closed this past May. We also saw some nice demand for short-term service on our systems. Utility margin was down versus the prior year’s fourth quarter, as a result of a transition to a…

[Operator Instructions] And your first question comes from the line of Graham Price from Raymond James. Go ahead, please. Your line is open.

Hey. Good morning, guys, and thanks for taking my questions. I guess, given that it’s year-end, just wanted to get a sense of where the annual base decline rate on existing production stands today. And then, maybe where you see that changing over time?

I couldn’t tell you across our basin what the annual decline rate actually is. But, I think, in terms of how it will change, the Utica wells -- let’s focus on the WDA where most of our activity is. The Utica wells there do have a shallower decline than the Marcellus wells, over the first year or two. And then, the two, both Marcellus and Utica at that stage tend to decline similarly, at similar percent on a year-over-year basis. So, as we drill more and more Utica wells, we will see a bit more shallower decline related to the -- as we develop that Utica program. But, then it sort of conforms to what we see related to the Marcellus as well.

Thanks. That’s definitely helpful. And then, for my follow-up, I was just curious to kind of get a sense of when we might see further delineation kind of in southern WDA area sort of near the Boone Mountain well?

Sure. I think, our next appraisal well is scheduled for our fourth quarter of this fiscal year or first quarter of 2020, and that will be located approximately 5, 10 miles north, northeast of the Boone Mountain well. So, it will be a year out, maybe a little bit less.

[Operator Instructions] Your next question comes from the line of Chris Sighinolfi from Jefferies. Go ahead, please. Your line is open.

Dave, I always appreciate the detailed remarks in your outlook. If we could, could we circle back to pipeline and utility operating cost for a moment? I know you had flagged this on last quarter. And I don’t know if I just misscalibrated your comments at that point for if spending shifted modestly from 2019 into 4Q. It seems like that might have happened, based on your comments. But, I guess, I’m curious if you could quantify -- if that did happen, if you could quantify the magnitude. And then, also, what drives the timing of when that spend has to happen?

Yes. Chris, there’s a little bit of spending that moved forward, but not a ton. I mean, may be 1 million or so dollars. And in terms of what’s driving the timing for our compressor units, it’s all based on the number of run hours. So, you have to do these overhauls every increment. And we just happen to have a number of our units, all reach those milestones within the same year. The other element is on the pipeline integrity side. We’ve got to do integrity assessments on a seven-year cycle. So, we take our whole system and split it into seven different components. It just so happens that fiscal ‘18 -- or excuse me, the work that we’re doing in fiscal 2019 is the highest year in that seven-year cycle. So, we’ve got a couple of things that are going against us on -- all on the same year, but then that should moderate as we get into 2020.

Yes. I guess, what I’m interested is that I think you had revised the O&M increase in the pipes to a range 5% to 7.5% year-on-year next year, which incorporates I guess both of those activities. And then, if we’d profile ‘20, how much would you estimate or help us guide, of that might come back up?

I guess, I don’t want to be overly specific on and I wouldn’t certainly expect a similar level of increase. I think, there’s a good chance that we’d actually have lower O&M expense in 2020 than what we will in 2019.

Okay. And then, I guess on utilities side in that regard, you talked about the transition of the low-income program in New York. I think that’s something you flagged earlier on in the year as well. But the $2.5 million that you had mentioned for fiscal 4Q as sort of a temporal shift when it’s recognized. Should we expect then the benefit perhaps in fiscal 1Q or 2Q ‘19, your higher activity and earnings quarter, so that utility would have -- the order of benefit would be very similar to that 2.5?

Yes. The level of discounts that are granted stay exactly the same, it’s just that instead of recognizing them kind of as volumes flow through the system, it’s going to be on a straight line basis. So, that’s going to have the effect of punishing the low volume quarters and helping the high volume quarters. But, you are thinking about it the right way.

Okay. And one more question on the utility, Dave. The bad debt has been something I think that’s been a bit of a tailwind as we’ve had very strong economic climate and low interest rate. But we have seen rates rising and we’ve seen articles about some of the credit card companies becoming a little bit more careful about their lending standards et cetera. So how much of bad debt expense is tied to rates or I guess better stated, what drives the assessment on that?

Yes. So the adjustment that we were talking about was made in the fourth quarter of fiscal 2017 and it didn’t recur in 2018. So when you go back to fiscal 2017 we had a pretty warm winter. And so customer bills were lower than we had expected. And so we accrued an amount of bad debt expense over the course of the first three quarters of fiscal 2017 that was higher than we actually needed. So we took that down in the fourth quarter of 2017. When you look at 2018, our level of bad debt expense or I should say the level of final bills and late bills really isn’t that different than what it’s been in the past. So we haven’t really seen much of deterioration in the credit or payment habits of our customers.

Okay, I misunderstood it. I think it was just really -- your comments were addressing the year-on-year change not a change on the customer base.

Right.

Okay, understood. Sorry about that. Okay, if I can ask just one or two more questions intended to John. Obviously, I realized the full Netherland Sewell reserve report is not out yet, we’ll wait for your K for that. But just curious, I think you had said in the prepared remarks that 20% or 500 BOEs now out of the reserve base is represented by Utica. Curious the detail -- a little bit more detail about maybe the type curves used by Netherland Sewell in assessing the Utica program and the Marcellus program, is that the same as what you’ve posted and discussed today? Or did they make any adjustments that we should be aware of?

Chris, it’s early in the process. As you know a lot of these -- the Utica wells have only been producing for two years or less. But we are very similar to what Netherland Sewell has posted, and you’ll see the detail as we -- once we release that information. It’s mostly WDA, is where we have the reserve increases. We do have some in 007, since we’re drilling and we’ll be bringing on some new Utica wells there as well. But really the driver is the WDA. Yes, there is -- early on in these programs, there’s a little bit of deviation, but as time goes on, it tightens up.

Okay. Deviation where they as the reserve auditor would tend to be more conservative than you?

It varies. Sometimes we tend to be a bit more conservative, sometimes they do.

Okay. And the time -- I guess you’ve had a shift in your program focus over the last year obviously toward more Utica development. Any comment -- I guess any help in explaining maybe the influence that might have had on what we’ll ultimately would see in this reserve report?

I’m not sure I understand that question.

Well, you obviously pivoted in terms of the focus of the program and I would imagine that would influence how they’re going to look at a five-year window of development activity for each of the regions.

Certainly, our focus in the WDA is going to be Utica. I guess, Chris, I’m still not sure I understand what -- where your question is here.

Well I was just -- I guess trying to gauge, John, year-on-year given the pivot in the program as Netherland will look that. I guess they’re tethered to one and the same type curve comment and how much to anticipate. I mean you obviously share with them a little bit more about your detail in terms of what you’re going to do longer term than maybe we see in your official financial forecasts. So I was just curious how much you might have deviated not only in terms of the type curve view, but in terms of the activity level on WDA versus maybe what they had thought you would do a year ago?

Yes. I’m not going to comment on that Chris. At some stage our Reservoir Engineering Group goes through this well-by-well about how on a well-by-well difference between each and every one between Netherland Sewell and Seneca is -- that’s something I would have to sit down and really walk through. So that’s just -- that’s a lot of detail that we typically just don’t get into. But suffice it to say that Netherland Sewell and Seneca are well within our boundaries in terms of how we look at the Utica.

Understood. Thanks for the time.

Your next question comes from the line of George Wang from Citi. Go ahead please, you line is open.

I just want to hone in on Utica. It seems that one of the biggest drivers was stock. So just in terms of D&C design just namely the drill and the competing design for Utica, can you give more color on whether you guys are still tweaking to find the best well spacing and landing zone? Just also the impact to potential well cost savings than the improving returns?

Sure I’ll touch on that. And as I said in my statement today, we’ll get into much more detail on that in six months as we continue to get more information. But right now, we’ve been testing and let’s begin at stage spacing. We’ve been testing between 150- to 200-foot stage spacing to determine if we see any impact to production. Obviously, if we move to 200-foot, that will be cost saving in terms of our -- on a cost per-well basis. We have also been testing target in our area there is -- we’ve been drilling within both lower Utica and then a little bit deeper in what we call the upper Point Pleasant. And over the next six months, we’ll have sufficient wells within both of those zones to, again, determine which -- where we see better production and, I guess, more effective fracking. As far as well spacing, we’re starting wide around 1,200-foot. And with time, once we lockdown the state spacing the target -- what target we’re going to focus on, then we can begin to look at whether or not we want to begin to tighten the well spacing up. But right now, at least for the near future, we’re going to -- we’ll be at 1,200-foot.

Got you. And for the WDA Utica, in terms of restricted drawdown, have you quantified a potential improvement to EUR just with a better draw down management?

Yes. It’s hard to speak specifically to how -- what the difference in the EUR will be. All we know is that we did bring on two wells early in the program without the draw down management and both of those two wells are to-date, by far our worst wells. And so what time? It does make significant difference, I would say on a per foot basis -- I am sorry. I was going to say 300 to 400 Ms per 1,000-foot. So, it makes a significant difference.

Got you. Good to hear. And my last question, just with more producing wells in the Utica and most of data point under the belt. Can you guys comment on sort of your latest Utica test results in comparison to other kind of peers, especially in the northeast of PA?

Well, I can certainly do it with -- in terms of Tioga. We don’t have a whole lot of peers in and around our WDA activity. But when you go to our Tioga or 007 track, we actually have a slide in the deck -- let’s see what page that is, on Slide 26 that shows exactly how we compare to the surrounding Utica wells.

Your next question comes from the line of Holly Stewart from Scotia Howard Weil. Go ahead please, you line is open.

John, I missed that last comment on those wells on the draw down management. Specifically what wells were you referring to? And then if you could just sort of repeat yourself on that?

We had two wells early. We’ve talked about this about a year ago maybe a little more on a pad we call E09-S that we brought those wells on too strongly. And they did not perform the same as the rest of our -- basically the rest of our inventory there.

Okay. And is there a specific rate right now that you’re getting those wells up to and holding them at?

No, it’s more just watching how much the pressure declines on a daily basis.

Okay.

It has nothing to do with the rate. Yes, it’s just press decline. We’re just minimizing that.

Yes. Okay, just wanted to clarify that. And then I apologize if I missed this as well, but can you just give a little color on how to think about that production cadence in 2019. I heard in -- I guess in your initial comments about owning an 11-well CRV pad coming online. I know there is -- maybe it’s a larger pad at 007. So I’m just trying to think about how we should model kind of the production coming in throughout 2019?

Sure. We’re going to be bringing on, in terms of bringing online wells, right now we’re scheduled to bring out about 45 wells; 21 of those will be Utica and of those Utica, four will be in 007. And then we’ll be -- the others we’ll be bringing on 24 Marcellus wells. And that will be split between the WDA and Lycoming.

Okay. And any front half versus back half weighted that we should kind of think through?

Yes. The WDA Utica has certainly weighted heavier than the front half. I think we have one other pad that comes on in the back half in the WDA that are six wells in the Utica. And then most of our WDA Marcellus wells will be in the back half. And then Lycoming and the EDA I mean -- and 007 are sort of spread evenly across the calendar year or across the fiscal year.

Okay, that’s great. And then, maybe just one last one I guess also for you John would just be on, what you’re seeing, maybe if it’s service cost deflation or escalation. What you’re seeing thus far and kind of what your expectation is in 2019?

It’s actually been fairly flat. Potentially a little bit of creep on the drill side. But I think at least on the completion side we should -- I’m hoping that we should stay relatively flat.

And there are no further questions at this time. I’ll turn the call back over to Ken Webster.

Thank you, James. 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 3:00 p.m. Eastern Time on both our website and by telephone and will run through the close of business on Friday, November 9th. 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 5899309. This concludes our conference call for today. Thank you and goodbye.

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