Tyler Lewis - Director, IR Nick DeIuliis - President and CEO David Khani - EVP and CFO Jim Grech - EVP and CCO.

Neal Dingmann - SunTrust Mitesh Thakkar - FBR Capital Markets Joe Allman - JPMorgan Caleb Dorfman - Simmons & Company Jeffrey Campbell - Tuohy Brothers Lucas Pipes - Brean Capital Brandon Blossman - Tudor, Pickering, Holt & Company David Gagliano - BMO.

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 growth in the Utica we’re seeing even more impressive results on unit cost. In the fourth quarter total all in Utica unit costs were $2.24 an Mcf.

That's a dramatic improvement compared to the previous year’s quarter and the higher Utica volumes along with the lower gathering and transportation costs -- those contributed to the lower all in unit cost results.

We spent a lot of time talking about [indiscernible] potential across acreage and the ability to develop multiple formations for the same pad. This is a concept that we initially tested back in June 2013 with our first Upper Devonian which was on the NV39 pad.

This well was developed on an existing Marcellus pad and we saw some very impressive results, not only from the Upper Devonian well, because if you remember also from two underlying Marcellus wells. Then below the Upper Devonian and Marcellus there of course is the dry Utica.

During the quarter we’ve not only started drilling four dry Utica wells and one Marcellus well from the same pad in our 100% owned acreage in Monroe County, Ohio but we have also started drilling two dry Utica wells in Pennsylvania. One of them will be in Greene County and one in Westmoreland County.

These dry Utica wells are going to be drilled off of existing Marcellus pads and as different areas and formations such as the dry Utica continue to be delineated and developed across Pennsylvania and West Virginia, that’s going to open up entirely new frontiers for CONSOL.

We’ve got just over 470,000 net acres across Pennsylvania and West Virginia that are perspective for dry Utica, which are not part or subject to either joint venture where we own 100% of it. So these stacked pay opportunities, especially when you start to consider dry Utica, they’re expected to meaningfully improve our options for production growth.

They’re expected to reduce our capital intensity, our targeted production levels and they’re going to move the needle on our NAV per share. And the opportunity for these types of E&P, continuous improvement project, they’re not just relegated to the Utica, Marcellus and Upper Devonian horizon.

When you look to our Virginia coalbed methane field, we’re becoming increasingly excited about the potential decline and advance completion test designs across the multiple coal things.

We’re also excited about technology, that we’re being able to use from improved legacy field production levels and decline rates and we’re excited about our already capitalized midstream infrastructure that has both room in the pipe and price basis advantages relative to Northern Appalachia.

So the opportunity set in Virginia is part of the total production portfolio. That can be used to help reduce unit cost, increase segment margins and reduce capital intensity. So stay tuned in 2015 to see how that potential unfolds as well. So a lot of exciting things on a E&P horizon for CONSOL Energy.

Making all these exciting things come separation, it takes a strong team and in ’14 it’s hard to deny the massive transformation that we saw in E&P division that was driven by such a team. To start with, we brought on Tim Dugan as our Chief Operating Officer.

Tim's industry experience is invaluable and with his leadership we change and advance the foundation of E&P division by centralizing leadership under one roof and by completely restructuring the department by organizing them into asset teams. The progress, the rate of change, success of our E&P division is seen throughout the year.

It’s been in process and in 2014 we saw very [indiscernible] production of 235.7 Bcf, which is well above the 30% growth target for the year. Now the total we had record Marcellus Shale production of 111.7 Bcf in 2014, that was over 90%, specifically 93% higher than 2013. That team momentum is only going to continue to grow.

Our E&P division has a goal of reducing drilling and completion cost by 15% by year end 2015 and when you look where we’re at today, we’re already seeing that objective come to fruition, preserving the 30% production growth in both 2015 and 2016, also doing all of that with a very efficient 2015 capital spend of $1 billion in E&P.

I have a little more to say on the 2015 capital in a minute. But before we do that let’s shift over to coal. And when you look the coal segment, our Pennsylvania operation had another outstanding quarter, by not only meeting production guidance and finishing the quarter at 8 million tons, but by also having total all in unit cost of $42.61.

These low costs helped generate a healthy margin, resulting in just under $160 million of cash flow before capital expenditures. Our marketing efforts continue to make more progress and during the quarter contracted an additional 1.4 million tons in 2015. That brings us to about 80% contracted for the year.

The team continues to lock interim sales with what we consider to be must-run power plants for multiyear duration. It's really good news when you put that in the context of the thermal coal MLP that is underway and Dave will provide an update on that. On the metallurgical side, the market continues to be challenging but there is good news.

Our Virginia operations or Buchanan mine saw remarkably low unit cost once again this time for the fourth quarter.

The mine's undergone efficiency projects while operating on a reduced schedule and we think that these cost levels of Buchanan are sustainable in the first quarter of 2015 and they’re potentially going to be expandable throughout the entire year, but that will be dependent upon the market and the sales volumes that we secure.

As a result of the cost structure, our Virginia operations again have managed to make a healthy margin and level of cash flow. There aren’t too many U.S. Met operators if any that can say the same and that in and of itself is a big reason why we’re pursuing a MetCo IPO this year.

It’s an asset that not only makes money in a very challenging Met market but has the potential to make a significant amount of money when the market churns. Nothing out there like it. So in 2014, we finished up our growth capital associated with the coal division when we completed the Harvey Mine.

That’s been up and running since this past March and now that growth capital is complete and we see these mines running on maintenance and production capital moving forward.

Now in addition to E&P and Thermal and Met within the Company, we often talk about our other segment and one of the benefits of being a 150 year old company is having a suite of assets, where we might consider non-core to our current operations which will most certainly have value to others.

This segment continues to be an important part of the story and it’s been a big positive for CONSOL. Last quarter we reiterated our confidence in hitting the $1 billion mark in proceeds over a five year period. We were ahead then and we’re even more ahead now.

In the fourth quarter the other segment had remarkable success and the Company saw cash proceeds from assets sales of $270 million. The majority of the proceeds were from several non-core asset sales, mainly thermal supply company and uncapitalized whole reserves in the Illinois basin to two strategic buyers.

These proceeds helped the company in addition number of ways, but above all things it provides optionality and liquidity that our peers don’t have and it's concentrate management’s focus to what we consider to be the truly core activity with Appalachian Shales and thermal and met longwall mine.

So we look forward to continuing our formal process for monetizing these assets throughout 2015 and expect momentum to continue. Now you know that as management, we are NAV per share driven and we do that when assessing where to allocate operating cash flows and how to use liquidity.

In today’s price environment we got to competing an attractive options of growing E&P production in prolific fields like the Marcellus and Utica, as well as reducing our share count at levels what we consider to be margin prices. For 2015 we’ve got two objectives across these two cash flows deployment opportunities.

First objective, we want to grow our E&P segment production 30% for both 2015 as well as 2016, which builds on a success in this area that we saw last year. Growing the production base in this manner it drives economies of scale, it improves financial metrics and it launches the critical mass for E&P as a standalone segment.

In short, it increases NAV per share and we expect to hit 30% growth harvest for both ’15 and 2016. We plan to accomplish this with the 2015 capital budget of about $1.2 billion in total or $1 billion for E&P when excluding coal.

That high level of capital efficiency and that low level of capital intensity for the growth targets, they're exactly what we expect to see as a result of lean manufacturing and continuous improvement by coal. Second objective, we need to progress from talking about and thinking about share count reduction to actually reducing the count.

Last December, CONSOL announced a $250 million share repurchase program. This is a definitive and a material start to a very compelling component of our strategic game plan over the coming years. Simply put, we look and view share count reduction as a great rate of return investment and a strong NAV per share driver.

As 2015 unfolds, we’re going to be very aware and very cognizant of pricing with margins, returns, spending and how we balance CapEx for production growth with the opportunity to taking our shares at discounted prices in the coming years. We're utilizing a very simple, but very powerful tool of that big NAV per share equation [indiscernible].

As long as we let it navigate our decision making, we feel we will optimize cash flow allocation for the shareholders. Now on the last quarter’s earnings call, we provided some views on changes to the E&P industry that we were seeing.

We knew then that it was going to get tough, especially for the producers who are over levered with both long-term debt and high cost long duration transportation agreements. We’ve been preparing for these challenges and we’ve lived through the volatility of commodity cycles before and we’ll be able to capitalize on a downturn.

These types of downturns create opportunities for us to continue to differentiate ourselves from our peers. That's the power of being a low cost producer with Tier 1 assets, focused and prepared as a management team and having a strong liquidity position.

Notwithstanding the challenging environment CONSOL will aggressively pursue its goals and objectives for ’15.

These goals continue to create a greater level of transparency with the IPOs of a pure play Thermal Coal MLP and MetCo by growing our E&P segment by 30% and by taking advantage of where our shares are currently trading at by reducing share count.

And with that I'm going to turn it over to Dave and he's going to provide additional thoughts on this quarter and the coming year..

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 drive our operating cost and capital intensity down.

During the fourth quarter, our E&P division had net income about $36.5 million and cash flow from operations of about $55.7 million. Now realizations declined by $0.36 per Mcfe to $3.90 per Mcfe in the fourth quarter. Including this, total average realizations was a hedging gain of $0.39 and liquids up with about $0.20.

Liquids production represented about 12% of our production and 17% of our E&P revenues. Our expectations for liquids productions remain consistent with previous stated guidance of between 10% and 15% of our total production by the end of 2016. We have forecasted that 4Q basis would be between a negative $0.80 and the $1.10 and came at about $0.87.

We expect the first quarter basis to be flat to maybe negative $0.20 as our marketing team has shifted away our volumes from a more negative Devonian sales pool to more positive basis areas as we have excess FT and have the ability to do so.

Looking in unit costs, even though our realizations have declined, our unit cost also declined as well and offset to keep our margins flat at $0.71. Our all-in Marcellus and Utica Shale cost came in at $2.83 and $2.24 respectively.

We continue to make progress on cost efficiencies as we’ve highlighted before at our Analyst Day as we increased stages per day based on moving rigs and we are making good progress. During the quarter for instance we have achieved 11 RCS/SSL stages within a 24 hour period. At the start of 2014 we were averaging only 4.

This types of [indiscernible] and metrics add up in a big way and help us get us towards the 15% reduction that Nick had mentioned before in our key targets. Our goal remains to take our E&P unit cost down by 5% to 10% annually over the next three years and we are on track to meet these goals. Now let’s look at coal.

During the fourth quarter active coal's active coal operations generated $187 million from cash flow from operations before capital expenditures.

For the year this totaled $729 million which was actually light of $800 million target due to mostly lower coal realizations and early [ph] equipment issues in Harvey Mine and more than half a year of tough geology in our Enlow Fork Mine. Despite that our costs were actually excellent in the quarter.

Our Enlow Fork cost came in at $38.24 and in addition of Buchanan cost had another seller in quarter at $53.96. Looking at these costs despite the fact that we’re setting in a weak pricing environment for met coal, we can actually make real margins and good margins again because of their cost structure.

So this energy environment is creating another down drift in oil prices and I wanted to highlight eight key points that should help you give you confidence that we can keep our program intact. First over the last two years we have been diligent on our headcount and administrative expenses.

We had a target of reducing expenses by $65 million in 2014 and we have eclipsed that at $70 million. Second, we have dramatically improved our balance sheet by reducing leverage long-term liabilities and environmental costs.

Our debt to EBITDA sitting at 3.2 time is very close to the target where we said a year ago and we do have some more and we believe if we continue to take more cost out of these areas, we believe we’ll keep our leverage ratios relatively intact.

Third, we continue to execute on our non-core asset sales program as Nick just mentioned and we took $270 million of cash proceeds, putting us slightly ahead of our $1 billion target. Fourth, we remain on target for a mid-year IPO for Thermal Coal MLP and a late third quarter, fourth quarter IPO of MetCo.

Fifth, we have avoided expensive transactions in oil in MetCo and stuck to our key core areas. Our focus will remain on bolstering our core area. Six, creating predictability in a volatile market. This is achieved by hitting our production targets, locking in our revenues where they make sense and reducing our unit cost across both E&P and Coal.

Seven, we’re lowering our capital intensity. One of the key ways we can improve our capital intensity is by managing our decline rates and benefiting from our HBP acreage. I will focus on this a little bit later. And then last, our supply chain group is moving from execution to strategic and will be a big differentiator in 2015.

Last year we began many programs that have just begun to be approved with an NAV uplift of about $50 million. This is just the tip of the iceberg and expect the benefits to increase to over $100 million in 2015 and reduce service inventory and vendor costs. We have begun to implement key safety and performance indictors with our key vendors.

Now let’s look at the commodity and how we manage the risk at around realizations. We continue to manage through commodity cycles by focusing on controlling the controllables and we are fortunate that we have a diversified portfolio of tier 1 assets and revenue streams that enable us to manage commodity and risk differently the most pure-play E&Ps.

We’ve produced four major commodities, natural gas, [indiscernible] metal and thermal coal. We measure the price risk using borrower evaluate risk which we highlight on page 153.

The natural gas stability we maintain a hedge program that we use a program hedge at a base level hedges and layers in additional opportunistic hedges when prices were above the certain threshold. During the fourth quarter the Company raised its hedge position from about 27% to 45% and this is purely on gas.

While the E&P space has felt the impact of falling oil prices, this decline has had a little impact on CONSOL’s bottom line. The Company offsets this down from oil by saving on diesel cost. This all consumes between 30 million and 40 million gallons of diesel per year, about two thirds of which is used on the coal side.

Metallurgical coal prices appear to be forming a bottom, a structural bottom absorbing the slowdown in fuel demand and the many supply growth projects coming out of Australia. To improve realizations we have reduced our Asian exposure and increased our Met ton sales to the domestic steel mills.

Last, our strong steady state thermal portfolio provides consistent visibility on revenue. We continue to contract at our thermal coal and are managed to lock in term deals over the multi-years. For 2015 our overall thermal coal portfolio is contracted about 85% in price.

As a result, our 2015 monthly has declined from about 10% at the beginning of 2014 to about 3.5% presently. Now let’s talk about capital. We announced this morning a $1.2 billion capital number. That’s down actually from 1.7 and excluding the benefits of carry.

Our 2015 E&P division capital of $1.1 billion is actually down 30% versus our 2014 spending levels of $1.3 billion. As Nick stated earlier, our goal is to achieve our 30% growth above ’15 and ’16 and we feel our budget achieves these goals. Some of the key assumptions behind the budget, one is our coal maintenance production capital about 160.

Our GNC [ph] capital will benefit from the 15% efficiency goals and additional reductions from all fuel service costs and last that CONE will bear a portion of its gathering capital.

Now I want to point out that our 2015 E&P capital budget really sets up our production for 2016 and 2017, as the cycle times that bring on our multi well pad ranges from 18 to 24 months.

So as prices have declined and access to capital is slowing, one question we’ve been getting recently is what is our decline rate? What is our maintenance capital spending needs? Our Marcellus base decline rate is about 34% and when you combine it with our CBM and conventional assets, we have an overall decline rate of about 14%.

Now when you factor in that we have a PA thermal coal business that essentially has 25 years of flat production, our BTU decline rate actually goes down to about 5%. So when you take all that in between coal and E&P of maintenance and capital just sitting around $460 million.

Combined with a lower decline rate, our HBP, our [indiscernible] benefit, our low cost FP [ph] and the $1.67 billion carry we can preserve and grow NAV in almost any energy price environment. So as Nick has touched upon, we do intend to participate in stock buybacks.

As everyone knows not all buybacks are good and for buying back shares at the right time when they trade at a significant discount to our internal views of NAV is good.

Due to where our share price is currently trading, we believe our stock is trading at a meaningful discount to our NAV and obviously we don’t provide what our NAV is but we do feel like this is the right time to buy back stock. So in summary, CONSOL remains incredibly active, focused on driving efficiencies and growing shareholder value.

The two transactions that we are pursuing along with stock buybacks are a step in the right direction. Now, I’d like to open it up for questions..

(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?.

Certainly and yes, ladies gentlemen this conference is available for replay. It starts today at 12:30 PM Eastern will lasts until February 6 at midnight. You may access the replay at any time by dialing 800-475-6701 or 320-365-3844. The access code is 350438. Those numbers again 1800-475-6701 or 320-365-3844 with the access code 350438.

That does conclude your conference for today. Thank you for your participation. You may now disconnect..