Good morning, my name is Kelly, and I will be your conference operator today. At this time, I would like to welcome everyone to the Fourth Quarter 2017 National Fuel Gas Company Earnings Conference Call. [Operator Instructions] Mr. Brian Welsch, Director of Investor Relations, you may begin your conference.

Thank you, Kelly, 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 Corporation. At the end of the prepared remarks, we will open the discussion to questions. The fourth quarter fiscal 2017 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 in Houston. If you plan on attending, please contact me or the conference planners to schedule a meeting with the management team. And with that, I'll turn it over to Ron Tanski.

Thank you, Brian, and good morning, everyone. Thanks for joining us today. Our 2017 fiscal year was another strong year for National Fuel, both earnings-wise and operationally. Each of our main operating segments posted strong earnings that were in line with our projections and Dave Bauer and John McGinnis will give more details about segment earnings drivers later in the call. As we noted in the guidance section of the release, earnings for 2018 fiscal year are forecasted to be down slightly, in large part, the decreased results from lower realized commodity prices in our Exploration and Production segment, where the higher priced financial hedges that we had in place have rolled off. Forward strip prices remain relatively flat in a $3 per MMBtu strip price and a $2.40 per MMBtu spot price where our natural gas production have been built into our forecast for next year. While this flat pricing appears to be the new normal and resets the base of our pricing assumptions moving forward, we illustrate in our Investor Relations slide deck that our drilling program remains economic in this environment. Unfortunately, we'll be missing the boost to earnings that we had expected from our Northern Access Project, which has been delayed. In our second circuit litigation against the New York DEC, oral argument for our case has been scheduled for November 16. If we were to use the Constitution lawsuit as an indicator of the time line, we may not get a decision from the court until August. Remember that the facts in our case are different from the facts in Constitution and we're not discouraged by the outcome in that case. As you know, we're also awaiting FERC action on our request for rehearing with respect to our waiver argument regarding New York's action --…

Thanks, Ron, and good morning, everyone. Seneca produced 40.4 Bcfe during the fourth quarter compared to 39.8 Bcfe in last year's fourth quarter. Total annual net production was 173.25 Bcfe this year. That is a new annual high for Seneca and was an 8% increase year-over-year and a total of 10% over the past 2 years, even while dropping to 1 rig from much of that time and entering into a joint development agreement where Seneca's working interest was reduced to 20%. Additionally, Seneca has generated significant positive cash flow each of the last 2 years, all in spite of weathering a tough commodity price environment. We achieved this through a combination of best-in-class Marcellus well costs, a joint development agreement with IOG and continuing to follow a disciplined risk management approach by locking in prices physically and financially when opportunities arise. Moving forward, we should continue to be cash flow neutral to positive over the next few years, even with our forecasted 10%-plus average annual production growth, as we execute on our long-term development plans. Our production growth for the year was largely driven by stronger-than-expected Marcellus well performance, including better-than-projected flush production rates as we brought on previously curtailed wells and minimal curtailments due to the improved strength in the spot market. For the year, we curtailed a total of 6.2 Bcf net compared to 34.6 Bcf last year. Much of these curtailed volumes actually occurred very early and very late in the fiscal year. Our capital expenditures totaled $246 million, an increase of $147 million compared to last year. The key drivers for this increase included lower year-over-year upfront and working interest proceeds associated with the IOG joint development agreement, bringing on a second rig in May and drilling and completing a greater number of 100% working…

Thanks, John. Good morning, everyone. Last night, National Fuel reported fourth quarter earnings per share of $0.53. While this was lower than the $0.66 per share on last year's fourth quarter, earnings were right in line with our projections. For the full fiscal year, operating results were $3.30 per share, an increase of 7%. The earnings for the quarter at the regulated subsidiaries were pretty straightforward. The only item of note was O&M expense in the Pipeline & Storage segment, which was up $3.4 million over last year. During the quarter, we incurred about $1.5 million in cost to overhaul 2 major compressor units. While overhauls themselves aren't unusual, we typically don't have 2 in 1 quarter. We also saw an increase in project development costs, mostly related to the Empire North project. As you'll recall, we gave conservative approach with respect to these costs and expensed them in the early development -- early stages of development. At Seneca, production for the year was a little below the midpoint of our guidance. In the latter part of the quarter, spot pricing in Appalachia dropped significantly from levels we saw earlier in the year. Not only did this reduce price realizations relative to forecast, but it also led us to curtail 2.5 Bcf of production during the quarter, which in addition to impacting Seneca's production, had a follow-on effect on our Gathering business. Spot prices have remained depressed throughout October. But as cold weather returns and as new infrastructures added in the basin, we expect prices will recover. There were a couple of unusual expense items during the quarter at Seneca that we don't expect to repeat. First, LOE came in as $1.07 per Mcfe, which was meaningfully higher than in prior quarters, but it was generally in line with our…

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

Maybe first for John. If you could just give us a sense of -- I think you said in 2019 that the WDA would be just specific to Utica development, but give us a sense this year in 2018 in both the WDA and EDA, kind of the split there between Marcellus and Utica. And if you've got well count numbers, that will be great.

Sure. As I mentioned in the discussion just now, we still have 3 wells that are currently coming on and we will be drilling 3 more wells, I think, for the -- at least bring in 3 more wells online during 2018 in the WDA area. So we'll be doing some drilling. I don't have that drill count now, but I know we'll be bringing on 3 additional wells. Out East, once we're done in Gamble, we'll be moving to Tioga on our first pad there and I believe it's 7 wells that we'll be drilling on that pad, and that will all take place during this fiscal year. We won't see production from that until 2019. I believe we head there in the second quarter.

Okay. And then another one just on Atlantic Sunrise, if you could maybe help us just understand how you envision that project filling up. Is it 100% full on day 1? Is that existing production versus incremental production? Just trying to think about how you utilize that project from the get-go?

Yes. It'll be full on day 1. We have existing production there now, could fill it today. And we're projecting that it comes on in July. And if we see that it's going to slip a little bit, we may be out in the market trying to fill that gap. But as of today, we could fill it from day 1.

Okay, great. And then just one final one from me and Dave referenced it in his comments, but just wanted to follow up. Assuming at this point, given where we are in the spot market, we are still curtailing volumes for 1Q?

Yes.

And your next question comes from the line of Graham Price of Raymond James.

Just real quick on the Utica test wells. Just wanted to get a sense of maybe how much testing is left with regard to determining optimal proppant loads and stage spacing, things like that. And then any potential uplifts to EURs that we could see from that?

Yes. A quite a bit of testing is left to do. For example, in the 3 most recent wells, we actually tested 3 different targets. And they're all within 30, 40 feet of each other, but we've actually seen differences even with that small of a change. As we move forward, we will -- it will be an ongoing, I guess, testing program. We will be changing -- at least into for the next year, we'll be testing different stage spaces -- spacing. We'll be testing different well spacing as well. So still quite a bit of work to do. And in terms of improving these well results significantly, I don't think that will happen. It's more towards fine-tuning and cost-saving.

Okay, got it. That's great. And then real quick for my follow-up, just wondering about completed well costs for those 8 Utica wells that have been drilled. I know that these costs will be coming down, but just kind of wanted to get a sense of maybe where you're at today.

Well, overall, they're about 20% higher and most of that is on the completion side. I don't know what they are today, but I know we're expecting, on the completion side, they'll be a little north of $3 million once we move into full development.

Okay. And you expect to move to full development kind of late 2018?

Yes. Yes, towards the end of 2018 moving into 2019, we will have fine-tuned our completion practices and be moving forward on that.

Your next question comes from the line of Becca Followill of U.S. Capital Advisors.

Just following up on that question. I think you said it's $3 million for completed well costs for just the completions portion?

It will be a little over between $3 million and $3.5 million.

And then the drilling portion?

We're estimating a little over 2 -- between $2 million and $2.5 million. So in all-in, between $5.5 million to $6.5 million, I think we're looking at $6 million, $6.2 million.

And that's where you expect to be?

That where we expect to be. It's a little more expensive now because we do a lot of science on these pads -- on these wells. Our stage spacing is tighter than what I think it'll end up. So there's still a lot of work to do, but it will reduce as we go forward.

How long do you think to get to that level?

Within a year, 9 months to a year.

And targeted well spacing at this point?

Good question. Probably minimum, 1,000 foot. But I think we'll probably start a little wider that, around 1,200. But that's something we are still working out.

Great. And then last question is, can you tell us how much gas was curtailed during October?

About 1.5 Bcf.

And your next question comes from the line of Tate Sullivan of Sidoti.

Can you go into more detail on your utility, just in terms of the customer growth rates year-over-year? I think it declined slightly in Pennsylvania, and give some context for those rates of growth?

Sure. Our -- as you know, we've got a pretty high concentration of the customer base in both New York and PA at better than 95%. There is some population growth, but we don't count on large growth in customer count, probably in the 0.5% area per year.

About 0.5% percent per year?

Yes.

Okay, great. And then the year-over-year decline in the quarter in the utility, was some of that weather related in Pennsylvania or was it mostly the lower rate case coming through in New York in April?

So you're saying the earnings of...

For just the utilities.

Quarter-over-quarter?

Year-over-year?

Oh, year-over-year. Yes, the biggest chunk of that is going to be weather in Pennsylvania, which was -- I think the winter was somewhere around the 10% warmer than normal area. On top of that, we had some costs creep in the OEM side, but weather was, by far, the biggest factor.

[Operator Instructions] Your next question comes from the line of Chris Sighinolfi from Jefferies.

Dave, I just had a question with regard to the timing of that deferred tax liability reassessment. Was that due to something within the regulatory approval process for Atlantic Sunrise or the fact that you're [ heading ] a fiscal year or something else? Just what -- I guess, what made you take a reassessment at this point?

So this is with respect to the Atlantic Sunrise adjustment?

Yes. Your PA tax going down.

Yes, you got to pick a time when we make the adjustment. We've typically been pretty conservative and waited until we've seen shovels in the ground to make the adjustment. So with construction pretty much underway on Atlantic Sunrise, the probability of that project being completed was high in our estimate and that led us to record the adjustment.

Okay, okay. That's helpful. And I guess, what would be next steps for Empire North? I did see some incremental precedent agreement volumes added, I think, since the last call. And you had obviously mentioned in prepared remarks some additional expensing items associated with that project this past quarter. So I'm just wondering what milestones to look forward to, to [ strip date's ] progress on that and potential time line for it?

Yes. The next steps would be the actual filing of the FERC application for the 7(c) for that project, Chris, and that's basically it. The spending to date has been preliminary engineering for the compressor sites and logistics for that. So we're looking to get that done pretty close to the end of the year. And as a matter of fact, we're starting outreach hearing or outreach meetings next week to cover any questions that locals might have with respect to the siting of those compressor sites.

When -- Ron, when you say the end of the year, you mean this calendar year?

Yes, the calendar year, yes. I'm sorry.

Just being -- okay. And with -- I guess, with regard to the precedent agreements in place on that project, are those both third parties or a Seneca represented at all on that front?

No. Seneca is not represented. So a portion of it, however, is our utility and I forget the exact portion of that, Dave. Do you...

Yes, it's relatively small.

Yes, it's a relatively small. But it's a third-party production that would be utilizing that space.

Okay. Two more questions, if I could. One was, Dave, if I heard you correctly with regard to the payment made, I guess, that was to TransCanada just to keep on ice for some time the ability to carry the Northern Access volumes all the way into [indiscernible]. Is that right? Is that sort of how to understand it? Then if Northern Access does eventually go forward, they complete their portion of the build, you get reimbursed?

That's exactly right, Chris. It basically suspends the project until we get approval on Northern Access.

Okay, okay. And then, I guess, a final question from me is just there's -- there was a shareholder proposal or idea floated about tracking stock potentially for your utility company. And then I have my own thoughts about it, but I was just curious if you guys had obviously considered that and thought about it either amongst the management team or conversation at the board level and what, if any, response or thought you've given to that.

Yes. It's a little tough to comment on that right at this point in time, Chris. We're in the process -- yes, the lawyers are concerned about anything we say being considered proxy solicitation. So I'd just prefer not to comment on it at this point.

[Operator Instructions] And there seems to be no further questions at this time. I turn the call over to the -- back to the presenters for closing remarks.

Thank you, Kelly. 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 10. To access the replay online, please visit our Investor Relations website at investor.nationalfuelgas.com. To access by telephone, call 1 (800) 585-8367 and enter the conference ID number 96083185. This concludes our conference call for today. Thank you, and goodbye.

And this does conclude today's call. You may now disconnect.