Ladies and gentlemen, thank you for standing by, and welcome to the 2017 CONSOL Energy Third Quarter Results. As a reminder, today's call is being recorded. I would now like to turn the conference over to the Vice President of Investor Relations, Tyler Lewis. Please go ahead.

Thanks, Lydia, and good morning to everybody. Welcome to CONSOL Energy's third quarter conference call. We have in the room today Nick DeIuliis, our President and CEO; Don Rush, our Executive Vice President and Chief Financial Officer; Tim Dugan, our Chief Operating Officer; and Steve Johnson, Executive Vice President and Chief Administrative Officer. Today, we'll be discussing our third quarter results, and we have posted an updated slide presentation to our website. As a reminder, any forward-looking statements we make or comments about future expectations are subject to business risks which we've laid out for you in our press release today, as well as in our previous Securities and Exchange Commission filings. We will begin our call today with prepared remarks by Nick, followed by Don, and then Tim. And then we'll open the call for Q&A which Steve will participate in as well. Before handing it over to Nick, one housekeeping item. You will notice on slide 3 of our slide presentation, as well as in our press releases today, a description of the post-spin company names and stock trading symbols. In short, the gas business or RemainCo will be named CNX Resources Corporation and will continue to be listed on the New York Stock Exchange and retain the ticker CNX. The coal business or SpinCo will be named CONSOL Energy, Inc. and will be listed on the New York Stock Exchange under the new ticker of CEIX. Lastly, the master limited partnership that is currently named CNX Coal Resources, ticker CNXC, will change its name to CONSOL Coal Resources LP and will trade on the New York Stock Exchange under a new ticker of CCR. Again, a summary of these changes are laid out in detail on slide 3 of the third quarter slide presentation, which is accessible on the Investor Relations portion of the company's website. With that, let me turn the call over to you, Nick.

Thanks, Tyler. Good morning, everyone. It's been a tremendously exciting and quite busy quarter for a number of reasons, and I'd like to spend most of my time this morning discussing the impending spinoff transaction of the Coal and E&P businesses. But before we get into those details, just a couple of highlights from the quarter, we summarized this on slide 4 of the slide deck that Tyler just referenced. The team's been steadily executing throughout the quarter and with some well design modifications and continuous improvement initiatives that Tim Dugan and his team are focused on, the operations are humming along nicely. The Monroe County wells, they're starting to get turned-in-line, and not only are we seeing very nice production improvement in Monroe SWITZ field, we're also seeing some production improvements across the Marcellus in the Morris Field in Greene County, Pennsylvania. I'll save the exciting details for Tim to cover in a couple of minutes, more in depth. But in short, the team is doing a great job and we came in slightly above our third quarter guidance of setting up expected fourth quarter production of just over 120 Bcf based on the midpoint of the full year guidance and that in turn sets us up for a production and EBITDA ramp that we're expecting to see in 2018. When you look at the third quarter, we also closed on some additional asset sales. That included about $55 million of surface acres and other miscellaneous non-core assets. In total, year-to-date, we closed on $427 million of asset sales. And even though this is within our $400 million to $600 million guidance range for 2017, we're continuing to pursue the sale of various non-core assets including the Virginia coalbed methane area and some scattered Marcellus and Utica acres. These…

Thanks, Nick. Definitely exciting times and good morning to everyone on the call. Before I start, I'd like to remind everyone that we issued third quarter preliminary results in an 8-K on October 16, and all of our results have fallen within those given ranges. Our quarter results can be found on slide 7. In general, the third quarter kept us on track for our 2017 guidance, and as we reported, an adjusted EBITDA from continuing operations of $168 million, and on net income, we reported an adjusted loss of $36 million or negative $0.15 per diluted share this quarter. Both of these numbers exclude the gain on the sale of assets and unrealized gain on commodity derivatives along with some other non-reoccurring items. Flipping to slide 8, you could see we generated $94 million in total free cash flow this quarter, including the $82 million of additional asset sales that we closed in the quarter. Also during the quarter, we paid down approximately $95 million of 2020 and 2021 bonds utilizing the cash on hand. And as Nick has already laid out in October, we began buying back shares. Let's shift our focus now to our changing leverage ratio which you can find on slide 9. We have been hard at work reducing our leverage ratio for almost two years now, and that hard work has paid off as we have brought it down by over 40%. And going forward, we have many levers to continue this trend. Using cash on hand, the spin distribution, additional cash flow generated, and our rapidly growing EBITDA, we'll quickly reach our goal of a sub-2.5 times leverage ratio with cash to spare in 2018. And we feel that 2.5 times ratio is the right balance sheet for us, especially when you combine…

Thanks, Don, and good morning, everyone. Looking at slide 13, production ramped meaningfully in the third quarter as we turned in line 29 wells and continued our rapid pace of completions. We expect to turn in line at least 15 additional wells in the fourth quarter with majority of the activity set to happen in November. Based on the positive early results we've seen on recent TILs and our planned development schedule, we expect to end the year with an exit rate of around 1.4 Bcfe per day. That will put us on pace to reach our 2018 production guidance of 520 to 550 Bcfe which we are reaffirming. We ran two rigs during the quarter, one in the Morris field in Southwest PA and one in the SWITZ dry Utica area of Monroe County, Ohio. In total, we drilled 10 wells. We now expect to bring a third rig online in December of this year to drill Southwest PA Marcellus wells. This rig was originally planned for early 2018. In Southwest PA, we drilled six Marcellus wells, turned in line five in the quarter with an average lateral length of just over 9,700 feet. We're seeing favorable early results on those recent TILs which I'll discuss shortly. In the Monroe County, Ohio, Utica, we drilled 4 dry Utica wells, completed 7, and turned in line 12. Those 12 SWITZ TILs have an average lateral length of about 9,100 feet, and we're seeing improved early productivity compared to similar TILs in 2015. In just a moment, I'll discuss some of the design and operational improvements we've made that are driving the change. In the Penn/Shirley area of the West Virginia Marcellus, we completed 13 wells and turned in line 11, with an average lateral length of about 7,600 feet. Now…

Thanks, Tim. This concludes our prepared remarks. Lydia, can you open the line up for Q&A at this time?

Certainly. Our first question is from the line of Neal Dingmann with SunTrust. Please go ahead

Good morning, guys. Nice update, Nick. Nick, a question for you and Tim, just looking at maybe those slides 15, 16, just how much increase you've seen on both the Southwest PA Marcellus and Ohio. I guess should we read anything into you're bringing that third rig on, talked about bringing it in the Marcellus versus maybe prior calls it sounded like you were talking about sort of going forward a little bit quicker on the Utica side, is there anything we should read into that?

No, not at all. In fact, I think if you look at where our rigs are now, I mentioned we've got three Utica wells drilling right now. Two of them are operated. We've only got two rigs running. So we have actually – we have accelerated one of those wells for a couple of different reasons, but none of them should be interpreted as negative. The rig coming on line is really a – we're sticking to the schedule that we put together in the development plan and following that as we get wells drill-ready.

Got it. And then just one last one, Nick, for you, just on a broader scale. It's certainly nice to see the increase in the buyback program. When you look going forward for 2018 and out, your thought about sort of free cash flow growth, buyback, dividends, the whole sort of encompassed now once that you've separated, could you just discuss how you sort of view all those things collectively?

Sure. The philosophy would be a consistent one from what we've applied the last couple of years, which is we're going to filter all of these options of deploying capital across an NAV per share sort of filter spectrum. And when we look at that incremental dollar, I think we had some discussions throughout the commentary this morning that we want to get a balance sheet that's 2.5 leverage ratio or lower. That's going to happen much sooner rather than later. And at that point, it is a jump-off for the incremental dollar of capital allocation between further debt reduction, a share buyback, which we think has some very compelling rate of return metrics on an NAV per share basis that's facing us now, or an incremental opportunity set on activity level based on what Tim's team is developing on things like the deep dry Utica. So I think when you look out into the future through, say, 2018, we haven't put out a capital budget number or that type of information as of yet. We're still working on that, as Don mentioned. But I think your expectation should be we like free cash flow. We like to reduce share count when we see discounts to what we think the company is worth at the levels that we're seeing, and we're going to only invest in the drill bit where it's high rate of return opportunity sets like the core Marcellus and deep dry Utica that we're operating in the Monroe County, Ohio today.

Got it. Thanks, Nick, Tim.

And next we go to the line of Jeffrey Campbell with Tuohy Brothers. Please go ahead.

Good morning, and congratulations on the successful culmination of the divisions of the E&P and the coal. My first question was regarding the third rig in Southwest PA Marcellus. Should we think of this as a third core area that's joining Greene and Monroe for 2018, and also, what's the expected production mix in the area?

I think we've, over the last several quarters, we've talked about focusing on the areas of high rate of return, and those have been consistently Southwest PA and Monroe County, Ohio, with the continued delineation of the deep dry Utica. So really, all we're doing is this rig was originally scheduled to come in, in early 2018. We're just moving it forward some. That's really because it's driven by a couple things, but primarily the efficiencies we have continued to gain throughout 2017 and improvement in cycle times and having things ready.

And can you just remind me again, what's the expected production mix for your Southwest PA drilling in 2018?

I don't have the exact mix in front of me, but we've got a good mix of Marcellus. It's similar to 2017 as we continue to delineate the dry Utica, that will increase. But I can get those exact numbers and follow up.

Okay. Yeah, that will be fine. And the other thing I wanted to ask was with regard to West Virginia. I mean, there's actually a lot of completion activity there. But just should we think of that as cleaning up assets from the former JV, or is there any potential for that area to maybe attract a rig at some point in the future?

There's the potential there for that to attract a rig. But as we have done over the last couple years, we prioritize our assets, and we make the right economic decisions. And these were DUCs that were, as I mentioned, drilled back in 2014, 2015. So when you look at them from a sunk cost basis, generate a good rate of return. But our well results down there have been very good. We've applied the same completion technology and methodology that we've applied in Monroe County, Ohio, and in the Morris Field that we talked about in Southwest PA, and we're seeing similar improvements.

What's really neat about that area that we designated as Shirley/Penns is that, to Tim's point, the well profile that we've seen come in on the recent tied in line effort there have been very positive surprises to the upside. And you start to couple that with what we might be able to do with the current completion designs, the current drilling and completion efficiencies, you start to see a rate of return proposition there that competes very well with the rest of our opportunity set, whether it's Monroe with the Utica or Southwest PA with the Marcellus. So it's been a pleasant surprise. But the real trick here will be seeing what those wells look like when we now apply with what I'll call late 2017 drilling and completion efficiencies and design completions.

Okay. Great. Well, that was great color. I appreciate it. Thank you.

And next we go to the line of Holly Stewart with Scotia Howard Weil. Please go ahead.

Good morning, gentlemen. Maybe, Nick, first, I guess just a clarification as we think about, and I'll say GasCo just to keep things simple, If you look at slide 6, it looks like the, call it, $1.53 billion gets you to about a 3.1 debt to EBITDA level and you say that kind of the target is 2.5. It looks like with the ramp in EBITDA next year at GasCo, you really don't need to repurchase debt to kind of get to that 2.5. Is that a fair assessment?

I think if you look at what the combination of our production guidance for 2018 and how that would basically play out over the four quarters coupled with what our expectations are on unit costs, because of what we're seeing in areas like the dry Utica, and put our hedge book with the forwards on top of it, you're exactly right. You get to sort of a 2.5 or less on the front half of 2018.

Okay, front half. Perfect. And then maybe, Tim, remind us on sort of where we are for average rig count for 2017 and does that production guidance number for 2018 imply the three rigs throughout the year?

Yes. So we have a average of two rigs this year. Like Tim said, Holly, we'll be adding the third rig in December. As far as beyond that, we haven't provided additional color regarding the development for 2018 at this time.

Okay. Yeah. I was just curious on the number that – the production target though that you have out there for 2018. Is there any implication in that number in terms of rigs?

Yeah. There would be, yes.

Okay. Just not seeing it at this point. And maybe just one more final one, any color on the GP&T cost? It looked like it just creeped up slightly in the full-year guidance. I'm just curious how we should think about that for 2018? So any color on the third quarter would be great.

Yeah. Sure. This is Don. So ultimately, that's just really a result of the production mix. Like Tim and Nick talked about, our Shirley/Penns areas have gone really well. It's a little bit ahead of schedule on the production and the volumes that we are seeing there, and some of the the Monroe dry Utica, with some of the lower gathering costs or slid back a little bit in the schedule. So it's really just a change in the timing and the mix of the wet versus dry production in Utica versus Marcellus production. So that's what created Q3. And like Tim mentioned, we'll see that costs coming down as the blend changes in Q4 and into next year.

In 2018. Okay. Great. Thanks, guys.

We go to the line of James Spicer with Wells Fargo. Please go ahead.

Hey. Good morning. Kind of a follow-up to the last question. Pro forma for the spin, you'll have – you're getting the $425 million distribution, you have $280-plus million of cash on the balance sheet plus $100 million of tax refund. You'll have over $800 million of cash on the balance sheet. Just over the near term, how do you allocate that cash between permanent debt pay-down versus share repurchase versus CapEx spending?

The overall approach, first step, I was thinking a bit in terms of getting our leverage ratio down. But to a point where it's 2.5 times or lower, that creates a lot of optionality for subsequent capital allocation decisions. After that, then the thought is CapEx program to get our production and EBITDA ramp in 2018 in place. Those have very high rate of returns tied behind them that we think adds significant value to NAV per share. That – just generally speaking, again, we've not put out 2018 CapEx numbers, et cetera, but generally speaking, we should be free cash flow neutral to modestly positive in 2018 under that type of a metric when you compare it to capital budget. And then the rest of the allocation between debt and/or things like share repurchases or incremental activity set, that goes back to the straight-up incremental rate of return metrics, which one has the greatest IRR and adds the most NAV per share to the growing intrinsic value of the company. So basically, get the balance sheet in order to take advantage of optionality and then allocate that capital where we see the best opportunities in the most efficient way as possible.

Okay. Makes sense. Thank you.

And we have no further questions. I'll turn the conference back to management for closing remarks.

Thank you, everyone, for joining us this morning. We look forward to speaking with you again next quarter. Thank you.