Ladies and gentlemen, thank you for standing by and welcome to CONSOL Energy’s Fourth Quarter Earnings Conference Call. As a reminder, today’s call is being recorded. I’d now like to turn the conference over to the Director of Investor Relations, Tyler Lewis. Please go ahead.

Thanks John. Good morning everyone and welcome to CONSOL Energy’s fourth quarter conference call. We have in the room today Nick DeIuliis, our President and CEO; David Khani, our Chief Financial Officer; Jim Grech, our Chief Commercial Officer; and Tim Dugan, our Chief Operating Officer of our E&P Division. Tim is a little under the weather today, so we also have in the room Larry Cavallo, our Vice President of Exploration and Development to help Tim during Q&A if needed. Today, we will be discussing our fourth 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 as in 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 Dave. 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 Tyler. And before we turn it over to Dave who is going to go over some more of the details, I’d like to first provide some of the highlights for both the quarter and for the year. And we can start over on the E&P division. The Company posted record production levels of 70.5 Bcf for the quarter, and as we’ve highlighted in the past the growth engine of CONSOL has been the Marcellus Shale and it’s easy to see how the impact the statement has had on the overall growth of the Company. If you look at the quarter Marcellus production volumes are 88% higher than the 2013 fourth quarter. The growth has been remarkable to stay the least and as the Marcellus becomes a bigger part of the production mix it’s got a lot of implications across the entire E&P division due to low costs, which in turn contribute to higher rates of return. And you go on top of that, the fact that the majority of our acreage is held by production and that we’ve got the high net revenue interest, especially compared to the peers across the industry, you can see why even in lower commodity price environment we’re able to make good returns and good profits. In addition to the Marcellus, the Utica Shale segment, it continues to exceed our expectations as well. Last quarter we discussed and we highlighted the rapid growth and how we raised our 2014 production guidance as a result and you look it today, the Utica Shale continues to surpass expectations where we had record production in the quarter of 7.1 Bcf, which was up from half a Bcf in the 2013 fourth quarter. That resulted in the Utica exceeding our annual 2014 production guidance. In addition to the…

Thank you, Nick and good morning everyone. Today I will provide an overview of the fourth quarter results and provide an update of accomplishments in key metrics as well as how we are going to manage through energy environment and sustain the program. Similar to the past quarters, we have posted a comprehensive slide deck to our Web site and my prepared comments will mainly tie to Slides on 10 through 15 and 137 through 162, which can be found on the finance section. Before launching into the details of the quarter and the outlook, let me touch on some key housekeeping items. We have updated our disclosure of our business segments to realign towards how we manage each unit. For coal we have three segments. We have Pennsylvania, we have Virginia and we have other operations. For our E&P division, we have Marcellus, Utica, CBM and other. In about a week we will release our 10-K which will provide greater detail of these segments down to the pre-tax line items. Our goal again is to provide transparency and help you better to model our company. Second, we are going off of hedge accounting and now we'll let the gains and losses of our hedge positions flow through our income statement. Now for the bottom-line, net income and EBITDA; CONSOL reported net income for the fourth quarter 2014 of $74 million or $0.32 after including or excluding the one-time items, our adjusted net income was $58 million and $0.25 per diluted share and our adjusted EBITDA was $262 million. Now let's look at some of the operating details and expected projections. Since Nick just highlighted our production, I’ll just focus on some of the other items. Our E&P operations really did post strong results and it will enable us to…

(Operator Instructions) We’ve question first from the line of Neal Dingmann with SunTrust. Please go ahead.

So, first question just around production, if you could give me an idea on that, 30% production growth Nick, or David that you were speaking of, obviously a pretty solid number. How do you think of that when it comes to your JVs? I’m just wondering these sort of number one, how much of the JVs are sort of included in that? And then secondly how do you think about that if [indiscernible] has decided to cutback more, would you guys maybe pick up some of that slack or how do you all think about that 30% growth?

Yes, the 30% and the path too, it's going to be very similar to what our journey was in ’14, which means Marcellus and Utica are effectively 95% plus of that production ramp. Now what the mix is between Marcellus and Utica, that is a very fluid situation. Right now we’re watching everything from NYMEX to basis to well cost and well profiles to come up with an optimized mix, but for the path of 30 or ’15 and frankly the path of 30 to ’16 will be Marcellus and Utica driven. ’16 now you start to look at dry Utica and what that's like being and where we go with that. That will be more of an impact I think as we get through the middle of 2015 with that test well data that will be coming in. But that’s where it will come from. Dave, any comments?

No, and I just say we’re doing some work on CBM and so that might play into the roll at some point down the road.

Okay, and then just wanted secondly on that the hedges. David maybe for you, any thoughts here? Obviously with prices lower that I know you mentioned that in fourth quarter and you stepped up the hedges a bit. Any thoughts today on where hedges are about would you consider walking into any more and I know in the past that not too terribly long ago you all added about 100 million cubic feet a day. I think it was above $4 and the strip wasn’t quite there. I was just wondering how you are able to accomplish that.

Well, the strip was probably there because we didn’t do anything that was unusual. We pay attention very closely to the commodity and when the time is right above our threshold we’ll step in and we'll lock it in. And remember Neal, we were up to about almost 80% last year because the commodity was there and we felt it was the right thing to do and if the commodity gets there it will -- and it is very volatile. Everybody is short the commodity right now. The strip is not very liquid beyond 2015. So it really sets itself up for – as activity starts to slow and production growth eventually slows and the industrial man eventually comes in, it will set itself up to be able to lock in more down the road.

And then just lastly, just you mentioned obviously that -- I know because it does make a lot of sense with the MLPs coming up. On the thermal MLP is there a certain amount of either for ’16 or ’17 amount of volumes that need to be contracted or the pricing needs to be walked in, in order to pull off the MLP and just when I guess for -- on both sides I guess would be my question around the thermal and then the latter MLP, how you think about that? David is there something that has to be contracted?

It's a good question and we think about it a lot, but I think if you look at our production, it is -- it's been in place for a while and so our customers are pretty consistent. It's a little different than if we were building new mines and trying to find a market for coal. So the repeatability of contracting with the same customers and the right customers will have a low heat rate coal plans in the right markets, will happen year-in and year-out. So it really ends up coming down to more of a price question as opposed to can you contract it out.

Along those lines, what's David saying, for 2016 is to taking all the coal that we have sold for our Pennsylvania operations which has the -- we have some [indiscernible] that's unpriced. When it comes over a 30 million tons which is in over 50% of the production or the complex and that really is all built off of our core customers, as David has said and so if year after year we build up to that foundation and layer in more sales in two tiers as we go forward and we expect to keep doing the same, using those core customers, filling out the daily the contract portfolio for future years. And again it comes with a matter of timing in the market when we think it's optimal for us enter into those negotiations, and when the customers are ready to enter into those contracts as well. But we’re going to build off of that strong base going forward.

Our next is from Mitesh Thakkar with FBR Capital Markets. Please go ahead.

My first question is just in terms of the equipment issues which you mentioned at Harvey and geological issues you mentioned at Enlow Fork. Are all of those behind us or are you still kind of going through the initial teething troubles at Harvey? How should we think about it? Obviously fabulous performance on the cost side at Enlow, despite geological issues?

The equipment issues at Harvey are behind. That was more of an explanation when you look at 2014 in total, what were some of the drivers of the results. So that equipment item was sold basically mid-year -- just before mid-year in ’14. On the geology side for Enlow, there will be different periods of time over the next 12 to 18 months where geology will be a factor. We spend a lot of time and effort with our technical experts to map that out a panel by panel and those implications or those things that we would be challenged with are reflected in the guidance numbers that we gave and the cost views that we gave for ’14 and for ’15.

And just a follow-up on the Met side, how should we think about normalized cost at Buchanan, again very good performance on the cost side. Should it -- was this more like you ran at all cylinders in terms of productivity or how should we think about more on a normalized basis for that one as well?

The cost performance that we posted in 2014 and quarter-by-quarter at ’14 for Buchanan was driven really by a whole range of different activities on the efficiency front, from staffing levels and the scheduling of production, scheduling of maintenance projects, all these things accumulated into the cost results that you saw. Our view in ’15 is when you look at Q1, Q1 cost of Buchanan should be comparable to what we saw in Q4 of last year at Buchanan, which of course is a really good result. Now what happens Q2 on out is going to be driven in part by what the market opportunities are for Buchanan. If we sit through the current view we have in the release on 2015 for Buchanan, Q2 to Q4 should be normally higher than what we see in Q1 and Q4 of last year. If we’re able to take advantage of a strengthening market or additional sales opportunities that our sales team and partners are working on constantly, then Q1 and Q4 of last year, those cost results and expectations should continue on for Q2 and beyond and into '15.

Our next question is from Joe Allman with JPMorgan. Please go ahead.

Hey David, in terms of the CapEx, I know you said that the 2015 budget for E&P is $1 billion and in 2014 you spent $1.3 billion. If you just isolated the exploration and development spending, where do you expect that to be in 2015 and what was that equivalent number in 2014?

The $1.3 billion is pretty close to D&C, but we try to keep that as it close to apple-to-apples.

Okay. So in other words in 2014 you spend about $1.3 billion in D&C and then in 2013 $1 billion is D&C? Is that what you're saying?

That’s right. There is a little bit of -- I’m sorry, there is about -- there is some CONE in both of them, I'm sorry. There's about -- there is some CONE gross capital in there, but we’re not breaking it out now because we haven’t provided the CONE budget publicly yet.

Joe, the big – if you look at ‘15, the big, I call it non-delineation or between delineation and exploration dollars, what the spend would be for the dry Utica, the reduction plan in ‘15, that well in Green County PA, the well in Westmoreland County PA and what we’ve got moving on in Monroe, and I say somewhere between exploration and delineation because we’ve always got expectation and views for success in those locations. But that would be about the most exploration oriented or focus that you would see in the $15 billion budget.

Okay, that’s helpful. And what was the total carry that you received in 2014 and what’s your expected carry in 2015?

Well, we generated slightly over $200 million for the year. We’ve received about $180 million of it in 2014. So we’ll have some carryover of carry in 2015. And right now we’ll plan for zero but we’re hoping for a spend that would generate somewhere in north of $200 million.

Okay. So I know that Nobel carry is off but the Hesh [ph] carry is still on?

Yes, and that's baked into it. I believe it’s about 100 million.

Okay. And then on the production side, so I know you’re growing 30% full year ‘15 over full year ‘14, but the exit rate of ‘14, the exit rate in ‘15 released based on preliminary modeling is more like up 10% or 15% depending on -- if I make the adjustments. So example in the fourth quarter ‘14 if I add back the shut in production, the implied exit to exit growth is about 10%. So if you could talk to that. And then, but it ramps up in 2016. If you actually had the 30% expected growth in 2016, it really revs up. Could you just help us with kind of there is a bit of slower growth in 2015 and then it seems the ramp up in 2016, does that imply you’re going to be spending more in 2016? If you can just help us with that.

No, it’s hard to give you the well count by quarter but we should not have a problem meeting or exceeding our 30% growth, because a lot of the activities that we have spent dollars on in ‘14 will go to putting the wells on and it’s really going to be just quarter-to-quarter. I think that's -- it’s hard -- it’s just a quarter-to-quarter thing. I don’t think you have to read into the exit rate versus exist rate.

And I'm sorry, but what I'm saying is like the 30% in 2015, a lot of that has -- at least of that is really the ramp up that you saw in 2014 between the first quarter and the fourth quarter?

Right. Right.

And then so, I’m getting something like 10% or 15% 4Q ‘14 or 4Q ’15. It's still a good growth right, but --?

Okay. So you’re saying we’re going to need spend a lot more dollars in ‘16 because you’ve seen the 4Q ‘15 ramp exit rate is not high enough. It’s hard because I think -- we haven’t given you the 4Q ‘15 numbers. So I think if you have to see the wells coming all line to see what our actual level would be.

Got you. Is it fair to say though that there is a ramp up just in quarter-to-quarter? Is there ramp up in 2016 based on your preliminary kind of look at 2016.

And you mean as far as capital?

Yes, capital leading to actually a quarter-to-quarter to ramp up in production.

Well, part of the answer Joe will be how productive will the Utica wells be, because right now those Utica wells could be two to three times a Marcellus well. And so it’s really hard to say that we’ll have to ramp up a lot more activity to do that.

The other thing Joe, and Larry and Tim I might give a little more color on this is that a big driver of this the timing, especially on the completion side of the equation, when we do the completions which are good proxy for guidelines lines and how that timing is quarter-by-quarter late in the year versus earlier in the year. I think that’s a big driver too of we sort of smooth out or sculpt the 30% in ‘15 and then into ‘16. And that ability to do that is going to create I think a lot of capital efficiency and lower capital intensity and ‘16 number we get there but you guys might want to comment little on that?

It is. A lot of it is just timing. With completions coming out of the winter months we’ll see more turn in lines later in the year that will contribute to the ‘15 growth but that’s where lot of the ramp in ‘16 will come from those wells that turned in line later in the year in ‘15 and mostly a similar type ramp in ‘16. So our plan will achieve 30% growth in both years.

That’s helpful. Then just two quick ones. So what kind of returns do you think you’re getting. If you use non ex futures prices, what kind of returns are you getting in the Marcellus and in the Utica? And then just a second question, when you calculate your NAV, are you using NYMEX futures to do that or are you using some other kind of approach there?

We do it both ways. We have an internal view and we also use a NYMEX view. But again the NYMEX just, if you look at the liquidity in the NYMEX, the amount of volume that's created on the NYMEX, it drops by 90% from ’15 into ’16. And then it drops by 97% into’17. So even though it’s the best way to get some sort of visibility on what price discovery have, it's based on very, very illiquid transactions. So it’s very hard to want to base everything off of the curve right now. So, we do it both ways. Our returns really range anywhere from about 10% up to about 25% to 30%. So they have come down and what's also baked in there is the cycle time improvements that we’re doing as well as expectations of some service cost inflation.

So you said they're not baked in there or they are baked in those returns.

Yes, so that’s partially -- that’s what offsets it and so the key for us is to move around the program a little bit to make sure that we’re optimizing those rates of return based upon what we see as the realizations.

Okay. So David, so the 10% to 25%, so you are baking in some service cost deflation?

Absolutely.

Our next question is from Caleb Dorfman with Simmons & Company. Please go ahead.

To run back your service cost inflation, what are your current well cost in the different areas of the Marcellus and how much savings have you fully realized? Does your CapEx budget fully take into to the savings? You have only gotten so far or do you think there could be additional savings?

Well, we have a good piece of the 15% efficiency gains built into our capital budget because we feel very good about it. I would say we feel like there is more upside there over time and Tim could probably talk to that. We've baked in some servicing cost deflation into our capital numbers. We look at it every week and we’re hoping to eclipse it. I know there is a lot of percentage of reduction numbers that are being thrown out there. We’ll just say we’re going to be very cognizant of those reductions and we’re trying to accomplish a couple of things. One is, we’d like lower cost, we’d like to keep the activity level intact and so we’re trying to partner with the right service companies to keep their program in place. And then second is that we’re trying to keep the right crews and get better productivity as well as just cutting cost because we can wake up and cut our way into a problem for 2016.

Okay, that’s helpful. So David, you used to include a slide in your slide deck which had cash burn assumptions and EBITDA assumptions. That wasn’t in there this time. Can you help us think through cash burn in 2015 and 2016?

Yes, right now we show a very modest cash burn and that’s -- basically what we’ve done is we have taken the current commodity view and thrown it through the 2015 model. What we haven’t done now is, there's some actions and some things that we will do to offset that. And so if you look in our slide deck you’ll see our debt to EBITDA goes up slightly. You do not want that to happen. And so I think when you wake up at the end of this year you’ll see that we have offset the commodity fall, particularly in natural gas. That’s really -- probably the biggest impact to our model.

Okay and then a question for Jim Grech. Can you talk about how much incremental coal to gas switching you are seeing right now and when I look at Northern Appalachian price indices, it seems like they fallen off maybe $4 to $5 a ton in the past maybe two, two and a half weeks. Can you sort of discuss what you’re seeing in the pricing environment right now?

Hey Caleb. There's a couple of things we’re seeing. First off, as far as our contract coal sales, our customers are taking all of the coal that we have sold and have been consistently taking it. So haven’t seen any of that really slowing down. There is always an issue here and there with weather but there's nothing systemic of customers trying to start slow walking, taking coal. The pool has been very good and the railroads have been moving the coal. The effect that we’re seeing in the market with the low gas prices is very little to almost non-existent spot activity at the moment for thermal coal. We are getting some conversations going with some of our customers who are looking out into later in the first quarter and the second quarter about the potential for getting into the spot coal buy in, but there is a lot of waiting and seeing what’s going to happen here with the rest of February and March with the winter weather and what that does to stockpiles. So, I think Caleb, the answer to the question is that it's still to be determined, the effect that the low gas prices are going to have on the coal market as far as the demand side of it. We're just going to have to wait and see how the rest of the winter plays out?

Our next question is from Jeffrey Campbell with Tuohy Brothers. Please go ahead.

I wanted to start with a couple of Utica Shale questions. It seems that you were really calling out Utica Shale activities this quarter. You increased your targets with increased acquisitions. You increased your ’15, ’16 production guidance and then you pointed out drilling in Green and Westmoreland. Earlier this week your Ohio Utica JV partner announced dialing back activity in 2015. Can you qualify your current attitude towards the Utica relative to last year’s Analyst Day?

We continue to be -- if not more excited now about the Utica than we were at Analyst Day last year. Our JV partner is just a portion of the Utica, that is the wet -- really the wet Utica over in Ohio. But as you move eastward and get into to dry Utica where we have a 100% working interest, that’s where we’re talking about the wells in Westmoreland and Green County. We’re very excited about the results there. And then when you -- now when you look at production in 2014 in the wet area, we operated the top four oil wells in the Utica in the third quarter in the state of Ohio. So we continue to be excited about that.

And another thing too. A lot of the potential for CONSOL on Utica, and in particular dry Utica was based last year at Analyst Day off of the concept of the stack pace and the improved capital efficiencies and reduced capital intensity that we could accrue if we’ve already got midstream assets, or pad assets, or water infrastructure in place is to get -- thinking one way to get a certain production target, another player of the horizon that has economic opportunity like dry Utica, you can get a certain production ramp much more efficiently. I think you would be able to individually across this place. That’s another key component of how we feel about dry Utica and looking at where we're at today on that issue, we are way more excited than we were back at Analyst Day. Analyst Day it was a -- it was a concept and we had logic tied to it with where we think this could apply, but you couple that with the data that’s flowing in from the industry and what we’ve got planned for our drilling program on the dry side, coupled with the capitalized infrastructure we've got in place across Utica and Marcellus field, that that could be something that is definitely moving the needle on anything for share for us in the out year, starting as I said in ’16.

Slide 64 shows Utica drilling cost reductions without any reduction for service cost deflation. What’s a reasonable expectation for deflation in Utica wells? Or is Utica a player where the crew is particularly important as you referred to earlier today?

The numbers that we show in there do not have deflation [indiscernible] that they did come in at a very low $2.24 all in cost. Some of that is a function of the carry that we get and the benefit in digging new rate. Some of that is -- really a lot of that is a function of the quality of rock and the productivity of the wells and so -- can we continue to take those cost down? It will -- it's a good question. I think it's burning at a very low rate and I think if we could keep it flat, that would be great. If we could take it down, so much better. I think the Marcellus is probably -- my guess is Marcellus is really more of the area we’ll be taking more cost down.

And if I could ask one last question, Slide 28 and 35 suggest that 100% of current completions feature RCS/SSL. First is that correct? And if so, should our modelling be biased more toward the higher RCS type curves going forward? And if you want more data, when do you think you’ll have enough to consider revising towards the RCS type curve?

Yes, all of our completions are RCS/SSL. We have seen the benefit of that, the increased IP and the increased EURs. We continue to work on optimizing our completion. We’ve seen the benefit of RCS, but now we’re looking more regionally area by area and optimizing our completion design based on area specifics. So we’ll continue to see progress in that area, but we are using RCS/SSL in all areas.

So let me just to return to the last part again. Is it increasingly more realistic then to be thinking of the higher type curves that you published for the RCS rather than the normalized 5,000 curves?

Yes, we continue to see our type curves improve.

Our next question is from Lucas Pipes with Brean Capital. Please go ahead.

Nick and Dave, you emphasized share repurchase opportunity in this market environment and in light of some upsell and post constrains with organic growth targets and then investing it in your cash flows, what do you think would have to happen for these share repurchases to take place?

Lucas, again the filter we’re using for all of this is NAV per share built during -- if you go back, last time we had our third quarter earnings call and if you go back to sort of the November timeframe, where that balance sat between I’ll call it share count reduction and allocation of cash flow for that versus the E&P production ramp, we’re probably looking at taking the momentum that we were coming out of ’14 with and coming out with a plan or set of plans that would get us north of 30% in ’15, ’16 and a certain level of share buybacks. If you fast forward to where we're at today, okay, we still have those. As we said in the commentary there's two overwriting objectives, but there's been a shift, and again the recent we’ve had a shift is because we’re adapting and using [indiscernible] NAV per share filter with the new assumptions, new pricing, new efficiencies, new share price et cetera. So rewriting all of these things so to speak real time. And that shift has resulted in the balance and the objectives for ‘15 that we quoted which is now 30% ramp. So giving up on some of that upside that we have built with momentum, and now refocusing more than emphasis to the share count reduction. Now where it goes tomorrow, we don’t know. We don’t know what’s going to change over the long haul especially with pricing, with share pricing and with everything else. But what we do know is how we’re going about that decision making is management. So we’re still going to use that NAV per share builder. We constantly look at the changing assumptions from well type curves to deflation, savings to commodity price changes up or down, and then we run math and we’ll see where we come out at with the 30% versus the share count reduction efforts for going in to ‘16 and beyond.

Great. So you would maybe relax some of those constraints that I mentioned under -- depending on the value proposition.

Longer term, yes. And I think a way to think of it is -- instead of saying we’re moving towards relaxing, it is -- if you look over the next three years, our two big buckets of capital allocation will be capital expenditures for E&P production growth and share count reduction. What the waiting is between the -- of those year-over-year, that’s where we’re always using NAV per share filter to make the right optimal allotment. Today in 2015, its $1 billion to get that 30% ramp in ‘15 and ‘16 and a certain level of share count reduction that will result from that.

That’s very helpful. And maybe to shift gears, Jim, coal production guidance came down a little bit at least on my numbers. Could you maybe walk me through the drivers of that? Is this a result of decreased utilization, competition within Northern Appalachia, competition from outside of the base in natural gas? If you could maybe give us a flavor for the thermal coal market and your sales commitments there?

Lucas, the decrease in the production that is shown for the Pennsylvania operations was really due to two factors. Neither of them had to do anything with the market. One is this more long wall moves occurring in new year than in the previous year which of course takes tons out of the forecast and we didn’t have that baked in all way there. We have changed that and revised that as we go forward. And second one is, we still expect to have some of these geologic conditions, the slow down some of our mining in the PA Ops. And so the combination of those, adding in some long wall moves and geologic conditions is we took the tonnage down in those numbers and it was nothing to do with market conditions.

And the other side of that Lucas is, we’ve got a benefit of having an actual number for ‘14. So if you back to first quarter ‘14 we had a very strong quarter Pennsylvania operations and we were effectively able to walk up the production number and the actual results as things unfolded. Our expectation and hope is that in ‘15 we have the opportunity -- we'll do that with the same thing. As Jim said the market will be there, take it. But first things first, giving you the best shot of what we see ‘15, with geology, timing and everything else, that’s where we come out at. When we have the first quarter call we’ll be able to give you an update on what the progress has been and where we sit relative to a new production growth for the year.

And next Brandon Blossman with Tudor, Pickering, Holt & Company. Please go ahead.

I hate to drag this down but just a couple of details application questions. One on the CapEx, even just directionally, rig count that you’re expecting 2015 versus 2014 to kind of normalize that?

The rate count on average will remain relatively flat. We've got about ten rigs running now and we'll average about 10 rigs throughout the year in ‘15.

Okay, great. That’s helpful. And then kind of reconciling the 5% to 10% CAGR on production cost savings or big efficiencies or cost savings with 15% and I think that 15% savings on D&C was a year end 2015 number? Or is that a full year average number?

I think last year we talked about a 15% reduction in D&C by the end of ‘15, and we are well on our way to achieving that. And that’s doing well with 5% to 10% reduction that Dave was talking about earlier this year.

Great, that’s easy. And then on basis -- so basis in the fourth quarter came in above what you expected and then there was a comment that you may be able to be flat or so no basis differential in Q1 based on different selling points. Is there more detail available to that? And I assume this is all relative to Henry Hub pricing. Is that correct?

That’s correct.

Yes Brandon, what our marketing department was able to do is to basically split between two different pricing points and get us to more favorable one. For example last year the Dominion south, we had about 26% of the gas being sold there. And that’s going to go down about 14% in 2015 as the production and again using some of those flexibility we have in the FT, we’re going to move it away from that lower price market and move it over the TETCO M3 market which again in 2014 was about 15% of our gas sales and in 2015 it's going to go up to 29%. So basically we flipped. We cut the DTI sales point in half and just about doubled the TETCO M3 into a much more favorable market. So when David was giving that quote, if you take the TETCO M3 market the East Tennessee trend goes on 5 market and the TICO [ph] market, that’s about two thirds of our gas production is going to those three pricing points which are some of the more favorable pricing points that you’re going get and that’s leading to the difference in the basis from the first quarter this year to fourth quarter of last year.

Okay, great and presumably at least as we look throughout the year, kind of the Q1 hedge profile I assume as is a bit higher than the average for the year?

That’s about right.

And your next question is from David Gagliano with BMO. Please go ahead.

Appreciate all the focus on the NAV and obviously it makes sense. The question -- obviously we all have NAVs and they’re pretty sensitive to the price deck. And I know there's a lot of sensitivity around giving a price deck but my question is what point do you -- if you can just give us a sense, maybe a range or something like that, do the projects become NAV negative.

And remember, the capital that we’re spending this year really actually goes to production next year. So you have to think like that as well. So it’s a good question. I think it is a function of what we see the improvements also in efficiency gains going out. So it’s a moving target. So you got to be careful about using one price. But I would say if we were looking at $2 kind of realizations for a multi-years, that’s where it start to really impair dramatically your activity.

$2 realization? Okay, fair enough. Then the Thermal related question I guess. Obviously we’ve had that collapse lately in at least the near prices. So my question is that all things content here, as we look forward to the next couple of quarters -- given the margins that were just reported on the gas segment, given the fall in pricing, do you still expected to be delivering positive margins on a near term basis in the gases if prices stay where they are?

We do and obviously it’s very volatile but we do, yes.

And if we mark to market without the hedges, would that still be the case?

There will be moments in time where they will be neutral, but close -- and there will be spots like liquids will be positive and so you got to look at each product.

And that will conclude our question-and-answer portion, I’ll turn it back to presenters for any closing comments.

John, thank you. Thank you everyone for participating today. If you could please just instruct the callers on how to access replay information?