Ladies and gentlemen, thank you for standing by, and welcome to CONSOL Energy's Third Quarter 2016 Earnings Conference Call. As a reminder, today's call is being recorded. I would now like to turn the conference call over to the Vice President of Investor Relations, Mr. Tyler Lewis. Please go ahead, sir.

Thanks, John, 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; Dave Khani, our Chief Financial Officer, and Tim Dugan, our Chief Operating Officer. Today we'll be discussing our third quarter results and we have posted a slide presentation to our website. As a reminder, any forward-looking statements we make or comments about future expectations are subject to business risk which we have laid out for you in our press release today as well as in our previous Securities and Exchange Commission filings. Related to our recently announced transaction to separate our joint venture with Noble Energy, CONSOL Energy is unable to provide a reconciliation of projected incremental EBITDA resulting from the agreement to projected operating income, the most comparable financial measure calculated in accordance with GAAP, due to the unknown effect timing and potential significance of certain income statement items. Also during the quarter, we made certain adjustments to the financial statements. With the sale of the Buchanan, Miller Creek and Fola mines which all now reside in discontinued operations, our coal segment is now only comprised of Pennsylvania mining operations. Our Baltimore terminal any remaining idle mines, water operations, legacy liabilities, and various other nonoperating corporate items now reside in miscellaneous operating expenses. Short-term compensation and stock-based compensation now reside in SG&A across the E&P, coal and other segments. E&P maintains an other corporate expense line item which now includes items such as unutilized FTE and idle rig fees. To reflect these changes, we have (1:54) historic income statements that can be found on the Investor Relations portion of CONSOL Energy's website under supplemental table. We will begin our call today with prepared remarks by Nick, followed by Dave and then Tim. And then, we will open the call up for Q&A. With that, let me turn the call over to you, Nick.

Thanks, and hello, everybody. I'm going to be brief this morning, but I would like to focus my time today providing some general high-level commentary on the highlights of the quarter. And also before passing it over to Dave Khani, I'd like to talk about how the philosophical and cultural changes we've implemented here at CONSOL have helped us weather the downturn and put us in a position we are today, which I believe is a turning point for the company. To start, CONSOL Energy had a strong quarter highlighted by the company benefiting from many of the areas that we have been focused on over the past year. Specifically, we created a plan last year with the goal of maximizing free cash flow and using this cash to delever our balance sheet. This quarter, we again posted a strong organic free cash flow of approximately $103 million, which is our third consecutive quarter of successful generating free cash flow. Year-to-date, we have generated total free cash flow of around $608 million, and we have used our free cash flow to continue to pay down debt and improve our liquidity position and which has increased to $1.4 billion at the end of the third quarter. We remain focused on further delevering the balance sheet to set up the company to successfully split the Coal and E&P segments. Our primary avenue to accomplish this remains through our subsidiary, CNX Coal Resources or CNXC. And this quarter, we took another step towards separating the businesses by completing an additional 5% drop into CNXC. Now, stated by CNXC on yesterday's earnings call, they're seeing improvements in the domestic thermal, the international thermal, and international high-vol metallurgical coal markets. Not only does this bode well for CNXC with their current shipments and contracting progress…

Thanks, Nick, and good morning, everyone. As highlighted in our press release this morning and indicated on slide 24, CONSOL reported third quarter GAAP income of $25 million attributable to CONSOL Energy shareholders, on a GAAP basis earnings included two main pre-tax items attributable to continuing operations which totaled approximately $164 million. First, we had $160 million unrealized mark-to-market gain on our commodity derivatives instruments, and second we had a $4 million total pension settlement and other expenses. After adjusting for these items, CONSOL's posted an adjusted net loss from continuing operations of $36 million or negative $0.15 per share and adjusted EBITDA of $156 million. More importantly, we generated free cash flow in the quarter. We generated organic free cash flow of $103 million, as Nick stated, and year-to-date total free cash flow of $608 million. Our organic free cash flow in the quarter increased despite E&P capital expenditures increasing to $64 million from $38 million, reflecting the restarting of drilling capital in August. For E&P production and highlighted on slide 26, the E&P division finished the quarter with production of 96.4 Bcfe. During the quarter, we had 1.5 Bcfe of (7:28) adjustments. We had very few turned-in-lines in the quarter, and this highlights our low natural base decline rate within our portfolio. For the fourth quarter, we have six Green Hill wells coming online – actually have just been turned online. And with yesterday's announcement of the separation of our Marcellus joint venture, we increased our 2016 E&P production forecast to 390 to 390 (sic) [395] (7:53) Bcfe, or about 20% growth for the year. On the cost side, we had another solid quarter with total all-in and cash costs of $2.36 and $1.31 per Mcfe, respectively, which is near the upper end of our guidance range. With…

Thanks, Dave, and good morning, everyone. Since this was the first quarter that we – since we've added back drilling activity from when we made the decision to lay down all of our rigs back in mid-2015, I'd like to focus my remarks on providing some operational updates and highlights. As stated last quarter, with the combination of strong summer weather, the slowing inventory build, and rig counts remaining below levels needed to maintain flat production in our region and across the U.S., we've seen 2017 NYMEX driven higher, which has in part played a role in our decision to add back modest activity. We added back two rigs in August which started drilling dry Utica wells in CONSOL's 100%-owned acreage in Monroe County, Ohio. In the quarter, we drilled two wells at an average lateral length of approximately 8,600 feet. And after the close of the quarter, we TD-ed a third well. Over the course of these three wells, our drilling costs and days to drill improved to levels that exceeded our original expectations, which we previously stated last quarter. Specifically, last quarter, we talked about drilling cost goals of $1,060 per foot of lateral. Over the course of the first two wells, our drilling costs improved to $1,040 per foot of lateral, and our costs further improved on the third well to $950 per foot of lateral. As for the days to drill, our original expectation was 26 days spud to TD, which was accomplished on the second well. On the third well, we exceeded this goal by three days. These are great accomplishments by our team and they nicely illustrate that not only did we pick up where we left off a year ago, but we are exceeding our goals as our rapid rate of improvement continues.…

Thanks, Tim. John, if you could please open up the line for questions at this time.

Certainly. And first, go to the line of Holly Stewart with Scotia Howard Weil. Please go ahead.

Good morning, gentlemen.

Good morning.

Good morning.

Maybe first question, Tim, you mentioned the EUR improvement in the Green Hill area and maybe the changes or differences in completion design. Can you maybe just talk about the proppant loading and kind of what you're doing in that area specifically that's driving this improvement?

Well, it's really stems from all the modeling work we've done and proppant loading is part of it. But it's also we're looking at the sequencing of the wells, looking at our unbounded wells versus our interior wells, and how we treat one versus the other. And just our completion designs are becoming more and more custom to each individual pad in each area.

Okay. And can you specifically identify how big that area is?

Well, we've got our fields broken down into – I mean, we look at our fields, we've got it broken down into AOIs. So – and we continue as we go through our asset assessment which is just an ongoing project. Those areas are continually redefined as we get more and more data, and we add that data into our model. We adjust our AOIs. They can be as small as 5,000 acres, and they can be as large as 20,000 or 30,000 acres. It just depends on what geology tells us, how the reservoir characteristics change across that area. So, we'll see varying sizes of AOIs or areas of interest.

Okay. And then, maybe as my follow-up, you guys mentioned ethane recovery in the quarter was a pretty big jump sequentially. You referenced a project. Can you give us some details on that project? And I'm assuming you're moving volume now on that project in Mariner East, if I remember correctly

Yeah, we did – we started sales through Mariner East back in April, but we did see an increase in our NGLs this quarter. A lot of that we had some gas sort of which termed as lean (21:45) or damp gas that we moved from a dry outlet back to our Majorsville, so that we could recover the ethane. And then, we had some spot sales for the quarter as well. So, our NGL volumes were up this quarter.

Yeah, CONE Midstream has the ability to move the sort of the quasi-wet gas in periods when it is uneconomic to a dry system and back and forth. So, that's the flexibility of the CONE system.

Great. Thanks, guys.

Our next question is from Neal Dingmann with SunTrust. Please go ahead.

Hi. Good morning, gentlemen. In one of your old slides, and maybe, Tim, a question for you. You mentioned in the press release today about having the Monroe County Utica wells being among or the best returns you have out there. I'm trying to look – I'm looking at one of your older presentations. It shows about 622,000 net potentially Utica acres. One, is that still kind of mostly accurate? And then if so, these higher returns that you're referring to around Monroe, does that consist of the bulk of that or – I know some of that is in that deeper Utica area, so I'm just trying to sort of diverge the two, but in trying to figure out how much you guys are classifying in that sort of Monroe bucket

Well, the 622,000 acres covers our entire footprint, Ohio, West Virginia, and Pennsylvania. Monroe, when we look at our (23:15) costs and our opportunities, Monroe does provide right now the highest rate of return. Because we have moved into more of a development mode there. We're now – got two rigs out there, drilling pad development. So, we're able to quickly take advantage of learnings and that's why we've been able to get our days and costs down even further. But we've got – we'll be drilling in Monroe County here for the next year or two pretty steadily. But when we look at that 622,000 acres, a lot of it resides in Pennsylvania and Northern West Virginia as far as Utica potential.

Very good. Tim, and could you also talk about – I want – just to make sure I have this correct, the DUC inventory as it sort of sits today and where you see it the end of this year, and how you'll attack it next year.

Sure. With the agreement that we announced yesterday, we walked out of that agreement with 53 DUCs, Marcellus DUCs. We've got two wells. We'll have two wells at the end of the year that will, I guess, technically not be DUCs. They'll be completed waiting to be turned-in-line. So, essentially, 55 Marcellus wells at the end of the year that essentially are DUCs. And then, we've got 15 additional DUCs that are Utica wells. 10 of those we own 100% interest in. Those are the wells that we're drilling right now in Monroe County. So, we're looking at – and year-end numbers, we'll have 70 DUCs. And then, next year, as we're putting our plan together, we've got to put it in front of our board here in the next month or so for approval. And – but it will involve quite a few of those DUCs, where we add those to our list of opportunities, and look at them from a rate of return standpoint. And we'll blend those into our plan for next year. But that will – there will be more details about that in our Analyst Day in December.

Okay. And then, just lastly over on the coal exports, I think David Khani was mentioning them. You certainly have seen a nice pickup in coal prices all around. Is it fair to say we'll return maybe back to more of a normalized level next year, meaning you'd have less exports than what you've had in the last year or two, and likely a bit better pricing?

Yeah, I think that's fair – I think we have a fairly contracted book into next year, and I think the export number for this last quarter was about 10%, and if you looked at the export number in the first two quarters, it was around 25% or 30%. Some of that was because of the local demand. The weather was very weak. And so, it was more of a push. Today, the export market is pulling coal out of the U.S. and so, it will be somewhere – it will probably be somewhere in the middle.

Very good. Thank you, all.

The next question is from Jon Wolff with Jefferies. Please go ahead.

Good morning.

Good morning.

Good morning.

Could you go through the DUC benefit of heading into next year, similar to how you explained it about a year ago, in terms of pre-spend capital and how that will help you? That's one question.

So, yeah, last year we gave a number of how much capital we had sunk in there and how much capital we need to spend. I think Tim yesterday mentioned that, on average, we'll need about $4 million per well to complete the wells. So, you can do the math on the roughly 70-ish wells. Roughly $280 million, maybe a little less, because not all of it is 100% owned.

And to get to that goal of at least growing next year, is that enough on its own? That level of DUC conversion?

Yeah, I mean, if you think about what we put online this year was in the upper 40s. So, here you're talking about a higher number, because these will be more 100% owned. So, yeah, those would be enough to grow our production.

Got it. And on the frackapalooza or frackageddon (27:46), the determining factor of how much sand seems to be the right mixture would have to do with natural fracturing, is it the thickness of the reservoir, other factors that you care to share in your learnings (28:06)?

It's reservoir thickness. It's well spacing. It's spacing to adjacent pads. It's a lot of different factors. But the reservoir – well spacing, lateral spacing, and reservoir thickness are probably two of the bigger components. So, there is certainly a benefit to more sand, but there's also a limit to how much sand you need to pump to get that benefit and maintain the economic benefit.

Got it. The Baltimore port, can you update us on how active the shipment area that is for you and third parties, and is that a core asset? Is it something that could be – I guess everything could be sold at the right price, but any thoughts on that?

The terminal is now being operated, managed as I'll call it a stand-alone business unit. So, what that means is there's not just the ongoing relationships that we've seen historically with the Pennsylvania Mining Complex with some of our partners like (29:15), but also third-party volumes that are going to the terminal and people know now that it's open for business. So, our expectations when you look at the cash flows or the EBITDA contribution to the terminal would represent, especially with some of the tailwinds that we're seeing in the coal markets that the CNXC team talked about yesterday on the export side, it should have some pretty promising days in front of it. Where it sits and where it ultimately resides looking at the terminal, there is obviously an argument to be made that it should reside with CNXC because of its relationship with the Pennsylvania Mining Complex and how one feeds off the other. And I'm sure there's also the avenue of third party showing interest in the terminal as well. So, that's under the diversified business unit segment that we've got within the company. And the job number one is to make sure that we're maximizing the EBITDA and NAV of the asset obviously safely and compliantly, and while we're doing that, whereas the proposition with respect to the terminal if you look at things like CNXC and future drops or third-party divestitures.

Yeah, and just to give you a little bit more color too. Right now, I think we'll probably see somewhere around 8.5 million tons of coal exported out of the facility, it has capacity of about 15 million tons, so if this trend continues on export, then you could expect that number to go up for next year.

Got it. Last one on CONSOL's smaller met footprint. Is it – is the coal staying local to Pittsburgh area, or is it – is a lot of it being exported?

Both domestic as well as export. But there's domestic opportunities with the met crossover of the nature of the Bailey product and there's also obvious export opportunities. Those both interestingly should grow over time because of what the quality trends are doing at the Pennsylvania Mining Complex with the sulfur dropping. So, there's also some inherent, I think, advantages or opportunities that they have on the CNXC team that should bode well for getting more opportunities of the Bailey product marketed as a crossover met.

And I think from a domestic standpoint, we always talk about the targeting the (31:40) power plants (31:43) obviously they are looking to maximize price domestically. One of the key things that they have done is be able to ship to those plants that have basically a flat basis to natural gas to NYMEX, and so that, we can deal with avoiding kind of the impact of power prices within the basin as much as we can.

Makes sense. Thank you.

And next we'll go to Jeffrey Campbell with Tuohy Brothers. Please go head.

Good morning.

Good morning.

I noticed on slide 11 that the entirety of the West Virginia DUCs are operated. Can you add some color on where the drilling was concentrated and how that acreage might rank order as you start to look at allocating 2017 capital?

Well, a lot of it, the DUCs in West Virginia are DUCs that through our agreement yesterday just moved over to us, just transferred over to us. So, they will – we will look at how we're going to incorporate those into our 2017 plan. But there is also – we have some additional drilling potential down there as well. In fact, when you look at wet gas development potential between the Pittsburgh International Airport and the area in West Virginia that is now operated by us, that's where really the majority of that wet gas drilling potential exists. So, again, we're putting our plan together for next year, and we'll roll that out on our Analyst Day in December. But that will likely certainly get a strong look and it'll have an impact on our percentage of wet...

Yes.

...for 2017 as well.

Right. I'll just add, I was curious about it, both on the success that you had that you brought out in the last quarter selling ethane and also the strength that we've seen in propane prices recently. And on the theme of West Virginia, you may have already answered it but thinking about your reference to further asset sales, I was just wondering what your outlook might be for West Virginia, considering it is wet but it's also not very proximal to the majority of your acreage in PA. I wonder if that really matters or not.

The geology – the rate of returns tied to geology, marketing, obviously capital investment, et cetera, are favorable for the areas of interest within West Virginia that we're retaining 100% of. And under the asset monetization process, once again just like all the other monetization areas that we consider, we're going to be very clinical about that. We'll see what the market might support when it comes to interest in those assets versus what we think we can extract value from on NAV per share basis by developing that internally. And if there is a window where that first metric exceeds the second metric, then we'll transact. And if there's not, we won't. So, it's definitely something that's obviously in the asset base with the rest of the acreage position and we control a big inventory. It will be considered as both a development and a monetization candidate, and we'll just do the math to see which one makes the most sense.

And now that we have the flexibility to sell the whole (35:10) independent of the JV, we have probably more opportunity down the road to do so.

Okay. Thanks. I appreciate that. The last one is I just was listening to your description of the modeling. If I understood it correctly, you're talking about modeling completions on computer before you actually go out and drill in some instances. And I was just wondering, does well control – you mentioned geology already earlier. I'm just wondering if well control is of much use in this modeling., because when we think about the Gaut, there probably wasn't a lot of well control for drilling and Utica well where you did, so I was just wondering, is that also an important variable or is this pretty much geologically based?

Well, the earth model is geologically based and the earth model feeds our frac model, which then in turn ends up feeding our production model, our rate transient analysis. But certainly, we keep adding data points to get more and more control. We had enough data points when we drilled the Gaut to have the confidence to drill the well up there when many questioned it, but again, we got what we expected up there. We are really pleased with the results. But we were not shocked by the results. So, we had enough control to give us the confidence to go up there and drill that well.

Okay. Great. Thank you. I appreciate it.

Thank you.

And we'll go to James Spicer with Wells Fargo. Please go ahead.

Hi. Good morning. You touched on this a little bit in your prepared remarks but just wondering if you could comment a little bit further on timing of potential additional coal dropdowns given the recovery in pricing there.

Yes, sure. The approach is going to be the same that we've applied since CNXC is IPO-ed just probably just over a year and a half ago. And that's one where we will look primarily first and foremost at the CNXC team to see if they see an opportunity for what we would call an accretive drop of a certain percentage interest of the Pennsylvania Mining Complex into CNXC. If that's there and that occurs, and on our side of the fence, the CONSOL Energy side, we think that's a fair evaluation marker, that it would represent, then we're likely to proceed with that type of an opportunity. In the end, I think the theme is one of what's good for CNXC is typically going to be good for CONSOL Energy and its shareholders, and we just need to make sure we're balancing the valuations and the short-term dynamics of those opportunity (37:48) drops when they pop up. But so far through, what has been looking back over the last year and a half, a very chaotic time within the markets for coal and natural gas, power, et cetera, we were able to use that approach I think quite efficiently and looking now forward with more stabilized markets, I think that process will bode very well for both parties moving forward.

Okay. Appreciate that. And secondly, just a clarification comment. The 5 million cubic feet a day bump in production guidance, is that – actually, sorry, that's Bcfe bump in production guidance. Is that taking your 85 million cubic feet a day of incremental production from the dissolution of the JV and just the pro rata taking that from the effective date on October 1, is that what you're doing (38:45)?

It is both the result of is production we picked up through the exchange agreement and the continued improvements that we are seeing in our overall production, our base production.

Yeah, so if you take the 85 million and you turn it into Bcfe, it gets you about 8 Bcf of the 10 Bcf. So that's – 80% of it is the acquisition, about 20% of it is productivity improvement.

Yes. Okay. Makes sense. Thank you.

You're welcome.

And we'll go to the line of Jon Wolff with Jefferies. Please go ahead.

Hey, another quick one on, post the Noble deal, the amount of royalty interests you own in Pennsylvania and I guess West Virginia, Ohio?

Of the acreage?

Of the acreage, yeah.

Yeah, overall our – our overall NRI really has not changed with this deal. So, there's not really a big change in what – the acres that moved over into Noble's operated area. We didn't give up much in the way of fee acreage. We have looked at that. Our NRI, our HBP percentages, have remained essentially unchanged.

Okay. And you probably won't want to answer this, but on CONE, how strategic does it become, given the split and maybe if you're doing a little bit less wet gas, I would think?

CONE, you seeing strategic for us, or for...

Yes. For you.

Well, we kind of are the operator of CONE, and so we've kind of developed CONE. And I think CONE right now is important to us. So we see – continue to grow CONE and continue to go towards the GP splits. So, I think right now, we feel very good. When you look at the acreage that we now operate, I think we've got the flexibility, when the market dictates, to take advantage of wet gas. We've got plenty of acreage that we can develop that is wet.

Got it. Can you give us a little on the GP splits and when they kind of kick in?

Yeah, so last quarter, not this quarter but last quarter, we started to get into the second split, and so if we continue – and then we grew the distribution another annualized 15%, which we declared about a week ago. If we continue on the same pace, we will be into the next split, I think, within the next three or so quarters. So it's almost, I think almost every year if we continue on the pace, that's the math. So...

Yeah, got it. Makes sense. That's it. Thanks.

Thank you.

And next we'll go to Lucas Pipes with FBR. Please go ahead. Lucas N. Pipes - FBR Capital Markets & Co.: Hey, good morning, everybody. I wanted to ask a follow-up question on the coal business, and specifically as it relates to CNXC, that entity had a great performance year-to-date. Had a great rebound on the back of higher coal prices, both domestically, internationally. The distribution has been reinstated for all unitholders. In terms of additional dropdowns from CNX to CNXC, what is holding you back at this point?

Lucas, the math that I sort of walked through a couple minutes ago on a prior question, that's the process we use. We look for what I would call an accretive window from the CNXC side, where they see an opportunity to acquire an additional ownership stake in the Pennsylvania Mining Complex. We'll look at it from our end on an NAV per share valuation basis. If those align, that's a go. I think the two things that drive that, one that drives the math and the calculation itself right now, if you look at CNXC, with their efficiency and operating cost metrics have been, have been stellar since they have been public. So, really it comes down to coal pricing that's gotten a lot better, as you mentioned with our release yesterday. So, there's increasing chances for those equations and that math to line up the way we want it to. The second thing are the market, the capital markets. Can the capital markets support what I would call the financing of that acquisition, or that drop? And that's something I think that's changing as we speak. Obviously starting from a very low basis, where the capital markets have effectively been shut down for the coal space for a long time, and now it looks like things are starting to warm up. So, we're interested to see what the CNXC team comes up with both on pricing and those views coupled with what they obviously disclosed at the close of market yesterday and what the capital markets will support to provide what I'll call financing for those drops to occur. Lucas N. Pipes - FBR Capital Markets & Co.: That's very helpful. I appreciate that. And then maybe a quick one, and I apologize if this has been asked before, but I recall that when you sold Buchanan, there was a little bit of a kind of call option on higher met coal prices. Could you all remind us what a $200 met coal benchmark price could mean on that metric? Thank you.

So, it's a good question, and yes we built into the sale of Buchanan a kicker, a met kicker if met coal prices were to rise. And so, basically for every $1 over a realized $75 mine price for export tons, CONSOL will get $0.20 on that dollar. And so, we're probably expecting that it will probably kick in this quarter because of the sharp rise that we saw in the benchmark price. What the math will be from $200 net to the mine, it could be just, say, anywhere between $100, $150, somewhere in there if you want to take the middle point of $125 at the mine, $125 minus $75 is $50, $50 times some portion of the 4 million to 5 million tons that it will produce, right, will go export probably 50% to 75% of that. So, let's say 3 million tons. You can do the math – 3 million tons times 20% times $50 a ton. You can get to some number that could be pretty meaningful for CONSOL, if the price holds up. Lucas N. Pipes - FBR Capital Markets & Co.: Well, that's great color. Thank you very much for taking my questions.

You're welcome.

And we'll go to Holly Stewart with Scotia Howard Weil. Please go ahead.

Hi, guys. Just another quick follow-up or two. Dave, it might be actually too early to know this, but I was just looking at the LCs that are outstanding with the Noble agreement changing, do you know how that ultimate mostly is going to change your postings?

It shouldn't change too much at all, and we have been working on ways to actually bring those LCs down. So – and I think as our credit actually might improve, we might have the ability to take some of those LCs down.

Okay. Great. And then, just one final one. I think (47:00) mentioned the second plugless completion test. Any color there that you guys can provide that you're seeing so far?

We don't have a lot of data back on that yet, but we haven't seen anything yet to give us any negative thoughts on it. It's – we think that the plugless completions, that's probably one of the next big steps in really reducing our overall capital costs from drilling and completion standpoint. So, it was – the job was successfully executed, and as we get more production results, we'll roll them out.

Great. Thanks, guys.

Thank you.

And that will conclude the Q&A session. I'll turn it back to the company for closing comments.

Great. Thanks, John. Thank you, everyone, for joining this morning. We look forward to speaking with you next quarter. Thank you.