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've 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 towards new look post the sale of the 5 mines. I will then pass it over to Brett, who will review our accomplishments and goals for 2014. As Dan has mentioned, we've 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 of our coal business and multiple sale processes going on. However, the most important event was the shift in focus towards becoming a strong E&P company. For 2014, this will be a transition year as we ramp up our gas and liquid volumes to a higher level and rebrand ourselves as a top-tier E&P company. Our remaining coal business will always be a Tier 1 asset. If you look at Slide 3, we focused on the press release on what we considered to be the key metric for the quarter, pretax income, which was $16 million. We chose this metric because GAAP net income and EPS were greatly affected by 2 items: the sale of 5 mines, which closed on December 5 and a tax benefit arising out of the reversal of prior quarters' tax revisions. On Page 1 and 9 of our earnings release, we provided both pretax and EBITDA reconciliation tables that adjust for discrete items. The results was adjusted pretax 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 5 mines and today's commodity price environment. Keep in mind that a…

Thank you, Dave. Good morning, everyone. It's 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 3 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 5 mines in West Virginia in a transaction value of $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. 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 improvement, we are set to grow in 2014. The most frequent question I've been asked lately is what are we as a team doing to at least meet the 30% gas production…

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

[Operator Instructions] A question comes from the line of Holly Stewart with Howard Weil.

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

Sure. Actually, I'll have Dave address that.

Yes. 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's through a sales process or through an MLP process.

Okay. So then just to be clear, the assets and the CONE 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 one on the E&P side or for Nick. I guess what types of things on the D&C side this year will you be testing that we would kind of consider pilots and ultimately would change how we would value CNX?

I think there's a number of things we're doing on the D&C side. I'll use, say, 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 that we've 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's not just going to be an application we saw in Southwest PA historically, but now it'll be in the areas like Southwest PA and northern West Virginia, as those new south regions of the Marcellus come online. We've talked a lot about lateral length, and we feel that's 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 see is going to continue to accrue a lot of benefits for us. So, if you look at 2012, we're around 5,500 foot in the Marcellus on average lateral. Last year, we came in at almost 8,000 feet on average. There will be a lot of benefits on efficiencies that accrue from that as well. Of course, that's SSL, RCS, that's a big one. When you look at the potential incremental improvements from it, if you just look at Southwest Pennsylvania, where we've been most of our applications for SSL, RCS to date, it's taken the EURs per thousand lateral foot from somewhere around 1.6 Bcf per thousand foot up to 2, 2.0. And we expect similar types of incremental improvements when you look at our drilling prospects in northern West Virginia. And then we're going to test…

And we do have a question from the line of Jim Rollyson with Raymond James. James M. Rollyson - Raymond James & Associates, Inc., Research Division: Maybe David, you've 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's going to have to go up somewhat on the E&P side specifically in order to sustain the 30% growth you guys are kind of forecasting for 2015 and 2016?

I think -- let's break it out 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'll be more in a maintenance mode. So the coal numbers should, in theory, come down. But 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 will -- 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 -- could, if it ends up going into more an MLP, that effectively will take the capital number down as well on the midstream side. James M. Rollyson - Raymond James & Associates, Inc., Research Division: 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 cost in the E&P side of things as volumes go up 30% a year for the next 3 years? Is that something 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 costs for Marcellus and the Utica would trend down as the volumes ramp. But I'll break that conclusion to 2 different components. The most important when we look at it is the component of what's occurring with the drilling cost, the completion cost, 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 cost, the trends in 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 cost per foot went from $220 -- $220 a foot in 2012 down to under $200, $190 a foot. The average lateral cost went from about $530 a foot down to about $380 a foot, okay? And again, the reasons for those were the multi-pad drilling, the longer laterals, et cetera. Same issue you see on the completion side or the same trend. The average stage cost in the Marcellus between '12 and '13 were basically held flat, and that's despite redoing some service contacts with our primary service provider and partner, Calfrac, where we adjusted those costs to market. So, again, adjusting for things like RCS or SSL, which, of course, will change as completion costs, our expectation is all the trends are heading in the right direction on the most important drivers of cost at the Marcellus, which are drilling and completions. When you look over to Utica, a similar type of a trend when you look at drill and complete costs. Those costs will continue to go down. It's still early in the Utica, of course, but towards the end of '13, 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 at the second component of cost, whether it's firm transportation or direct administrative overhead, all those fuel costs, that's just straight economies of scale. And as the production volumes continue to climb in the Marcellus, and, again, 56% quarter-over-quarter for the fourth quarter '13 and then 80-plus percent expected for '14 versus '13, you should see economies of scale helping reduce those unit costs.

And we do have a question from the line of John Wolff with ISI Group.

Just been studying your gas bits and just wondering if you could start with talking a little bit about where you are in Marcellus, northern West Virginia in terms of average lateral paints [ph], your SSLs, how many feet, is there still trial and error of, kind of where you would see yourself versus the rest of the industry, like Antero? And are you kind of 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, a lot of the attention, and rightfully so, has gone to what we've been doing in Southwest PA. So when you look at in terms of which subfields that 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's come over the past couple of years. You look at 2014, we're going to be drilling just over 2 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 control. We had a well in Philippi, Century, in Audra, all 3 of those areas that came on from upper well pads to single wells. And those results are at or above the expectations that we had with the type curves. On SSL and RCS, that is probably, that northern West Virginia area is number 2 in terms of our certainty of it being applicable, right behind Southwest PA. So our plan for 2014 is that all the wells that we'll be drilling in northern West Virginia will apply RCS/SSL.

Okay. Is there -- 200 feet, 250 feet, 300 feet? Do you have a feel for sort of averages in terms of stage lengths?

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

Yes, the spacing, just to be clear, John, the spacing that we have been using had been about 300 feet. We've halved that to about 150. And then within the 150 feet, we have decreased the spacing between the curves. So reduced cluster spacing, we've basically gone from about 60 feet per cluster to about 30 feet, with an average 150 feet. Then, obviously, we're getting about 5 clusters within that 150 feet.

So the [indiscernible] 300-foot on the stage spacing before, 150 after. And then it stands at 60-foot before on clusters and 30-foot after. Did we answer your question, John?

Yes, I got it. Last one on Utica. There was a high-profile transaction over the last few days for nonproducing dry gas, which kind of made some people blush in terms of the dollars paid of around $12,500 an acre. And I was just wondering, do -- 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 has sort of heated up in the sweet spots of the play?

Well, the Utica, we said earlier, it's early. We've got our certain population of what I'll call flow base -- flow back data. But like all the operators out there, it's right now a bit infrastructure-constrained, at the moment, that's going to change. And we talked about well cost earlier, they're declining. That's 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 dryer 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 the raise the return above the cost of capital where we've got the concentrated footprint. Where we don't have the concentrated footprint but 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 have and we're 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.

I think, John, overall, you could expect us to high-grade our portfolio. We're going to add areas where we need to supplement, whether it's extending 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'll be times where we'll divest some of the other area, noncore Utica areas as well. So we'll be happy to have more indicators out there with it that has a toll handle. Take advantage of it.

And we do have a question from the line of Mitesh Thakkar from FBR Capital Markets. Mitesh Thakkar - FBR Capital Markets & Co., Research Division: Just looking at the Marcellus and with all the growth being planned around 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 then to the Midwest?

Mitesh, it's Jim Grech here. In looking at the basin, in total, then I'll get to looking at CONSOL's positions, looking over the next 3 years, we see a lot of volatility in the basin because of the timing between when production's coming online and when takeaway capacity is coming online. In total, we look out over 3 years and we see 6 Bcf a day of production coming online in the basin, getting it up to 20 Bcf a day type of range but we're also seeing the same time frame about another 7 Bcf a day called pipeline capacity coming on to move the gas out of the basin. So when you look at the timing and location of the growth in FT versus the growth in production, it's going to take some time for the market to sort that out. So what we in CONSOL are doing, right now, we have a 34% of our FT capacity, takes the gas out of the basin, takes it down to the East -- out the East Coast and down to the Southeast. Starting later this year and into next year, we're going to be adding more capacity that's going to take us out to the MidCon and the Gulf markets. So we're targeting by 2016, by the start of 2016, to have 337,000 decks [ph] 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. Mitesh Thakkar - FBR Capital Markets & Co., Research Division: And that's all going to the MidCon and the Gulf markets?

Yes, we also have some going on in the Southeast market as well. Mitesh Thakkar - FBR Capital Markets & Co., Research Division: Okay, great. And just a follow-up on that, how much of your '14 and '15 production has the basis hedged and what are the plans going forward?

Well, in 2014, we have 57% of the portfolio has a hedge on it. And as we go to 2015, right now we're sitting at about 26% hedged for our portfolio. And I'm sorry, you asked another question what are our plans going forward? Mitesh Thakkar - FBR Capital Markets & Co., Research Division: Yes.

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

And we do have a question from the line of Joe Allman with JPMorgan.

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

Well, the SSL RCS approach is going to result in different metrics besides just the spacings, of course. So if you look at what we were doing earlier on in the Marcellus, if you take something like the sand, just 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're 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 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's 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's tied to, of course, those tighter spacings. But it's also something that's independent that's been viewed to try to optimize the completion techniques. That's probably the best example that I could give you of how we're trying to intersect that with the RCS and SSL.

Got you. That's helpful. And 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. When 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 areas to sub area, it's an awfully big optimization challenge. And in trying to get data sets that isolate a certain number of those variables and in trying to get a beat on what the impact is of one of those variables, it's a challenge across a field this stable is 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 those things we talked about earlier, from more what I'll call lean manufacturing efficiency drivers, light pad drilling and extending lateral lengths and then coupled with the different variables that are more what I'll call science-driven SSL, RCS, the opportunity for downspacing 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 6 months of 2014 are going to bring those final data set into the overall database, specifically on that Upper Devonian-Marcellus interaction and on downspacing, so that when we go into '15 and we start working at the 3-year drill program for '15, '16, '17, it reflects the cumulative experience coming off of that database. So I think we're -- right now, we're probably 2/3 to 3/4 on the way there, based on what we know. But when we get into the last 6 months of '14, we'll have the benefit of the full data set because those production rates and well profiles will start to roll in.

Yes, and just an 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's 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 then what kind of increase in production and particularly reserves do you need to justify the increasing 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 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 cost, we're somewhere, as I said, $220,000 to $240,000 of additional completion cost per thousand foot of lateral. So there's your impact on drilling and complete costs, there's your benefit on EUR; of course, it's 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 make sense where you're getting -- you're getting that 15% to 20% improvement in EUR.

Great, that's helpful. 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?

Look, Joe, in terms of basis, we said that for 2014, we have 57% hedge position and of that hedge position, the 35% of it is NYMEX and then another 22% has the NYMEX plus the basis hedge. And maybe a little way -- more to help you figure that out, for example, Dominion, let's take a look at Dominion. About 18% of our gas, we'll be selling at Dominion Southpoint. And as far as swing in volatility, for the total revenues of our company, that's only about 3% to 4% of the total revenue the company's going to go through that 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's been very volatile at the Dominion Southpoint sales.

And we do have a question from the line of Mike Dudas with Sterne Agee. Michael S. Dudas - Sterne Agee & Leach Inc., Research Division: David, very helpful, you went through some of the bullet points on cash generation and spending this year. Could you maybe give a little -- like, timing wise, first half and just maybe the 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 to second and third quarters?

Yes, so obviously, like, for example, BMX should be online by the end of first quarter, so second quarter capital goes down, flow [ph] and cash flow was up. We will try to get our tax rebate as fast as possible. We're 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'll be in the first half of this year. The carry on Hess side is pro rata on the spending throughout the quarters. And on the Marcellus side with Noble, if gas stays above 4 throughout 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'll 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'll figure out what's going to go on in the first half and then we'll have a line of sight and path to timing of when we realize it, but I think that you think about that as a second half item. Michael S. Dudas - Sterne Agee & Leach Inc., Research Division: That's very helpful, David. Is Baltimore in part of these discussions on monetization?

Baltimore, at the present moment, is not. Michael S. Dudas - Sterne Agee & Leach Inc., Research Division: I have a follow-up maybe for Jim. Maybe share your thoughts on the cold weather and what utilities are thinking about. There's a very helpful chart in the appendix about where inventory level to PJM. If gas stays relatively firm throughout into the summer, I mean, with the differential and pricing and the PJM relative to Henry Hub, do you think that utilities will be coming back in the market strong for uncommitted coals, especially if the weather stays the way it is the next 30, 45 days?

Yes, Mike, I'll talk about the view of the market, then I can give you some real-time [indiscernible] that we have going on. Looking at the market, you look over the past 4 quarters from the end of 2012 to the -- through 2013 and coal, the demand has outpaced production. And as we said, we're seeing that with the coal inventories coming down. We have estimates that the PJM at the end of January will be at 14 million tons, which is below the 5-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 in the 28 million tons range, which, again, are below the 5-year average. 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've 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 1.2 Tcf, maybe even a little bit lower. That's well below the 5-year average of 1.7 Tcf. So coal inventories are down, the gas inventories are down, and we just came off 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're 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 looking at our numbers, as we entered the year and the numbers that were in the earnings release there, Mike, we had about 2.6…

Well, the short-term pricing, we'll certainly have all these factors that we have in the power markets nowadays that's leaning towards just a market that's going to have volatility like we've never seen before. As the coal power plants are shutting down and the gas power plants are stepping in to fill the void, we're 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's been happening with record power prices as well. So over the next 2 years, as significant amount of coal-based generation is going to come offline, we think that's going to add even more volatility and pricing. So -- and 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 in the marketplace are leaning to 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.

And we do have a question from the line of Mark Lear from Credit Suisse. Mark Lear - Crédit Suisse AG, Research Division: Can you talk about how you're 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 just 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 a 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 gas-rich [ph] areas, how much we're going to spend in our Utica, Marcellus and the other areas that we have? And so right now, unless our view changes on the coal market, we're just going to go to maintenance mode and so it'll be just what is the level and areas we're going to spend on.

And on the coal side, when you look at what that maintenance level is, I think $4 a ton is a good number and a good assumption to use moving forward sort of second half of '14 on out.

And I think the second part of your question is about the 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 2 and, clearly, when basis flows out and when Jim talks about 3% to 4% impact to our overall revenue, because the fact that we have more of a diversified revenue stream here, those are the days that you say you're 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's a decision that we'll have to make at some point in time. Mark Lear - Crédit Suisse AG, Research Division: Great. And then just a 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 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 has itself, in total -- we don't see there's going to be any constraint, long term, on the basin, on processing. There's certainly going to be adequate processing available and there's 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's not a constraining factor for us or for the basin, in our view.

And we do have a question from the line of Lucas Pipes with Brean Capital.

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?

Yes, 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've made, we really strengthened our balance sheet. We have the cash. We're going to move on these asset sales from value to the shareholders at maximum value. For lack of a better term, there's no fire sale here, but there is real value in these assets. So when we see an opportunity, whether it's to hold true value through a structure like an MLP or to do a value of a sale, it's just the numbers on the inside. We're okay as long as we have the opportunity to grow and we have the control on the growth. So that's where we're coming from.

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

The way we're looking at the capital spend for the E&P segment really ties to the production growth that we've put out there of the 30% compounded annually. And the way we're approaching the execution of that production ramp is to embrace one of the principles of lean manufacturing, where there's analogies of trying to debottleneck the individual lengths of the production chain, whether it's drilling and drilling efficiencies or completions or midstream, staffing, service providers, all of those things, of course, at any given moment in time, there's going to be one of those that's going to be the bottleneck. And our approach is that we've got a high level of confidence that we're going to have a current base plan to get that 30% production ramp and then we work that base plan to debottleneck it further, so that if we want upside because natural gas prices rise or because something else, some other straining variable comes in and changes things to the positive, we've got the opportunity to do so. And it's very similar, it's the same analogy of what we do on the coal side and when you look at how we try to maintain the longwalls and develop lead days, so as Jim Grech had spoke to earlier, if and when that market volatility or those price spikes occur, we've got the opportunity to produce beyond our base plan. So there's an analogy there between the 2 segments, but on the E&P side, very much looking at that process from locating where a future well lateral should be to actually tying it in line and creating revenue in all those different steps and debottlenecking that, so that if we do want to go north of 30% production growth, that opportunity is there. But right now, the plan is 30% and you saw the production guidance of the 215 to 235 Bcf and I think that's the best assumption to stick with for now.

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

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

All right, and that last question then comes from the line of Neal Dingmann from SunTrust.

Just one question. One of your peers has mentioned, kind of in their Southwest PA, just a sizable amount of unproven resource potential for some of the dry Utica there. I guess 2 questions around that. One, have you identified how much sort of unproven resource potential you all have there? And then secondly, any plans to drill any [indiscernible] efforts drilling efforts in Utica there any time soon?

We talked historically of Marcellus, Pennsylvania, West Virginia, we talked Utica, of Ohio. Of course these formations don't stop at the river or the state borders. The best example of a stack play opportunity of Marcellus and Utica is 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. And that's, 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're going to take an approach there of pushing upwards the second half of '14 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 talked about Upper Devonian as one formation. But we've got the Burkett, where most of our emphasis has been -- most of the industry's emphasis has been to date, and we've also got the Rhinestreet. So for 2014, we'll be testing that, of course, too, at the 6 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, and I talk to 3P, which we'll state where the 3P not only magnitude is at, but what the contributors and components of it are. But it's very early to say what that opportunity might be for Utica and PA. But, again, we've seen with the Marcellus, with the Utica and now the Upper Devonian, the stack play opportunity and incremental economics as technology continues to advance. The potential is certainly there.

Okay. And then the last two -- really, just last one question. On the 8 rigs that it sounds like you have running in Marcellus, will a lot of those continue in that same sort of focus that we've been in, in Southwest PA or will you go up to Northern West Virginia bit more and then same with the sort of the drilling plan in over in the Utica, kind of your thoughts of where you'll maybe keep those rigs running?

Well, right now, we've got 8 rigs running across the Marcellus between ourselves and our joint venture partner. Five of those I'll call them in the wet area and that might change between 4 and 5 over the course of '14 and 3 or 3 to 4, because we would reallocate one of those rigs, potentially, would be, what I'll call, in the dry area. The rig counts right now, we've got 1 in Northern West Virginia on the dry side, 1 in Southwest PA and 1 up in Central PA, in Westmoreland County, and the 5 wet rigs are in different counties in West Virginia: Ritchie, Tyler and I think the bulk of them, 3 of them, are in Marshall County. When you look at what we've got on 2014 in the Marcellus, the TD count, which is probably the parameter that's most applicable here, it's going to be roughly a 50-50 split between that West Virginia wet region and then the dry Marcellus. Say 75 wells or so TD'd on the dry side, and then about 85 will TD'd on the wet side for the Marcellus. Utica, the story there is pretty straightforward for '14. It's going to be Noble County, Ohio on our side of the fence and sort of 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'll do probably about a dozen on our side down in Noble County, Ohio, and our partner will probably do about 20 up in Harrison, Belmont.

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