Ladies and gentlemen, thank you for standing by and welcome to CONSOL Energy’s Fourth Quarter 2015 Conference Call Result. 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, everybody. Welcome to CONSOL Energy’s fourth quarter conference call. We have in the room today Nick DeIuliis, our President and CEO; Dave Khani our Chief Financial Officer; Jim Grech, our Chief Commercial Officer; and Tim Dugan, our Chief Operating Officer of our E&P Division. Today we’ll be discussing our fourth quarter results and we have posted slides 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 previous SEC filings. We will begin our call today with prepared remarks by Nick, followed by Dave and then Tim. Jim Grech will then participate in the Q&A portion of the call. With that, let me start the call with you, Nick.

Good morning. I’d like to kick things off with a quick recap of the macro environment in the industries in which CONSOL operates. Throughout the fourth quarter, natural gas prices fell by approximately 25%, oil declined approximately 15%, the BMA index for metals settled another $8 a metric ton lower and thermal coal storage is 9% above five-year averages. Over the course of the past year, the fourth public coal company recently filed for bankruptcy and the administration continued a politically driven assault on the production and utilization of coal. It’s truly an unprecedented time in every way, shape and form. Now even considering these issues in the coal market, CONSOL has accomplished in an extremely challenging environment, some pretty staggering things. We’ve done this by managing what we can control, and specifically we’re talking about things like safety, unit costs, capital, capital spend, gas hedging and coal contracting. And I’d like to briefly touch on each one of these. So, let’s start with safety. Safety, as most of you know is our core value and CONSOL had one of its best years ever in 2015, and especially when you look at severity level and safety performance. So zero incidents, zero accidents is our standard that means there is still more work to be done but we had a very good year in safety in 2015. And I applaud our employees especially when considering the onslaught of distractions that they’ve had to contend with throughout the year. So whether it had to do with changes across the industry to be seen, share price performance, headcount reductions or you name it, there were plenty of distractions. I couldn’t be more proud of our employees for upholding our number one core value, throughout what’s been a challenging time across the industry that…

Thanks, Nick and good morning everyone. My comments will tie to our updated slide deck which is posted to our IR site under presentations to analysts. As highlighted in our press release this morning and indicated on slide five, CONSOL posted fourth quarter ‘15 adjusted EBITDA attributable to CONSOL Energy shareholders of $206 million. Cash flow from operations of $102 million and adjusted net loss of negative $0.26 or negative $0.11 per share. There were a handful of adjustments during the quarter; specifically CONSOL again received a benefit of approximately $110 million resulting from recent retiree medical plan amendments. This benefit resulted in lower operating and other coal costs in the quarter as well as lower annual cash payments going forward related to these liabilities by about $15 million to $20 million. In addition to the OPEB benefit, there were some additional items such as pension settlement expense, unrealized gain on commodity derivative instruments, gain on the sale of non-core assets, and $65 million tax valuation allowance. We have updated guidance for Coal, E&P and some corporate expense on slides 45 to 46, but first I want to applaud our teams that have demonstrated that they can exceed our forecast by reducing capital intensity and unit costs. We have world class assets and people managing them. Now, looking over the E&P side; as stated on slide eight, E&P Division finished the quarter with a record production of 95.5 Bcfe and our average daily volumes now track above 1 Bcfe per day. As Tim will discuss in more detail, we have also announced the results of our second Pennsylvania dry Utica well in Green County which is very exciting. The combination of a small uplift in prices and cost reductions improved margins by about $0.51 per Mcfe sequentially. We realized $2.78…

Thanks Dave. CONSOL continues to make great strides on E&P front. And today, I’d like to talk about significant improvements to-date, the accelerated rate of that improvement and most importantly the exciting growth potential we see in our business going forward. In early 2014, we reorganized our E&P Division and cross functionally integrated asset teams. While this change was challenging initially, the new structure provided an increased focus that has really borne fruit and is repeatedly driving improvements in our E&P business. This is a primary driver behind our continued organic growth at lower cost and increased efficiency. This renewed focus was a point of emphasis at our analyst day in June of 2014 where we unveiled our plans to grow the E&P business with specific goals for improvement through 2016. I’m happy to say that we have met or exceeded the targets discussed at that analyst day. We targeted a 5% to 10% annual reduction in operating expenses from 2014 through 2016. We sit here today in the beginning of 2016 with operating cost approximately 25% below where we started in 2014, and our efforts on this front will continue. Operationally, we’ve been focused on implementing lean manufacturing techniques, the impact of which can be seen in our drilling operations where horizontal drilling days have been reduced 29% from 14 days in 2014 to 10 days in 2015. Over the same period of time, our rig move day decreased 27% from 11 days to 8 days. We’ve achieved 24-hour drilling footages in excess of 1 mile several times in last two years with the longest being 6,118 feet. Footage drilled per day is a key drilling metric and has improved 22% from 2014 and approximately 83% from 2013. Applying lean manufacturing techniques, data mining and rapid adoption of industry…

Thanks Tim. And John, if you could open the call now for Q&A?

[Operator Instructions] And first line of Neal Dingmann with SunTrust. Please go ahead.

Nick, for you or Dave, and I don’t want to get too far ahead of myself, as you guys obviously now are sort of certainly appearing to be turning the corner on the free cash flow and I know as well as the liquidity. When you guys look ahead, I understand the plan this year as far as just knocking out those prior drilled wells, at some point what I am getting at is obviously given where you bonds seems to be trading a bit unrealistic, how do you -- and Dave, even you guys are looking at this -- look, let’s say even in 2017 or further between buying back the bonds, new drilling when you kind of look at just overall strategy?

We will -- without getting too particular in details of where we would put the dollars, just know we will do it probably in three buckets. It would go to essentially pay down our revolver, buyback our debt at a discount and/or start to layer in activities said into the dry Utica. I think those are the three areas. And it will be a function of how much free cash flow we generate and the relative rates of return between buying back our debt and drilling.

Okay. Go ahead.

And I think the rates of return that Tim is talking about, we are getting more and more confident on and obviously we set a sort of a timetable of mid-year of this year to before when we do make announcement of what we would do of our capital budget.

Makes sense. And then moving over that I was going to hit that part that Tim was addressing. How do you guys think about in this environment the completion cost? Obviously things such as -- it was nice to see those, dissolvable plug; I think that was few hundred-thousand you were able to save there. Nick, either for you or Tim, number one, what are you assuming for completion costs today; how does that compare since you are not drilling new wells today? And then are there other things like this -- things like the dissolvable plug and different things that could knock out a couple of hundred thousand dollars going forward?

I think the dissolvable plugs, as we showed on our recent Utica completions, shown considerable savings. That’s probably the most recent significant step, if you take market conditions out of the picture. The dissolvable plugs will become a standard. We were able to reduce several days off of our drill out and we were able to save about $0.25 million per well with those. But service costs have certainly come down and been a part of our savings. And we evaluate every well or how we choose to complete. We relook at our service costs because they are changing so quickly. So, we can take advantage there as much we can. I think there in this environment, we are not sure where the bottom is but they have come down significantly, and we do our best to stay on top of that.

And Tim, with these wells, how are you thinking about continuing with more extended laterals? I don’t know if you have done real done out. [Ph] I know there has been a couple out in the play 10,000ish. I mean, what your thoughts as far as where you think economic wise make sense in this environment or really in any environment I guess?

I think with technology and completion techniques, we continue to improve. We drilled over 10,000 foot lateral in Monroe County, Ohio and were able to successfully complete it. It has really come down to with the dry Utica, the completion practices, can you initiate the stimulation of fracture in these longer laterals. Right now, the Pennsylvania dry Utica at about 13,500 feet; that limit is somewhere around 7,000 feet. So that’s probably the limiting factor on lateral lines, as you go eastward and they get a little -- or westward and they get a little shallower that length is extended. So, it’s more of a pressure and technical limitation than it is economic. I mean the longer the laterals that -- lateral is the cheapest part of the well to drill. So, if we can drill longer laterals, we’ll certainly take advantage of that.

Our next question is from Pavan Hoskote with Goldman Sachs. Please go ahead.

So, you now have data from about 20 dry Utica wells drilled across Pennsylvania, Ohio and West Virginia, and we also have a lot more industry data points. So, as you start to put it all together, what parts of your Marcellus and Utica acres do you most the most confidence, both in terms about productivity as well as acreage prospectivity? And then if you rim [ph] development mode cost, where do you see well level breakevens and IRRs in these different areas?

Well, I think our largest data set -- the largest data set that we operate and control is in Southeast Ohio and Monroe County, so we have a high degree of confidence there with what we’ve been seen from a production standpoint but also what we’ve seen from improvements, operational improvements and our drilling and completion practices. But as I said in my remarks, the results that we’ve seen in Southwest PA continue to exceed our expectations. So, our confidence level across the Utica grows every day. From a rate of return standpoint, breakeven prices with the Pennsylvania, Utica wells, we’re targeting $12.5 million to $15 million per well, at $15 million assuming the 95% NRI which is higher than other operators, our breakeven price is around a $1.85, to achieve a 15% rate of return. If we get that -- I’m sorry, it’s $2.11 at the $15 million mark. If we get that down to $12.5 million, it drops to about a $1.85. Southeast Ohio where the wells are a little bit shallower, we’ve already shown that we can get our cost down around $10 million mark, the breakeven price there is going to be a little over $2.

And so my follow-up to that would be that you have a lot of good quality acreage that seems breakeven between $1.85 and $2, for which you’re not getting a lot of credit. Now, at the same time, investors are placing a pretty heavy premium on leverage and liquidity. I fully understand your earlier comments that you do not need to sell assets, but would you consider divesting some of these high quality Marcellus and Utica acreage; is that an option at all?

Pavan, when it comes to the asset sales, we do point out that we do not need to do it because we are free cash flow positive, so. But we are actively marketing, in some cases negotiating a bunch of packages that will impact some potential acreage and E&P acreage, so it can impact Marcellus or Utica and maybe some of the other areas. But again, I want to point out, given our free cash flow plan, we will be very disciplined and really only complete transactions that create value for our shareholders. And that does take into consideration where our debt trades at. So, we will always make sure that we’re thinking about the rate of return for the use of proceeds as well. And we have consummated about a 100 million of proceeds so far. And as Nick pointed out we have done 5 billion since 2012. So, we’re not shy in selling assets. So, it’s just -- the markets right now are difficult and we’re going to be very patient and selective when we do so.

And then on an unrelated point, in your prepared remarks you talked about high coal inventories leading to coal shipment delays. Two questions on that. I understand that ultimately the buyers are obligated to take those volumes, but do you think there’s risk to further 2017 contracts -- risk that you’ve been able to find for the contract for the next six months for 2017? And then secondly what do you see as the impact on local gas pricing because of the weak coal markets?

Pavan, on the question about 2017, we’ve actually started being engaged with our customers for coal contracting in 2017 and ‘18 and actually beyond that. Our position for 2017, we have a great start on that right now at 61% contracted for our Pennsylvania operations. And some of the tons that we do get shifted out from 2016 into 2017 will add to that percentage sold. So, we’re looking at 2017 as we’re about two thirds sold already. And we do believe that the inventory levels will lead to a constricted spot market for the first three to six months of this year but we think as we get later in the year for the customers that we are contracted with, the customers that the power plants that have best capacity factors as the coal plants in the United States, their inventories will come down through the year and will be purchases by them in 2017. And I can’t say that’s true for all coal plants across the country but the ones that we’re dealing with the strong capacity factors that they have, they will get their inventories back under control, and they will be purchasing for 2017. The other question you had on impact of coal prices on local gas prices. I’ve never seen that correlation as really been the other way around; the gas prices have had an effect on the coal prices. And as we see the forward strip in contango with the price increasing here over this year and next year, we think that in turn will get some headroom in the coal prices and allow them to rise as well.

Next is from Evan Kurtz with Morgan Stanley. Please go ahead.

Just a couple of questions on liquidity, I guess first, what are your thoughts on just tapping capital markets and putting the whole liquidity issue to bed once and for all?

Right now with our internal free cash flow plan, we are confident that we can ride out this volatile market. So, the capital market is very expensive. And so again we’re confident in our base free capital plan and we have 850 million of liquidity already and no maturities. So, going and try to tapping to this expensive capital market doesn’t make a lot of sense.

And then just one on dropdowns; what kind of signpost should we look for, or are you looking for rather as far as moving forward with further dropdowns I guess in terms of multiples or just commodity market conditions?

Obviously, the dropdowns have to make sense from both the sponsor as well as the MLP. And that would pertain either to CNXC or CNNX. And so it has to be accretive to CNXC or CNNX and it has to also be value added to us as the sponsor. So, we look at both things. And we want to make sure that when we go through the process, it’s both marks.

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

Just a couple of quick follow-ups, first on the D&C cost outline. Can you kind of walk us through both ends, kind of the high end and then a low end of the range?

Are you talking about the capital for 2016?

Yes, 2016 D&C?

Yes. So, where would we incrementally spend capital above is sort $205 million, that’s in our base plan now.

I think if the market dictates, we’ve got the flexibility to spend some additional capital on dry Utica. We could also accelerate some of our DUC inventory and complete some of those. But if we were to drill, it’d be probably dry Utica in Monroe County. But first option would be to further work down our DUC inventory and get those wells and mines, because that’s going to be the highest rate of return projects we have.

So, the high end of that range does include drilling a dry Utica well?

Yes, absolutely.

And then Tim, maybe just on the well cost of the dry Utica, can you outline kind of where we’ve gone from I guess the first Westmoreland well to the GH 9 and then any detail on the Marshall County well? I know you’ve mentioned 9 million in efficiency gains; if you can just kind of talk us through that 9 million?

Well that’s really looking at what we did in Monroe County, the gains that we saw over the first five wells in Monroe County, the efficiency gains. We expect to see those same efficiency improvements in Pennsylvania as we drill more deep wells there. So, we think there’s a significant savings there very easily another $4 million or $5 million just in efficiency improvements. And then taking out the non-productive time and the science work, that’s where that $9 million that I referred to comes from. And then when you look -- when you look, we’re already I think ahead of the curve when you compare what we have done to what our peers have done, when you consider the lateral lengths that we’ve drilled. GH 9 was over 6,100 feet; our peers were generally drilling 3,000 to 4,000 foot laterals and their costs -- some of them were several million dollars higher than ours. GH 9 will come in about $27 million. So, you take that $9 million off there, we’re already fairly close to our $15 million target. And we think that as we drill more wells, the continued efficiencies will come quickly. And we’ll get to that $15 million range within handful wells. On the completion side, we will continue to evaluate that. In some areas, there may be a need to spend more money on completions. We may be able to cut those costs. We’re using high cost proppants, we’re using ceramic proppants. We think as those become more widely used, the cost of those will come down. So, we’ve got some evaluation and data to collect on the completion but we don’t want to push the cost down too quickly until we have a good understanding of what we need to do to enhance our EURs.

Is there a target on a per lateral foot basis that you’re trying to get to?

Well, the target we’ve used in Pennsylvania is $12.5 million to $15 million; we think we can get to $15 million fairly quickly. And then, we’ll work it down over the course of the next year or so to $12.5 million. Our average lateral lengths in Pennsylvania have been around 6,000 feet. So that comes out to $2 million per 1,000 foot of lateral. And that will work its way down over time, continue to improve. And then in Ohio, we’ve set a $10 million target for the Ohio dry Utica.

And then just one follow-up, maybe for Jim. On the NGL realizations during the quarter, I mean a nice move up versus last quarter as well as compensate, just curious if there is anything abnormal kind of going on there. I know you saw a little bit of increase in NGL prices during the quarter but does it seem like enough to warrant the big percentage to move up, so just kind of curious as to anything there?

Holly, a lot of it has to do with two things, one the seasonality and the prices jumping in the fourth quarter; and two, the mix of our NGLs, we had -- about half of it was propane, and propane went from $0.07 or $0.08 a gallon up to $0.35 a gallon. So, the seasonality and the mix in the propane in that mix led to the higher realizations. Now, at the end of this quarter here, we do expect to start exporting ethane with the INEOS contract, and that would we think further bump our ethane realizations but that wouldn’t have had effect obviously on the fourth quarter; it’s going to have effect here at the end of the first quarter.

Our next question is from Sameer Panjwani with Tudor, Pickering, Holt. Please go ahead.

I appreciate the color on the cost of that GH 9 well. I was looking for some more color on the ops front in terms of rate of change when it comes to drilling days between the Gaut and GH9?

I believe we were up around 100 days on GH 9; I don’t have that exact number, I could get that for you but it was certainly an improvement over the Guat. With both -- as we have said in the past, the most challenging part of the drilling operations in the deep Utica wells is drilling the vertical section, getting down through the Salina, [ph] getting -- we have to set almost 12,500 feet of 9-5/8 inch casing. So, we’re drilling 12.25-inch hole for 12,000 feet. And that is by far the most challenging part of the hole. We expect -- we’ve got to get that down to roughly 50 days; this is what our target is. And that’s in line with that $12.5 million to $15 million total well cost target that we have. But both the first two wells we had planned on longer drilling times, we knew we had to work through some of the learnings, and I think we’ve done that. We’ve got some -- a lot of data, not just production data but with all the other wells we have interest in; we have information on drilling of -- and operations for quite a few wells. And that will help us get down to that 50-day target.

So, I guess is it fair to assume that for the entire length of a lateral and the vertical and the completion to be about 60 to 65 days is what you have baked into that in that budget that you stated?

Yes.

Okay. And then just last question from me. So current well costs and current pricing, I guess as current well costs, what do you think the economics are at current pricing and also what’s the breakeven?

Well, at current pricing, when we talk about breakevens, we’re really focused on the target costs that we’re working towards. I don’t have a breakeven cost that the $26 million or $27 million that we spent on those first two wells. We knew going into it we were going to spend more money on those first couple of wells with science and some of the learnings that we had to go through. As I mentioned, the breakeven price when we hit our target -- at $15 million, our breakeven price is $2.11 and we if get it down to $12.5 million, it will be down around to $1.85.

Okay, great. Thank you for the color.

We expect to get there fairly quickly in the next handful wells.

And next we go to Mathew Korn with Barclays. Please go ahead.

Stepping back a bit, is there any sign or even early developing worries on future supply, even the gas side or the coal side among your buyers? By that I mean do you see the reduced drilling activity, the rig counts, or just CapEx, the coal mine shutdowns et cetera, et cetera; is there any concern we’re going to wake up in the morning in mid ‘17 and the futures curve is going to be a lot higher than where it is now?

On the coal market, supply side, we’ve been sort of heading on this theme for it seems like probably a span of three quarters now. There are permanent substantial shifts that are occurring and we’re seeing these in every basin in United States and as you can see the data quarter-on-quarter sequentially annually. The numbers that we’ve seen most recently, just about every basin seems to be down 30%. But more importantly behind those reductions in production numbers are again permanent closures of finding supply sources. We’ve seen it in Northern Appalachia over the past number of months. It’s certain locations that have been supplying Northern Appalachian coal to the markets for decades. And you’ve obviously been seeing it in Central Appalachia; you’re seeing it in the Illinois basin in a major way. And our view is based on the government’s talking about, you’re going to see that maybe across the board, the Powder River basin. So there’s been a permanent significant shift on the coal side, the supply but Jim Grech has some additional color on that and also the E&P side.

Yes Matthew, I’ll start with the coal where Nick left off. The customers, the buyers on the coal side are expressing a lot of concern about the reliability of supply from domestic producers. The financial strength of CONSOL is one of the things that stands out along with the strength of our reserve base as we’re out contracting. And some numbers to back up what’s going on with that is we’re taking much more domestic contracts and sales this year than we have in previous years, as customers are -- the domestic market actually is expanding for us. For example, last year in the export markets, we had about 5.3 million tons of export coal from our Bailey complex. This year we’re going to have about 1.5 million tons and almost all of that’s metallurgical coal not thermal coal. And part of that is with the production numbers but the overwhelming majority of that is us getting into new markets domestically because the customers are worried about the reliability of supply. We are selling coal in the upper Midwest; we’re selling coal in the river systems again and we’re selling coal down in the southeast, the markets that are geographically the farthest away from us. And one of the reasons we’re doing that is because the customers concern about supply and they want diversification in their supply base and they look around at who’s going to be here in the coming years in the coal space, and CONSOL certainly stands out. The same type of concerns, I won’t say are as deep or as spread out in the gas side but we are starting to hear them from the customers on the gas side and maybe more importantly from the pipelines who want you to enter in the long term commitments, so looking at the financial stability in the E&P space. I think it’s going to be there to fulfill their FT commitments on these pipes who’s going to be able to be there five years, ten years, 15 years from now. Again, I’d say those concerns are there. They’re not as rampant as they’re in the coal space but we do start -- we are starting to hear that from the customer base the concerns about the E&P side, financial stability of the producers, and again CONSOL comes out really well in comparison with our peers in those types of metrics.

Thanks, it’s very helpful color. We’re getting -- particularly in the coal side, of course we’re getting fewer and fewer windows to how the market’s actually behaving. Maybe follow-up, just quickly regarding Buchanan. The aim is there to add more domestic sales to [indiscernible] towards more the domestic market, steel mill capacity here in the States is down in the mid 60s, we’ve seen some mill closures over the past several months. Have you seen any kind of noticeable loosening of that domestic market, and counter to that have the bankruptcies we’ve seen like Walter, have they had any effect in that market as of yet?

Matthew, statistically, again I’ll give you some numbers on that. Buchanan, this year, about 20% of the -- I mean last year 2015, about 20% of the coal stayed domestic. And in 2016, we’re going to have similar production numbers. And we think at least 40% if not more of that coal will be in the domestic markets. And we’re contracting for that already or have that under contract. So, same dynamic as the thermal markets, the metallurgical market in the U.S., there’s concern about the financial stability on the supply side, and we’re taking advantage of that and we’ve doubled our domestic sale for Buchanan in 2016 over 2015.

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

Good morning and I share the congratulations on the cost improvements. First, I want to ask, pulling together your remarks today, going forward, are we to assume that the dry Utica is the first zone of choice once capital is allocated to drilling again? And if so, does this mean the Utica exclusively on existing pads or can the Utica become the first zone on new pads?

It provides us with additional flexibility and optionality. We certainly have -- we’ve got to get to get to our goals of $12.5 million to $15 million. And as I said, we expect to do that over the next handful of wells. So, I would expect in the next year or two that Utica’s going to continually become a larger and larger part of our development program and our growth. It certainly doesn’t completely push the Marcellus aside. The Marcellus will continue to be a big part of our growth strategy but the Utica will play a bigger and bigger role as we move into ‘17 and ‘18. And remember, we want to share the infrastructure, and so we really like to hit both zones, and maximize the rate of return.

And I’ll turn it back to the presenters for any closing comments.

Great, thanks John. That concludes our fourth quarter earnings call. Thank you everyone for joining today’s call. John, if you could please review the details for the replay information.