Tyler Lewis - Director-Investor Relations Nicholas J. DeIuliis - President, Chief Executive Officer & Director David Michael Khani - Chief Financial Officer & Director Timothy C. Dugan - Chief Operating Officer-Exploration & Production James C. Grech - Chief Commercial Officer & Executive VP.

Pavan P. Hoskote - Goldman Sachs & Co. Neal D. Dingmann - SunTrust Robinson Humphrey, Inc. Jeremy R. Sussman - Clarkson Capital Markets Jonathan D. Wolff - Jefferies LLC Holly Barrett Stewart - Scotia Capital (USA), Inc. Evan L. Kurtz - Morgan Stanley & Co. LLC Brandon Blossman - Tudor, Pickering, Holt & Co. Securities, Inc. Michael S. Dudas - Sterne Agee CRT.

Ladies and gentlemen, thank you for standing by and welcome to CONSOL Energy's Third Quarter Earnings Conference Call. As a reminder, today's call is being recorded. I would now like to turn the conference over the Director of Investor Relations, Tyler Lewis. Please go ahead..

Thanks, Ryan, and good morning, 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; Jim Grech, our Chief Commercial Officer; Tim Dugan, our Chief Operating Officer of our E&P Division; Jimmy Brock, our Chief Operating Officer of our Coal Division and Chief Executive Officer of CNX Coal Resources.

Today we'll be discussing our third-quarter results. We have posted slides to our website. As a reminder, any forward-looking statements we make or comments about future expectations are subject to business risk which we have laid out for you in our press release today as well as in our previous SEC filings.

We will begin our call today with prepared remarks by Nick, followed by Dave and then Tim. Jim Grech and Jimmy Brock will then participate in the Q&A portion of the call. With that, let me start the call with you, Nick..

Good morning, everybody, and thanks for joining us. Before we turn it over to Dave Khani I want to provide some general thoughts, highlight a few areas, some of which the team will touch upon in greater detail this morning.

Now back on our second-quarter call we started that by emphasizing the 18-month plan that we are executing in order to weather the current environment. We'd like to reemphasize that 18-month plan because we think it's incredibly important that we take a long view of where we're heading as a company and as an industry.

Those who make the prudent decisions now in terms of controlling expenses and deploying capital and pragmatically managing the balance sheet, they're going to be rewarded in the long run and that's exactly what we're doing. Our 18-month base plan is highly achievable even as we face continued depressed commodity prices.

We will continue to use the proceeds from our asset monetization program to pay down debt. We will continue to grow production on the E&P side while making important progress in terms of capital intensity and efficiency. We will continue to lock in tons and increase our market share in the tightening coal space.

We will continue to drive structural changes that are economically compelling. And in doing these things we will bring forward meaningful value to our shareholders as we unlock the substantial upside that exists with our asset-rich company.

Now let's walk through just a couple of specifics, and some of this you might have heard yesterday on the CNXC earnings call. So from an operational standpoint on the coal side, this quarter we increased efficiency, squeezed costs and, most importantly, we ran safely.

Our ability to do so paid off with the Pennsylvania operations, the coal segments seeing total unit cost reductions this quarter while operating on a reduced work schedule. So that's a very impressive result. Our coal marketing team has done a tremendous job locking in contracted volumes in 2016, 2017 and 2018.

Specifically we've contracted an additional 4.7 million tons for the Pennsylvania operations during the third quarter for full year 2016 so that brings our sold position in 2016 to 74% based on our sales guidance.

Now questions have been raised about our ability to lock in coal contracts in this environment which without question continues to be challenged because of depressed natural gas prices and subsequently depressed thermal prices. So let's put those issues to bed.

We've been consistently executing the thermal marketing strategy that we laid out earlier in the year, and we're demonstrating that our Pennsylvania complex is built to compete and thrive, even under the pressures of low prices and regulatory challenges that have many other operators in the coal industry in a precarious position to say the least.

Plus not only are we seeing success in locking up our tons, but in the process we're also, as I said earlier, taking market share from our competitors. We're entering markets where we hadn't previously participated and in a big way. For instance, we're locking up multiyear commitments with key power plants in the upper Midwest and Southeast regions.

These are areas that historically, as you heard earlier yesterday, have been served by the Illinois basin, Central App producers and Powder River Basin producers. Since our coal is 13,000 BTUs per pound it travels very well. People often forget to take into account BTU adjustments when comparing the different basins.

Not all tons are created equal, and CONSOL has a premium product which is illustrated by our contracting success. We are far from done, so you should continue to expect contracting success moving forward and we should be well over 90% sold for 2016 by the end of this year.

Now additional pushback that CONSOL has heard recently, besides our ability to lock in ton, is questions about what price we're contracting the tons for. The market has been more challenged lately.

You can see this in any public trade publication out there when looking at Northern Appalachian pricing for 13,000 BTU four-pound sulfur coal which is the proxy for our Pennsylvania coal operations. Our contracts vary across customers and depend on a multitude of factors, including where the tons are shipped.

On average, though, we are pricing for newly-contracted 26 tons at market. So some pain at the current market levels today for much gain tomorrow, so to speak.

This is the result of taking market share and solidifying our footprint as the anchor supplier to the largest, most efficient and most environmentally-compliant coal power plants in the PJM and SERC regions.

For 2017 and 2018 we're not pricing the majority of these tons since we believe that we will see natural gas prices recover, which in turn are going to help thermal pricing. Compared to historical norms regarding our contracted position in outer years at this point in the year, we're substantially more contracted when looking at 2017 and 2018.

For the tons that are priced for 2017 and 2018, the curve is in contango, reflecting higher prices and a rebound when compared to 2016 levels. If we shift over to E&P, I'm not going to steal Tim's thunder. He's going to have more to say about this in a minute, but our excitement continues to grow for the dry Utica.

We announced some initial IP rates for our Monroe County pad that has four dry Utica wells and one wet Marcellus well. We expect Monroe County, Ohio to become a much bigger part of our development over the next couple of years.

Last quarter we announced our first dry Utica well in Westmoreland County, Pennsylvania with a 24-hour flow test to sales at 61.4 million cubic feet per day. We're still conducting flow tests on the Gaut well and seeing continued and ongoing positive indications through flowing pressures.

We're more excited about Central Pennsylvania dry Utica today than we were when we reported Gaut's 24-hour flow test results in the second-quarter call. And, again, Tim's going to have more to say on the E&P specifics shortly. On the corporate side I want to briefly touch on asset sales.

During the quarter we put out a range of total value for assets available for sale between $1.55 billion and $2.3 billion.

As we've discussed previously, we're actively engaged in multiple processes in an effort to monetize a portion of that $1.55 billion to $2.3 billion bucket, and we've received pushback or questions in some circles regarding our ability to execute sales in a depressed commodity price environment.

Now these aren't unreasonable questions given the challenges that both the coal and E&P industries are going through, but while they may be reasonable questions, recent deals we've executed gives us the confidence that we have in our plan.

And a case in point is when we recently announced two coal transactions where we received over $100 million which included assets that accounted for about $6 million of expected EBITDA in 2016. So we're executing in this environment and we've be able to command premiums.

Some areas and assets have a higher sales probability than others but we are hard at work to try to bring value forward in order to pay down debt.

We're creating competitive processes and being methodical in order to increase shareholder value, and given the sensitivity around these processes that are underway we're limited in what we can discuss but we'll continue to provide updates as they occur.

So this was an important quarter when you look at moving the needle on our base plan, remain focused on the long-term view and systematically executing that plan. And with that I'm going to turn it over to Dave Khani..

capital needs to be cut harder in 2016. This is why we announced that we would drop rigs on our second-quarter call and manage our drilled and unconnected inventory next year. Capital discipline is now being exerted onto the E&P industry, reversing the last several years of outspending.

The sharp growth in Appalachian gas and NGL production has begun to slow. We expect the backlog of uncompleted wells will be needed to essentially offset the underlying 32% to 35% base PDP production decline rate within the basin. Overall U.S.

natural gas production will flatten and begin to decline next year with associated gas falling and net imports declining with higher exports to Mexico and LNG. This should translate into higher NYMEX, assuming normal weather demand next year.

We see potential for basis differentials to begin tightening into the start of 2017, driven by up to 4.5 Bcf per day of additional takeaway capacity out of the basin as well as slowing supply growth. Year end 2017 looks even better with an additional 9 plus Bcf per day of capacity coming online and incremental demand rising further.

While we expect gas differentials to improve starting later in 2016, we are currently modeling conservative basis differential assumptions in our base case plan of between $0.40 and $0.50 per MMBtu. And, again, we have hedged a considerable amount of this basis.

NGL realizations were also significantly impacted in third quarter from widening basis differentials as compared to Mont Belvieu pricing on the Gulf Coast. We see potential for improvement in NGL realizations on the horizon.

This includes the addition of ethane deliveries on the 70,000 barrel per day Mariner East pipeline in January and the improved regional access to the TETCO pipeline that transports NGL products to the Gulf markets starting in the fourth quarter.

Additional export capacity is also coming online next year on the Gulf Coast and the first wave of new ethylene crackers comes online in 2017.

Furthermore, NGL supply growth will likely slow considerably as current low prices have materially impaired liquid's economics, with NGL extraction often generating a flat-to-negative margin when including processing costs.

While our primary method of managing our liquids risk has been to maintain a balanced approach to our development plans with volumes making up around 10% to 15% of our total production, we have also proactively executed on a limited amount of takeaway options to diversified points of sale.

We have agreements in place with INEOS to export 3,000 barrels a day of ethane starting in January 2016, 4,000 barrels a day of ethane starting in January 2017 and a cumulative 4,000 barrels of day of propane and butane beginning in early 2017.

The INEOS propane and butane shipments will likely represent approximately 25% to 35% of our daily production volumes of those products. While we are not prepared to discuss pricing details, our propane and butane sales agreement is linked to Brent Crude pricing.

We have updated our NGL realization outlook for fiscal year 2015 and fiscal year 2016 to $12 to $13 per barrel and $12 to $14 per barrel, respectively. While we cannot control pricing, our opportunity is posting very strong results in both exceeding production target and driving down unit costs.

Total operating costs including DD&A during the third quarter improved 16% year-over-year and 9% sequentially to $2.63 per Mcfe. This outpaces our 10% to 15% expectation and is a strong result when considering that liquids represented 4% higher production year-over-year.

We continue to expect production costs to fall further next year to $2.52 to $2.65 per Mcfe. Now let's look at the coal operations. During the quarter, the Pennsylvania operations margins expanded year-over-year as improved unit costs more than offset the decline in realization.

Considering that PA operations sold 0.5 million less tons in the current quarter year-over-year, this decrease in cost illustrates a team embracement of the zero-based budgeting effort we underwent. Spot prices for both thermal and met coal have declined throughout the quarter.

We have shipped about 1 million tons of thermal coal into the spot into the quarter and this negatively impacted our realizations. Now, as Nick mentioned, we are making significant strides in contracting our thermal coal portfolio. While we're not finished contracting out, it is important to understand our contracting strategy.

Our goal is to be 90% contracted for 2016 thermal coal tons with multiyear contracts with the highly-efficient (18:33) power plant. The current coal and natural gas market remains oversupplied, negatively impacting realizations.

However, supply response for both coal and natural gas is underway, and the thermal markets are displaying contango pricing into 2017 and 2018 based on some of the contracts we've just signed. However, our goal is to lock in 2016 pricing and keep 2017 and 2018 more open to capture the future market recovery. We expect 2015 U.S.

and NAV coal production to decline about 90 million tons and 14 million tons respectively. According to our analysis and as well as a confirmation from DTC, the NAV market has experienced the largest production cutbacks year-to-date versus the other areas, and this is before we've seen mine closures starting to kick in.

Our Virginia operation's Buchanan mine has more exposure to the international markets. As we've experienced BMA prices ticking down, our average realized prices have followed. To help offset this we continue to focus on increasing our domestic sales mix.

Now all of our costs forecasts are in line with the last quarter and show substantial improvements when looking back over the last several years. For PA operations we continue to expect full-year 2015 total operating costs including DD&A to be between $40 and $43 per ton and Virginia and other operations between $50 and $56 per ton.

Now let's talk about the balance sheet and our liquidity. On the debt side, CONSOL remains committed to managing our balance sheet and improving our liquidity position in what continues to be a very challenging commodity price environment.

As we've previously stated, we will use the proceeds of the $419 million of CNXC IPO and cash proceeds of the recently-announced divestiture to help pay down our credit facility. As a result, our leverage ratio has slightly improved to approximately 3.75 net debt to EBITDA as calculated per our credit facility agreement.

Our goal is to continue to improve this ratio with our base free cash flow plan while accelerating it meaningfully with proceeds from asset divestitures. Our liquidity position remains solid at approximately $855 million at September 30.

In addition, CONSOL holds 12.7 million shares of CNXC limited partner units with a current market value of approximately $160 million, and 19.1 million CNNX limited partner units with a current market value of about $180 million. We've also made significant strides in reducing our off balance sheet liabilities.

You will recall that this has been an ongoing process since 2013 at which time we have proactively addressed our legacy liabilities. We reduced them by nearly $2.8 billion to date and lowered our cash servicing cost by over $250 million.

We now expect legacy liabilities to be approximately $1.5 billion at year-end 2015 with an annual servicing cost for 2016 of approximately $107 million versus $143 million expected for 2015.

As we have said, the decisions that have resulted in these reductions were difficult because they affected our retirees, but they were necessary and prudent to strengthen CONSOL's balance sheet and lower our cost structure to become profitable in this sustained lower commodity price environment.

Now one question we also consistently get and that I would like to address is what would we need to see in order to bring drilling rig activity back early? First, we focus on generating 15% after tax rate of returns for full fueled economics, not single LIRRs.

Now while Monroe and PA Dry Utica might be able to generate these returns in this pricing environment, we want to watch prolonged production a little longer before committing capital. Second, we want to lower our cost of capital, which has risen in this environment and warrants debt pay down to calm both debt and equity holders.

In any case, we are very flexible in how we can adjust our 2016 capital. We'll move it up and down to meet our required thresholds. Some other things to think about in summary. Looking forward we have several things that will positively benefit net income, EBITDA, and cash flow from operations.

We will receive a full year benefits from the continued focus on zero-based budgeting resulting in decreased G&A and operating expenses along with our increased E&P and coal production. And also benefiting cash flow for 2016 will be reduced E&P CapEx, asset sales, legacy liability reductions and reduced financing costs.

So with that I'd like to pass it over to Tim Dugan to talk about some of the E&P side..

Thanks, Dave. I'll provide an update on CONSOL's progress in the Dry Utica and some of the recent successes we've had in the play, which continue to look better each day. First a brief update on the Gaut 4IH well that we announced last quarter and then some new results in Monroe County, Ohio.

As you recall, the Gaut 4IH is located in West Moreland County, Pennsylvania, somewhat at the frontier of the Dry Utica play in Southwestern Pennsylvania and Eastern Ohio. On the second quarter conference call we reported that the well had a 24-hour IP rate of 61.4 million cubic feet a day, with an average flowing pressure of 7,968 pounds.

This outstanding flow rate is the second best IP result in the Utica play to date. We are now about half way through a 65-day multi-rig flow test that we are conducting to determine reservoir deliverability and well drainage, which will aid in future well layouts and pressure draw down management.

Through these tests the Gaut 4I continues to show increasingly strong performance and we have some slides in the investor presentation highlighting the flow tests.

We are currently about half way through the extended flow portion of the test where we are flowing at 20 million cubic feet a day and have seen flowing casing pressure decline by only 350 pounds over the last 10 days.

Preliminary analysis of the data indicates permeability to be in the microdarcy range, which is orders of magnitude better than a typical Marcellus well, and we don't expect to see the extent of the reservoir in this three-week flow period as we had originally thought.

High reservoir pressure, high reservoir deliverability and large reservoir extents make us all very excited about the potential of the Utica in this area.

Sticking with the Utica but moving westward to Monroe County, Ohio, an area which is emerging as a core part of the dry window of the Utica/Point Pleasant, we recently began flowback on our first Utica well on the Switz 6 pad which contains four Utica wells and one Marcellus well.

The first well to flow, the Switz 6D, achieved an average 24-hour IP rate of 44.7 million cubic feet per day at an average pressure of 6,835 pounds. This is an extremely strong result, nearly 40% higher than the prior highest IP reported in Monroe County.

These positive initial results caused us to challenge our prior type curve assumptions for Monroe County, and as a result we've increased our EUR estimates from 2.2 Bcf per thousand feet of lateral to 2.4 Bcf per thousand foot of lateral.

Some of our peers are estimating as high as 2.6 Bcf per thousand foot for offsetting wells so there is the potential for this to move even higher pending additional data. CONSOL has identified an inventory of approximately 40 additional locations in a contiguous block of approximately 13,000 net acres in Monroe County.

We also recently cemented the casing on the 6,100-foot lateral of our GH9 well located on CONSOL-fee acreage in Central Greene County, Pennsylvania, less than four miles from EQT's successful Scotts Run well. This well is scheduled to be fracked in the fourth quarter and we expect it to be turned inline in early 2016.

Perhaps the most important and encouraging recent development in the Utica has been our ability to lower drilling cost, which dropped by 55%, while reducing drilling days by 60% from the first well CONSOL drilled in Monroe County to the fifth.

This confirms our view that drilling and completion costs in the Utica will follow the same downward trend as the Marcellus as we move up the learning curve and demonstrate CONSOL's ability to successfully execute on our cost reduction goals.

CONSOL's Utica drilling experience in Monroe County, Ohio, should serve as an analog for deeper Utica drilling in Pennsylvania and Northern West Virginia and we provide some detail in the presentation as to what buckets those cost savings will come from to get us to our target range of $12 million to $15 million per well in the Pennsylvania Dry Utica and $10 million to $12 million in the Ohio Utica.

In summary we're highly encouraged by the success we have seen in the Utica to date and over the next two to three years expect the Dry Utica to become the primary focus of our development plan and a greater and greater contributor to production growth.

Our increasing productivity per well is enabling us to increase production with less capital and we're finding our prior capital investments are paying greater and greater dividends in terms of production growth and operational improvements.

Cost improvements in the Marcellus in addition to the strong potential of the Utica play are lowering our required break-even realized price and increasing our IRRs and NAV.

While there may be some fear in the market regarding the impact of Utica production on gas prices with the potential of structurally lowering the threshold price for development, we are relatively agnostic to that potential impact due to the fact that we have over 600,000 net prospective acres for the Utica/Point Pleasant.

Furthermore, if the Utica truly does move the cross-curve down within the basin and across all plays in the U.S., logic indicates that Utica development will displace other higher cost developments and not be additive. With that, I'd like to turn it back to Tyler..

Thanks, Tim.

And Ryan, at this time can you please open the call for questions?.

Okay. Our first question comes from Pavan Hoskote with Goldman Sachs. Please go ahead..

Thanks a lot. Good morning, everyone..

Good morning..

A couple of questions on the cost structure to start with. Now on the E&P side, you break out unit production costs, transportation costs and taxes but when we reconcile these costs with the E&P cash costs that you report on your income statement we typically see additional costs per quarter of about $50 million per quarter.

Can you talk a little bit about the nature of these costs and whether we should expect a reduction going forward? And then on the coal side there seems to be a pretty significant reduction in costs quarter-on-quarter.

Can you talk about whether that is circular or one time?.

Okay. So the $50 million of additional costs some of that would be in unused FT. That would be in some of the compensation plans that we have as well and we could provide a breakout for you if you like further offline..

Yeah, Pavan, there's a couple line items, the corporate expense line item which has un-utilized FT in it. There's also the G&A. We provide a breakout for those line items in our guidance in our investor deck now..

Got it. And then on the coal side, there was a pretty significant reduction quarter-on-quarter.

Is that something we should assume going forward, or what are some one-time items in there?.

Those were part of the cost reduction effort that we have undertaken. I think we've mentioned that we went through a head count reduction. We've also spent a lot of time with our suppliers. And we've found some ways to debottleneck and get better production..

Got it. And then, an unrelated question on E&P CapEx. It's still very early days to talk about 2017 and lots of moving pieces between now and then.

But big picture, can you talk about how you expect 2017 CapEx to trend with the 2016, given that unlike in 2016, you will not have the benefit of a backlog reduction in 2017?.

That is correct. We won't have the drilled uncompleted wells, but we will have the dry Utica and the impact of it to help us here. So and I think what we've done is we've created the ability to go on to existing pads and start to drill either Marcellus or Utica wells and bring them on within three to four months.

So we don't need a long lag time to do it. So the question comes down to what's the capital intensity of our dry Utica program versus effectively our either wet Marcellus, dry Marcellus and wet Utica. If the capital intensity comes down, then we can effectively dial up the capital to some level to solve for some production growth rate.

And that'll be a function of what kind of rate of return we're looking at, what the commodity price will do and what we're trying to solve for..

Got it. Thanks a lot..

Our next question comes from the line of Neal Dingmann with SunTrust. Please go ahead..

Good morning, gentlemen. Say, Nick or David, quick question on the asset sales. I'm looking and to me, your liquidity appears actually quite decent, I mean, around $1 billion or so. But I've heard some others say – definitely some numbers they throw out on what you – their thoughts on what you have to raise here in the near term or further out.

Just any color you could add. I know you've got a number of packages out there. Your thoughts on either what you think or what you'd like to sort of sell on an asset value either near term or a little bit into 2016..

I think that the first thing to keep in mind is that if you look at the plan between now and year-end 2016, our plan that we've communicated is an organic free cash flow plan. Meaning that it's exclusive – it's a free cash flow plan exclusive of asset sales that we're talking about here.

So the asset sales would be additive and, again, the use of proceeds there would go towards liquidity and debt. Now with respect to the magnitude, timing and specifics, we purposely didn't want to say much there because of the sensitivity of where they're at other than to say we've got 30 of these processes running, give or take, concurrently.

So there's, again, a collection of assets that could statistically hit at different points in time.

And, Dave, if you want to add some thoughts to that?.

Sure. So from a liquidity standpoint, I think we're almost -we're exactly where we want to be. From a leverage ratio, our goal is to be down in the three range or lower. And so the asset sales will effectively help us solve for how we get there. So it depends on if we sell all non-generating-EBITDA assets. We could get there with a certain number.

If we sell some generating-EBITDA assets, we'll need a little bit higher because we'll lose some EBITDA. So we're trying to solve for effectively liquidity and leverage ratio. And as Nick said, we have lots of processes going on of which we've got a lot of competition on each asset and we have competition between each asset.

And we'll execute on the ones we think are the best ones and there are going to be times when we pull things back because we think that the value isn't what we're going to get..

No. And, guys, Nick, that's a great point that the free cash flow is exclusive of that. Let me ask on that free cash flow kind of assumptions around that, I guess particularly with what's going on. I think I've got you a little over 30% hedged.

What are you assuming for prices, either coal or gas, when you're looking at that assumption? Or anything you can say around your assumptions to base on that free cash flow?.

Yeah. So we give you – in the slide deck we'll give you the – we give you a lot of the line itemized so you can go in there. And we made some adjustments for a little bit of the basis and/or the realizations on some of the liquids. For the coal side, we're almost 75% locked up.

For the E&P side, we're actually about – on the gas side we're about 68% to 70% roughly and growing. And so we're almost there on where we want to be on the gas side and we've layered on a bunch of basis hedges. So we really are for the most part locked in on the revenue side with a little bit more to go.

And I don't know if, Jim, you wanted to add anything to it..

I would like to add on the coal contracting side, both Nick and Dave had said in their comments that we're in that 74% range contracted right now and we do expect to be at 90%-plus by the end of the year and we're on path to do that. So we will be locking in those sales on the coal side by the end of the year.

And the hedging, as David said, we're very close to where we want to be as far as getting all of the basis hedges in place along with the NYMEX hedges that we already have..

Okay.

And then the last question, if I could, just Nick, maybe for Tim, after this – I thought it was a tremendous result in Monroe and then obviously the result you've had – I think the Gaut well speaks for itself – how are you going to attack the Utica dry gas? Or just the Utica in general next year, given sort of the massive acreage that you all have? That's all I have.

Thanks..

Generally, and Tim can follow up with some details here, but generally we really see, I'll call it, three to four promising areas of dry Utica. One of course is Central Pennsylvania which is Gaut. There's over 100,000 acres that we control in the dry Utica up in that range.

And this flow data and test data will tell us more and more about what to expect from well profiles. The second of course is Monroe. We've always been excited about Monroe, frankly, just because of what the geology told us and what also the other third-party well data were indicating. And this is better than that.

So I feel good about that, and that's of course a 100% controlled area. We quoted a number of locations, that's an opportunity there to not just have stack pays but to control the pace of activity and production growth for the next two to three years.

And then the third and fourth areas are, of course, Greene County, PA, with our GH well that's coming in in January, as Tim said. Coupled with what we've got going on with opportunity on the dry Utica in the panhandle of West Virginia.

Noble, our partner on the Marcellus side, will be looking at a JV Utica well result coming online at some point soon, which will give us some indications there.

So amongst those four sub-areas of the dry Utica, we think we've got very promising, rate of return-driven capital deployment opportunities compared to what we've got within the existing portfolio. And as Dave said earlier, we'll be rate of return driven.

And we'll take the NYMEX forward curves, we'll look at what the well profiles are shaping up to be coming off of those test data.

And last but not least we will have to demonstrate and put in a reasonable drilling and complete cost, and Tim talked about the accomplishments and what we've achieved on drilling complete costs just within Monroe County to date, getting down to that, those targets of $12.5 million to $15 million in PA and $10 million to $12 million in Eastern Ohio.

You couple all of those together, the geology, the drilling complete costs and the forwards, we think we've got those four areas that give us a lot of opportunity to measure activity level and measure production growth rate over different gas price regimes.

Tim?.

Yeah. I think as Nick said we are – just as we did in the Marcellus, we are developing a broad list of opportunities in the Utica. And I think nothing really speaks to that more than the Gaut well.

It's in an area that most others didn't put much credibility up there, to the quality of the wells that we would see, but it says a lot about – that well says a lot about our geologic and technical staff, our engineering staff. The tests we're doing are confirming the results we saw. The initial IP of 61.4 million.

This well looks stronger and stronger the further into the test we get and we're just really – we're confirming what our technical staff told us we would find and it's going to turn out to be a huge opportunity. Everybody knows about Greene County, I think, because of some of the results that have been advertised from our peers.

Monroe County, there's additional data points and as Nick said in the panhandle of West Virginia we've got a new data point coming there shortly. So we're excited about it. We think it gives us a lot of different opportunities to drill some very successful and good rate of return wells..

Thanks for all the details, guys..

Our next question comes from the line of Jeremy Sussman with Clarkson. Please go ahead..

Yes. Thanks very much for taking my question. I guess, first, you talked about being free cash flow positive next year. Obviously E&P CapEx coming down is a big year-over-year delta.

So I guess, first, can you remind us what level of asset sale proceeds you assume in that number, and then, second, maybe go though some of the more specific productivity initiatives that you're undertaking on coal or gas? Thank you..

Sure. So, Jeremy, I think before what we said in the second quarter was that we would need somewhere between $75 million and $125 million to generate free cash flow end sum.

What we're saying today is with all the things that we've done in locking in revenue and taking costs out, we will be free cash flow neutral in the fourth quarter and we will be free cash flow positive in 2016 with zero asset sales and zero dropdowns..

Got you. Okay, that's helpful. And maybe just changing gears, David, we've seen a couple of coal bankruptcies the past quarter so obviously these have been high-cost met coal producers but at the same time you've divested a lot of coal assets and legacy liabilities over the past couple of years.

I guess what I'm getting at is, for argument's sake, if there are further bankruptcies in this space, is there a risk that some of these liabilities could flow back through CONSOL or do you feel pretty comfortable about where you stand today? Thank you very much..

Jeremy, it's a good question and we've been getting it too so thanks for asking this question on the call and hopefully we can put it to bed.

We have received a bunch of enquiries about the possibility of legacy liabilities from Murray Energy coming back to CONSOL, and you will recall that in December 2013 CONSOL sold the subsidiary of, to Murray Energy, the stock of CONSOL's Consolidated Coal Company subsidiary and other subsidiaries that had held certain UMWA pension, retiring, medical and other liabilities.

The transaction was structured as a sale of stock of these subsidiaries. CONSOL and Murray Energy exchanged fair value in that transaction with CONSOL receiving $850 million of cash for the stock of CCC.

The subsidiaries of those stock that CONSOL sold were generating sufficient cash that satisfied the liabilities and those liabilities remain the liabilities of those subsidiaries, so what I'm saying is we think it's really unlikely that those liabilities will come back to CONSOL and we are fairly confident..

Great. Thank you very much..

You're welcome..

Next question comes from the line of Jon Wolff with Jefferies. Please go ahead..

Good morning, guys..

Morning..

Just looking at the handout on the Gaut well in Westmoreland, obviously it came off a big peak which is expected.

I'm just trying to understand from the 20 million a day or so that you're producing now, the 25 to 30 psi drawdown per day, does that keep the well relatively flat at a plateau level until you reach line pressure or do we expect declines, sort of ratable declines?.

Well we're still in the middle of our test and the pressure decline is getting shallower and shallower each day. In the last 24 hours it dropped about 28 pounds so pressures are remaining higher than what we had originally anticipated.

We're not going to reach radial flow through this flow period, but we'll be able to take that data and extrapolate and make some estimates, but we're halfway through the flow period so I don't think we're ready to talk about what we think that well's going to do but we certainly expect that it's going to flow at a stable rate for some period of time.

But I don't know that we're ready to say that it's going to do that for three months, six months, nine months..

Right.

Can you tell us what the initial pressure psi was and where we are today?.

We're still over 9,000 pounds. I believe we were at about 9,100 pounds today and we started out after the extended shut-in period where we were installing our production equipment, we were just under 10,000 pounds, about 9,940..

Okay.

So from a linear standpoint if I take 25 psi to 30 psi per day, that's suggests like a seven, eight-month plateau and the line pressure is – what? – 500 or 1,000?.

I guess that's the – that would – your math. That's your math, yes..

Okay.

I guess what I'm trying to ask is does the plateau rate, do you stay relatively close to the plateau rate until you hit line pressure? Or are there declines expected, some amount of declines?.

Well, you know our technical team is analyzing all the data. At some point, yeah, it's got to decline. I don't think we're going to hold it at 20 million or 30 million a day until we hit line pressure, but we're not ready to say how long we think that, that flat rate is going to hold. But it will be a managed pressure decline.

That's the reason we're doing this testing. We want to understand the extent of the reservoir.

This is going to give us more information to help us design our fracture, our simulation times on the next wells more optimally, and also understand the unilateral spacing between wells and understand the drawdown of pressures as we produce these wells further and further..

Okay. And last one on that, obviously you're trying to monetize assets quickly. Not a lot of drilling rigs, or no drilling rigs running.

Do you think about putting a little more activity here to try to solve this one more quickly? Or is it better to just watch the well for a while?.

I think the data will tell us much more than throwing additional capital on the learning curve. I think the data will give us the learning curve that we need.

And you get into sort of the first, second quarter of 2016, we should be sitting in a position where we've got an order of magnitude more confidence in which of those four sub-areas of the dry Utica we want to look towards when you get into 2017 and beyond on production growth, and to what extent those activity levels are warranted.

So we're able to get the data and the insight and learning curve that we need based off of the test program for the dry Utica that we've already laid out and we're watching the data on currently..

I mean if you think about it, we'll have seven data points to look at, probably more than anybody else in the industry. So we should get to a pretty fast decision point.

And that's why we put a band around the capital number of $400 million to $500 million, so we give ourselves the flexibility if we want to add back activity based on the Utica results we can do it..

Okay.

In Ohio on the Hess JV, are there no rigs running? Anything completing? And I believe the (48:08) is done now? Is that accurate?.

(48:15) is pretty much exhausted, and I think we pretty much have stopped activity as well. It's not economic really to want to drill wet wells today..

Got it. Thank you..

You're welcome..

And our next question comes from the line of Holly Stewart with Scotia Howard Weil. Please go ahead..

Morning, gentlemen.

A couple of questions, first what was driving the production beat for the quarter? And then maybe an extension upon that would be are you still expecting the same amount of ducks as you head into 2016?.

Well, I think the production improvements this year are two-fold. One is just timing of getting some wells online and the quality of those wells. We're seeing, continuing to see better results than what we had anticipated.

And the other big factor is some of our midstream de-bottlenecking projects with the loop line we're laying in North Nineveh has contributed significantly. We've had an additional tap we've put on a NFG line and we've been able to take advantage of some interruptible volumes there.

And those two combined have contributed to the majority of the production growth..

So same kind of expectation for the number of ducks heading into 2016?.

Yeah. If anything we could actually have a little bit more if we wanted to manage that production growth rate..

Okay.

And then maybe along the same lines is, do you have much in the 20% growth number for the Dry Utica for next year?.

Just the seven wells that we are drilling this year that some will be coming on at different points over the next several months..

Okay.

And then my last question would be you made me think on the INEOS contract, are you currently in ethane rejection or extraction mode?.

We're the, Holly, we're in a majority ethane rejection. We have a very small amount of extraction going on right now..

Okay.

So the INEOS contract would put you into extraction?.

That's correct. Yes. We would....

Okay.

Sorry?.

That's correct. Yes..

Okay. And I lied. One final question if I could, is there much on the midstream side at this point? I know you've got $50 million of CapEx in next year's budget for additional midstream.

Is there much left at the CONSOL level to drop into CONE?.

Well, yes. We have EBITDA outside of the anchor system, which we have only 75% in. We have EBITDA in the additional and growth system, which is only 5% inside the MLP. So 95% is owned by the sponsors. So there is, yes, there is a lot of dropdown inventory..

Okay. Great. Thanks, guys..

You're welcome..

Our next question comes from the line of Evan Kurtz with Morgan Stanley. Please go ahead..

Hey. Good morning, guys. Just a question on Hess. I guess it was a headline that hit Bloomberg a little over a week ago or so that maybe they would be looking to exit the JV.

Would you – I know you kind of consider that core acreage, but would you consider exiting with them or is there a – do you have a right of first refusal, would you actually buy their stake? Is that something you're looking at?.

Yeah, you know, we don't comment on specific assets so it's hard for us to answer that question. So just know we have multiple processes going on and when we feel ready to announce something, we'll announce a sale..

Okay..

Right..

And then maybe just an update on domestic met contracts.

How are those shaping up for next year?.

Evan, in our domestic contracting front, we're going to probably see an approximate doubling of the tons that we put on the domestic market year-over-year from 2015 to 2016.

We're probably in the range of 20%, give or take, domestic tons this year and we expect to be in the 40% to maybe mid to upper 40% range by the time we're done with our contracting for 2016, which we're in the middle of right now..

Does it feel – is it too early to say whether it will be down $10 a ton or $20 a ton or where's it shaking out?.

Yeah, Evan, right now since we're right in the middle of the contracting, I really don't want to comment on pricing. But domestic prices are giving us better margins, better overall prices, than export pricing and so that's why we've turned our focus to getting more domestic tons.

And again when you follow this happening in the domestic metallurgical coal markets and the weakness of a lot of the suppliers, it's giving us more opportunities. So that's why we're building our position domestically.

But, again, since we're in the middle of the contracting right now, I really don't want to get into talking about any type of pricing..

Okay. I understand. And then maybe just one final one, if I may. If you look at your priced tons for next year versus this year and just the delta – I'm sorry, the priced tons versus what you had this quarter versus last quarter for next year and just kind of run the math on the delta, it was pretty low. It was like $27, a little over $27.

And I know there's always a lot of moving pieces and things shifting in and out that make that number fairly questionable, but could you give a sense of what those tons are priced at for next year..

Well, Evan, first off, you're right that the pricing that you have there is very questionable. When you take the changes that go across the whole portfolio, because on the base tons we have changes that occur with them as well.

And you put all the changes just on what appears to be incremental tons, you have a skewing of the data and you get the averages – what looks like an average sales price is really something that is not indicative at all as to what we're selling the coal for.

So with that said, we go to a lot of different markets, Evan, metallurgical, thermal and in various regions, the Midwest, the Southeast, Northeast, and so the pricing is different across all those markets.

I'd just say in general we're selling – if you see the indices that are out there, you know the 13,000 four-pounds, those types of pricing that you see in those market indicators is generally what we're realizing for our pricing as well..

Okay. Great. I'll turn it over. Thank you..

You're welcome..

And our next question comes from the line of Brandon Blossman with Tudor Pickering Holt. Please go ahead..

Good morning, guys..

Good morning..

Hey, Brandon..

Just looking for any incremental color on how basis moves over the next two or three quarters? And kind of specifically with (55:40) now commercial, does that change your realization picture? And the narrowing of basis that you're projecting, is that a seasonal trade? Or is that related to some incremental infrastructure coming online?.

Well, Brandon, the basis we do have with our portfolio for next year, we've got about 47% to 50% of the portfolio covered, NYMEX and basis. So let's just say we have approximately half of our portfolio covered basis-wise for next year and we're working on increasing that percentage every day, looking to increase it.

So for the half that is exposed to market, it varies greatly by season with the different sales points that we have. And for example in the first quarter of next year, we're probably looking flat to negative $0.10 type of basis.

And then as you get into the middle of the year we're into the $0.55 to $0.65 negative basis, and then get to the end of the year and you're in a negative $0.40 basis. So it varies by time of year.

So in that half of the book that we have exposed, overall average basis would probably be in the negative $0.40 to negative $0.50 for the year for the total book that we have out there..

And if you look out at the forward curve and what it implies, that $0.40 to $0.50 will start to go down into the $0.30 range, just using the strip, although the strip's very liquid..

And again, Evan (sic) [Brandon], that's on our total book, hedged and unhedged. You put that together and you're going to get those basis ranges that I just laid out for you..

That's helpful.

And then what's the – any color available on the current FT resale market? Are they buying or selling?.

We've had some good success so far on the resale market. In the release, we referenced $4.3 million of release capacity. We expect by the end of the year to at least double that if not improve on that slightly more before the end of the year with some deals that we have going on right now..

Okay.

And any color on what term? Is that just short term?.

Yes, Brandon. It's all very short term type of release sales that we're doing..

All right, thank you for that.

And then, second question – I'm not going to ask about particular asset sales, but any color from you guys' perspective, in terms of what the A&D market looks like for raw acreage in the basin?.

Constantly changing, and more a function of what's the new data coming in, is looking like across different horizons, as well as geographic locations...versus what pricing will do. Pricing's, I think, less of a driver on the valuations, versus data, and geology, and well results..

Okay. So sounds like maybe some potential good news there. Thank you, guys. Appreciate it..

You're welcome..

And, due to time, our final question will come from the line of Michael Dudas, with Sterne Agee. Please go ahead..

Let me big picture here for Nick, or the panel. Given where net gas prices are, and coal prices are, it seems like we're reliving the winter of 2011 and 2012.

How better positioned, or different, is CONSOL to weather and recover from this environment than it was three years ago? It's certainly not being reflected by what the stock prices is reflecting in the near term here, despite everybody's doom and gloom on energy prices..

Mike, it's a little bit of two different stories on the coal and E&P sectors. On the E&P sector, I think Dave mentioned that we're seeing activity levels and capital expenditure levels starting to finally shift within a rationalized level of activity, and capital expenditures that reflect that quantity..

Good..

So we're starting to see those responses, as we speak. On the coal side, a little bit of a different situation, where – from our perspective, we've seen, within the United States, a significant and a permanent shift of market share on the generation grid from coal, to natural gas.

And that significant and permanent shift is going to require a significant, permanent supply response – emphasis on both significant and permanent. And we've seen some of that.

I think we're going to see a lot more of that as time goes on so that's more of a fundamental change that we're watching the fallout occur as we speak versus E&P more your traditional activity level responding to pricing forwards..

Perfect.

And the follow-up is looking at your potential on dropdowns for coal in 2016, any thoughts of visibility relative to the performance and how you guys are thinking about it given the current environment?.

Yeah. I would just say we modeled in a 20% drop every year as sort of a base way to do it, but I would say we also created a lot of flexibility, timing and sizing and ability of how to finance it so there's a lot of ways in which we can do this. We'll watch and see and figure out how we want to drop it in but know that we think about that every week..

Excellent. Thanks, gentlemen..

You're welcome..

Great. Thank you. Thank you, everyone. This concludes our third quarter earnings call. Thank you all for joining..

Ladies and gentlemen, as you heard, that does conclude today's call. I want to thank you for your participation. You may now disconnect..