Tyler Lewis - CONSOL Energy, Inc. Nicholas J. DeIuliis - CONSOL Energy, Inc. David Michael Khani - CONSOL Energy, Inc. Timothy C. Dugan - CONSOL Energy, Inc..

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc. Holly Barrett Stewart - Scotia Howard Weil Joseph Allman - FBR Capital Markets & Co. Jeffrey Campbell - Tuohy Brothers Investment Research, Inc. Jacob Gomolinski-Ekel - Morgan Stanley James A. Spicer - Wells Fargo Securities LLC.

Ladies and gentlemen, thank you for standing by, and welcome to CONSOL Energy's Fourth Quarter 2016 Earning Results Conference Call. As a reminder, today's call is being recorded. I would now like to turn the conference call over to the Vice President of Investor Relations, Mr. Tyler Lewis. Please go ahead, sir..

Thanks, John, and good morning to everybody. Welcome to CONSOL Energy's fourth quarter conference call. We have in the room today Nick DeIuliis, our President and CEO; Dave Khani, our Chief Financial Officer, and Tim Dugan, our Chief Operating Officer.

Today, we'll be discussing our fourth quarter results and we have posted a slide presentation to our website.

As a reminder, 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 Securities and Exchange Commission filings. We will begin our call today with prepared remarks by Nick, followed by Dave and then Tim.

And then, we will open the call for Q&A. I wanted to highlight quickly that we plan to file our 2016 10-K and our annual reserve release next week on February 8th. With that, let me turn the call over to you, Nick..

Good morning, everybody. Given the recent Analyst and Investor Day that we hosted in Pittsburgh on December 13th of last year, I'd like to spend my time today briefly reiterating some of the main points that were discussed at the events, and while leaving more of the quarterly details for Dave Khani and Tim Dugan to discuss.

As many investors know, CONSOL has gone through a period of intense change highlighted in-part by many strategic transactions that have contributed to our transformation into what is essentially a new company today.

These changes also help to solidify our corporate culture by building upon the foundational goal of optimizing the allocation of all capital resources to enhance the long-term NAV per share of the company. This remains at the forefront of our decision-making matrix.

On the operations front, the degree and rate of improvement over the past two, two-and-a-half years has been significant. In short, we recently raised EURs across our asset regions. And in some cases, we did that substantially. LOE has improved. IRRs are up. Capital efficiency is up and capital intensity is down.

We've consistently beat many of our cost projections, especially when compared to those that were laid out during our 2014 Analyst Day a few years ago. Tim Dugan is going to highlight some of the operational improvements that we've continued seeing in the fourth quarter.

Moving forward, we believe that there are two key developments that will further drive the NAV per share of the company. First one is how we're moving acreage in the non-core category over to the core category in an expedited yet methodical fashion.

And the second development is our vast stack pay opportunity set being a big driver to the NAV per share. Our substantial footprint provides delineation opportunities both through our own drill bit, as well as through participation in competitor wells, which has given us what we believe to be the most significant data set in the basin.

It has been a key part of our program and it's going to continue in helping to convert non-core assets to core. With our unrivaled opportunity set, we remain focused on executing on our philosophy, and that really manifests itself through three steps.

First step is to prudently grow E&P production over the next three years by efficiently allocating capital to high IRR, NAV per share accretive areas of interest, which will also grow EBITDA. This drives our continued commitment to growing free cash flow, which we believe will deliver long-term value to our investors.

Second step is through the growing EBITDA along with debt reduction from free cash flow and asset monetizations. We drive the leverage ratio below 2.5 times. Dave Khani is going to go into more detail on our balance sheet and liquidity position, especially given the continued success we saw during the fourth quarter and full year 2016.

Now, as part of our 2017 base plan, we expect to monetize between $400 million and $600 million of assets. We've got a proven track record in that area and due to the recent dissolution of the Marcellus joint venture we've got far more strategic and operational control of our monetization program.

Third and final step is a strong balance sheet allowing us to not only invest in high IRR organic E&P opportunities, but to also opportunistically reduce share count, to take advantage of where CNX shares are trading versus our internal NAV per share view.

We continue to see a compelling opportunity to grow NAV per share through share count reduction. I'd like to end by further elaborating on how we intend to execute the separation of the E&P and remaining coal business. As stated in the Analyst Day, under the right conditions, we would separate the E&P and remaining coal businesses in 2017.

Just over a month later, we sit here today viewing a separation of the businesses as a top strategic priority for 2017. There are different ways to achieve the split. And in this morning's earnings release, it was noted that we're pursuing three parallel paths. One, being an outright sale.

Second, being a spin-off, and the third being additional drop-downs of undivided interest into CNXC. Ultimately, we believe that the separation of the businesses can happen this year in one of these three forms. The path we choose, that's going to be the one that offers the best, the highest, NAV per share proposition for our owners.

Our efforts are underway. We're going to run a competitive process and the best coal team in the business is ready to go. We closed out a very busy and productive 2016 on a strong note with the Noble joint venture dissolution.

You can expect this momentum to carry over into 2017, as we continue to advance the strategy we laid out on our Analyst and Investor Day back in December of last year. Allow me now to turn things over to Dave Khani. He's going to review our financial performance during the quarter..

Thanks, Nick, and good morning, everyone. I'll frame my remarks as they pertain to finance teams three NAV drivers, capital allocation, accurate forecasting and balance sheet and cost of capital. But before I hit on these drivers, I'd like to summarize our quarterly financial results as indicated on slide eight.

CONSOL reported a fourth quarter net loss attributable to CONSOL Energy shareholders of $306 million, the GAAP loss this quarter included a $237 million impact from unrealized loss in commodity derivatives and AMT allowance an a few other items highlighted on this slide.

After adjusting for these items, which is reconciled in our press release, CONSOL posted an adjusted income from continuing operations of positive $0.5 million and adjusted EBITDA attributable to CONSOL of $205 million. Now let's talk about the $167 million AMT allowance recognized this quarter.

Related to taxes, this year, we reviewed current and historical tax positions taken by the company. These positions did put pressure on certain tax deferred assets related to alternative minimum tax credits. As a result, the company recorded a valuation allowance of $167 million during the fourth quarter related to these attributes.

Cumulatively, this will result in a receipt of over $120 million in cash refunds of which we have already received $20 million during 2016. We expect to receive the remaining balance over the next 12 plus months. Now at the Analyst Day, we highlighted three main NAV drivers, and I'm happy to say that we're slightly ahead of our goals.

First on capital allocation, we will be within the target leverage ratio zone of 2 times to 2.5 times, no later than the second half of 2017 with our improved forecast. Our management team is again assented to generate free cash flow and therefore the team will strive to beat our free cash flow targets.

Once we get our leverage ratio below our 2.5 times target, we'll have increased flexibility on how we allocate use of our free cash flow either drill, buyback stock or buyback debt. Moving over to our accurate forecasting.

For the fourth quarter, we met or exceeded our forecasting for all of our key line items for E&P, DBU and coal, culminating in higher EBITDA and free cash flow. Now one area we incurred higher costs in the quarter was SG&A. We achieved higher key metrics defined in our short-term incentive compensation plan and discretionary 401(k) contribution plan.

This resulted in fourth quarter accruals of $21 million. Had these accruals been reported ratably over the year, the quarter impact would have be about $10.5 million. We expanded our transparency at our Analyst Day by postponing 2017 segment EBITDA.

On slide 16, we raised our 2017 adjusted E&P EBITDA guidance simply marking to market a more recent strip price. Also we updated our NGL estimates for 2017 and 2018, which can be found on slide 14. As a result of our higher EBITDA forecast, our leverage ratio targets declined by 0.3 turns faster than our December outlook. This can be seen on slide 12.

Now one of the components in help securing our free cash flow plan and forecast is through our programmatic hedging, which helps eliminate commodity risk and basis and regional pricing volatility. Throughout the quarter, we layered in an additional 215 Bcf of NYMEX natural gas hedges, along with 149 Bcf of basis hedges through 2021.

We continue to focus on marrying up NYMEX and basis hedges to derisk regional pricing pressures. You can see on slide six, when you look at these hedges together, we have 287.1 Bcf hedged at a price of $2.50 per Mcf. These volumes have revenues fully locked in.

Now please keep in mind, when you're looking at our hedge position versus our peers that we are hedging in basis and that is a big difference. Now last piece on forecast, and then I'll touch on is regarding legacy liabilities. You can see on slide 13 that we list out a summary of our legacy liabilities.

As of year-end 2016, long-term liabilities of nearly $1.3 billion were modestly higher than our forecast, primarily due to actuary reductions in discount rates. However, we expect 2017 long-term liabilities on the balance sheet and cash servicing cost to decline by $40 million and $20 million respectively.

We continue to take a zero-base budgeting approach to reducing these costs. These liabilities are no exception and we'll continue to manage these costs down lower. Now last NAV driver is our balance sheet and impacts on cost of capital. During the quarter and year, CONSOL generated total free cash flow of $349 million and $957 million respectively.

We closeout our 18-months free cash flow plan and drove down our cost of capital by over 5% during this time period. Utilizing this free cash flow, CONSOL has remained focused on strengthening balance sheet and liquidity position. We've paid down almost $915 million in debt, attributable to CNX.

Our net debt book to leverage ratio for year-end 2016 now stands at 4.4 times, which is down from 5.1 times at year-end 2015 after normalized for the previous OPEB plan changes and using the bank methodology.

Over that same time period, our liquidity position doubled to $1.73 billion with zero drawn on our revolver and credit facility and sitting with cash on hand. We had $952 million drawn on our credit facility at year end 2015. Our ability to pay down debt or buy back stock earlier in the process should continue to drive down our cost of capital.

While on the topic of debt, I did want to take the opportunity to reemphasize that CNXC's net debt of $190 million is consolidated on our balance sheet, CONSOL does not guarantee this debt. As such, when you look at slide 11, we excluded, in order to provide total and net debt attributable to CNX, which now stands at $2.5 billion at year end.

Now let's talk about coal. CNXC reported its fourth quarter earnings last night and again posted solid results with nice increase in sales volumes. As they discussed, coal realizations increased by 2% and CNXC sees continued success on the contracting front.

Their total sold position for 2017 is 98% of the estimated total sales and approximately 66% sold for 2018 based on their guidance. In regards to our met coal kicker, CONSOL conservatively forecast between $10 million and $20 million in EBITDA in 2017 associated with the Buchanan royalty.

Now met prices have pulled back some, but our royalty continues to remain in the money. In the fourth quarter of 2016, we have accrued approximately $10 million associated with the royalty payments. We received about $5 million of cash and expect to receive the remaining balance in the first quarter of 2017.

Now, as Nick stated, we are pursuing three parallel paths regarding the separation, and we spent time with our bankers to help analyze the feasibility of these initiatives.

At our Analyst Day, we needed to see three things in order to pursue an accelerated separation, improved financial conditions, improved CNXC performance, and capital market strengths. There seems to be positive momentum in all three of these areas.

CNXC has gone from 0.4 times coverage ratio to NYSE at 1 times coverage ratio in the fourth quarter, and leverage ratio has declined by 2.5 times. So in summary, we are on track or ahead of our projection provided at our December Analyst Day and confident that our team will work hard to beat our plan.

We hope that our investment community has confidence that we are best-in-class capital allocators and the improved financial flexibility will translate into faster velocity for NAV per share growth. With that, I'll turn it over to Tim, who will now focus on his operating results and NAV drivers..

Thanks, Dave. Good morning, everyone. We see three main drivers to improve our NAV per share; operating cost improvements, productivity improvements, and our Utica delineation and non-core to core program. Let me touch on how we're tracking on all three fronts while providing a brief summary of the quarter. First, an operation summary.

During the quarter, we drilled seven dry Utica wells in Monroe County, Ohio, with an average lateral lengths of 9,600 feet while averaging 24 drilling days per well, or two days less than our previous projections.

Over the course of the first nine wells that we've drilled since resuming activity, we averaged 25 days per well and an average lateral length of 9,500 feet. These drilling efficiencies in part continue to drive our cost performance.

In the quarter, our total production costs were $2.27 per Mcfe, which is a decrease of $0.10 per Mcfe compared to the year earlier quarter. We expect further cost improvements across 2017 and 2018 driven by reductions in lifting costs and transportation gathering and compression costs.

On the topic of costs, we've been getting a lot of questions around service costs and what we're seeing and ultimately what investors should expect.

Our forecast and guidance include anticipated changes in cost due to market conditions, but as we've stated in the past, we may see some changes in service cost as activity increases but we don't anticipate across the board increases, and we expect that we'll be able to offset much of these potential increases through continued efficiency improvements and technological advancements.

Offsets will come through things like continued focus on spud to turn in-line cycle times and the use of our production control room to reduce production downtime and more effectively deploy our well tending manpower. Currently we're not sourcing sand directly from the supplier, but instead we're sourcing it through the oilfield service companies.

This has been more efficient, and in our opinion, more economic given the logistical considerations. In other words, the bang hasn't been worth the buck for CONSOL. Now, shifting over to production. Volumes during the quarter grew to a record of 101.3 Bcfe or an average of 1.1 Bcfe per day.

The main driver this quarter came from Marcellus volumes growing to 56.5 Bcfe, driven in part by 7.2 Bcf of production, which came from the dissolution of our Marcellus joint venture. For the full year 2016, we finished at 394.4 Bcfe, which was in line with our production guidance of 395 Bcfe.

Our liquids production in the quarter was 10% of the total, down from 14% in the third quarter of 2016, due to the Marcellus joint venture dissolution and reduced activity in the Ohio, wet Utica. In the quarter, our coal bed methane volumes grew quarter-over-quarter to 17.4 Bcf compared to 17 Bcf in the third quarter of 2016.

Part of the increase was due to additional non-op production received in October that contains catch-up volumes from earlier in 2016. Our total CBM decline in 2017 is expected to be 5%. And similar to the Marcellus and Utica, enhanced completion designs and improved well results are a driver behind the lower CBM decline rate.

Utica volumes declined this quarter compared to the previous quarter. However, with the limited activity in late 2015 and the first half of 2016, there were no new Utica wells turned-in-line since December of 2015.

Despite the modest decline this quarter, the dry Utica will be a major growth driver for the company in the future and we expect it to represent approximately 15% of our production in 2017 and 24% to 27% of our production in 2018.

And this number could grow even larger with additional success in the Pennsylvania deep dry Utica, which we expect over the course of the next handful of wells scheduled throughout 2017 and 2018. In 2017, we'll average three new horizontal wells drilled each month. We're currently running two rigs focused on dry Utica in Monroe County, Ohio.

One of these rigs will move to Southwest PA in the March/April timeframe to drill Marcellus wells followed by more deep dry Utica. Starting in November, we plan to add a third rig, which will focus on Marcellus at the Pittsburgh International Airport in Allegheny County, PA.

Our frac schedule is fairly consistent throughout 2017 and averages six wells being fracked each month. This is a combination of the new wells we're drilling and about 20 of the wet Marcellus DUCs that we received from the dissolution of the Marcellus JV. From a production standpoint, we expect to start turning wells in line in late March.

Our turn-in-line schedule is lumpy throughout the year and it picks up in May with nine Monroe County, Ohio wells planned. And then it peaks in August with 14 turned-in-lines, including two of the new dry Utica wells planned in Westmoreland County, PA. We continue to be very excited about this area and the potential it represents, so stay tuned.

Now with an increase in liquids pricing, we've gotten a lot of questions on our appetite and ability to accelerate some of our wet production, through either drilling more or accelerating our DUC drawdown.

In actuality, we've already accelerated the completion and turn-in-line of our scheduled wet DUCs due to the improved cycle times experienced with the current completion of the Pittsburgh International Airport. Our liquids production as a percent of our total portfolio is expected to go down below 10% in 2017 and even lower in 2018.

Historically, our liquids mix has been around 10% to 15% of our total production. However, there has been more of a focus on dry Utica, especially from Monroe County, Ohio which in combination with the Marcellus JV dissolution and our reduced activity in the Ohio wet Utica is really driving these changes.

Regardless, we do take a diversified portfolio approach and try not to chase liquids, the same mindset is applied to our marketing efforts regarding basis. In the end, we continue to rank our opportunity set and adjust activity based on economics.

That said, we do maintain the optionality to increase our liquids exposure as a percent of our total portfolio, if the economics in liquid rich areas indicate a change is justified. We can choose to increase our activity in the Marcellus wet area or through additional activity in the Ohio wet Utica.

We're continuing to evaluate our non-core acreage with an additional non-operated well being drilled this quarter. With a broader view of the basin, our earth model indicates the structural features within the Utica create compartments of varying reservoir properties.

And over the next two years we have approximately 11 planned delineation points to characterize the Utica. Ultimately, this data, including acoustic logs and cores will allow us to further refine our earth model, define the core Utica boundary and optimize our stack pay development with the Utica, Marcellus and Upper Devonian.

Now just a bit on marketing. In general, we're very encouraged by market conditions. Of these, we believe rig counts to be the most positive.

We've been expecting the low rig counts in 2016 to have an effect on supply and based on recent storage withdraw levels and the lack of strong supply response to recent high prices, we believe that available supply has finally been reduced to a level which supports healthy pricing.

While regional rig counts are higher than a year ago, they remain well below the peak levels that led to the oversupply situation and lower pricing.

Finally, with respect to pipelines, regulatory challenges continue and unforeseen developments at FERC have created even greater uncertainty about 2017 projects receiving FERC certificates and time to be completed this year. That said, we continue to expect new regional export capacity of 10 Bcf a day to be in service by the end of 2018.

We're well prepared to take advantage of the markets as the new projects are on schedule. And should there be further project delays, our strong regional basis hedge position should protect our price realizations and cash flow. With that, I'll turn it back over to Tyler..

Thanks, Tim. This concludes our prepared remarks.

John, can you please open the line up for questions at this time?.

Certainly. And first from the line of Neal Dingmann with SunTrust. Please go ahead..

Good morning, guys. Nice details today. So first question is going to be maybe for Tim or maybe for Nick, whichever do you want to look. I'm looking at from the Analyst Day the slides that you show with all just the massive acreage both in the Utica and Marcellus.

And so my question is, could you talk about maybe, Tim, the plans to – delineation plans, I guess, particularly in the Utica, does the fee acres come into play? I mean, mostly I guess, my question is, you've been drilling around Monroe and for the remainder of this year, where should we expect you to kind of focus the drilling?.

I think for Analyst Day in our one slide, I don't remember the slide number, but we did lay out several delineation points, wells, both operated and non-operated that will be drilled in the next two years, and that is our plan going forward, the 11 delineation points that I talked about.

And with that we expect that those points will really help us further characterize the Utica and bring some of that non-core acreage into the core category..

And have you guys thought what – I haven't asked you guys in a while, just versus others out there, you certainly have a much larger fee position both in Utica and Marcellus than others.

Is that something you'd consider just in outright monetizing or is it still too valuable to drill on given what it does to your working interest?.

I think with everything we do, we rank our opportunities. We rank them in our portfolio.

And as economics dictate, we make the decisions on activity, where to go, and that remains – it's fairly fluid as these delineation points come in over the next couple of years, we've got a base plan in place, but that plan will be adjusted as we get more and more information in, so it's all economically driven..

All right. And then just last question on the takeaway, in particular, I think you mentioned at the Analyst Day about the dry gathering system.

What about if you'd go further down, we've seen some pretty positive activity, surrounding some of your activity in West Virginia, do you have the takeaway down there, if you could just talk about any of the sort of southern takeaway you have or don't have?.

We do. We've got one of the benefits, I guess to our acreage position and our marketing position is the flexibility we have in takeaway, the number of takeaway points we have. And we've looked at how we would handle dry Utica volumes in West Virginia and we've got a plan in place to be able to do that.

But that's all part of the consideration, when we go through our asset assessments, we consider every aspect from our fee acreage and land position to marketing and takeaway capacity and ability to move the gas..

Very good. Thanks..

Yes. Just in addition, I would just give the CONE system is between the Anchor System, which is about 85% utilized in DevCos II and III which are sitting probably more in than 5% and 25% utilization. So there is spare utilization capacity on that CONE system..

Very good. Thanks, David..

Our next question is from Holly Stewart with Scotia Howard Weil. Please go ahead.

Good morning, gentlemen. Just maybe few high level ones here for Nick. Nick, it looks like you added the potential sale of the coal business as one of the strategic options, it doesn't seem like you would have done that unless you had a reason to.

So I guess are you getting any inquiries on selling the coal business outright? Why sort of add that to the list here over the last six weeks?.

Sure. The three processes we've laid out, what we're trying to do is we're trying to give ourselves the most looks across these different avenues to effectuate a separation and choose the one that we feel has got the best NAV per share proposition moving forward. And we want to do that in a way where it's a competitive process.

So we've got a horse race, so to speak that's ongoing. When you look at the M&A side, I think one of the biggest attributes that would make that attractive to a potential buyer is not just the asset base itself, and how it's Tier 1 and one of one, but the team they're operating at.

So when you look at what the opportunity set is out there in the coal space, there's been so much topsy-turvy, up-down rollercoaster rides here over the last two years in the coal space within the United States and globally, frankly.

And if you look at that team coupled with that asset, that would be an outstanding platform to build upon subsequent to just the Pennsylvania mining complex. So I think that reflects a couple of things.

Like we said, getting as many different looks as we can across these avenues, a competitive process to make the best NAV per share decision, but also recognizing, on that one in particular, you've got an operating team and a coal mining complex that would be a great platform to build upon moving forward..

Okay, great. And then maybe just curious on CONE, sort of how you're thinking about that business. There's no real link to Noble now in the upstream side at this point. They have recently done another acquisition in the upstream space.

So, just sort of thinking about, would you be interested in owning that whole, I guess, piece of the pie for CONE, kind of high level thoughts there?.

Yeah. We like CONE. We see value in CONE. And you see we've put a value on CONE in our Analyst Day for an NAV. And so I think the question you need to ask Noble is, does Noble want to sell CONE? For us, we like CONE..

Understood. Thank you..

Next we will go to Joe Allman with FBR. Please go ahead..

Thank you. Good morning, everybody..

Good morning..

Good morning..

Good morning..

This is for Tim probably. So, Tim, could you just once again review what your current activity is, your current E&P activity and what the plans are over the next, say, few months? I know you're going to be – you've got two rigs in Utica, you're shifting to Southwest PA, then you're shifting back to Utica.

Could you just review that for us again? And then talk about kind of key data points or key tests that you're focused on over the next few months..

Well, like I said, we've got both rigs right now in Monroe County, Ohio. In the late March/April timeframe, one of those rigs will move over to Southwest PA and drill some Marcellus wells. There are wells that we've already got some sunk capital there. We've got top holes drilled.

So we've got to go in and drill laterals and then we've got some additional DUCs on that pad that we'll be able to complete. And then from there, we'll be moving up to Westmoreland County, PA to drill some offsets to our Gaut well. We've got two wells planned up there. And then we'll follow up with – we've got two frac crews running right now.

We'll have one and a half to two frac crews running consistently throughout the year. So our activity is going to be pretty steady. It will move back and forth between Marcellus and Utica. And then as far as data points, as I mentioned, we've got a non-operated data point that will be coming in – well that will be drilled, will be spud this quarter.

And we've got a couple others planned for later in the year, some operated, some non-operated. But as those come in, we'll update our plan and our earth model and make decisions accordingly based on the data that we get in and what we learn about the Utica..

And so – just a quick follow up.

Any changes to your drilling or completion techniques that you're looking at over the near-term that will be particularly interesting to you?.

Nothing significant. I mean, we continually are looking at our drilling and our completion practices and how we can improve them, make them more efficient. There's always a certain amount of ongoing testing from prop and loading, lateral spacing, landing zone targets.

All those things are continually being looked at and updated, but there's no step changes that I see coming. Certainly we have some things we're working on to improve efficiencies.

We've talked about our frac plug drill out, trying to minimize the number of plugs or use plugs that will allow us to get through the drill out process quicker and get our wells turned-in-line sooner. We're continuing to see a decreased number of days per well on the completion side.

And as you can see from our drilling numbers in Monroe County, we've already come down below what we were projecting as far as cycle time. So one thing I will say is we expect those learnings to carry over into Pennsylvania to the deep dry Utica and Pennsylvania and we expect to see significantly improved cycle times over there as well..

Okay. Very helpful. Thank you..

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

Good morning. Couple of quick ones, well maybe not that quick.

But anyway, when will you provide results from your recent Upper Devonian tests?.

When we have production results that we're comfortable with and we've got enough data to providing a sound update..

Okay.

I just wondered if you kind of had a rough idea in mind, would it maybe be third quarter, fourth quarter, something like that?.

Most likely, yes, second half of the year..

Okay. I noticed the five Marcellus wells that had the 60-day rate of 12.5 million cubic feet per day.

I was just wondering, first, how much do you think you might be increasing recoveries or improving present value by choking back those wells? And then secondly is, was this approach special to that pad or that area or is this is pretty typical practice throughout your Pennsylvanian Marcellus production?.

I think the managed pressure approach is becoming more of a common practice as we're bringing pads online and we are seeing a benefit from it. We think we're seeing an EUR uplift. And so it's become more of a standard practice..

Okay. Thank you. And my last question is you have quite a number – you've mentioned this, you have quite a number of passive interests in Utica wells over the course of 2017 and 2018.

I was wondering first, is your decision concerning which wells to invest in, driven exclusively by location or does the operator matter? And do the goals for these wells differ from the Utica wells that you intend to operate in any way?.

We look at everything. I mean it's probably driven more by location and what we aim to learn geologically about the rock. And so we can better identify the Utica boundaries, but we certainly look at each operator as well. But I don't think we would step into a deal with an operator that we didn't have full faith in..

Typically there's an overlap or correlation where the rate of return will be there with the capital investment coupled with where we're interested in acquiring the data because of things like geology that's been brought up..

Okay. Thank you. I appreciate it..

And then we'll go to the line of Jacob Gomolinski-Ekel with Morgan Stanley. Please go ahead..

Hey, guys. Thanks for taking the question.

Just on the sale of the coal business, and the release said, a sale or a spin, so just wanted to understand how you're evaluating each option, a sale versus a spin to shareholders?.

The ultimate metric will be our view taking a look out into the future on what the NAV per share proposition is for each, so those three processes of course offer up different points in time views of how they deliver value back to the ownership and that's the type of assessment that we'll go through.

It's also one of the reasons and drivers why we want to run these in parallel to compare one versus the other. So, an example of a sale, it's a one-time decision and we need to make that assessment off of that one-time valuation. Whereas something like a spin-off is an ongoing view as to what that will do as time progresses.

And we evaluate both of those, along with the third with the continued drops into CNXC and we see which one of those makes the most sense for the ownership as it sits today..

Yeah. Just we want to make sure that we'll look at tax efficiency, the goals of being a pure play E&P company when we come out of it, and allow for enough debt mapping and leverage at both entities so that we have both entities – the outcome where it'll be positive post-display..

Got it.

And then in terms of the leverage ratio, so it sounds like – I mean you would have to get to that – given it's the 2 – 2.5 time requirement for share buybacks, I would imagine something similar for the spin?.

Yes. I mean, I think right now we're on a path irregardless of the separation that we're going to get to that 2.5 times by year-end. And obviously our goal is to generate higher free cash flow to accelerate, and to give us the flexibility that we have all three of our options, including stock buyback to be in there.

With the separation that could accelerate the leverage ratio decline and we'll view that as optionality, and if that's the case then we can execute a stock buyback even sooner..

Thanks. And then just the last question.

In terms of the target leverage ratio, can you just talk about what you think – how you think about it in terms of including or excluding things like the mine closing cost, post-retirement benefits, gas well closing et cetera in the numerator, I get the bank calculation, but in terms of what you think is appropriate in terms of a run rate and sustainable cash structure?.

Yeah. We look at it as in the denominator, so it's in the EBITDA cost already, so that's how we look at it right now and that's how the banks look at it right now too..

Okay. So you just have it in both. Okay.

So the 2.5 times is inclusive of both the liability and the liability service cost?.

Yeah. Well, you wouldn't put the numerator and the denominator. You'd pick one. So you're not double counting. So we count it in the denominator and not in the.....

Always a negative. Sure. Got it. Okay. Okay. That's it for me. Thanks very much..

Welcome..

And we will go to James Spicer with Wells Fargo. Please go ahead..

Yeah. Hi. Good morning.

On the $400 million to $600 million of asset sales, wondering if you could give us a sense at all of timing as to when we might hear some on that, whether you have processes that are already in place? And also what the near-term focus is?.

The asset sales, as you stated, the target is $400 million to $600 million within this year. We do have, as we always do, over the past number of years a bunch of processes in the loop that are running in conjunction with one another.

And just a couple of thoughts there, it's going to be somewhat difficult to time out with specificity month-by-month or quarter-by-quarter, but the expectation should be that you're going to see a significant portions of the $400 million to $600 million occur in the first half of this year, as well as the second half.

And also the types of E&P assets that would be contributing to that would not materially affect our development plans and production plans and activity set within the next three to five years. So I don't think you'll see a material impact with what we have in store on the E&P operational side as a result of these asset sales..

Okay. Great. That's helpful.

And then also just to clarify, your 2 to 2.5 times leverage target, is that on a – that is on a consolidated basis or that's just CNX standalone?.

That is net CNX. So that's excluding the roughly $191 million of net debt that CNXC has..

Okay. Got it. Thank you..

And to the presenters, we have no further questions in queue..

Great. Thank you everyone for joining us this morning. We look forward to speaking with everyone again next quarter. Thank you..

Ladies and gentlemen, that does conclude your conference for today. Thank you for your participation. You may now disconnect..