CNX Resources Corp (CNX) 2016 Q3 法說會逐字稿

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

Thanks Jon, and good morning to everybody. Welcome to CONSOL Energy's third-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 will be discussing our third-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 have laid out for you in our press release today as well as in our previous Securities and Exchange Commission filings.

Related to our recently announced transaction to separate our joint venture with Noble Energy, CONSOL Energy is unable to provide a reconciliation of projected incremental EBITDA resulting from the agreement to projected operating income, the most comparable financial measure, calculated in accordance with GAAP due to the unknown effect of timing and potential significance of certain income statement items.

Also during the quarter, we made certain adjustments to the financial statements. With the sale of the Buchanan, Miller Creek and FOLA mines, which all now reside in discontinued operations, our coal segment is now only comprised of Pennsylvania mining operations. Our Baltimore terminal, any remaining idle mines, water operations, legacy liabilities, and various other nonoperating corporate items now reside in miscellaneous operating expenses.

Short-term compensation and stock-based compensation now reside in SG&A across the E&P, coal and other segments. E&P maintains another corporate expense line item which now includes items such as unutilized FT and idle rig fees. To reflect these changes, we have recast historic income statements that can be found on the Investor Relations portion of CONSOL Energy's website under Supplemental Table.

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. With that, let me turn the call over to you, Nick.

Thanks and hello everybody. I'm going to be brief this morning, but I would like to focus my time today providing some general high-level commentary on the highlights of the quarter. And also before passing it over to Dave Khani, I'd like to talk about how the philosophical and cultural changes we've implemented here at CONSOL have helped us weather the downturn and put us in the position where we are today, which I believe is a turning point for the Company.

To start, CONSOL Energy had a strong quarter highlighted by the Company benefiting from many of the areas that we have been focused on over the past year. Specifically, we created a plan last year with the goal of maximizing free cash flow and using this cash to delever our balance sheet. This quarter, we again posted a strong organic free cash flow of approximately $103 million, which is our third consecutive quarter of successful generating free cash flow. Year-to-date we have generated total free cash flow of around $608 million, and we have used our free cash flow to continue to pay down debt and improve our liquidity position, which is increased to $1.4 billion at the end of the third quarter.

We remain focused on further delevering the balance sheet to set up the Company to successfully split the coal and E&P segments. Our primary avenues of accomplishments remains through our subsidiary, CNX Coal Resources, or CNXC. In this quarter, we took another step towards separating the businesses by completing an additional 5% drop into CNXC.

Now, stated by CNXC on yesterday's earnings call, they are seeing improvements in the domestic thermal, international thermal, and international high vol metallurgical coal markets. Not only does this bode well for CNXC with their current shipments and contracting progress over the next three years, but even more importantly, this continues to help set the stage to support drops of additional interest into CNXC looking into the future. That ultimately supports our goal to separate of course the businesses.

Speaking of cultural changes, I mentioned at the outset, over the course of the past two years, CONSOL has instilled what I will call a startup mentality into a 152-year-old institution by reinventing itself as an agile data-driven premier natural gas company with a steadfast commitment to the prudent allocation of cash. The CONSOL culture places an emphasis on conservatism and modesty and focuses on our two most important constituencies, which are our employees and our shareholders. Now what does that culture look like in action?

We've reduced annual expenses, including legacy liabilities and G&A, corporate expenses by approximately $300 million compared to 2012. Recently, we monetized the naming rights of CONSOL Energy Center, home of the Pittsburgh Penguins, which is going to provide us with significant long-term cost savings. We believe that we have best-in-class governance practices with a focus on prudent capital allocation. And some other changes include naming an independent board chairman, and we have changed the executive compensation structure to more directly align with shareholder interests. All of these actions, and many more that I won't mention here, they ultimately result in CONSOL derisking and strengthening our Company and our balance sheet, again focus placed squarely on actions that align with employees' and the shareholders' interests.

When we look back on the last few years, it's been quite a remarkable time in our history. We transformed and streamlined our operational focus. We've divested over $5 billion in coal assets and created a vehicle to own and operate the best thermal coal complex in the world. We've assembled a vast E&P footprint with the best stack pay opportunity set in the Basin. We've separated the Marcellus joint venture, unlocking new opportunities across that footprint. And we've transformed our balance sheet and our corporate culture. All of this was done in the midst of an epic market downturn.

Most importantly, the approach and the culture we have built is not going to retreat as markets continue to improve. This is going to be the new normal for CONSOL Energy.

Now Dave Khani is going to discuss the quarter in more detail.

Thanks Nick and good morning everyone. As highlighted in our press release this morning, and indicated on Slide 24, CONSOL reported third-quarter GAAP net income of $25 million attributable to CONSOL Energy shareholders.

On a GAAP basis, earnings included two main pretax items attributable to continuing operations which totaled approximately $164 million. First, we had a $160 million unrealized mark to market gain on our commodity derivatives instruments. And second, we had a $4 million total pension settlement and other expenses. After adjusting for these items, CONSOL posted an adjusted net loss from continuing operations of $36 million, or negative $0.15 per share, and adjusted EBITDA of $156 million.

More importantly, we generated free cash flow in the quarter. We generated organic free cash flow of $103 million, as Nick stated, and year-to-date total free cash flow of $608 million. Our organic free cash flow in the quarter increased despite E&P capital expenditures increasing to $64 million from $38 million, reflecting the restarting of drilling capital in August.

For E&P production and highlighted on Slide 26, the E&P division finished the quarter with production of 96.4 Bcfe. During the quarter, we had 1.5 Bcfe of [out-of-purity] adjustments. We have very few turn in lines in the quarter, and this highlights our low natural base decline rate within our portfolio.

For the fourth quarter, we have six Green Hill wells coming online -- actually have just been turned online. And with yesterday's announcement of the separation of our Marcellus joint venture, we increased our 2016 E&P production forecast of 390 to 390 Bcfe, or about 20% growth for the year.

On the cost side, we had another solid quarter with total all-in and cash costs of $2.36 and $1.31 per Mcfe respectively, which is near the upper end of our guidance range. With the 1.5 Bcfe negative production adjustment that I just referenced, our costs would have been about $0.02 lower. Our Marcellus and Utica cash costs declined year-over-year to $1.35 and $0.88 per Mcfe respectively. We expect our total unit costs to decline in the fourth quarter.

In the quarter, our average realized sales price was $2.54 per Mcfe, which includes a negative basis adjustment, BTU uplift, modest ethane sales into Europe, and the benefits from our hedge position. We continue to implement our program and hedge layering process for hedges out through 2020. As noted in Slide 22, we have added 52 Bcf of NYMEX hedges and 142 Bcf of basis hedges through this process. As a result, our basis hedges now closely match our NYMEX book. While this creates more certainty on our margins, this also protects our borrowing base and our liquidity. As of 10-25-2016, our hedge book was about $29 million to the positive.

While we've been adding programmatic hedges, we remain bullish on the commodities and are still nicely positioned to capitalize on it. We can capture rising markets through our open positions, our netback power contracts and through additional asset sales. Looking at a forward curve, our hedge book and are operating cost structure, we anticipate our E&P margins will rise sequentially into the fourth quarter of 2016.

Now we'll talk about coal. CNXC reported third-quarter earnings last night and posted solid results despite encountering geological issues at its Enlow Fork mine. As they discussed, realized coal prices increased 9%, which was in line with their previously stated guidance given last quarter.

More importantly, the Company signed a higher price coal contract for 2017 as domestic and international thermal and met prices have increased significantly. CNXC is now expecting coal realization to be up 5% to 10% over 2016 average realizations.

As for capital, the E&P division is still tracking to stay within our guidance range of $190 million to $205 million, but given some of the movement within our drilling and completions schedules, we will likely be at the higher end of the range. We are striving to be the best capital allocators and we are very focused on our highest rate of return projects.

With our recent announcement and with the separation of our Marcellus joint venture with Noble, we are still in the capital budgeting process for 2017 and expect Noble board approvals in December. That said, this is how we are thinking about our capital allocation for next year. First, we will rank all our project areas to drill the highest rate of return projects based on our asset assessment ranking process that we've refined over the last 18 months. Included in this assessment is our wet and dry DUCs that we have higher rate of returns based on Sun Capital. We will then decide how much capital we will add based on the ability to spend it efficiently to capture margin appropriately, which will include hedging.

Second, we will put this through our (inaudible) per share filter to compare rates of return for drilling versus buyback of debt and stock. Then we will overlay our risk parameters and our strategic goals of splitting our Company. In the end, we expect to grow production and still generate free cash flow.

On Slides 27 and 28, we talk about our liquidity and balance sheet. Year-to-date, CONSOL has paid down approximately $600 million of debt and almost doubled our liquidity to $1.4 billion. During the quarter, our pro forma trailing 12-month bank leverage ratio remains about 3.7 times.

Yesterday, I mentioned some of the immediate credit enhancing benefits associated with our agreement to separate the Marcellus joint venture with Noble. Through receiving approximately $205 million in cash along with the incremental annualized EBITDA of around $55 million, we expect the net debt to EBITDA ratio to get reduced by about 0.6 turns. With the recent agreement, we have more clarity and confidence in reaching our leverage goals, achieving a sub-3 times leverage ratio by year-end 2017, and we expect to achieve this through further cost-cutting initiatives, selling additional assets, growing production, reducing capital intensity, and capturing the normalization of commodity prices.

Now, we are currently in our fall redetermination process with our banks and we expect to complete this in November. We are requesting that our lenders reaffirm our Company's $2 billion borrowing base, and we expect that it will get reaffirmed.

So let me summarize now before I turn it over to Tim. We are executing our base free cash flow plan and continuing to monitor and challenging our cost structure. We are focused on spending our stakeholders' capital judiciously. Now, this is our base plan, and as you can see, we are not comfortable accepting the status quo. Our leverage ratio, which is really our last balance sheet metric that needed to be improved, will be our target before year-end 2017.

While the investment community is looking for upside in our company, I'll point out that our top-tier asset base has significant upside. We have proved this with our recent coal transactions, and now with the monetization of our carry.

Let me pass this over to Tim now.

Thanks Dave and good morning everyone. Since this was the first quarter that since we've added back drilling activity from when we made the decision to lay down all of our rigs back in mid-2015, I'd like to focus my remarks on providing some operational updates and highlights.

As stated last quarter, with the combination of strong summer weather, a slowing inventory build and rig counts remaining below levels needed to maintain flat production in our region and across the US, we've seen 2017 NYMEX driven higher, which has in part played a role in our decision to add back modest activity.

We added back two rigs in August, which started drilling dry Utica wells in CONSOL's 100% owned acreage in Monroe County, Ohio. In the quarter, we drilled two wells at an average lateral length of approximately 8,600 feet, and after the close of the quarter, we TDed a third well. Over the course of these three wells, our drilling costs and days to drill improved to levels that exceeded our original expectations which we previously stated last quarter.

Specifically, last quarter, we talked about drilling cost goals of $1,060 per foot of lateral. Over the course of the first two wells, our drilling costs improved to $1,040 per foot of lateral and our costs further improved on the third well to $950 per foot of lateral.

As for the days to drill, our original expectation was 26 days spud to TD, which was accomplished on the second well. On the third well, we exceeded this goal by three days. These are great accomplishments by our team and they nicely illustrate that not only did we pick up where we left off a year ago, but we are exceeding our goals as our rapid rate of improvement continues. In fact, we utilized our reduced activity over the course of the second half of 2015 and the first half of 2016 to refine our database and model-centric approach that we take towards development. These things help explain why CONSOL has remained consistently excited about the dry Utica.

We've remained consistently optimistic on the dry Utica because we are confident in our industry-leading team and engineering work compared to other Appalachian operators who have wavered each quarter, creating confusion in the marketplace with inconsistent views. With each new data point that we add to our model, we get a stronger picture of how the reservoir changes across the Basin. With over 112 wells and 32 producers now in our earth model, we have a clearer picture allowing us to rank each specific field on reservoir potential and create a development plan around it. We continue to improve our visibility of Utica control and we will continue to be the company that delineates the dry Utica through the drill bit and nonoperated participation opportunities.

Another modeling example that has helped CONSOL continue refining its program and improve capital efficiency has to do with how we are completing our wells. In the days of Propageddon, we are seeing some operators that are pumping extreme amounts of proppant in their completions. We have noticed in our production results that there exist differences in regards to completion designs and what works from area to area, and sometimes field to field. If we can establish from our model that there is negligible production benefit from pumping 3,000 pounds per foot of proppant compared to 2,500 pounds per foot of proppant, we could ultimately save six figures and shorten the learning curve by not having to pump that 3,000 pound per foot test in a well. If we are able to make these decisions through a modeling simulator versus a field test, we are able to be more efficient and ultimately save money.

So, despite extreme proppant loading getting some attention these days, especially as of the last two quarters, CONSOL has been pumping a lot of sand for quite some time. But again, this is based on modeling work that our team has done for each specific area.

In summary, CONSOL is taking a more methodical approach to our completions and using our data set, along with modeling capabilities, to drive our completion designs and ultimately NAV. You can see these results in our latest Green Hill Marcellus wells that we have brought online where we've moved our type curve to 3.6 to 3.8 Bcf per 1,000 foot of lateral from our previous results of 3.0 to 3.5 Bcf per 1,000 foot of lateral, with some wells' performance exceeding 5 Bcf per 1,000 foot of lateral.

Our modeling work has helped us to find the recipe for Marcellus completions, and we expect to do the same in the Utica. We believe that we have the largest data set across the industry in terms of Utica dry wells. As a result, this has driven our confidence as we have built out an earth model and corresponding heat map of the Utica play. Through these data points, we are able to understand how the reservoir characteristics change across the Basin and how they relate to reservoir productivity. This is the same methodology that we used to drill the Gaut well in Westmoreland County, which continues to be the second-best Utica well in the Basin and has cumulatively produced over 6 Bcf to date. Many thought the Gaut well was a fluke. And in fact, that well was no fluke, but instead it was good, solid engineering and geology work, and we expect to replicate those results as we look forward and the Utica continues to evolve.

With that, I'll turn it over to Tyler.

Thanks Tim. Jon, if you could please open up the line for questions at this time.

(Operator Instructions). Holly Stewart, Scotia Howard Weil.

Good morning gentlemen. Maybe first question, Tim, you mentioned that your improvements in the Green Hill area and maybe the changes or differences in completion design. Can you maybe just talk about the proppant loading and kind of what you're doing in that area specifically that's driving this improvement?

It really stems from all the modeling work we've done and proppant loading is a big part of it but it's also we are looking at the sequencing of the wells, looking at our unbounded wells versus our interior wells and how we treat one versus the other. And just our completion designs are becoming more and more custom to each individual pad in each area.

Okay. Can you specifically identify how big that area is?

We've got our fields broken down into -- we look at our fields. We've got it broken down into AOI, and we continue as we go through our asset assessment, which is just an ongoing project, those areas are continually redefined as we get more and more data, and we add that data into our model. We adjust our AOIs. They can be as small as 5,000 acres and they can be as large as 20,000 or 30,000 acres. It just depends on what geology tells us, how the reservoir characteristics change across that area. So, we will see varying sizes of AOIs or areas of interest.

Okay. And maybe as my follow-up, you guys mentioned ethane recovery in the quarter was a pretty big jump sequentially. You've referenced a project. Can you give us some details on that project? I'm assuming you're moving volume now on that project in Mariner East, if I remember correctly.

Yes, we did -- we started sales through Mariner East back in April, but we did see an increase in our NGLs this quarter. A lot of that -- we had some gas which term is lean or damp guess that we move from a dry outlet back to our Majorsville so that we could recover the ethane, and then we had some spot sales for the quarter as well. So, our NGL volumes were up this quarter.

CONE Midstream has the ability to move sort of the quasi-wet gas in periods when it is uneconomic to a dry system, and back and forth. So that's the flexibility of the CONE system.

Great. Thanks guys.

Neal Dingmann, SunTrust.

On one of your old slides -- maybe Tim, a question for you -- you mentioned in the press release today about having the Monroe County Utica wells being among or the best returns you have out there. I'm trying to look. I'm looking at one of your older presentations here. It shows about 622,000 net potential Utica acres. One, is that still kind of mostly accurate? And then if so, these high returns you are referring to around Monroe, does that consist of the bulk of that? I know some of that is in that deeper Utica area, so I'm just trying to sort of diverge the two but then trying to figure out how much you guys are classifying in that sort of Monroe bucket.

The 622,000 acres covers our entire footprint -- Ohio, West Virginia and Pennsylvania. Monroe, when we look at our Sun costs and our opportunities, Monroe does provide right now the highest rate of return. Because we have moved into more of a development mode there, we are now -- got two rigs out there drilling pad development. So we are able to quickly take advantage of learnings. And that's why we've been able to get our days and costs down even further. But we've got -- we will be drilling in Monroe County here for the next year or two pretty steadily. But when we look at that 622,000 acres, a lot of it resides in Pennsylvania and northern West Virginia as far as Utica potential.

Again, Tim, could you also talk about -- I want to make sure I have this correct -- the DUC inventory as it sort of sits today and where you see it at the end of this year and how you will attack it next year?

Sure. With the agreement that we announced yesterday, we walked out of that agreement with 53 DUCs, Marcellus DUCs. We've got two wells -- we will have two wells at the end of the year that will I guess technically not be DUCs; they will be completed waiting to be turned in line. So essentially 55 Marcellus wells at the end of the year that essentially are DUCs. And then we've got 15 additional DUCs that are Utica wells. 10 of those we own a 100% interest in. Those are the wells we are drilling right now in Monroe County. So, we are looking at year-end numbers we will have 70 DUCs.

And the, next year, as we are putting our plan together, we've got to put it in front of our board here in the next month or so for approval, but it will involve quite a few of those DUCs where we add those to our list of opportunities and look at them from a rate of return standpoint, and we will blend those into our plan for next year, but there will be more details about that in our analyst day in December.

Okay. And then just lastly, over on the coal exports, I think David Khani was mentioning have you certainly seen a nice pick-up in coal prices all around. Is it fair to say return maybe back to more of a normalized level next year, meaning you would have less exports than what you've had in the last year or two, and likely a bit better pricing?

Yes, I think that's fair. I think we have a fairly contracted book into next year. And I think the export number for this last quarter was about 10%. And if you looked at the export number in the first two quarters, it was around 25% or 30%. Some of that was because of the local demand, the weather was very weak, and so it was more of a push. Today, the export market is pulling coal out of the US, and so it will be somewhere -- it will probably be somewhere in the middle.

Very good. Thank you all.

Jon Wolff, Jefferies.

Good morning. Could you go through the DUC benefit heading into next year similar to how you explained it about a year ago in terms of pre-spend capital and how that will help you is one question?

Last year, we gave a number of how much capital we had sunk in there and how much capital we need to spend. I think Tim yesterday mentioned that, on average, we will need about $4 million per well to complete the well. So, you can do the math on the roughly 70-ish wells (multiple speakers) roughly 280, maybe a little less because not all of it is 100% owned.

And to get to that goal of at least growing next year, is that enough on its own, that level of DUC conversion?

Yes. If you think about what we've put online this year, it was in the upper 40s, so here you're talking about a higher number because these are will be more 100% owned. So, yes, those would be enough to grow our production.

Got it. And on the Fracapalooza or Fracageddon, the determining factor of how much sand seems to be the right mixture, does it have to do with actual fracturing, the thickness of the reservoir, other factors that you'd care to share in your learnings?

It's reservoir thickness. It's well spacing. It spacing to adjacent pads. It's a lot of different factors. But the well spacing, lateral spacing and reservoir thickness are probably two of the bigger components. So, there is certainly a benefit to more sand, but there's also a limit to how much sand you need to pump to get that benefit and maintain the economic benefit.

Got it. The Baltimore port, can you update us on how active a shipment area that is for you and third parties? Is that a core asset? Is it something that could be -- I guess everything could be sold at the right price, but any thoughts on that?

The terminal is now being operated, managed as I'll call it a standalone business unit. So what that means is there's not just the ongoing relationships that we've seen historically with the Pennsylvania mining complex, with some of our partners like XCoal but also third-party volumes that are going to the terminal and people know now that it's open for business. So our expectations when you look at the cash flows or the EBITDA of contribution to the terminal would represent, especially with some of the tailwinds that we are seeing in the coal markets, that the CNXC team talked about yesterday on the export side, it should have some pretty promising days in front of it. Where it sits and where it ultimately resides, looking at the terminal, there's obviously an argument to be made that it should reside with CNXC because of its relationship with the Pennsylvania mining complex and how one feeds off the other. And I'm sure there's also the avenue of third parties showing interest in a terminal as well. So that's under the diversified business unit segment that we've got within the Company. And the job number one is to make sure that we are maximizing the EBITDA and NAV of the asset, obviously safely and compliantly, and while we are doing that, where is the proposition with respect to the terminal if you look at things like CNXC and future drops or third-party divestitures.

Just to give you a little bit more color too, right now I think we'll probably see somewhere around 8.5 million tons of coal exported out of the facility that has the capacity of about 15 million tons. So if this trend continues on export, then you could expect that number to go up for next year.

Got it. The last one on CONSOL's smaller net footprint, is the coal thing local to Pittsburgh area, or is it a lot of exporting being exported?

Both, domestic as well as export. There's domestic opportunities with the met crossover of the nature of the Bailey product, and there's also obvious export opportunities. Those both, interestingly, should grow over time because of what the quality trends are doing at the Pennsylvania mining complex with the sulfur dropping. So, there's also some inherent I think advantages or opportunities that they have on the CNXC team that this should bode well for getting more opportunities of the Bailey product marketed as a crossover met.

I think, from a domestic standpoint, we always talk about targeting the must run power plants. And obviously they are looking to maximize price domestically. One of the key things they have done is be able to ship to those plants that have basically a flat basis to natural gas to Nymex so that we can deal with avoiding kind of the impact of power prices within the Basin as much as we can.

It makes sense. Thank you.

Jeffrey Campbell, Tuohy Brothers.

Good morning. I noticed on Slide 11 that the entirety of the West Virginia DUCs are operated. Can you add some color on where the drilling was concentrated, and how that acreage might rank order as you start to look at allocating 2017 capital?

A lot of the DUCs in West Virginia are DUCs that, through our agreement yesterday, just moved over to us, just transferred over to us. So, they will -- we will look at how we're going to incorporate those into our 2017 plan. But there is also we have some additional drilling potential down there as well. In fact, when you look at wet gas development potential between the Pittsburgh International Airport and the area in West Virginia that is now operated by us, that's where really the majority of that wet gas drilling potential exists. So, you know, again, we are putting our plan together for next year and we will roll that out at our analyst day in December, but that will likely certainly get a strong look, and have an impact on our percentage of wet for 2017 as well.

I'll just add I was curious about it both on the success that you've had that you've brought out in the last quarter selling ethane, and also the strength that we've seen in propane prices recently.

And on the theme of West Virginia, you may have already answered it, but thinking about your reference to further asset sales, I was wondering what your outlook might be for West Virginia considering it is wet, but it's also not very proximal to the majority of your acreage in PA. I wonder if that really matters or not.

The geology, the rate of returns tied to geology marketing, obviously capital investments, etc., are favorable for the areas of interest within West Virginia that we are retaining 100% of. And under the asset monetization process, once again, just like all the other monetization areas that we consider we are going to be very clinical about that, we will see what the market might support when it comes to interest in those assets versus what we think we can extract value from on an NAV per share basis by developing it internally. And if there is a window where that first metric exceeds the second metric, then we will transact. And if there is not, we won't. So, it's definitely something that's obviously in the asset base with the rest of the acreage position that we control with a big inventory. It will be considered as both a development and a monetization candidate and we'll just do the math to see which one makes the most sense.

And now that we have the flexibility to sell the whole stack pay independent of the JV, we have now probably more opportunity down the road to do so.

Thanks. I appreciate that. The last one, I just was listening to your description of the modeling. If I understood it correctly, you're talking about modeling completions on a computer before you actually go out and drill in some instances. I was just wondering. Does well control -- you mentioned geology are your other -- I was wondering if well control is of much use in this modeling. Because when we think about the Gaut, there probably wasn't a lot of well control for drilling a Utica well where you did. So, I was just wondering. Is that also an important variable or is this pretty much geologically based?

The earth model is geologically based. The earth model feeds our frac model, which then in turn ends up feeding our production model, our weight transient analysis. But certainly we keep adding data points to get more and more control. We had enough data points when we drilled the Gaut to have the confidence to drill the well out there when many questioned it. But again, we got what we expected up there. We are really pleased with the results but we were not shocked by the results. So we had enough control to give us the confidence to go up there and drill that well.

Okay, great. Thank you. I appreciate it.

James Spicer, Wells Fargo.

Good morning. You touched on this a little bit in your prepared remarks, but I'm just wondering if you could comment a little bit further on timing of potential additional coal drop-downs given the recovery and pricing there.

Sure. The approach is going to be the same we've applied since CNXC was IPOed probably just over a year and a half ago. And that's one where we will look primarily first and foremost at the CNXC team to see if they see an opportunity for what we would call an accretive drop of a certain percentage interest of the Pennsylvania mining complex into CNXC. If that's there and that occurs and on our side of the fence, the CONSOL Energy side, we think that's a fair evaluation marker that it would represent, then we are likely to proceed with that type of an opportunity.

In the end, I think the theme is one of what's good for CNXC is typically going to be good for CONSOL Energy and its shareholders, and we just need to make sure we are balancing the valuations and the short-term dynamics of those opportunity windows for drops when they pop up. But so far through what has been looking back over the last year and a half, a very chaotic time within the market for coal, natural gas, power, etc., we were able to use that approach I think quite efficiently, and looking now forward with more stabilized markets, I think that process will bode very well for both parties moving forward.

Okay, I appreciate that. And secondly, just a clarification comment. The 5 million cubic feet a day bump in production guidance, is that -- actually sorry, I guess that's Bcfe, bump in production guidance. Is that taking your 85 million cubic feet a day of incremental production from the dissolution of the JV, and just pro rata taking that from the effective data on October 1? Is that what you're doing?

It is both the result of the production we picked up from the exchange agreement and the continued improvements that we are seeing in our overall production, our base production.

So if you take the 85 million and you turn it into Bcfe, it gets you about 8 Bcf of the 10. So that's 80% of it is the acquisition, about 20% of it is productivity improvements.

Okay, makes sense. Thank you.

(Operator Instructions). Jon Wolff, Jefferies.

Another quick one on post the Noble deal, the amount of royalty interests you own in Pennsylvania and I guess West Virginia, Ohio --

Fee acreage?

The fee acreage, yes.

Overall our overall NOI has really not changed with this deal, so there's not really a big change in what -- the acres that we -- that moved over into Noble's operated area. We didn't give up much in the way of fee acreage. We've looked at that. Our NRI, our HPP percentages have remained essentially unchanged.

Okay. And you probably won't want to answer this, but, on CONE, how strategic does it become given the split and maybe you doing a little bit less wet gas I would think?

CONE you're saying strategic for us or (multiple speakers)?

Yes, for you.

We kind of are the operator of CONE, so we've kind of developed CONE, and I think CONE right now is important to us. So, we see -- continue to grow CONE and continue to go towards the GP split. So I think, right now, we feel very good. If you look at the acreage that we now operate, I think we've got the flexibility when the market dictates to take advantage of wet gas. We've got plenty of acreage that we can develop that is wet.

Got it. Can you give us a little on the GP splits and when they kind of kick in?

Yes. So, last quarter, not this quarter but last quarter, we started to get into the second split. And so if we continue on -- and then we grew the distribution another annualized 15%, which we declared about a week ago. If we continue on the same pace, we will be into the next split I think within the next three or so quarters. So, it's almost I think almost every year if you continue on the pace, that's the math. So --

Yes, got it. Makes sense. That's it. Thanks.

Lucas Pipes, FBR.

Good morning everybody. I wanted to ask a follow-up question on the coal business. And specifically as it relates to CNXC, that entity had great performance year-to-date, had a great rebound on the back of higher coal prices, both domestically and internationally. The distribution has been reinstated for all unitholders. In terms of additional drop-downs from CNX to CNXC, what is holding you back at this point?

The math that I sort of walked through a couple minutes ago on a prior question, that's the process we use. We will look for what I would call an entry window from the CNXC side where they see an opportunity to acquire an additional ownership stake in the Pennsylvania mining complex. We will look at it from our end on an NAV per share valuation basis. If there is a line, that's a go. I think the two things that drive that, one that drives the math and the calculation itself right now. If you look at CNXC, with their efficiency and operating cost metrics have been have been stellar since they have been public. So really it comes down to coal pricing that has gotten a lot better, as you mentioned, with our release yesterday. So there's increasing chances for those equations and that math to line out the way we want it.

The second thing are the markets, the capital markets. Can the capital markets support what I would call the financing of that acquisition or that drop. And that's something I think is changing as we speak, obviously, starting from a very low basis where the capital markets have effectively been shut down for the coal space for a long time, and now it looks like things are starting to warm up.

So we are interested to see what the CNXC team comes up with, both on pricing and those views, coupled with what they obviously disclosed at the close of market yesterday and what the capital markets will support to provide what I will call financing for those drops to occur.

That's very helpful. I appreciate that. And maybe a quick one, and I apologize if this has been asked before. But I recall that, when you sold Buchanan, there was a little bit of a kind of call option on higher met coal prices. Could you all remind us what a $200 met coal benchmark price could mean on that metric? Thank you.

So, it's a good question. Yes, we built into the sale of Buchanan a kicker, a met kicker, if met coal prices were to rise. And so basically, for every dollar over a realized $75 buying price for export tons, CONSOL will get $0.20 on that dollar. And so we are probably expecting that it will probably kick in this quarter because of the sharp rise that we saw in the benchmark price. What the math will be from $200 net to the mine, it could be just say anywhere between $100 and $150, somewhere in there. If you wanted to take the middle point of $125 at the mine, $125 minus $75 is $50. $50 times some portion of the 4 million to 5 million tons that it will produce, we'll go export probably 50% to 75% of that, so let's say 3 million tons. You can do the math on 3 million tons times 20% times $50 a ton, and you can get to some number that could be pretty meaningful to CONSOL if the price holds up.

That's great color. Thank you very much for taking my questions.

Holly Stewart, Scotia Howard Weil.

Just another quick follow-up or two. Dave, it might be actually too early to know this, but I was just looking at the LCs that are outstanding. With the Noble agreement changing, do you know how that ultimately is going to change your postings?

It shouldn't change too much at all. And you know, we've been working on ways to actually bring those LCs down, so -- and I think, as our credit actually might improve, we might have the ability to take some of those LCs down.

Okay, great. And then just one final one, I think the deck mentioned the second plugless completion test. Any color there that you guys can provide that you are seeing so far?

We don't have a lot of data back on that yet, but haven't seen anything yet to give us any negative thoughts on it. We think that, the plugless completions, that's probably one of the next big steps in really reducing our overall capital costs from a drilling and completion standpoint. So it was -- the job was successfully executed, and as we get more production results, we will roll them out.

Great. Thanks guys.

And that will conclude the Q&A session. I'll turn it back to the Company for closing comments.

Thanks Jon. Thank you, everyone, for joining this morning. We look forward to speaking with you next quarter. Thank you.

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