Dan Zajdel - Vice President of Investor Relations Nicholas J. DeIuliis - Chief Executive Officer, President and Director David M. Khani - Chief Financial Officer and Executive Vice President James C. Grech - Chief Commercial Officer and Executive Vice President of Energy Sales & Transportation Services Timothy C. Dugan - Chief Operating Officer

Neil Mehta - Goldman Sachs Group Inc., Research Division Brandon Blossman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Caleb M.J. Dorfman - Simmons & Company International, Research Division Holly Stewart - Howard Weil Incorporated, Research Division Lucas Pipes - Brean Capital LLC, Research Division Andrew Coleman - Raymond James & Associates, Inc., Research Division Michael S. Dudas - Sterne Agee & Leach Inc., Research Division Mitesh Thakkar - FBR Capital Markets & Co., Research Division Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division Evan L. Kurtz - Morgan Stanley, Research Division Kuni Chen - UBS Investment Bank, Research Division

Ladies and gentlemen, thank you for standing by. Welcome to the CONSOL Energy Second Quarter 2014 Results Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn the conference over to the host, Vice President of Investor Relations, Mr. Dan Zajdel. Please go ahead.

Thank you, Greg, and good morning to everybody and welcome to CONSOL Energy's second quarter conference call. We have in the room today, Nicholas Deluliis, President and CEO; David Canney, our Chief Financial Officer; Jim Grech, our Chief Commercial Officer; and Tim Dugan, our COO of E&P. Today, we will be discussing our second quarter results. 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 is in our previous SEC filings. We also have slides available on the website for this call. We will begin our call today with prepared remarks by Nick, followed by David. Tim and Jim will then participate in the Q&A portion of the call. With that, let me start the call with you, Nick.

Thanks, Dan. Good morning. Dave Khani is going to cover our quarterly results in detail in a few minutes, but before that, I wanted to highlight a couple of major points on the quarter and more importantly, where we're heading into the second half of 2014 and when you look beyond 2014. And I'll start with the E&P segment. And how we're executing our plans so far this year within E&P. Our momentum that continues to build, that momentum is being illustrated many different ways across our gas operations. You can see qualitative accomplishments, that show the E&P momentum. The best example is probably the Utica results from our Noble County wells that we discussed in our operations release. So for the first time, we're seeing the Utica play begin to grow and supplement our already sizable Marcellus position. And when you flip over to the Marcellus, we're seeing the benefits of the lean manufacturing approach everywhere we look; from asset team structures were subfields within the Marcellus compete for capital, due to drilling efficiencies on those torsels and horizontals to improve logistics. When you look at rig mobilization and demobilizations, to much more efficient completion jobs that utilize the advanced completion techniques of SSL and RCS. And the second quarter quantitative results, they also show the stability in E&P momentum as well. Production for the overall E&P segment in quarter came in on target and we're optimistic enough looking into the rest of 2014 to raise the lower-end of our production guidance range, where it now sits at 225 to 235 Bcf. And our Marcellus total all in cost came in under $3 and the cash cost for the Marcellus came in under $2. So when you couple these qualitative accomplishments to blossoming Utica play, lean manufacturing into Marcellus,…

Thank you, Nick, and good morning. Today, I will provide a quick overview of the quarter, compare our results to our stated goals noted at our analyst day and provide insight into our results to help you model our company. We posted an updated slide deck on our website. My prepared comments will tie to slides 10 through 16 and several slides within the financial section on pages 154 to 180. From the results, CONSOL energy posted a net loss for the second quarter of 2014 of $25 million, or a loss of $0.11 per share compared to a $13 million loss, or $0.05 per share, a year ago. Included in this, whereas in the second quarter where the impact of several transactions, including the early extinguishment of 2017 maturity bonds, the new credit facility, the pension settlement and partially offset by a coal contract buyout. In total, these transactions reduced our net income by $41 million, or $0.18 per diluted share. So if you back out the adjusted net income, excluding these transactions, were $16 million or 17 -- of $0.07 per diluted share and also includes the impact of raising our 2014 effective tax rate in this quarter from 21% from 19%. This caused us to have a tax rate to look unusual for the quarter. Our 20 -- our 2Q '14 adjusted EBITDA and operating cash flow totaled $246 million and $220 million respectively. Now in mid-June, we hosted a very productive analyst day where we focused on improving returns, lowering the capital intensity of our business and improving our cost to capital. Specifically, we pried into some key some targets in many different areas and I'd like to provide a snapshot of where we are at the end of the quarter. First on production. We're modestly…

Greg, would you please instruct the callers on how to queue up for questions, please?

[Operator Instructions] Your first question comes from the line of Neil Mehta from Goldman Sachs.

Nick, can you talk a little bit about gas basis? Where did it -- where was the number for the second quarter? And how has it been trending in the third quarter? And more importantly, I know you provided some updated disclosures here on some of the slides, like 117, what are you doing to mitigate this risk?

Neil, this is Jim Grech. In the second quarter, our basis it's ran on average in the negative mid 40s. I don't have the exact number for you, but they give you a range of $0.44 to $0.47. Now in looking forward at the pricing for the third and fourth quarters, you have the basing, but the bases, which also have the gas strip price, you got the liquids uplift and you have our hedge impact. And so when you put all off 4 of those components together in the pricing, and we forecast out using today's market prices, we have about a 3% to 5% variance from what we posted in the second quarter, looking out into both the third and fourth quarter. Again, Neil, take into account gas price, hedge impact, basis in and liquids uplift. So you put all those together and we're in that 3% to 5% range.

Perfect. And our expectation is natural gas prices will rally back well above $4. But if we stay below $4 for 3 consecutive months, that Kerry [ph] temporarily shut off. Can you talk about in that scenario how that would impact your 30% production target? And if you're committed to that 30% growth rate, is it fair to assume that you wouldn't have to issue equity to achieve that?

The 30% 3-year production ramp is something that we're definitely committed to. We feel that's the quickest and highest accretion to NAV per share that we can do with our operating cash flow currently, which of course is driven by Marcellus and Utica. So that's a constant with or without carry for sub $4 or north of $4 gas price. On the idea or concept of issuing equity, right now, again, looking at the NAV per share decision tree, the thought of issuing equity is something that is not attractive in the least to us at any point of the foreseeable future. So that as an option, if its got a ranking its got to be last, if it even has a ranking. In terms of the specifics on managing through carry and the rest of the year, I'll turn it over to Dave for a little more detail.

Yes. When we set the 30% reduction target, we tried to find that middle ground where we could live with the volatility of gas pricing as well as factor in the improving rates of return either through uplift of EOR or declining cost per well. So we try to find that middle ground and we clearly have the asset base and the ability to grow at a much faster clip. But we wanted to have that measured growth, so that we don't have to jerk our program up and down like we did in 2012. That wasn't it -- it wasn't helpful for us. We missed that on the learning curve and some of the cost efficiencies. So we're going to try to be very consistent looking out. And I think the other thing to think about is, we measure our rate of return not on sort of a quarter or annual basis, we're looking at probably more 3-year kind of period to -- what generates most of our net NAV per well.

Perfect. And last question for me is that can you talk through the potential for monetizing some of your mineral rights for both gas and for coal, as you see some of your peers have done? Is that an opportunity set as you think about restructuring and capital allocation?

Yes. We are studying it intensely right now. And it is in our opportunity set and the question is how do we best monetize it because we have a -- we're effectively 150-year-old company sitting with a fairly sizable key position in coal and a pretty meaningful position in gas.

Your next question comes from the line of Brandon Blossman from Tudor, Pickering, Holt. Brandon Blossman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Did I hear a slight change in the color around the MLP? It sounds like an IPO is a definite go versus what you talked about as a possibility in the analyst day?

Are you telling that for our gathering system? Brandon Blossman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Yes.

Yes, we've actually made a very definitive statement at the analyst day that we were going to IPO, and we filed a document, an S-1 document, which we will probably make public some point in August. So yes, we're all going ahead. Brandon Blossman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. Good. Utica results pretty impressive results released in the offset date. Can you kind of give some color around how those results match up to your type curves that you laid out in the analyst day and what your expectations around those type curves on a go forward basis?

I think -- this is Tim Dugan, Brandon. I think they match up fairly well. We're pleased the liquids production is higher than what we had originally anticipated. So these are strong wells. We got them flowing now and they're holding pressure very well. We've got next group of wells out in Noble County scheduled to come on this week. We have 2 wells on our Noble 30 pad coming on by the end of this week and one on our Noble 16 pad. So we should see some increases in production, but we are excited about the results that we've seen first 3 Noble 19 wells they're averaging 23 million cubic feet a day with their equivalents with the initial rates. Brandon Blossman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: So it is fair to say that you're biased upward against your type curves, currently?

Yes. They look very strong. So yes.

Your next question comes from the line of Caleb Dorfman from Simmons & Company. Caleb M.J. Dorfman - Simmons & Company International, Research Division: I guess first question is sort of a follow-up on one of the previous question. With the potential for gas prices remaining stopped throughout 2014 or into 2015. Do you think you would alter your drilling emphasis within the Marcellus north to Southwest, where the rates of return are higher and away from Central PA and Northern West Virginia?

So I think, looking again at the 3-year, 30% ramp, there's a drill plan behind it of course. It's got contributions across these different subfields. Now the asset team structure that Tim seems to have put together, looked at that very issue. But if there are shifts, there'll be marginal shifts within those subfields and they'll still equate to a 30% annual production ramp. Caleb M.J. Dorfman - Simmons & Company International, Research Division: Okay. And then I guess a for Jim Grech. Obviously basis differentials are an issue on the gas side of the business, but it also seems like that it could be an issue on the coal side of the business. Have you heard from any of your customers who have exposure to the Marcellus gas, that they're starting to run their gas plants harder in one of their coal plants or is that not an issue yet?

Caleb, that hasn't made its way to us yet, as far as running gas plants harder than coal plants. Now what we have noticed from the customers is, where there is more of an urgency to be buying coal at the moment for 2015, though some of those decisions for some of the customers have been put off till a little bit later in the year. Now with that said, we've been very successful in contracting for 2015 and we feel very comfortable with our position going into 2015. But as far as the flipping of generation, we haven't heard a lot of it yet, like I said, the only thing we've been noticing is maybe the customers being a little more hesitant. Still think they're going to buy for 2015, but waiting a little bit longer to make those decisions on the coal side. Caleb M.J. Dorfman - Simmons & Company International, Research Division: Great. And then one final question. I know that you in Q2 and then I guess when looking into Q3, there's the geological issue and then operational issue. If those weren't occurring, would you have had the demand to sell more coal throughout the summer?

Yes, Caleb. Our demand has been very, very strong for our coal. The Bailey Complex coal. So any ton that we produce, we have a customer on the other end waiting to take it.

Your next question comes from the line of Holly Stewart from Howard Weil.

A couple of questions. First, I guess, I'll go to basis differentials also and I think as you all pointed out, you've probably had one of the better differentials thus far. Were you able to remarket some of your unused capacity and if so, could you provide what the benefit was during the quarter?

Holly, what we do is, the amount of optionality that we have in our portfolio, and about 20% of our portfolio is on daily pricing and to the extent that we can depending on what's happening in the market, flip that between different markets. So our gas marketing team does that. As far as quantifying the amount of flipping around that we did or jumping from market-to-market, I don't have that number for you, Holly, but I can tell you that we actively do it and with the 20% of the market on a daily pricing, that gives us that optionality to try to find the best home for that gas.

Okay. Well then may be moving to ethane. I think you guys pointed out several different long-term options in the press release and with what you're going to do with ethane. What are you actually doing with ethane today? It sounds like some of it's being blended into the stream. Just kind of thinking bigger picture on treatment of ethane over the next few years.

So, Holly right now, most of our ethane is ethane rejection. There is -- we do have some release capacity that we have on the ATEX line to Mont Belvieu that we were using. It's about 2,000 barrels a day. And they're using that for the next several months. But in the near term, all of our ethane is being sold for e-content. Now as we go out though into the future, we're building optionality into our portfolio on different fronts. One is if we want to increase the amount of ethane rejection, we have our line that we have with those 5,000 barrels a day from Majorsville down to McQuay, ethane purity line where we can take ethane down and blend it with the dry gas down at McQuay. So that's the one option that we have during that pipeline is coming online this year. Then as far as selling the ethane, we have several different markets we're looking at. One is we have our announced contract with INEOS which gets us into the export markets, and that will start up in 2015. We have the announced deal that we have with the Shell Cracker and we're also talking to other facilities of that type and expanding our presence in that market. And then again, on the Atex line to Mont Belvieu, we're looking at picking up a some more release capacity in the future for having that optionality as well. So one of our portfolio lets us maximize the realization we get from ethane whether it's rejection or taking it to the export market or taking it to the domestic market.

Okay, but no real, like from a contract standpoint, no real need to continue or to put ethane into your barrel at this point? Contains the mix I guess of your barrel at this point?

That's correct. If you're talking about the ethane rejection side of it, no there is no commitment for us to do that. That's entirely at our discretion how to take it and sell to it one of these other options that we've been developing.

Your next question comes from the line of Lucas Pipes from Brean Capital.

I really appreciate the sense of urgency to boost the NAV per share. And when I think about your production growth on the gas side, kind of all else equal, your credit metrics should improve. So in light of this, would you consider adding on more debt to it, kind of further advance your NAV per share, has that maybe even shifted since the analyst day, that thinking?

And the answer is right now, no. I mean, obviously, today, we're out in the marketplace, but we're just trying to lower the cost of capital. We're not adding on, if we wanted to we would have just add on -- I think we have a lot of different levers that we're looking at pulling here from non-core assets sales to the MLP to other things that we could do that were -- are probably more NAV accretive than issuing debt.

That's helpful. And then, maybe to shift to the kind of thermal gas side, more from a macro perspective obviously the environment has changed a little bit since the last update. Could you maybe share your thoughts on the market with us, inventories on the coal side, kind of your outlook on the basis more broadly going forward? I'd appreciate your thoughts on that.

On the coal side, Lucas I'd like to start with our mine inventories. And our mine inventories are running between 350,000, 375,000 tons at the mine right now, maybe even a little lower than that today. And it's much lower than our typical $500,000 tons plus. So our mine inventories are very, very low and I'll go back to the comment I made earlier. If we have a ton of coal there, our customers want us to ship it. So that inventory I'll just consider that working inventory that we have. As far as our customers inventory on the coal side, again, we're getting very strong demand from our customers to ship coal for this year. We've done very well for contracting our coal for this year and for next year. And I think, again that's a sign of the inventory situation or the concern about inventories next year at the coal consumers. And a couple of numbers on that, above and beyond what was in our earnings release about our coal position and as that would relate to inventories. By the end of the third quarter, we project to have about 24 million tons of our portfolio sold next year. And that's the sales and also, the coal that we haven't sold, but not price and colored coal. All of that type of coal, you add that up, we think we're going to be around 24 million tons by the end of the third quarter and about 28 million tons, if not more, but 28 million tons by the end of the fourth quarter. So going into next year, we're going to have maybe about 2 million tons of Buchanan and about 2 million tons of Bailey left to sell going into next year. Not a lot of coal but again, that strong demand, I think that we're -- that strong demand we're getting I think is a sign of the inventory concerns at our customers in them wanting a reliable supplier. On the gas side, you asked about our basis outlook. Volatility is the key word. On basis we saw some of the markets that we're in have very strong positive basis over the winter, and now they're in the negative basis situation. Again, if you can predict the weather well, then you can probably predict what the basis is going to be. Our view is a lot of volatility and when we see what we think is attractive basis or attractive NYMEX strip in the marketing, we hedge it off, take that risk off the table.

Your next question comes from the line of Andrew Coleman from Raymond James. Andrew Coleman - Raymond James & Associates, Inc., Research Division: Just want to ask about the PD 10 that you all had in the release. That's a 5.731 Tcf, is that -- that's not a number for June 30, that year end '13 number, do you have a number for June 30 that will incorporate the moving gas price from year end number?

Well, what we did was we took the year end '13 reserves at 5.7 Ts that you noted and we just updated it for June 30 lookback as if we did the same process for the normal PV 10. What we didn't do was, we didn't update the reserve for midyear. We normally do that in a full-blown reserve analysis once a year. So it effectively is a lookback 12 or -- to sort of average 12 months, but starting at 6/30 in 2014. Andrew Coleman - Raymond James & Associates, Inc., Research Division: Okay. So it's got a be little bit upside then in terms of the additional NCF or barrels that you could book from the higher gas price for last year month?

That's right. There's -- there's RCS, SSL, up lifters. Their normal production uplift, as you watch the wells because we normally get that as well as all the pipe bookings and everything in the Utica, which is a very limited booked right now. And so, as as that activity turns, so we'll able to book more of that. So I would expect to see a very different number for year end. Andrew Coleman - Raymond James & Associates, Inc., Research Division: Okay, great. And same question was I guess. As you think about hedging -- as far as you've been hedging on natural gas. What size of the market need to be or as CONSOL's production need to be where it might look at, trying to lock any of the dirty hedges on NAV [ph], on NGLs or anything up the liquid side?

Well the liquids market is a tougher market to hedge. It's less liquid in general from a hedging perspective. And so you really can't get a lot of duration on it. So the best way you could do it is through probably more direct sales. And that would be and I'd say that's probably our method right now, as we get more sophisticated figuring on how to do it and unlock, we may be able to come up with a better way to give us some limit -- capture the upside as well as limit our risk or drop our VaR.

Your next question comes from the line of Michael Dudas from Sterne Agee. Michael S. Dudas - Sterne Agee & Leach Inc., Research Division: Tim, could you comment on maybe service cost issues and then, any trends that you've seen through the first half and how it's going to play out given the ramp up of activity in the region?

So we've been -- we have renegotiated some of our service contracts and some of our pricing. And seen a downward trend, but with activity picking up, some services will get tighter. But so far, we have not seen an upward movement in pricing. Michael S. Dudas - Sterne Agee & Leach Inc., Research Division: Looking at your gas transportation diversity that you talked about here in the call, are you still active with some discussions looking at some of the Gulf Coast markets as you're trying to play things out of next couple of years? Is that something that can be moved -- moving at a better speed?

Yes, Michael. Jim Grech here. We're looking at the Gulf Coast markets and the Southeast markets as well. And we announced at the Analyst Day a smaller sale, but maybe indicative of something we're going to start looking taking a harder look at was the 50,000 a day sale that we had to Schenair [ph] down to the West LA markets and for LNG export. But as far as the diversification, what we've signed here in the last few days, which we didn't have time to put into our earnings release was our memorandum of understanding to be an anchor shipper on the Nexus pipeline. And that doesn't go down to the Gulf, I think it gets us up directly into the Michigan markets and also, with the potential for the Canadian markets and Chicago markets. So we have that in place. We're very optimistic about that pipeline being built. It has a substantial existing infrastructure to build off of and has a very strong end-user commitment on the other end of the pipe. So if you're on about that, adding that to our portfolio, giving us that diversification up to the Midwestern markets, and we still are in active discussions for the Southeast and also, we're down into the Gulf as well, Michael. Michael S. Dudas - Sterne Agee & Leach Inc., Research Division: Excellent, Jim. My final question is regarding the MLP. I'm pleased to see, its seems like that's going to be coming at a pretty much quicker pace than I've seen others in the markets. So congrats, hopefully on that end, but I think for Nick, you talked about the race and looking at the net asset value opportunities, et cetera. I guess, nothing's really changed from the June analyst day, but is there things have you seen just in the last few weeks or progress maybe on some of these other asset sales that gives you the confidence that maybe you're going to get to them faster and get to that magic point of free cash flow for the business?

I think it's 2 things that give us confidence. One is what's our view on the likelihood of executing what I'll call our base plan, whether it's base production, base cost, base realizations for E&P and for the thermal segment. And we're just as confident, if not more confident on our ability to do that through '14, '15, '16 than we were, say, 6 months ago. So our confidence level in base plan, I'll call it, has gone up, which is great. But the other side of it is, what types of opportunities do we see incrementally to improve off of that base, so whether it's the unit cost in the Marcellus or whether it's the marketing opportunities for Bailey or what Buchanan has displayed through a really tough downward trend in the market trough, and all this other, which Jim mentioned. And when we look at the incremental opportunities to make improvements off of that base plan, there's more and more of those options and opportunities coming on the table, which is again, in our mind, you think out of it as a breakeven point in time, do our base plan or some point in time, where we go free cash flow positive and from what you think you can improve off of that, that brings that time forward. So it's those 2 things in general that are traded in the sense of urgency and excitement to keep driving.

Your next question comes from the line of Joseph Allman from JPMorgan.

This is actually Daley calling in for Joseph Allman. And my question is around the recompletion. Can you guys talk about the cost that's associated with the recompletion efforts and over what time period you guys expect to drill up the 200-plus identified locations? And then, if there's any update on the reserve of that, what you guys expect from the recompletion?

Well, we have done 6 recompletions to date this year. We're still in the early flow back stages on all 6 of them. But so far, the results are promising. The actual results -- we've seen initial rates between 3 million and 6 million a day, which exceeds what we saw from the initial recomplete that we have shown at analyst day. So we're very pleased with what we've seen. We're seeing good pressure. It looks like we've contacted some new rock with the recompletions, so that confirms both the RCS and SSL and the effectiveness of it. So moving forward, we do have approximately 200 of them out there and we're looking at where -- evaluating those candidates and prioritizing them. But we don't have the specific schedule for them right now.

Okay. And is there, do you guys have an estimate on how much is the recompletion cost?

Right now, we're looking between $1.8 million and $2.2 million per recompletion. And there's a range there because as we work through these efficiencies and we continue to get better at what we do, those costs will come down.

Okay. And were there any ultimate EOR uplift -- update that you guys are seeing from the recent recompletion?

We haven't put any numbers like that out yet, because we're still in the early phases of the flow back in initial production.

It might be a better question for the next quarter.

Your next question comes from the line of Mitesh Thakkar from FBR Capital Markets. Mitesh Thakkar - FBR Capital Markets & Co., Research Division: My first question is just on the coal side. On the met side, you mentioned that you're are planning to shift some tonnage from the export market to domestic market. Can you give us some quantification around it? And how should we compare it against let's say, your 2011 or 2012 kind of volumes in the domestic market? And then, whether it's going to be a high-vol or a low-vol product?

The shifting of the tons, Mitesh, is that we're talking about is getting mainly the low-vol coal from the export markets back into the domestic markets. And we say we have at about 50% increase in those tons that translate through. We've been a little over about 1 million and 1.1 million tons in the domestic market with the low-vol. And so, what we're seeing is that, that's going to get up to 1.5 million, 1.6 million tons in the domestic market with the low-vol. Hopefully, higher than that, but our estimate right now is right in that range. And you asked about previous years and future years, in total in 2013, we had about 7.4 million tons of export coal. And that was all types that was low-vol, high-vol and thermal. This year, we're about 5.6 million tons of export coal and then, looking forward to 2015, we are seeing some strength, we're expecting to see some strength with the export thermal and export high-vol markets. We're getting some good customer discussions on going in Europe. We were making some very good inroads there with our coals. And so we're expecting that to rebound some. But next year on the low-vol side, again the focus is to bring more of that coal back to the domestic market. Mitesh Thakkar - FBR Capital Markets & Co., Research Division: Great. And just a follow-up question but on the gas side. When you think about your position in the Marcellus and Utica, are you seeing any opportunities where you could probably swap some of your assets out, which are probably not core to you and maybe you look elsewhere in some of the other basins like Permian or Eagle Ford that you can get sort of diversification from a basis standpoint. And I know it's a transient issue, but just longer term, how do you think about that? And whether you have the or whether you will just go out and buy something from the cash flow, which you're probably going to get from the asset sales?

I think that when you look at our E&P opportunities, we look at the Marcellus and Utica last quarter what we do, Appalachia is core to what we do. Outside of Appalachia, not a lot of interest to say the least with acquiring positions in other basins. We think again, going back to NAV per share, the best way we trade value on that metric is based on deployment of that capital into Marcellus and Utica. That being said, there are acreage footprints within the Marcellus and Utica that don't currently fall within our drill plan. And looking at those, as either opportunities to trade or acreage within our footprints at Marcellus and Utica or to monetize to third-parties that do have plans for those areas. That is something that we look at and we assess on a regular basis. So there's going to be what I call acreage footprint opportunities in the Marcellus and Utica for us to monetize, whether we do that through trade or sale remains to be seen. But our focus remains on Marcellus and Utica and not basins outside of Appalachia.

Your next question comes from the line of Neal Dingmann from SunTrust.

Say, Nick, your first question just on the takeaway. You guys seem to be in quite good shape maybe even better than others, just your thoughts on a go forward basis, how do you stay in front of that, as you see obviously that being built out?

Neal, this is Jim Grech. In Utica, we have 2 things that we need to say ahead of is not only the take away, but the processing capabilities. And on the processing, we feel we're in excellent shape as far as having the contracts and the facilities in place to do the processing of the white gas. And on the takeaway, again, we -- as you said, we're in very good shape with the pipeline portfolio that we have, and the nexus pipeline that we said that we've signed up for is an anchor shipper. Again, that's another potential outlet for our Utica gas to go up to the Midwestern market.

Okay. And just lastly also the Utica. As far as -- we all think you've reached -- I know there's still a lot of I guess on the completion and drilling the completion side for differing with how you do with the completion method. Your side, you did mention as far as how far out you would take these laterals, your thoughts on if you could get this sort of optimal area I mean is it you look how far out you'll take these -- some of these stages, et cetera? Or will you continue to be [indiscernible] done maybe for the next quarter or so itself?

I'm not sure I caught all of that, but we are continuing to test our completions, design. We're very satisfied with the results we've gotten from the RCS and SSL. But there are still work to be done. Right now, we're 150 foot stages. We're looking at sand amounts. We have run some tests in the Utica with increased sand amounts. We got some wells coming on here in the next few weeks to a month or so, that will incorporate some of those tests, so we're anxious to see those results. We do expect to drill long laterals as we do more drilling in the Utica. The wells we've done in Noble County so far, they've been shorter than our average Marcellus wells, but that's been more due to lease limitations.

Your next question comes from the line of Evan Kurtz from Morgan Stanley.

Just a follow-up on the met coal comment that you make in your press release about growing volumes by 50% on low-vol next year. I was just wondering and it seems quite early to actually talking to customers about 2015 contracts. I was just hoping you provide a little bit clarity. Do you have target customers lined up for the coal, or is this something that you plan to think about as you go into the negotiations season?

Kevin, on the metallurgical coal market, it takes a while to break into the blends of customers that you haven't been in for a while or haven't been in at all. So what we've been doing is we think we have a couple of advantages on that in the marketplace. We have our R&D group here at CONSOL that has its own coke testing lab and facility. So we've had those R&D people going along with our salespeople out to the domestic customers. And testing different blends of coal with our own facilities. And we've been getting a very good response from the customers as far as incorporating us into their blends for next year. So when we say we that 50% increase, we think that our starting point as we work our way back into these blends, to get into these blends for the first time. So we have specific customers we're talking to. We have either contractual commitments that we're in the process of signing or we expect to get culminated here by the end of the year. So yes, you have to start early if you're going to break into a new market and that's what we've been doing.

And then maybe one other on just cost over coals moving back into the thermal market. At this point it would seem like it would make sense to sell as much of your lower grade high-vol into the thermal market as you possibly can. I just wanted -- if you can provide some insight, is that what you're doing, is that why we've seen the guidance shift a little bit this year? And maybe if you could kind of highlight some of the -- what sort of seaborne price you might need to see some of these tons shipped back into the met coal market, that will be helpful.

In our forecast in the earnings release for this year on the high-vol coal. We took 0.5 million tons approximately out of the forecast and that went into the thermal domestic market. So we have pulled some coal back and brought that into the thermal domestic market. Now looking forward, again, we're getting some that R&D and testing of coals, we now have been doing that domestically. We've been doing that internationally with a good focus on Europe. And we're getting some, what we think some good responses on that coal potentially for next year for the high-vol to get it into those markets for next year. So in response to your, what price it would take, with our Bailey coal, we send it to 22 different countries and thermal markets, low-grade met markets, PCI markets and our job is to get the best revenue and realization for our shareholders that we can. So there isn't a set price, I would say, to get us in the export market. We go between all the markets that we can access and pick out ones that we think give us the best realizations in the long term for our shareholders.

Your next question comes from the line of Mike Scalia from Stifel.

Neil asked you about the well configuration in the Utica including the lateral length. I was just curious, on the Marcellus, you seem to be getting better wells with the longer laterals. Have you found a link there or you see the EOR per foot go down to where the incremental lengths are not worth the additional cost? And if not, is there acreage configuration or is there some other limiting factors that would prevent you from going beyond 8,000-foot average that you plan for this year?

That's something the asset team's are looking at what the optimal lateral length is from the completion standpoint, drilling standpoint, reserve recovery and we don't have necessarily have an answer for that yet, but we think 8,000 is in the range, but we don't have a definitive answer. We have drilled longer laterals than when we have, that's usually do to lease consideration, making sure we don't strand acreage or resources. So that's our thinking right now.

Have you seen any difference between the wet and dry areas in terms of the lateral length, is there a preference to go longer in one versus the other?

Well certainly in the dry, there's less concern with handling liquids later on in the life of the well. The longer lateral lengths are less of a concern. And then you got the consideration of whether the wells are up-dip or down-dip, that certainly plays a role. So there's a lot of factors that go into it, but so far, we have not seen significant differences in lateral length between 8,000 or say 10,000 or 11,000 feet wet or dry as far as a breakover point or variations in result.

Greg, we're going to have time for one more question.

Okay, and that question comes from the line of Kuni Chen from UBS.

Just a quick one on the Illinois coal basin. I know you seen some deals in the space recently with valuations in the $2 per ton type of range. For the reserves that you have there, is there any reason to think that, that would go for any kind of premium or discount over other transactions that you've seen?

Yes. Obviously, this is greenfield reserves and so for, it's hard to give you $1 per ton. We're going to let the process work its way through. But I will tell you, we will find a way to maximize the value, either through selling it in one piece or breaking it up into multiple pieces that will make sense for multiple buyers. So you'll just have to stay tuned. It's a process that we're going through right now and hopefully, we'll have some good results third quarter or fourth quarter.

Okay, Greg. That concludes our call. Could you please instruct the callers on the replay information?

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