CNX Resources Corp (CNX) 2014 Q4 法說會逐字稿

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 would now like to turn the conference call 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; Dave 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'll be discussing our fourth-quarter results. Any forward-looking statements we make or comments about future expectations are subject to business risks, which we have 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 end 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 highlighted in the past, the growth engine of CONSOL has been the Marcellus Shale, and it's easy to see how the impact this segment has had on the overall growth of the Company. If you look at the quarter -- Marcellus production volumes were 88% higher than the 2013 fourth quarter.

The growth has been remarkable, to say 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 put 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 interests, especially compared to peers across the industry, you can see why even in a 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 at it today -- the Utica Shale continues and continued to surpass expectations where we had record production in the quarter of 7.1 Bcf, which was up from 0.5 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 costs. In the fourth quarter, total all-in Utica unit costs were $2.24 in 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 stacked pay potential across the acreage and the ability to develop multiple formations from the same pad. This is a concept that we initially tested back in June of 2013 with our first Upper Devonian well, which was on the NB39 pad. This well was developed on an existing Marcellus pad, and we saw some very impressive results, not only from the Upper Devonian well, but as you recall or 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 walls and one Marcellus well from the same pad in our 100%-owned acreage in Monroe County, Ohio. But we've 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 prospective 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 for 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 projects -- they're not just relegated to the Utica, Marcellus, and Upper Devonian horizons. When you look to our Virginia coal bed methane fields, we're becoming increasingly excited about the potential to find advance completion designs across the multiple coal scenes.

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

So the opportunities set in Virginia, as part of the total production portfolio -- that can be used to help reduce unit costs, increase segment margins, and reduce capital intensity. Stay tuned in 2015 to see how that potential unfolds, as well.

So a lot of exciting things on the E&P horizon for CONSOL Energy. Making all these exciting things to come to fruition -- it takes a strong team. And in 2014, it's hard to deny the massive transformation that we saw in the 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 has been invaluable, and with his leadership, we changed and advanced the foundation the of the 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, the success that our E&P division has seen throughout the year has been impressive. And in 2014, we saw record production of 235.7 Bcf, which is well above the 30% growth target for the year. Of 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 costs by 15% by year-end 2015. When you look at where we're at today, we're already seeing that objective coming to fruition, while 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. We'll have a little more to say on the 2015 capital in a minute.

But before we do that, let's shift over to coal. When you look at 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 costs of $42.61 a ton. These low costs helped generate a healthy margin, resulting in just under $160 million of cash flow before capital expenditures.

Our marketing efforts continued to make more progress. And during the quarter, we contracted for an additional 1.4 million tons in 2015. That brings us to about 80% contracted for the year.

The team continues to lock in term sales with what we consider to be must-run power plants for multi-year duration. This is really good news, when you put that into context of the thermal coal MLP that is underway. 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, our Buchanan mine, saw remarkably low unit costs once again, this time, for the fourth quarter.

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

As a result of the cost structure, our Virginia operations, again, managed to make a healthy margin and level of cash flow. There aren't too many US metal 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 net market, but has the potential to make a significant amount of money when the market turns. There's nothing out there like it.

In 2014, we finished up our growth capital associated with the coal division when we completed the Harvey mine. It'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 but that 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 asset sales of $270 million. The majority of the proceeds were from several non-core asset sales, mainly thermal and supply companies and uncapitalized coal reserves in the Illinois Basin to two strategic buyers.

These proceeds helped the Company in a number of ways, but above all things, it provides optionality and liquidity that our peers don't have. And it concentrate's management's focus to what we consider to be the truly core activities of Appalachian shales in thermal and met longwall mining. We look forward to continuing our formal process for monetizing these assets throughout 2015 and expect the 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've got the competing and attractive options of growing E&P production in prolific fields, like the Marcellus and Utica, as well as reducing our share count at levels that we consider to be bargain prices.

For 2015, we've got two objectives across these two cash flow deployment opportunities. First objective -- we want to grow our E&P segment production 30% for both 2015 as well as 2016, which builds on the 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 us to critical mass for E&P as a standalone segment. In short, it increases NAV per share.

And we expect to hit 30% growth targets for both 2015 and 2016. We plan to accomplish this with a 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 are exactly what we expect to see, as the results of lean manufacturing and continuous improvement take hold.

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 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, of margins, returns, spending, and how we balance CapEx for production growth with the opportunity to take in our shares at discounted prices in the coming years.

We're utilizing a very simple but very powerful tool with that big NAV per share equation in the sky. 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 the 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 one 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 2015. These goals continue to create a greater level of transparency to the IPOs of a peer play Thermal Coal MLP at 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.

With that, I'm going to turn it over to Dave. And he's going to provide additional thoughts on the 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 and key metrics, as well as how we're going to manage through this energy environment and sustain the program. Similar to the past quarters, we have posted a comprehensive slide deck to our website, 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 with 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 enable you to model our Company.

Second, we are going off of hedge accounting. And that will let the gains and losses that have hit our hedge position flow through our income statement.

Now, for the bottom line -- net income and EBITDA. CONSOL reported net income for the fourth quarter of 2014 of $74 million, or $0.32. After including -- 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.

Let's look at some of the operating details and expected projections. Since Nick has highlighted our production, I'll just focus on some of the other items.

Our E&P operations really did post strong results and will enable us to drive our operating costs and capital intensity down. During the fourth quarter, our E&P division had net income of about $36.5 million and cash flow from operations of about $55.7 million. Our realizations declined by $0.36 per Mcfe to $3.90 per Mcfe in the fourth quarter. Included in this total average realizations was a hedging gain of a $0.39 and a liquids uplift of about $0.20.

Liquids production represented about 12% of our production and 17% of our E&P revenues. Our expectations for liquids production remain consistent with previous-stated guidance of between 10% and 15% of our total production by the end of 2016.

We had forecasted that 4Q basis would be between a negative $0.80 and $1.10 and came in 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 our more negative Devinion sale pool to a more positive basis areas, as we have excess FT and have the ability to do so.

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

We continue to make progress on cost efficiencies, as we've highlighted before at an analyst day, as we increase stages per day, days 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 four. These types of efficiency improvements 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 costs 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, coal's active coal operations generated $187 million from cash flow of operations before capital expenditures. For the year, this totalled $729 million, which was actually light of our $800 million target, due to mostly lower coal realizations and early equipment issues at our Harvey mine and more than half a year of tough geology at our Enlow Fork mine.

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

So this energy environment is creating another downdraft in commodity 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 is sitting at 3.2 times -- very close to the target where we had said a year ago. And we do have some more, and we believe if we continue to take more costs out of these areas, we will be able to keep our leverage ratios relative intact.

Third, we continue to execute on our non-core asset sales program, as Nick has mentioned. And we took $270 million of cash proceeds, putting us slightly ahead of our $1 billion target.

Fourth, we remain on-target or our 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 and met coal 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 costs 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 bear fruit, with an NAV uplift of about $15 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 vender costs. We have begun to implement key safety and performance indicators with our key vendors.

Now, let's look at the commodity and how we managed the risk around realizations. Though 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 one assets and revenue streams that enable us to manage commodity risks differently than most pure play E&Ps.

We produce four major commodities -- natural gas, condensate liquids, met, and thermal coal. We measure the price risk using VaR, or value at risk, which we highlight on page 153.

For the natural gas stability, we maintain a hedge program that we use a program hedge at a base level of hedges and layers in additional opportunistic hedges when prices rose above a 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, its decline has had little impact on CONSOL's bottom line. The Company offsets this downturn by oil -- by saving on diesel costs. CONSOL consumes between 30 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 structural bottom, absorbing the slowdown in steel 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 out our thermal coal and are managed to lock in term deals over multi-years.

For 2015, our overall thermal coal portfolio is contracted about 85% in price. As a result, our 2015 monthly VaR 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 billion, 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 for both 2015 and 2016, and we feel our budget achieves these goals.

Some of the key assumptions behind the budget. One is our coal maintenance production capital of about $160 million. Our D&C capital will benefit from the 15% efficiency goals and additional reductions from all field service costs. And last, the CONE will bear a portion of its gathering capital.

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

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, our maintenance of capital is sitting around $460 million. Combined with a low decline rate, our HBP, our fee mineral benefit, our low cost FT, and the $1.67 billion carry, we can preserve and grow our NAV in almost any energy price environment.

So as Nick touched upon, you know, we do intend to participate in stock buy backs. As everyone knows, not all buybacks are good. But buying back shares at the right time, when they trade at 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. 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 in a step in the right direction. Now, I'd like you to open it up for questions.

(Operator Instructions)

First from the line of Neal Dingmann with SunTrust. Please go ahead.

Nice quarter, and good color.

First question, just around production -- if you can give me an idea on that 30% production growth, Nick, for you or David, that you were speaking of. Obviously, a pretty solid number.

How to you think of that, when it comes to your JVs? I'm just wondering, number one, how much of the JVs are included in that?

And then secondly, how you think about that? If Noble or Hess decides to cut back more? Would you, maybe, pick up some of that slack? Or how do you all think about that 30% growth?

Yes. With the 30% in the past, too, it's going to be very similar to what our journey was in 2014, which means Marcellus and Utica are effectively 95% plus of that production ramp. Now, what the mix is between Marcellus and Utica -- that's a very fluid situation right now. We're watching everything from NYMEX, to basis, to well costs and well profiles to come up with an optimized mix.

But for the path to 30% for 2015 and, frankly, the path to 30% for 2016 will be Marcellus- and Utica-driven. 2016, now, you start to look at dry Utica and what that might mean 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. I'd just say we're doing some work on CBM. So that might play into the role, at some point, down the road.

Okay.

Then, I just wondered, secondly, on the hedges -- David, maybe for you. Any thoughts here, obviously, with prices lower? And I know you mentioned that in fourth quarter, you stepped up the hedges a bit. Any thoughts, today, on where hedges are about? Would you consider locking in 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 right there. I was just wondering how you were able to accomplish that?

Well, the strip was probably there because we didn't do anything that was unusual. We're just -- we pay attention very closely to the commodity. And when the time is right, above our thresholds, we'll step in, and we'll lock it in.

Remember, Neal, we were up to about almost 80% last year because the commodity was there. And we felt it was right thing to do. And if the commodity gets there, it will.

And it is very volatile. Everybody is short in 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, as far as 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.

Okay.

Then just lastly, you mentioned, obviously, that -- I think it does make a lot of sense to the MLPs coming up. On the thermal MLP, is there a certain amount of, either for 2016 or 2017, amount of volumes that need to be contracted or the price that needs to be locked in, in order to pull off the MLP?

I'm just wondering, for -- on both sides, 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?

Yes. It's a good question, and we think about it a lot. I think, if you look at our production, 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 who have a low heat rate, coal plants, and the right markets will happen year in and year out. So it really ends upcoming down to more of a price question, as opposed to, can you contract it out.

[Mix] -- I'm sorry?

I'm sorry, Neal. This is Jim Grech.

Yes. Along those lines, with what David is saying, for 2016, if you take in all the coal that we have sold for our Pennsylvania operations, which we have some sold that's unpriced as well, it comes to over 13 million tons, which is over 50% of the production for the complex. And that really is all built off of our core customers, as David has said.

So year after year, we build off of that foundation and layer in more sales in future years, as we go forward. We expect to keep doing the same -- using those core customers, filling out the Bailey contract portfolio for future years.

And again, it comes to a matter of timing in the market -- when we think it's optimal for us to 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.

Good. That makes sense, Jim.

Thank you, all. Great quarter.

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

Good morning, gentlemen.

Good morning.

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 going through the initial dealing troubles at Harley? How should we think about it? Obviously, fabulous performance on the cost side at Enlow, despite geological issues.

Yes. The equipment issues at Harvey are behind us. 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 solved, basically, just before mid-year of 2014.

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, 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 in the cost views that we gave for 2014 and going into 2015.

Okay. Great.

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 is quarter-by-quarter in 2014 of 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 those things accumulated into the cost result that you saw.

Our view in 2015 is, when you look at Q1, Q1 costs of Buchanan should be comparable to what we saw Q4 of last year in 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 stick to the current view we have and the release on 2015 for Buchanan, Q2 through Q4 should be nominally higher than what we see in Q1 and Q4 of last year. If we're able to take advantage of the strengthening market or additional sales opportunities that our sales teams and Partner are working on constantly, then Q1 and Q4 of last year -- those costs results and expectation should continue on for Q2 and beyond into 2015.

Great. Thank you. And good luck.

Thanks.

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

Thank you, operator. Good morning, everybody.

Good morning.

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, what 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, D&C. We tried to keep that as close to apples to apples.

Okay. So then -- okay.

So, in other words, in 2014, you spend about $1.3 billion in D&C. And then, in 2015, the $1 billion is D&C? Is that what you are saying?

That's right.

Okay.

There is a little bit -- I am sorry. There is CONE in both of them -- I'm sorry. There is about -- there is some CONE gross capital in there. But we're not breaking it out now because we haven't provide the CONE budget publicly yet.

Okay.

The big -- you look at 2015. The big -- I'll call it -- non-delineation, somewhere between delineation and exploration dollars that we spend will be for the dry Utica that we've got planned in 2015. That's that well in Greene county, PA, the well in Westmoreland County, PA, and what we've got going on in Monroe.

And I say somewhere between exploration and delineation, because we've obviously got expectation and views for success in those locations. But that would be about the most exploration-oriented for focus that you would see in the 2015 $1 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 will 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 north of $200 million.

Okay. So I know the Noble carry is off, but the Hess carry is still on, so--

Oh, yes. That's baked into it. I believe --

$100 million.

It's about $100 million.

Okay. Got it. Okay.

And then, on the production side, I know you're growing 30% full-year 2015 over full-year 2014. But, like the exit rate 2014, exit rate 2015 -- at least, based on our preliminary modeling -- is more like up 10% or 15%, depending on if I make the adjustments. So for example, in the fourth quarter of 2014, if I add back in the shut-in production, the implied exit to exit growth is about 10%. So if you could talk to that?

But it ramps up in 2016. If you actually had the 30% expected growth in 2016, it really revs up.

So could you just help us with -- there's a bit of a slower growth in 2015, and then it seems to ramp up in 2016. Does that imply you're going to be spending more in 2016? If you could 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 30% growth because a lot of those activities that we've spent dollars on in 2014 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 to -- it's just a quarter to quarter thing. I don't think you have to read into the exit rate versus exit rate.

I'm sorry, Dave. What I'm saying is, I mean -- the 30% growth in 2015, a lot of that has -- at least half of that is really the ramp up that you saw in 2014 between the first quarter and the fourth quarter.

Right.

And so I'm getting something like a 10% or 15% 4Q 2014 and 4Q 2015. And to me, it's still good growth, right? But --

Oh, you're saying -- okay. So you're saying we're going to need to spend a lot more dollars in 2016 because you're seeing the 4Q 2015 ramp -- exit rate is not high enough. It's hard because we haven't given you the 4Q 2015 numbers. So I think if -- you have to see the wells coming online 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 a ramp up in 2016, based on your preliminary look at 2016?

You mean, as far as capital?

Yes. I guess, yes -- capital leading to actually a quarter to quarter 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. 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, too, is -- and Larry and Tim's comments give a little more color on this -- is that a big driver of this, as you know, is the timing, especially on the completion side of the equation. When we do the completions, which are a good proxy for timelines, and how that timing is quarter-by-quarter late in the year versus earlier in the year -- that's a big driver of how we smooth out, effectively, or sculpt the 30% ramp into 2015 and then into 2016.

That ability to do that is going to create, I think, a lot of capital efficiency and lower capital intensity in the 2016 number to get there. But you might want to comment a little on that.

It is -- a lot of it is just timing. With completions coming out of the winter months, we'll see more turning lines later in the year that will help contribute to the 2015 growth. But that's where a lot of the ramp in 2016 will come from -- those wells that are turned in-line later in the year, in 2015.

And we'll see a similar type ramp in 2016. So our plan will achieve the 30% growth in both years.

That's helpful.

Then, just two quick ones. What kind of returns do you think you're getting? If you use NYMEX 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 price deck?

We do it both ways. We have an internal review, and we also use the NYMEX view.

But again, the NYMEX just -- if you look at the liquidity in the NYMEX, the amount of volume that's traded on the NYMEX drops by 90% from 2015 into 2016. And then it drops by 97% into 2017.

So even though it's the best way to get some sort of visibility on what price discovery you 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.

You know, our returns really range anywhere from about 10% up to about 25%, 30%. So they've come down. But what's also baked in there is the cycle time improvements that we are doing, as well as great expectations of some service cost deflation.

Overall cost reductions.

Yes.

So you said they're not baked in there, or they are baked this those returns?

In there, yes. So that's partially -- that's what offsets it. 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.

Okay. Good. All right. Great.

All very helpful. Thank you. Appreciate it.

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

Good morning.

Good morning.

Going back to service cost deflation -- what are your current well costs in the different areas of the Marcellus? And how much savings have you fully realized? And does your CapEx budget fully take into the savings that you have 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.

Baked in some service costs deflation into our capital numbers. We look at it every week, and we are hoping to eclipse it.

I know there's a lot of percentage of reduction numbers for 2015 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 things. One is, we'd like lower costs. We'd like to keep the activity level intact, and so we're trying to partner with the right service companies to keep the program in place.

And then second is, that we're trying to keep the right crews and get better productively, as well as just cutting costs. Because we can wake up and cut our way into a problem for 2016.

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've 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.

So if you look in our slide deck, you'll see our debt-to-EBITDA goes up, slightly. We 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 in, particularly, natural gas. That's 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? When I look at the Northern Appalachian price indices, it seems like they've fallen off, maybe, $4 to $5 a ton in the last 2, 2 1/2 weeks. Can you discuss what you're seeing in pricing environment, right now?

Hey, Caleb. There is 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 we haven't seen any of that slowing down. There's 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, though, with the low gas prices is very little to almost nonexistent 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 the first quarter and the second quarter about the potential for getting into the spot coal buying. But there's a lot of wait and see in 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 it's still to be determined -- the effect of the low gas prices are going to have on the coal markets, 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.

Appreciate it, gentlemen.

Thank you.

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

Good morning. I wanted to start with a couple Utica Shale questions.

It seemed that you were really calling out the Utica Shale activities this quarter. You increased your targets with acreage acquisitions. You increased your 2015, 2016 production guidance, and then you pointed drilling in Greene 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?

Sure. 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, really, the wet Utica over in Ohio.

But as you move eastward and get into the dry Utica where we have 100% working interest -- that's where we're talking about the wells in Westmoreland and Greene county -- we're very excited about the results there. And then 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 stacked pays and the improved capital efficiencies and reduced capital intensities that we could accrue if we've already got midstream assets or pad assets or water infrastructure in place.

But to get thinking -- one way to get a certain production target. Another layer of the horizon that has economic opportunity, like dry Utica, you can get a certain production ramp much more efficiently than you would be able to individually across those plays. 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 in analyst day.

Analyst day, it was a concept, and we had logic tied to it with where we think this could a 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 the Utica and Marcellus fields -- that could be something that is definitely moving the needle on NAV per share for us in the out years, starting, as I said, in 2016.

Great. That was very helpful.

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 the Utica a play where the crew is particularly important, as you referred to earlier today?

The numbers that we show in there do not have deflation in there, as you said, and 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 of the D&C rate. A lot of that is -- a lot of that is the function of the quality of the rock and the productivity of the wells and debt.

And so can we continue to take those costs down? It's a good question.

I think it's running 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 the better. I think the Marcellus is probably -- my guess is Marcellus is really more the area we'll be taking more costs down.

Okay.

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 we be modeling -- should our modeling be biased more towards the higher RCS-type curves, going forward? And if you want more data, when do you think you'll have enough to consider towards advising towards the RCS-type curve?

Yes. All of our completions are RCS/SSL. We have seen the benefits of that -- the increased IPs and the increased EURs.

We continue to work on optimizing our completions. We've seen the benefit 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 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.

Okay. Thank you.

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

Good morning, everyone.

Good morning, Lucas.

Nick and Dave, you emphasized the share repurchase opportunity in this market environment. And in light of some of the self-imposed constraints with the organic growth targets and then investing this 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 the NAV per share filter. If you go back -- last time we had our third quarter earnings call -- and you go back to the November timeframe, where that balanced 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 2014 with and coming up with a plan, or set of plans, that would get us north of 30% in 2015, 2016, then a certain level of share buybacks.

If you fast forward to where we're at today, we still have those that we said in the commentary -- those two overriding objectives. But there's been a shift. Again, the reason we had a shift is because we're adapting and using that 10 NAV per share filter with the new assumptions -- new pricing, new efficiencies, new share price, et cetera. So rerunning all these things, so to speak, real time.

And that shift has resulted in the balance and the objectives for 2015 that we quoted, which is now 30% ramp. So giving up on some of that upside that we had built with momentum, and now refocusing more of that emphasis to the share count reduction.

Now, where it goes tomorrow? We don't know, right? We don't know what's going to change over the long haul, especially with pricing, with share price, and with everything else.

But what we do know is how we're going about that decision-making as management. So we're still going to use that NAV per share filter. 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 that math. And we'll see where we come out at with the 30%, versus the share count reduction efforts for going into 2016 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 the 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 -- or cash flow allocation -- will be capital expenditures for E&P production growth and share count reduction.

What the waiting is between the two 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, it's $1 billion to get us that 30% ramp in 2015 and 2016, and a certain level of share count reduction that will result from that.

Great. That's very helpful.

And maybe to shift gears. Jim, coal production guidance came down a little bit, at least in my numbers.

Could you maybe walk me through the drivers for that? Is this a result of decreased utilization, competition within Northern Appalachia, competition from outside the base of 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 there, shown for the Pennsylvania operations was really due to two factors. Neither of them had anything to do with the market.

One is the -- more longwall moves occurring in the year than in the previous year, which, of course, takes tons out of the forecast. And we didn't have that baked in all the way there. We had to change that and revise that, as we go forward. The second one is we still expect to have some of these geologic conditions to slow down some of our mining in the PA ops.

So the combination of those -- the adding in some longwall moves and the geologic conditions -- is what took the tonnage down in those numbers. It was nothing do with market conditions.

The other side of that, Lucas, too, is we've got the benefit of having an actual number for 2014. If you go back to first quarter 2014, we had a strong quarter in the 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 2015, we'll have the opportunity -- we'll do exactly the same thing because, as Jim said, the market will be there to take it. But first things first, giving you the best shot at what we see in 2015 -- with geology, timing, everything else -- that's where we came 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 bogey for the year.

Good luck with everything.

Thanks, Lucas.

Thank you.

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

Good morning.

Good morning, Brandon.

I hate to drag this down. But just a couple detail clarification questions. One on the CapEx. Even just directionally -- rig count that you're expecting 2015 versus 2014, to kind of normalize that?

The rig count, on average, will remain relatively flat. We have got about ten rigs running now, and we'll average about ten rigs throughout the year in 2015.

Okay. Great. That's helpful.

And then, reconciling the 5% to 10% CAGR on production cost savings or rig efficiencies or cost savings with the 15%. And I think that 15% savings on D&C was a year-end 2015 number, or is that a full-year average reduction?

I think, last year, we talked about a 15% reduction in D&C by the end of 2015. And we're well on our way to achieving that. And that fits in well with the 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 about what you expected. And then, there was a comment that you may be able to be flat or show 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, flip between the two different pricing points and get us to a more favorable one.

For example, last year, with the Dominion, South Point, we had about 26% of the gas being sold there. And that's going to go down to 14% in 2015 as the production. And again, using some of the flexibility we have in EFT -- we're going to move it away from that lower-priced market and move it to over to 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 South sales point in half and just about doubled the TETCO-M3, getting to a much more favorable market.

So when David was giving that quote, if you take the TETCO-M3 market, the East Tennessee Transco Zone 5 market, and the TECO market, that's about two-thirds of our gas production that's going to those three pricing points, which are some of the more favorable pricing points that you are going to get. And that's leading to the difference in the basis from the first quarter this year to fourth quarter of last year.

Great.

And presumably -- at least as we look throughout the year -- the Q1 hedge profile, I assume is a bit higher than average for the year?

That's about right. That's about right.

All right. Great. Thank you very much.

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

Thanks for taking my question. I 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. I know there's a lot of sensitivity around giving a price deck. But my question is, at what point do -- if you could 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've got to be careful about using one price. But I would say, if we were looking at $2.00 realizations for multi-years, that's where it would start to really impair, dramatically, our activity.

$2.00 realization. Okay. Fair enough.

Then the -- well, a somewhat related question, I guess. Obviously, we've had the collapse, lately in the -- at least, the near prices.

So my question is, all things constant here, as we look forward to the next couple of quarters even, given the margins that were just reported in the gas segment, given the falling pricing, do you still expect to be delivering positive margins, on a near-term basis, in the gas business, 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'll be neutral, but close. And then, there will be spots -- like liquids will be positive. So you have to look at each product.

All right. Fair enough. Thank you.

You are welcome.

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

John, thank you. And thank you, everyone, for participating today.

If you could please instruct the callers on how to access the replay information.

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