Good morning. My name is Carol, and I will be your operator today. At this time, I would like to welcome everyone to the National Fuel Gas Company Second Quarter 2019 Earnings Call. All lines have been placed on mute to prevent any background noise. After the speaker’s remarks, we will have a question-and-answer session. [Operator Instructions] At this time, I would like to turn the call over to Ken Webster, Director of Investor Relations. Mr. Webster, please go ahead.

Thank you, Carol 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 second quarter fiscal 2019 earnings release and May 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 AGA Financial Forum later this month in Fort Lauderdale. If you plan on attending, please contact me to schedule a meeting with the management team. With that, I’ll turn it over to Ron Tanski.

Thanks, Ken. Good morning, everyone. Thanks for joining us. As we highlighted in last evening's release, earnings for the second fiscal quarter of 2019 were fairly consistent with last year and in line with our expectations. Emerging from the winter heating season that was slightly colder than last year in our New York jurisdiction, we saw a slight uptick in earnings in the utility business where throughput was 1.7 billion cubic feet higher than last year's second quarter. Because our weather normalization mechanism offsets most of the impact of colder weather, the increase in utility earnings came largely from higher margin, lower interest expense and other minor rate adjustments. The higher earnings in utility helped to offset an expected decrease in the pipeline and storage segments earnings that was caused by the expiration of a shippers transportation contract and our Empire Pipeline system. As we've talked about before, KeySpan had used that capacity to import Canadian gas and transport it to its downstate service territory. The proliferation of Pennsylvania shale production closer to keySpan service territory ultimately made the Canadian gas uneconomic and KeySpan let the contract expire at the end of its term. Today, the capacity on the pipeline is fully contracted to move gas in the opposite direction and that capacity will be further expanded next year. In our exploration and production business, even though we achieved our highest ever average daily production rate this past quarter, we were expecting more. It's a slight disappointment that we modestly lowered the midpoint of our production guidance to the low end of the range that we established last August. Operationally, we've experienced longer drilling and completion times on our Utica wells which will shift production that we had planned for this year the fiscal 2020. The delay in well the…

Thanks, Ron. Good morning, everyone. Seneca experience mixed results in the second quarter. On a positive note, we saw some really nice well results. We brought to production four Utica development wells at DCNR 007, the first new wells since 2016. These wells are looking great and this trust is now producing over 60 million a day. Three other wells are producing at rates of around 15 million a day and our fourth well which is still cleaning up is currently at just over 10 million a day. Our two new Marcellus wells at DCNR 100 came on as expected as did our most recent Utica pad and the WDA. However, the quarter was not without its challenges. Though we achieved record daily production levels this quarter, we felt short of our expectations. The shortfall relative to our expectations was mostly a result of some operational curtailments. The impact of our continued testing efforts to optimize our Utica drilling and completion design and the WDA and to a lesser extent, drilling and completion delays at Tract 007 and the EDA. While these operational delays have the effect of pushing production out of the future periods, they are not expected to have a material impact on our ultimate well recoveries or program economics. Looking to the full year, we are lowering our fiscal '19 production forecast by around 5% or 10 Bcf at the midpoint, to a range of 205 Bcf to 215 Bcf. In addition to the items I discussed pertaining to the second quarter. Our revised guidance range reflects the expected impact of drilling and completion delays and the EDA on production for the remainder of the year and builds in additional production downtime to reflect the operational realities we experienced in the first half of the fiscal year.…

Thank you, John. Good morning, everyone. National Fuel's second quarter GAAP earnings were $1.04 per share. Similar to last quarter, we had items impacting comparability relating to hedging ineffectiveness and the marked-to-market of investments in the non-qualified benefit plan. Excluding those items our operating results were $1.07 per share, which is still a little below Street consensus, we're right in line with our own expectations. This was a quarter, where the benefits of our integrated, diversified business model were particularly evident. Our regulated businesses, utility in particular had strong quarters relative to forecast, which helped offset the near-term challenges in Appalachia that John described earlier. Looking at the results of our operating segments, the Utility had a really nice quarter, driven in large part by improved operating margins, which excluding the refund provision for income tax reform, were up $0.02 per share. This was the result of two main factors. First, we are seeing a modest amount of customer and industrial usage growth which can be attributed to the continued strong economic backdrop in our service territories and the cost advantages of natural gas. Second, the system modernization tracking mechanism Ron described earlier contributed a little less than $1 million of additional margin. We expect this tracker will provide about another $2 million for the remainder of the year, as the weather breaks and our level of construction activity ramps up. Surcharges accrued volumetrically, so similar to most ratemaking items, there will be some seasonality to the cash flows and earnings related to this mechanism. As expected the earnings of the FERC regulated pipeline businesses were down relative to last year largely due to the loss of a key spent on tract on the Empire system, which Ron described earlier. This reduced revenue by about $6 million in the quarter,…

[Operator Instructions] Our first question today comes from Holly Stewart from Scotia Howard Weil. Please go ahead.

Hi, good morning gentlemen. Congratulations Ron, may be all be so lucky.

It gets to you faster than you think Holly.

Maybe I'll start off one for, John, just you mentioned the minimal curtailments in the guidance, just maybe high level. How are your viewing the market right now and EDAs, is this temporary maybe due to the just shorter season patterns in demand or are we seeing pipes backfill post-Atlantic Sunrise in the whitening maybe to continue here?

Holly, obviously during the shoulder months, we always see this kind of decrease in spot prices across the basin to tell you the truth. Honestly, I hope it's temporary but we were expecting maybe a little bit lower prices through summer. But as always It depends a little bit on how hot the summer is.

True.

But as -- we've locked in quite a bit. So we do have some exposure, but if it stays in just above that $2 and above, we're -- I think that we're actually fine with that.

Okay, that's good color. Maybe I guess on that note, recognizing you're pretty locked in on the firm sales for 2019. But given pricing overall for NYMEX is kind of trending toward multiyear lows here. How are you thinking about that three rig program as we move into the back half of 2019 and beyond?

Yes, well, we've committed to firm capacity on pipe. And so we have -- we'll stay at three rigs, we've committed to light self, it's $330 million a day and so our goal in the short term, at least over the next couple of years is to make sure that when that pipe comes online that we can fill it.

Okay, great. And then maybe just one to other one we've heard a lot I think this quarter about just water in general, whether it's impacting the LOE or whether it's actually water infrastructure assets for sale. So it's been pretty topical, can you maybe help us think through your water handling both in the EDA and the WDA and if there is an opportunity for your midstream business, I guess it would be particularly in the EDA on third quarter water volumes?

Yes, it's actually a tough question. We have a very large Central Water Facility in the WDA. In the EDA, it's much smaller because the volumes that we see being produced in the East or just not what we see in the West. So we do -- we have a very large water facility. We typically do bring in third-party produce water when it is necessary. When we need the water, but we also will supply water to other operators, when they need it. I'm not sure it's a business, I want to get into. We view it as a means in which to drive down our water costs.

Okay, that's helpful. Thank you, guys.

Our next question comes from Ryan Levine from Citi. Please go ahead.

Good morning. What percentage of your California production is urban and how do you view the exposure to some of the political commentary coming out of the state?

Yeah, it's California's fun place to do business. Honestly, we don't see this Bill, I think it's Bill 345 which you're referring to. We don't believe the bill will survive. There's a lot of opposition already and not just from our own industry. But having said that, we have stepped back and taken a look at the potential impact on our operations. And honestly, we think it would be minimal because almost all of our operations are very rural in the San Joaquin basin.

And is any of the rural near any hospitals or any key infrastructure that is being proposed to be of concern?

No.

Okay. That's all from me. Thank you.

Our next question comes from Gordon Loy from Raymond James. Please go ahead.

Good morning, all and thank you for your time. So I just had kind of two quick questions, but the first one in the opening remarks. You guys mentioned that there is a continued trend towards drilling longer laterals and I just wanted to get a sense of, I guess what's the average lateral length that the company is drilling now and where do you guys foresee that going to.

Sure. Let's start in the WDA, six months -- nine months ago, we're drilling 6,000 foot roughly plus or minus a thousand foot appraisal wells in the Utica. Today we're drilling eight, nine, even over 10,000 foot Utica wells. Our Marcellus wells, we just recently drilled Marcellus pad. We typically average 6,000 to 7,000 foot, most of those wells were 8,000, 9,000, 10,000 foot. well, so we're seeing an increase of anywhere from 2,000 to 3,000 feet collateral, at least in the WDA. Perfect example in the East is we're now at a pad, in the Gamba Lycoming area, where we had assumed or expected that we'd be drilling 4,500 foot lateral. We just finished that well and it ended up being I think north of 55 if I remember correctly. And so just to give you a sense of perspective let's go to the West. For every 2500 foot of lateral, probably adds -- let's say we have four wells on a pad that may add four or five days to drill time and it may add, obviously it's going to add additional completion time, because we are going to be have more stages. So every four, five, six well pad for drilling that greater of a lateral, if I add anywhere from three to four weeks just to get that that pad online,

Got it, that makes sense. And then my follow-up is -- I'm looking on Slide 19 and you have kind of the well cost estimate for the Utica CIB and it's currently at about 95 per lateral foot. Is that kind of the expected well cost when it -- when you guys into more development mode or is that just what it's kind of averaging right now?

That's essentially, it's kind of what it's averaging right now. Early on, we try to make forecasts on that. And then as we get more and more wells, then we tend to look at what the averages or contracts, obviously that are associated with it. So --

Okay, that's helpful. That's all from me then. Thanks for your time.

Our next question comes from Chris Sighinolfi from Jefferies. Please go ahead.

Hi, everyone, good morning.

Hey, Chris.

Hi, Ron. Ron just wanted to echo holly offering my congratulations on your long career with NFG and the pending retirement. I personally learnt a lot from our interactions and conversations. And I also enjoyed time spent traveling together too. Thanks for all of that and wish you the best in retirement.

Thanks. I will buy you a beer when I see you at AGA.

Here we go. I think beer is free, but I'll let you pay for it. I think also, Dave, congrats on your role and I think, therein lies question, Ron, you had mentioned in your prepared remarks the anticipate shift among the internal team given Dave's pending move to the CEO role, but just any further clarification on what we might expect as the CFO search process either internally or externally take shape and we move towards the line.

Yes. It's our typical practice to announce those as they are made. With all of the attendant, pictures and releases and we'll just keep to that and announce at that.

Okay. But it's not something where we would see an interim notification, your intention is before July to have fully established.

Yes.

Okay.

Yes.

Okay. Great. And then if I could just pivot and follow up on some of the earlier questions John for you. You mentioned in your release last night and obviously on the call this morning multiple factors the longer laterals, the testing on well and completion design and the delays that you cited in the DCNR tracts in the East. Some of that seems to be more impactful in fiscal 2Q and some of it seems to be more impactful sort of on the program on a go-forward. I was just wondering in terms of fiscal 2Q, how if we thought of maybe as a percentage of the impact. How much of that was just the DCNR issues and are those resolved at this point?

Yes, I would say at least for specific to Q2. It was probably a small amount maybe half a B was related to the -- to some delays there. The larger impact will occur going into the next couple of quarters. We had one well that we had t sidetrack and redrill that put us back about 30 days and then a 007. We actually had one well that has some collapsed tubing which was a bit strange that took us a couple weeks, two to three weeks to sort of get that fixed. And so that sort of postpone the online date for three wells.

Okay. And then I guess the way that those-- that it reads those issues you see as very much add sort of specific issues to those -- well is not something that speaks to larger problems in that program. Is that right?

That's exactly correct Chris. But we view these as one-off issues and we don't foresee this being a consistent trend.

Okay and then you also had noted I guess in the prepared remarks, John, that the produced fluid percentage probably being problematic above 95% better in the 75% to 85% range, but just wondering any variability and ranges other than 75%, 85% or are you indicating that that's a sweet spot, your team believes is optimal for your program?

Actually, that's a great question Chris. We've had a lot of debate on this. Our ranges will typically go as at least in the West, towards below 50% and to as high as 100% and so we're not sure after only 21 wells, we're not sure, what that sweet spot is yet, but we do know that once we get to that 90% plus, really 95% plus that we are seeing an impact on these wells ,that wouldn't surprise me that the fresher the blend, the better the well. But there is, it's going to -- how we manage that going forward is going to depend a little bit on the impact on the economics and the well results.

Okay. I guess then, as it relates to Boone Mountain has been a standout for you guys. The appraisal there, can you just remind me, was that -- is that simply the resource opportunity in that area or did you do something different with that well and completion design versus the areas that…

No. That's just the resource potential within that area. We actually think and our appraisal drilling over the next few years we'll try to lock it down. But there is -- we think there is a corridor between our Rich Valley to 14 well and our Boone Mountain well, that will be fairly productive. Again that's just something we're going to have to lock down over the next couple of years.

Okay. And I guess finally -- this is all very helpful. The final question for me would be then, you mentioned I think in the WDA, six Utica, six Marcellus and then the EDA 10 Marcellus for the remainder of the year. I'm just curious given the program, so the time profile with longer laterals, et cetera. What sort of doc inventory do you envision at the end of your fiscal year setting up for next?

Yes, any docs that we have -- documentary, the only documentary we really have that significant will be in the WDA, where we have two rigs running. In the EDA, as soon as we're done drilling on a pad, we have a spot moving in to get that pad completed.

Okay. So the delay in the timing, didn't meaningfully change. I guess that year-on-year cadence in terms of where your inventory to complete in the West might be the -

Yes. No, it just pushes us back a month and a half is really what the delay is still.

Okay. Thanks a lot, appreciate all the time this morning.

[Operator Instructions] Our next question comes from Becca Followill from US Capital Advisors. Please go ahead.

Good morning, guys. Following up on Chris' question. The third part of the rationale for the lower guidance, the trending toward drilling longer laterals, what has changed from the prior guidance. I mean -- are you -- was it a prior guidance ex-lateral and now its ex or what's the different?

Yes, we set our guidance, our range, very early obviously before-- back in August I think is when we set it. And as we move forward and begin to better understand some of these areas we'll permit them long and if we have the opportunity to continue to drill them longer, we'll do so. Historically when we drilled Marcellus wells, we've drilled -- we permitted them long and have always ended up being maybe a 1,000, 2,000 feet shorter than what we have permitted because of structural complications and we're just not finding that in the Utica. So in terms of our forecast and we've tended to under forecast what our final laterals will be based on what we've done to date.

Okay, thanks.

Does that makes sense?

That makes sense.

Okay.

And then you also mentioned the reason for the two wells that underperformed. It was a combination of the produced fluid blend and choke management, are you doing this differently for Utica.

No, we- yes, we choke manage all of our wells in the Utica, in the WDA Utica so and that's a positive. They don't come on as strongly, but they're much better wells. The reasons those two wells did-- underperformed was because of produced fluid bond, it was just too high.

So it's not choke management. And then-

Exactly.

Because it's still, I mean you're still really early in the development at this play with the number of wells you drilled compared to how many you plan to. So when you do your forecast for 15% to 20% growth, how much do you factor into there, the fact that the mix is going to change and some wells are not going to work and you're still kind of in science. So how do you risk-adjust that 15% to 20%.

That's a great question. We've drilled 350 Marcellus wells and we've really gotten that we have fine-tuned our forecasting related to that program. The Utica, we drilled a whopping 26 wells and so we're still learning as you just mentioned and we try to be a bit conservative on our forecasts. But having said that, maybe at least during this early period, as we're trying to understand and optimize our drilling and completion. It's going to little -- typically a little slower than we envisioned. But I think as we continue to drill these wells, we will begin the lock down at least a more accurate forecast going forward. So there is a lot of noise early, we try to be conservative, but I think because we've been drilling Marcellus wells for long -- for such a long time for pushing 10 years, we under-appreciated the learning curve related to some of these new areas.

Got you. Thank you. That's all I had.

And we have no one left in queue at this time. I'll turn the call back to Mr. Webster for closing remarks.

Thank you, Carol 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 PM Eastern Time and by telephone and will run through the close of business on Friday, May 10. To access the replay online, please visit our Investor Relations website at investor.nationalfuelgas.com. And to access by telephone call 800-585-8367 and enter conference ID number 6683755. This concludes our conference call for today. Thank you and Good bye.

Thank you. This does indeed conclude today's conference and you may now disconnect.