CNX Resources Corp (CNX) 2013 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 conference is being recorded.

I would now like to turn the conference over to the Vice President of Investor Relations, Dan Zajdel. Please go ahead, sir.

Thank you, Brad, and good morning to everybody. And welcome to CONSOL Energy's fourth-quarter conference call. We have in the room today Brett Harvey, our Chairman and CEO; Nicholas DeIuliis, our President; David Khani, our Chief Financial Officer; and Jim Grech, our Chief Commercial Officer. 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 have laid out for you in our press release today, as well as in our previous SEC filings. We also have slides available on the website for this call.

We will begin our call with prepared remarks today by David Khani, followed by Brett Harvey. Nick and Jim will then participate in the Q&A portion of the call.

With that, let me start the call with you, David.

Thank you, Dan. Good morning. Today, I will provide a quick overview of the quarter, and then help recalibrate the investment community to our new look, posted sales of five mines. I will then pass it over to Brett who will review our accomplishments and goals for 2014. As Dan had mentioned, we have posted an updated earnings slide deck on our website, and I will refer to this throughout the call.

Before I discuss the fourth-quarter results, let's put 2013 and 2014 into perspective. Last year was a transformative year, with the sale of half our coal business and multiple sale processes going on.

However, the most important event was the shift in focus toward becoming a strong E&P company. For 2014, this will be a transition year, as we ramp up our gas and liquids volumes to a higher level, and rebrand ourselves as a top tier E&P company. Our remaining coal business will always be a tier one asset.

If we look at slide 3, we focused on the press release on what we considered to be the key metric for the quarter: pre-tax income, which was $16 million. We chose this metric because GAAP net income and EPS were greatly affected by two items: the sale of the five mines, which closed on December 5, and a tax benefit arising out of the reversal of prior quarter's tax revisions.

On page 1 and 9 of our earnings release, we provided both pre-tax and EBITDA reconciliation tables that adjust for the discrete items. The result was adjusted pre-tax income of $2 million. This, I believe, is the starting point and best metric to begin analyzing the earnings power of the Company post the sale of the five mines and today's commodity price environment. Keep in mind that a normal tax rate for CONSOL over the past three years has been between 20% and 23%.

Now, the fourth quarter was a noisy quarter due to the large coal transaction, and was impacted by two main items: lower overall coal production, resulting from the sales of the mines, as well as not benefiting yet from the overhead reduction that we had highlighted before. We also had impacts from lower pricing, which impacted margins, particularly from our met coal and higher hedges rolling off for natural gas.

Now, let's look going forward and how we are going to grow our earnings and cash flow. First, we have cost cutting that we highlighted. Over the past couple of years, we have been cutting overhead and operating costs to offset declining coal and natural gas prices.

Looking forward, we have successfully identified and began reducing another $65 million in administrative expenses. Some of these savings have come from employee headcount reductions already implemented, while the rest is from services and goods mainly attached to our coal business. None of these savings were recognized in the fourth quarter, and we do expect they surpass the $65 million over time.

Second, vendor streamlining inventory overhaul. Last year, we spent about $3 billion in goods and services to support our coal and gas business. We expect to bear significant cost savings tied to our vendor streamlining and supply inventory management overhaul. With the coal footprint reduced down to two key areas now, we can now more tightly manage our inventory leverage better.

Third, rising gas and coal production. The growth in our E&P business will manifest into wider margins over time, particularly from the 87% growth in Marcellus production we expect to achieve this year, as well as higher liquids percentage. We are seeing improvement in productivity per well, and lower well costs, which will drive higher returns. Imbedded in this will be the benefit of increasing reserves, and lower finding and development costs. In coal, BMX will be coming online by the first quarter, and we will have the ability to capture both contract and rising spot business.

Fourth, rising gas and coal prices. With the cold weather, both thermal and natural gas prices will begin to benefit from the sharp reduction in inventory. We will capture this with fixed-price contracts and hedging. While we are not forecasting a big bounce in met coal prices, the market will eventually become balanced. Our high-BTU and low-cost production will be able to capitalize on the flexibility to ship between thermal and crossover met.

Last, the reduction of underutilized firm capacity. As gas production grows, we expect to be able to use more of our firm transportation capacity. Last year, we paid about $30 million in underutilized FT.

If you look at slide 7, capital spending, for 2014 we expect to spend about $1.5 billion in capital, which was highlighted in our January 21 press release. This is down from the $1.7 billion spent in 2013, which includes about $260 million on land, and our DTI and Pittsburgh airport acquisitions.

But I want to highlight two trends here. From 2012 to 2014, our gas capital has doubled to about $1.1 billion, half of which is tied to our liquids activity. I want to remind you that our 2014 capital really sets up our 30% growth for 2015, as it takes about six-plus months to drill and complete on our multi-well pads. It is our goal to improve productivity of wells, and drive this capital number down.

Second, on land, we have been quietly increasing our land capital over the last two years to core up and find contiguous acreage packages. We will continue to high-grade our acreage position, and over time we expect to swap and sell Marcellus and Utica acreage to reduce our land capital. You can see the strength of our acreage position and how we're always drilling multi-well pads, as well as increasing our lateral lift in 2013 to about 8,000 feet on average. These efficiencies translated into a 29% reduction in drilling costs per lateral foot.

Moving to slides 9 and 10 on liquidity and deleveraging, we expect to outspend our cash flow in 2014 to foster the coal and gas growth. We started the year with $2.1 billion of liquidity, and expect to maintain most of it by year end. While we continue to drive up our E&P cash flows for production growth and a rising liquids percentage, there are several ways we will maintain our strong liquidity. One is: We're sitting with $327 million of cash on hand. Our BMX line will become a cash flow generator at the end of the first quarter.

We expect $100 million to $125 million in cash-tax rebate from the sales of the five mines. We expect to receive JV carry, which should total about $335 million between Hess and Noble. And we have incremental hedging on our gas side, which we have highlighted in our press release. And then we have the sale of non-core and infrastructure monetizations. So, these six items should help us keep our liquidity strong.

If you look at slide 11, you will see the deleveraging event from the sale of the five mines. For 2013, we have reduced our legacy liabilities by about $2 billion, greatly improving our credit metrics. At year-end 2013, we do have $2.1 billion of liquidity, but down about $270 million from 2012 levels.

However, in conjunction with the sale of five mines, we made the conscious decision to reduce our CONSOL Energy revolver by about $500 million. We have two undrawn revolvers of $1 billion each, and an undrawn accounts receivable securitization facility.

Moving over to slide 12, on hedging, we have been implementing a program hedge for the last several years, along with our annual coal contracted position. This helps create more surety in our underlying cash flows. With the increased emphasis on growing our gas division, we are actively adding more hedges, and highlighted this in our December 2013 investor presentation.

We recently added about 40 BCF of NYMEX and TECO hedges in late December and early January, and over time we expect this to grow. Our hedge program in the past has used straight swaps, and we're looking to add more and expect to add collars into the mix.

The overall goal is to reduce volatility and protect cash flows to enable our high growth. We provide a 2014 to 2016 hedge position on page 8 of our press release.

Moving over to asset monetization. As we highlighted in our press release earlier today, we are moving down a dual path of sale and MLP for our midstream assets. We are reconsidering an MLP route for two main reasons. The Company has been weighing the competing interests of valuation, liquidity, and maintenance of strategic control. The relative imports of these interests have changed recently.

The sale of the five mines have greatly improved our near-term liquidity, and significantly deleveraged the balance sheet. We have a list of assets that fit the MLP, including our Marcellus and Virginia systems. We're considering the sale of these systems as well, but believe that the dual process creates more competition to ensure that this is an accretive transaction to our underlying net asset value.

So, the catalyst to drive our stock higher are seven-fold. First, for an EP business, we expect our net asset value to grow because of production and reserve growth. We expect the productivity improvements. We expect the exploitation of our recently acquired areas. And we expect, over time, commodity prices and realizations to go up. For our coal business, a key area is for re-contracting out our coal business and to take market share, and to drive down costs and capital. And for corporate, it is asset monetizations, and driving more and more efficiencies and cost controls.

So, in summary, while 2013 was a very active year for us, we are very focused to reposition this Company to prosper. With that, I will pass it over to Brett.

Thank you, Dave. Good morning, everyone, it is good to be with you. 2013 was a very big year of change and accomplishments for CONSOL Energy. We had a big change at the top. We had some very valuable senior managers retire. We put together a new team; we refocused. And so, we made the adjustments at the top of the Organization.

We regained our gas production momentum, based on us slowing down in 2012, based on low gas prices. That momentum is now back in place. We are targeting 30% compounded growth on our gas side over the next three years.

We improved our capital efficiencies in gas. We improved our drilling efficiencies. We embraced the SSL and the RCS completion techniques, rebalanced our asset portfolio by selling mature coal assets and redeploying the value into our gas business. We sold five mines in West Virginia in a transaction valued at $4.5 billion.

We invested, again, another $1 billion in gas, including leasing 9,000 contiguous acres on the Pittsburgh airport, and leasing 90,000 contiguous acres with Dominion Transmission. We realigned the common stock dividend to help fund the gas production growth. And, as David said, we began 2014 with a much stronger and robust balance sheet: $327 million in cash; total liquidity of $2.1 billion.

Our goal in 2014 is simple: growth. 30% growth in natural gas production, and the other growth is really completing the BMX mine. Probably, I believe, the best investment in the coal business in the eastern United States in the last 20 years.

While adhering to our core value of safety, compliance, and continuous improvements, we are set to grow in 2014. The most frequent question I have been asked lately is: What are we as a team doing to at least meet the 30% gas production growth target? That is a big target, but we have the assets to do it.

First, we hired Timothy Dugan, an industry veteran, to lead our gas business. We issued a release on Tim last week, and I encourage you to read it. Once Tim gets settled, we intend to have him meet many of you, and you will see the value he will create for our shareholders.

Second, we successfully embraced the enhanced completion techniques known as SSL and RCS. Our recent operations release details that greatly, and shows the results we're getting.

And third, and perhaps the most importantly, our gas team and senior execs have been meeting daily for the past six months to track our progress, remove obstacles, to assure our success. You have already seen part of that outcome when you look at our drilling costs and our operations release. At CONSOL, we are driven by engineering. We have a 150-year-old history of efficiency, extracting resources from the earth. What we're doing now is shifting that focus more towards natural gas because the markets demand that value.

So, in summary, I believe that we have the team, we have the assets, we have the culture, and the value system to get where we need to get. We have the skill set to be successful in this shift towards gas. What has made CONSOL successful in all these years is the ability to adapt while embracing change.

Clearly, the energy business in the US is changing. And CONSOL will change with it on this great asset base that we have. In the process, I believe there are tremendous opportunities for us to create shareholder value, especially the way we are structured now. We are dedicating ourselves to 2014, just to do that.

Now, let me open this up for the questions.

Operator, could you please instruct the callers on the process for asking questions?

Of course.

(Operator Instructions)

Holly Stewart, Howard Weil.

Good morning, gentlemen.

Hi, Holly.

First, question for me, maybe for Brett, on just the potential sale or MLP of the midstream business. There is a quote within the release that says this has reduced the importance of minimum volume commitments to potential acquires. I was just wondering if you could expound on that?

Sure. Actually, I will have Dave address that.

Sure. I think when we went through the sales process, one of the things that we originally encountered was the level of minimum volume commitments. I think as we have stated our production growth and as we started to execute our production growth, we expect the need for that to come down. Whether it is through a sale process or through an MLP process.

Okay. So then, just to be clear, the assets in the Cohen joint venture would, I guess, fit within this process?

That would be one of the things that could fit into it, sure.

Okay. And then, maybe just another on the E&P side for Nick. I guess what types of things on the D&C side this year will be you testing that we would consider pilots that ultimately would change how we would value CNX?

There's a number of things that we are doing on the D&C side. I will use the Marcellus as the specific example but a lot of these, if not all of them, would apply to the Utica as well. Dave mentioned the pad drilling and the benefits we have seen through the efficiencies over the last 12 to 18 months, that's going to continue.

And, that trend will continue now as we drill more in areas like northern West Virginia. So, it is not just going to be an application we saw in southwest PA historically but now it will be areas like southwest PA and northern West Virginia as those new sub reasons of the Marcellus come online.

We talked a lot about lateral length and we feel that is a very appropriate metric to look at to try to evaluate where we're at on efficiencies and EURs and costs and margins and everything else. That lateral length, the evolution that we have seen, is going to continue to accrue a lot of benefits for us.

So if you look at 2012 we were around 5,500-foot in the Marcellus on average laterals. Last year, we came in at almost 8,000-feet on average. There will be a lot of benefit on efficiencies that accrue from that as well.

Of course, SSL, RCS, that is a big one. When you look at the potential incremental improvements from it, if you just look at southwest Pennsylvania where we have done most of our applications for SSL, RCS to date, it has taken the EURs per 1,000 lateral foot from somewhere around 1.6 BCF per 1,000-foot, up to 2 -- 2.0 BCF. And, we expect similar types of incremental improvements when you look at our drilling prospects in northern West Virginia.

And then, we are going to test these areas on SSL, RCS in central PA and in the Noble operated area of the joint venture as well into 2014. So, that of course has its obvious benefits as well. And then, there is the down spacing opportunity. That is probably the earliest in the analysis and development compared to those prior areas that I mentioned.

And, when you look at down spacing, when you look at what we're assuming currently for things like crude reserves, which we are going to release next week at some point, we basically take a conservative approach with the reserve numbers now. We've got 1,000-foot lateral spacing assumption in the Utica, and 750 in the Marcellus.

But, based on the testing that we have seen notice Marcellus, in particular, and when you couple it with RCS and SSL, we think there is a lot of opportunity to investigate down spacings down at the 500-foot. And, again that is in conjunction with RCS and SSL. So, we will have more to say on that as we test it more specifically probably in the back end six months of 2014.

And then, the last thing is Upper Devonian. And, we tend to look at upper divan as something that is a stand alone opportunity. But, a lot of what we have tested and evaluated in southwest PA has shown that depending on the timing of how we drill and, more importantly, complete, the Upper Devonian wells that sit above the Marcellus wells, the timing and sequencing of those completions can have a big impact and a positive impact on everything from well type curve to ultimately EUR for the Marcellus wells underlying it.

So the sequentialing of this completion techniques for Upper Devonian can really help what we see on the Marcellus. So, I think those are the big areas we will be looking at in 2014 for getting even better on the drilling and completion side.

Great list. Thank you guys.

Jim Rollyson, Raymond James.

Good morning, guys.

Hey, Jim.

Maybe David, you talked about CapEx last year on the E&P side, and obviously you guys have put out a budget for this year. As we think about that going beyond 2014 should we think about capital generally remaining in this general area? Or do you think it is going to have to go up somewhat on the E&P side specifically in order to sustain the 30% growth you guys are forecasting for 2015 and 2016?

I think let's break it up into coal and gas. Without giving any specifics, but BMX will be, and the overland belt at Enlow will be finished in the first part of this year, so we will not have any of that capital in next year. So, we will be more in a maintenance mode. So, the coal numbers should, in theory, come down. And, we're spending a lot of time trying to drive that mop capital number down as well.

On the gas side, generically, you should think that the number should go up, but what could offset it is how much land capital and how much asset sales that we do to keep the land piece of that in place. And then, how we handle the midstream piece will also, if it ends up going into more of an MLP, that effectively will take the capital number down as well, on the midstream side.

That's helpful, and either for you or for Nick. When you think about what you're doing on the production side, and various different things that you just outlined, Nick, how should we think about unit costs in the E&P side of things, as volumes go up, 30% a year for the next three years? Is that something that, on average, remains relatively stable, or do you think that trends up or down or how do you think about that today?

Our expectation, overall, would be that the unit cost for the Marcellus and Utica would trend down as the volumes ramp. But, I will break that conclusion to two different components. The most important, when we look at it, is the component of what is occurring with the drilling costs, the completion costs, because it all starts there.

And, that's where the core of the dollars are being spent. If you look at those operational issues that we summarized on the prior question, and then you translate that to what it means for costs, the trends and the data are pretty clear. If you look at the Marcellus, our average drill cost per foot, our average lateral cost per foot when you look at 2012 to 2013, those have declined significantly.

The drill costs per foot went from $220 a foot in 2012 down to under $200, $190 per foot. The average lateral cost went from $530 a foot down to about $380 a foot. And again, the reasons for those are the multipad drill, the longer lateral, et cetera.

Same issue you see on the completion side, or the same trend. The average stage cost in the Marcellus, between 2012 and 2013, were basically held flat. And, that's despite redoing some service contracts with our primary service provider and partner Cal Track where we adjusted those costs to market.

So, again, adjusting for things like RCS or SSL, which of course will change those completion costs, our expectation is all of the trends are heading in the right direction on the most important drivers of the costs in the Marcellus, which are drilling and completions. When you look over at the Utica, a similar type of a trend, when you look at drill and complete costs. Those costs continue to go down.

It's still early in the Utica, of course, but towards the end of 2013 our drill and complete costs were around $10 million, which was a significant decrease from where they were prior at about $12 million at the start of the year, and our goal there is to get them under $10 million for 2014 in the Utica. So, that first bucket is the most important.

When you look the a the second component of cost, whether it is firm transportation or direct administrative overhead, all of those field costs, that is just straight economies of scale. And, as the product volumes continue to climb in the Marcellus, and again 56% year -- quarter-over-quarter for fourth quarter 2013. And then, 80% plus expected for 2014 versus 2013, you should see economies of scale helping to reduce those unit costs.

Makes perfect sense and appreciate the color, Nick. Thanks, guys.

Jon Wolff, ISI Group.

Hey, Brett and David and everyone, good morning. Just been studying your gas business. And, just wondering if you could start with talking a little bit about where you are in the Marcellus, northern West Virginia, in terms of average lateral length?

Where [you're at with SSLs], to how many feet? Is it still trial and error? Where you would see yourself versus the rest of the industry, like Entero, are you on pace, behind? Start with that.

The northern West Virginia field is a very important significant footprint for us within the overall Marcellus field that we control. And, when you look at the history, the last 24 months, 3 years or so, lot of the attention and rightfully so, has gone to what we have been doing in southwest PA.

But, when you look at in which subfields have made the most progress without a doubt I think the northern West Virginia area is the most exciting when you look at how far it has come over the past couple of years. When you look at 2014, we are going to be drilling just over two dozen wells there in the calendar year. The average lateral lengths there are going to be somewhere north of 6,000 feet, probably around 6,200 feet.

You look back on fourth quarter results of last year and what we've seen there, we really had a program that helped delineate out those different areas of concentrated acreage that we controlled. We had a well in the Philippe, Century, and Adra, all three of those areas that came on from multi-well pads to single wells, and those results are at or above the expectations that we had with the type curves.

On SCL and RCS, that is probably -- that northern West Virginia area is number two in terms of our certainty of it being applicable right behind southwest PA. So, our plan through 2014 is that all of the wells that we will be drilling in northern West Virginia we will apply RCS, SSL.

Okay. Is it 200 feet, 250 feet, 300 feet? Do you have a feel for averages? In terms of stage length.

The SSL expectations in northern West Virginia will be very similar to what we are seeing in southwest PA, where it is going to add about $220,000 to $240,000 per thousand lateral foot to our drill and complete costs. We will get somewhere around a 40% IP rate increase. And, EURs will probably be benefited by say 15% to 20%. So, that is our overall expectations for what we would see there. And then, we will be at 150-foot on the spacing.

The spacing, just to be clear, Jon, the spacing that we had been using had been about 300 feet. We halved that to about 150 and within the 150 feet, we have decreased the spacing between the perps. So, reduced cluster spacing, we have basically gone from about 60 feet per cluster to about 30 feet. So, within every 150 feet then obviously we're getting about 5 clusters within that 150 feet.

So, the before and after, 300-foot on the stage spacing before, 150 after. And then, as Dan said 60-foot before on clusters and 30-foot after.

Did we answer your question, Jon?

Yes, that got it, last one on Utica. There was a high profile transaction over the last few days for nonproducing dry gas, which made some people blush in terms of the dollars paid, around $12,500 an acre. And, I was just wondering, you have a lot of acreage, do you consider monetizing any of it? Or do you consider growing it or any thoughts around just how M&A is heated up in the sweet spots of the play?

The Utica, as we said earlier, it is early. We've got our certain population of what I will call flow-back data, but like all of the operators out there, it is right now, a bit infrastructure-constrained at the moment. That is going to change. And, we talked about well costs earlier. They're declining, that is good news.

And, most of the challenge there is in the vertical section. But, when you look at the different opportunities from wet versus the drier areas, our view is that once these infrastructure constraints get addressed across the field, that we will have economic plays within those areas where we've got the concentrated footprints, whether it be dry or wet.

Now, of course, the wet is going to be more advantaged than the dry. But, we see the economic opportunities to drill those out at rates of return above the cost of capital where we've got the concentrated footprint.

Where we don't have the concentrated footprints, where we control significant acreage positions, I think that market indicator that you referred to is positive news for us as we try to consolidate what we already had, and we are going to make a go at, and fund that, or monetize, so to speak, the acreage positions that we control, but don't have enough of a critical mass to make a go at it on our own. So, from that perspective, that is a definitely positive development as we see it.

And, I think Jon, overall, you could expect us to high grade our portfolio. We are going to add areas where we need to supplement whether it's extend out laterals or core up. And, in the Utica, for example, we picked up a whole bunch of acreage in the Monroe area.

And, there will be times where we will divest some of the other area, noncore Utica areas as well. So, we will be happy to have more indicators out there as a tool handle. Take advantage of it.

I like that, okay. That helps.

Mitesh Thakkar, FBR Capital Markets.

Good morning, gentlemen.

Good morning.

Just looking at the Marcellus, and with all of the growth being planned out on the Marcellus, can you talk about your transportation infrastructure and ability to meet the planned production growth? How much of your production can you get out of the northeast market and into the midwest?

Mitesh, it's Jim Grech here. In looking at the basin total and then I'll get down to looking at CONSOL's position. Looking over the next three years, we see a lot of volatility in the basin because of the timing between when production is coming online and when take-away capacity is coming online.

In total, we look out over three years, and we see 6 BCF a day of production coming online in basin and getting it up to 20 BCF a day type of range. But, we also see in that same timeframe about another 7 BCF a day of pipeline capacity coming on to move the gas out of the basin. When you look at the timing and location of the growth of FT versus the growth in production, it is going to take some time for the market to sort that out.

So, what we at CONSOL are doing, right now we have 34% of our FT capacity takes the gas out of the basin, takes it down to the -- up to the East Coast and down to the southeast. Starting later this year and into next year, we are going to be adding more capacity that is going to take us out to the mid-con and the gulf markets.

So, we're targeting by the starting of 2016, by the start of 2016 to have 337,000 decks a day of export capacity. But, we also have more discussions under way right now to increase that number and we have a goal to get us to get around about 50% of our portfolio having the ability to move it outside of the basin in the future.

And, that's all going to the mid-con and the gulf markets?

Yes, we also have some going down into the southeast markets as well.

Great. And, just to follow up on that, how much of your 2014 and 2015 production has the basis hedged and what are the plans going forward?

Well, in 2014, we have 57% of the portfolio has the hedge on it. And, as we go to 2015, right now, we're sitting at about 26% hedge for our portfolio. And, I'm sorry, you asked another question, what are our plans going forward?

Yes.

Yes, as we hedge financially, we try to add as much basis as we can. So, right now, we added about 40B's of NYMEX and some TECO hedges. And, when the basis gets to a spot where we feel comfortable, we will try to lock it in.

Okay. Perfect. Thank you, very much.

You're welcome.

Joel [Allman], JP Morgan.

Thank you. Good morning, everyone.

Good morning.

In terms of the completion techniques, besides the RCS and the SSLs what else are you modifying? Are you using more prop in? Are you changing the pump rate?

Well, the SSL, RCS approach is going to result in different metrics besides just the spacing of course. So, if you look at what we were doing earlier on in the Marcellus, if you take something like sand, as an example, we were using about 350,000 pounds of sand per stage in the early days, pre-RCS, pre-SSL.

When you go and look at our drilling and completion practices now, in an area like southwest PA, we are probably somewhere around 200,000 pounds of sand per stage. And, of course, those stages now are going to be much more dense and larger in number. So, overall, when you do the math, SSL is going to probably increase that sand usage by about 15%, when you look at it on a per foot of lateral.

And then, of course, you're doubling the number of stages along with it. But, I just did the math there for you. So, that is going to allow for more stimulation in the rock formation. And, this tweaking of things like sand and how we're applying that in conjunction with RCS and SSL, you're right.

It is in many ways, it is tied to of course those tighter spacings but it is also something that is independent that is being used to try to optimize the completion techniques. That is probably the best example that I can give you of how we're trying to intersect that with the RCS and SSL.

Got you. That's helpful. And then, have you changed just one thing at a time, just to control for one variable, just to see what really is impacting production?

It brings up a couple of interesting thoughts. If you look at something like the Marcellus, there are a lot of independent variables out there. And, what the optimal mix is, on top of the rock nature changing from sub area to sub area, it is an awfully big optimization challenge. And, trying to get data sets that isolate a certain number of those variables and try to get a beat on what the impact is of one of those variables, it is a challenge across a field as big as what the Marcellus is and what we're doing within it.

But now, I think the good news is that when you look at all of those things we talked about earlier, from more of what I will call lean manufacturing efficiency drivers like pad drilling and extending lateral lengths, and then coupled with the different variables that are more what I will call science driven, SSL, RCS, the opportunity for down spacing, or syncing up your completion stages between Upper Devonian and Marcellus, I think we've got a better data set than we've ever had.

And, I think the back half six months of 2014 are going to bring those final data sets into the overall database, specifically on that Upper Devonian-Marcellus interaction and on down spacing. So, that we go into 2015 and we start looking at the three-year drill program for 2015, 2016, 2017, it reflects the cumulative experience coming off of that database.

So, I think we're -- right now, we're probably two-thirds to three-quarters of the way there, based on what we know. But, when we get into the last six months of 2014, we will have the benefit of the full data set, because those production rates and well profiles will start to roll in.

And, just in addition, just the fact that we have more activity, more wells drilled, more laterals, we have the ability to test and isolate what the benefits are. So, that is the advantage of having a lot of activity in the second half of last year and then the ramp-up into this year.

That's helpful. And, what kind of increase in production, and particularly reserves, do you need to justify the increase in costs you expect from the modified completion techniques?

The way we look at RCS, SSL, we look at it on an EUR basis benefit. Again, our expectation there, and we will have more to say about this when we release the reserve results, I think on February 7, so we're somewhere in the 15% to 20% EUR incremental increase range. And then, when you compare that to the costs, we're somewhere, as I said, $220,000 to $240,000 of additional completion costs per thousand foot of lateral.

So, there is your impact on drilling complete costs. There is your benefit on EUR. Of course, it is a function of lateral length. You can figure out the math for different lateral lengths. And, I think you come to the conclusion that RCS and SSL makes sense where you're getting that 15% to 20% improvement in EUR.

Okay, that's helpful. And then, lastly, you talked about your firm transportation, you talked about your basis hedging, and your financial hedges. So, for 2014, where you stand right now, how much exposure do you have to swings in basis?

Well, Joel, swings in basis, we had said that for 2014 we have a 57% hedge position, and of that hedge position that 35% of it is NYMEX, and then another 22% has the NYMEX plus the basis hedge. And, maybe a little more to help you figure that out, for example, Dominion, let's take a look at Dominion. About 18% of our gas will be selling at the Dominion south point.

And, as far as swing in volatility, for the total revenues of our company, that is only about 3% to 4% of the total revenue of the company is going to go through the Dominion sales point. So, the volatility around that sales point is not going to have a material effect on our overall revenue. But, we certainly do watch it closely because it has been very volatile at the dominion south point sales.

Got you. Very helpful. Thank you.

Mike Dudas, Sterne, Agee & Leach.

Good morning, gentlemen. David, very helpful, we went through some of the bullet points on cash generation and spending this year. Could you maybe get a little more, like timingwise, first half, maybe by second quarter we should start to see a lot more of the -- some of these situations come to fruition, so we can see, unless things change, a big month as we move into the second and third quarters?

Yes, so obviously, for example, BMX should be online by the end of the first quarter, so the second quarter, capital goes down, and cash flow goes up. We will try to get our tax rebate as fast as possible. We are going to do a fast-track filing here. I can't tell you how fast the IRS will give us our money, but hopefully it will be in the first half of this year.

The carry on Hess side is pro rata on spending throughout the quarters. And, on the Marcellus side, with Noble, if gas stays above $4 for the month of February, I think we will say that March 1, we will start to get the benefit of the Noble JV carry. Hedging benefits will happen throughout the year. So, that will be pro rata to production.

And then, the sale of noncore and infrastructure stuff, I would just say we will have pieces of potential noncore asset sales throughout the year. And, the infrastructure monetization is probably more of a second half realization. We will figure out what is going to go on in the first half, and then we will have a line of sighted path to timing of when we realize it. But, I think that we think about that as a second half item.

That is very helpful, David. Is Baltimore in part of these discussions on monetization?

Baltimore, at the present moment, is not.

Okay. I have a follow-up, maybe for Jim. Maybe share your thoughts on the cold weather and what utilities are thinking about, there is a very helpful chart in the appendix about where inventory level with the PJM.

If gas stays relatively firm throughout into the summer, I mean with the differential in pricing and the PJM maybe relative to Henry Hub, do you think that utilities will be coming back into the market strong for uncommitted coal, especially if the weather stays the way it is in the next 30, 45 days?

Yes, Mike, I will talk about a view of the market and then I can give you some realtime spot activity that we have going on.

Sure.

In looking at the market, you look over the past four quarters, from the end of 2012 through 2013, and coal demand has out-paced production. And, as you said, we're seeing that with the coal inventories coming down.

We have estimates at the PJM at the end of January will be at 14 million tons, which is below the five-year average, and below the 5-year minimum. And, also below last January by 6 million tons. We also sell coal down into the southeast. We look at the end of January for the southeast, inventories are getting down into the 28 million-ton range, which, again, are below the 5-year averages.

So, the production decreases are starting to show up in the coal inventories. But then, the other piece of that story is the gas inventories. The gas inventories themselves, we have had some record withdrawals from gas inventory. We think that at the end of the first quarter, the gas inventories could be down as low as 1.2TCF and maybe even a little bit lower. That is well below the 5-year average of 1.7TCF.

So, coal inventories are down. The gas inventories are down. And, we just came out this week with the PJM, where new winter peak electric generation demand records were set. So, we think you put all of those factors together, and you are getting into a domestic thermal market that has some very strong indicators of upwards price movement.

Now, what that means to us at CONSOL, or in looking at our numbers, as we enter the year and the numbers that were in the earnings release there, Mike, we had about 2.6 million tons of Bailey coal open to the market for sale. And, 2.6 we had on the thermal and about 1 million that we were seeing on the high vol which, as you know, we flip back and forth.

So, let's just say will is 3.6 million tons of Bailey available for sale at the present production level. Well, in the past two weeks, two to three weeks, I will say since the beginning of the year, we have been able to sell about 50% of that tonnage, about 1.8 million tons, but it is all for shipment here in the first 6 months of the year.

So, the market has been very active, but it is very short-term buying. I think the utility buyers are looking at their -- do they want to go too long on coal, how is it going to go for the rest of the year? We have had such a volatile market over the past years, the tendency to buy long seems to have left the market.

But, from a CONSOL position, so that would have about 50% of the available coal we have, that is on a 24 million-ton annual production level for the Bailey complex. That doesn't have any weekend or overtime production in there. We have the ability to ramp that production up to much higher levels if we so choose. The market prices have started bumping up a little bit with this demand.

But we are seeing some upward movement but it hasn't been a lot yet. But, we're thinking that based on the factors that I just laid out for you that there is really good potential as we get to the latter half of the summer and the year for some strong price movement. And, if that is the case, we will respond accordingly with our production.

Jim, that was excellent. It seems like utilities are going be short-term oriented for a while. Is that going to allow for maybe better pricing negotiation, because they need it so quickly and such as opposed to some term business?

Well, the short term pricing, we certainly have all of these factors that we have in the power markets nowadays, is leading just to a market that's going to have volatility like we have never seen before.

Okay.

As the coal power plants are shutting down, and the gas power plants are stepping in to fill the void, we are going to have a lot of spikes in gas prices and power prices as you can look at the last week, last couple of weeks, what has been happening with the record power prices as well. So, over the next two years as significant amounts of coal-based generation is going to come offline, we think that is going to add even more volatility and pricing.

So, when we think that volatility is going to be to the upside. So, if buyers are going to be more in the spot market and the conditions of the marketplace will be in the more volatility to the upside, because we're going to more gas generation and less coal generation, yes, I think there is upwards price exposure to coal buyers.

I appreciate that comment. Excellent slide deck, guys. Thank you.

Thanks, Mike.

Mark Lear, Credit Suisse.

Good morning. Thanks for taking my questions.

Hi, Mark.

Good morning, mark.

Can you talk about how you are thinking about the strategy of taking cash flows from the coal business to fund upstream development, gas development? I know you've talked a lot in the past about wanting to potentially separate or see the gas business on a stand alone basis. So, was wondering if I could get some color on that?

Sure. Right now, once we are finished with our BMX and our Enlow Fork expansion, we go to maintenance mode on our coal side for our capital. So, the decision really will be more about what is the capital spending levels we want to spend within our gassiest areas.

How much are we going to spend in our Utica, Marcellus, and any of the other areas that we have. And so, right now, unless our view changes on the coal market, we are just going to go to maintenance mode. And so, it will be just what is the level in areas that we are going to spend on.

And on the coal side when you look at that ha maintenance level is, I think $4 a ton is a good number and a good assumption to use moving forward second half of 2014 on out.

And, I think the second part of your question is about a split potential and the need for the coal business essentially to help supplement the gas business. I think there are definitely some synergies between the two.

And clearly, when basis flows out, and when Jim talks about 3% to 4% impact to our overall revenue because of the fact that we have more of a diversified revenue stream here, those are the days you say you are very happy to have a coal business to support your gas business. But, over time, when the gas business grows up, and the liquids percentages increases, then that is a decision that we will have to make at some point in time.

Great. And then, just quick follow-up. Looking at the Utica, particularly on the infrastructure side, I know Blue Racer has mentioned a number of operators, including yourself, that have made commitments there. I just was wondering if you could give some more color on your process and commitments in the Utica.

Mark and I are processing commitments that we have for both the Utica and the Marcellus, the wet area. We feel that we have adequate capacity to cover all of our production needs for the next several years. The basin as itself, in total, we don't see there's going to be any constraint long term on the basin, on processing.

There is certainly going to be adequate processing available. And, there is some of the NGL pipelines that are coming online as well to help move that out of -- the product out of the basin. So, it is not a constraining factor for us or for the basin, in our view.

Understood. Thank you.

Thanks, Mark.

Lucas Pipes, Brean Capital.

Good morning, everybody.

Good morning, Lucas.

First, to maybe quickly touch back on the potential midstream asset sale. Could you maybe tell us whether this is a must-do or rather an open-ended evaluation process? And, if you do decide to go forward, would you say that you would want to maintain some sort of interest in that asset?

That's a good question. When you look, when you think about must-do, I'm going to refer you back to our balance sheet. The changes we have made, we really strengthened our balance sheet.

We have the cash. We are going to move on these asset sales for value to the shareholders at maximum value. For lack of a better term, there is no fire sale here. But, there is real value in these assets.

So, when we see an opportunity, whether it is to hold some value, through a structure like an MLP, or to do a value of a sale, it is just the number is on the inside. We're okay as long as we have the opportunity to grow. And, we have control on the growth. So, that is where we're coming from.

That makes perfect sense. And, to maybe then switch to your CapEx budget. Would you say there is flexibility on the gas side to increase spending this year? And, I would assume, that at this point, you are baking in the carry, however, correct me if I'm wrong, could there be upside if the carry formally gets activated in February?

The way we are looking at the capital spend for the E&P segment really ties to the production growth that we have put out there of the 30% compounded annually. And, the way we're approaching the execution of that production ramp is to embrace the principals of lean manufacturing, where there is analogies of trying to debottleneck the individual lengths of the production chain.

Whether it is drilling and drilling efficiencies or completions or midstream, staffing, service providers, all of those things, of course, at any given moment in time there is going to be one of those that is going to be the bottleneck. And, our approach is that we've got a high level of confidence that we are going to have a current base plan that gets that 30% production ramp.

And then, we work that base plan to debottleneck it further so that if, if we want upside, because natural gas prices rise or because something else, some other extraneous variable comes in and changes things to the positive, we've got the opportunity to do so. And, it is very similar, it is the same analogy of what we do on the coal side.

And, when you look at how we try to maintain the long walls and develop lead days so that, as Jim Grech spoke to earlier, if and when that market volatility or there's price spikes occur, we've got the opportunity to produce beyond our base lanes. There is an analogy on the two segments.

But, on E&P side, it's very much looking at that process from locating where a future lateral well should be to actually tying into line and creating revenue and all of those different steps in debottlenecking that. So, if you do want to go north of 30% production growth, that opportunity is there. So, right now the plan is 30%. And, you saw the production guidance of the 215 to 235 BCF. And, I think that is the best assumption to stick with for now.

And, just to add to that, I would just say that our goal is to be more productive and drive the capital down per that production.

That's great. And yes, you provided excellent color on all of your initiatives there. Good job, excellent. Thank you.

Brad, I think we will have time for one more question.

Neil Dingmann, SunTrust.

Good morning, gentlemen. I'm glad to get in. Just one question. One of your peers has mentioned in their southwest PA, just a sizable amount of unproven resource potential, with some of their dry Utica there.

I guess two questions around that. One, have you identified how much unproven resource potential you all have there? And then, secondly, any plans to drill any -- going after some Utica there any time soon?

We talked, historically, of Marcellus, Pennsylvania, West Virginia, we talked Utica of Ohio, of course, those formations don't stop at the river or the state borders. The best example of a sack play opportunity of Marcellus and Utica that we can give you within the company is Monroe County, Ohio, where this year we do plan to drill both the Marcellus and Utica horizons within Monroe County.

Now, that, of course is, as I said, on the Ohio side of the border. That same type of opportunity needs to be assessed first for the Utica, within PA and the West Virginia panhandle. We are going to take an approach there of pushing that towards the second half of 2014 and seeing what some of the industry data might be.

And oh, by the way, at the same time, of course, you've got the Upper Devonian. And, again, we talk about Upper Devonian as one formation, but we've got the Burket where most of our emphasis has been and most of the industry's emphasis has been to date, and we have also got lime stream.

So, for 2014 we will be testing that, of course, too with the Upper Devonian laterals that we've got planned in Washington County, PA and in northern West Virginia. So, the Utica potentials there are reserve releases on top of 3P which we will state where the 3P not only magnitude is at but what the contributers and components of it are.

But, it is very early to say what that opportunity might be for Utica in PA. But, again, we have seen with the Marcellus, with the Utica, and now with the Upper Devonian this stack play opportunity and the incremental economics as technology continues to advance, the potential is certainly there.

Okay, and then, just last, really last question. On the eight rigs it sounds like you have running in Marcellus, will a lot of those continue in that same focused area we have been in, in southwest PA? Or will you go up to northern West Virginia a bit more? And then, same with the drilling plan in -- over in the Utica, your thoughts of where you will maybe keep those rigs running.

Right now we've got eight rigs running across the Marcellus between ourselves and our joint venture partner. Five of those I will call them in the wet area. And, that might change between four and five over the course of 2014, and three, or three to four, because we would reallocate one those rigs, potentially, would be what I would call in the dry area.

The rig counts right now, we've got one in northern West Virginia, on the dry side, one in southwest PA, and one up in central PA in Westmoreland County. And, the five wet rigs are different counties in West Virginia, Ritchie, Tyler, and I think the bulk of them, three of them, are in Marshall County.

When you look at what we've got on tap for 2014 in the Marcellus, the TD count, which is probably the parameter that is most applicable here, it is going to be roughly a 50%/50% split between that West Virginia wet region and then the dry Marcellus. 75 wells or so, TD'd on the dry side, and we're saying about 85 will be TD'd on the wet side for the Marcellus.

On the Utica, the story there is it is pretty straightforward for 2014. It is going to be Noble County, Ohio on our side of the fence, and Harris and Belmont County on the Hess side of the fence for 2014. The TD total for Utica is slated to be around 32 or so for the entire year. And, we will do probably about a 12 on our side down in Noble County, Ohio, and our partner will probably do about 20 up in Harris and Belmont.

Perfect. Thanks, Nick. Look forward to that big reserve report.

Okay. Operator, can you in instruct our callers on how to hear the replay information?

Of course. Ladies and gentlemen, this conference will be available for replay after 12:30 pm today through February 7. You may access the AT&T teleconference replay system at any time by dialing 1-800-475-6701 and entering the access code 314970. International participants may dial 320-365-3844.

And, those numbers again are 1-800-475-6701 and 320-365-3844. Again, entering the access code 314970. That does conclude your conference for today. Thank you for your participation and for using AT&T Executive Teleconference Service. You may now disconnect.