CNX Resources Corp (CNX) 2014 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the CONSOL Energy second-quarter 2014 results conference call. (Operator Instructions)

As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Vice President of Investor Relations, Mr. Dan Zajdel. Please go ahead.

Thank you, Greg, and good morning to everybody. Welcome to CONSOL Energy's second-quarter conference call. We have in the room today Nicholas DeIuliis, our President and CEO; David Khani, our Chief Financial Officer; Jim Grech, our Chief Commercial Officer; and Tim Dugan, our COO of E&P.

Today we will be discussing our second-quarter results. Any forward-looking statements we make or comments about future expectations are subject to business risks, which we have laid out for you in our press release today as well as in our previous SEC filings. We also have slides available on the website for this call.

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

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

Thanks, Dan. Good morning. Dave Khani is going to cover our quarterly results and detail in a few minutes, but before that, I wanted to highlight a couple of major points on the quarter; and, more importantly, where we are heading into the second half of 2014 and when you look beyond 2014.

And I will start with the E&P segment and how we are executing on our plan so far this year within E&P. Our momentum -- it continues to build. That momentum is being illustrated many different ways across our gas operations. You can see qualitative accomplishments that show the E&P momentum. The best example is probably the Utica results from our Noble County wells that we discuss in our operations release.

So for the first time, we are seeing that Utica play began to grow and supplement our already sizable Marcellus position. And when you flip over to the Marcellus, we are seeing the benefits of the Lean manufacturing approach everywhere we look -- from asset team structures, where subfields within the Marcellus compete for capital due to drilling efficiencies on both top holes and horizontals; to improved logistics, when you look at rig mobilizations and demobilizations; to much more efficient completion jobs that utilize the advanced completion techniques of SSL and RCS.

And the second-quarter quantitative results -- they also show this building E&P momentum as well. Production for the overall E&P segment in the quarter came in on target, and we are optimistic enough looking into the rest of 2014 to raise the lower end of our production guidance range, where it now sits at 225 to 235 Bcf. And our Marcellus total all-in cost came in under $3.00. And the cash costs for the Marcellus came in under $2.00.

So when you couple these qualitative accomplishments of the blossoming Utica play; Lean manufacturing in the Marcellus; and you put those with the quantitative results, and when you look at things like production and Marcellus costs, those two things combined show the much-anticipated economies of scale which are starting to appear in the E&P segment in total -- the total cost dropping and margins increasing. That is really good indicators for the shareholders when it comes to returns and NAV per share.

And you should expect more of that for the second half of 2014 as our production continues to grow in the third and fourth quarters. And all of this is affirmation of our commitment to the 30% annual production growth rate for the E&P segment for the next three years.

Now, when you look over to the coal segment, you see the same type of momentum. In the Pennsylvania operations, our three coal mine, five longwall complex. It fought through geology issues at Enlow Fork and equipment issues at the Harvey mine, and it delivered on our production targets for the quarter.

Thermal cash costs and total cost were significantly lower than those for second quarter of 2013, which continues the trend we saw in the first quarter of 2014, where the thermal costs were lower than the year prior.

Our marketing effort for our Bailey coal brand is being very well received by the customers. We are tactically executing term business with those much-run power plants that we talk about that sit in our core market regions, and we are doing that for the next three years.

When you couple this marketing strategy and the deals that go with it with the production levels and cost structure we have been posting through 2014, you see that our thermal segment is poised to continue to deliver free cash flow for the remainder of this year and beyond.

And when you look at the met side at Buchanan, we continue to drive down unit costs. And we are doing that despite decreasing production volumes, because we have got a very challenging market. And Buchanan remains an earnings and cash flow contributor while we are riding out the market trough; and most importantly, we are poised and prepped to return Buchanan to its historical production levels when the market rebounds.

So beyond E&P and beyond coal, our momentum also continues to build across all those other areas within CONSOL. And we have a number of projects in process for monetization of non-core assets that includes potential sale of 1 billion tons of Illinois Basin coal.

The MLP for our midstream Marcellus asset is on schedule. We expect a market event sometime late summer, early fall this year.

And our debt structure continues to evolve to a much improved position, when one looks at everything from rates, to covenant flexibility, to access to a wider creditor capital pool.

The effort on unlocking value for shareholders beyond the E&P and coal segment is only going to continue to grow. While we have teams focused today on executing the Illinois Basin coal reserves and Marcellus midstream MLP event, we also have teams developing the next series of opportunities to unlock NAV per share outside of core E&P and coal.

And examples of these types of opportunities that are being developed in the lab, so to speak -- they range from additional sale opportunities for non-core assets beyond the Illinois Basin coal assets to structural opportunities tied to our sizable fee ownership positions in both coal and natural gas.

And we increasingly think of all this other as the third segment of CONSOL that supplements E&P and coal. And we see just as much potential in this other segment as we do in natural gas and coal. The march towards additional opportunities beyond the Illinois Basin and midstream MLP continues, and that march is part of our everyday processes. It is an exciting proposition for the team in CONSOL.

Now, I want to include, before I turn this over to Dave Khani, with picking up on the key theme of where we left off during our June analyst conference -- and that is the issue of NAV per share driving our decision-making when it comes to operating cash flow deployment.

The biggest areas where management can make a difference in value creation for the shareholders is by efficient execution, of course; and then also by putting operating cash flow to work in the right places at the right times. So what does that mean?

That means in addition to all the things that we just talked about -- from growing gas production, and reducing coal costs, and maximizing gas and coal unit revenues -- we also need to really lock in on how we choose to allocate operating cash flows. There's only five possibilities for allocating the cash flow. There's capital expenditures, of course, that is tied to organic growth; there's dividends; there's deleveraging; there's share count reduction and M&A.

And management understands that which of these we choose and when we choose them -- those things are critical and make a huge difference for a company as asset-rich as CONSOL. We see tremendous opportunity for cash flow allocation to increase NAV per share, especially if we efficiently execute our strategy and plans like we've been doing.

And right now, we view ourselves to be in a race. We execute our plans, there is going to be a time in the not-so-distant future where CONSOL Energy in total becomes free cash flow positive. When that time comes, new options are going to be placed on the table for NAV per share accretion. That is great news, but we also recognize that time is money, and that is where the rates aspect comes in.

So every performance improvement that we make beyond our base plans, every revenue source that we are able to develop beyond our base plan, and every balance sheet opportunity we grab a hold of beyond our base plan -- those things move the needle forward to a point in time sooner where CONSOL Energy is free cash flow positive. That also, of course, moves forward the point in time where additional NAV per share options become available. So time is of the essence, and it is a great time to be at CONSOL Energy.

With that, I am going to turn it over to Dave Khani for more detail on our quarter.

Thank you, Nick, and good morning. Today I will provide a quick overview of the quarter, compare our results to our stated goals noted at our analyst day, and provide insight into our results to help you model our Company. We have posted an updated slide deck on our website. My prepared comments will tie to slides 10 through 16 and several slides within the financial section on pages 154 to 180.

So onto the results. CONSOL Energy posted a net loss for the second quarter of 2014 of $25 million or a loss of $0.11 per share compared to a $13 million loss or $0.05 per share a year ago. Included in this in the second quarter were the impact of several transactions, including the early extinguishment of the 2017 maturity bonds, the new credit facility, the pension settlement, and partially offset by a coal contract buyout.

In total, these transactions reduced our net income by $41 million or $0.18 per diluted share. So if you back out -- the adjusted net income excluding these transactions were $16 million or $0.07 per diluted share and also includes the impact of raising our 2014 effective tax rate in this quarter from 21% from 19%. This caused us to have a tax rate to look unusual for the quarter.

Our 2Q 2014 adjusted EBITDA and operating cash flow totaled $246 million and $221 million, respectively. Now, in mid-June we hosted a very productive analyst day, where we focused on improving returns, lowering the capital intensity of our business, and improving our cost of capital. Specifically, we provided some key targets in many different areas, and I would like to provide a snapshot of where we are at the end of the quarter.

First, on production: we are modestly ahead of our E&P production target of 30%, achieving 34% over the year-ago quarter. We lowered the lower end of the production target, as Nick noted earlier. And our confidence in the second half as well as our future outlook for 2015 and 2016 continues. In essence, we are on pace to meet or exceed this target.

Second, improving recycle ratio: now, this ties to our improving E&P margins, which expanded by about 45% to $1.00 per Mcfe. We achieved this through our continued mix shift to our lower-cost Marcellus as well as the rise in our liquids production.

Third, on coal: cash flow generation of our coal business is on track for the $800 million annual goal, despite not running at full utilization in the quarter.

Fourth, reducing our VAR. We have contracted a meaningful percentage of our open coal position and layered on some additional program and active hedges on our open natural gas volumes. Our goal is to protect cash flow, capture upside when available while reducing our VAR. For our 2015 position, our monthly VAR has now declined about 10% to 6.3%.

Fifth, lowering our cost of capital. So on June 18, we closed our $2 billion revolver, which respectively lowered our interest rate and our annual expenses. And this morning we announced a partial tender of our 2020 maturity debt that has an 8.25% coupon and adding on to our 2022 maturity paper, which has a lower coupon.

Sixth: cash flow neutrality goals. For the first half of the year, our cash declined about $180 million down to $147 million. For the second half of the year, we have the potential to become cash flow positive. We have started to achieve this based upon both of our businesses generating higher in operating cash flows, having a modest decrease in the second-half CapEx, having additional non-core asset sales, receipt of additional carry over the first half, as well as having the IPO of our Marcellus gathering system.

Now, let me take a look at the quarter in more detail. In our E&P division, production was a record at 51.9 Bcfe. As stated earlier, it is 34% higher than the second quarter, but also 7% higher sequentially. Unit pricing was unchanged at around $4.44 per Mcfe versus the year-ago period. We recognized hedging losses of about $0.13 and an uplift from our liquids production of about $0.34.

Liquids production represented 5% of our E&P volumes and about 12% of our E&P revenues. We expect liquids production to continue to rise throughout the year and grow between 5% and 8% of our overall volumes. This represents our growing Marcellus and Utica production.

I would also like to call everybody's attention to our realized gas price for the quarter. Within the earnings release we have increased our hedging disclosure to show the pipelines where we have hedged our basis. This disclosure should enable you to estimate our future average realized prices when combined with the percentage of our 2014 sales that we expect to ship on each pipeline. This data is located within the marketing section on page 116.

Now, the flexibility to ship on multiple big pipelines combined with our hedging program helps us maximize our netbacks. Again, in this second quarter, we posted the highest netback among the large Marcellus peers that have announced to date.

Now, while our average realized gas price was essentially flat, our unit gas margins improved to $0.45 to $1.00 per Mcfe, because we were very successful as well as lowering our unit costs. I remind you that we expect unit costs to decline between 5% and 10% per year over the next three years. This quarter, unit cost declined about 5% overall and 8% or $0.24 for our Marcellus production. Our all-in Marcellus Shale cost came in at $2.94, with the cash portion coming in around $1.75. We also saw nice declines across our other areas of Utica and our conventional production.

Specific to drilling and completion activities, we continue to make progress on the cost efficiencies that we illustrated at our analyst day. We highlighted some of these efficiency improvements in our quarterly operation update a couple of weeks ago, such as increases in stages per completed day and decreasing the number of days to move the rigs. In all, for both drilling and completion we remain on track to realize our targets of a 15% decrease in costs through 2015.

Now let's look at our coal division. Overall, coal had a good quarter as we achieved the midpoint of our production guidance range. As we throttle up our Harvey mine and get past some of the geological issues at Enlow, we expect production and unit costs to improve as we get into the fourth quarter.

As we are in a maintenance mode for the coal division, cash flow generation remains the key metric. In the second quarter the coal division generated $179 million of cash, essentially flat year over year and a slight decline from our first quarter. So through the first half of the year, the active coal division generated nearly $400 million of cash.

Now, our coal marketing team has made substantial progress, as Nick has highlighted, in locking up 2014 and 2016 volumes as we target those must-run plants post-MATS. Having our Tier 1 coal portfolio is a key differentiator to provide stability in cash flows and minimizing our value at risk revenues.

Corporate and other: we have several initiatives in place within our supply chain group to streamline our coal and gas vendor groups, standardize our processes, and reduce our inventory levels. We have talked about this several quarters. We are now beginning to see the fruits of these efforts initially impacting our working capital, but we expect it to translate into several of tens of millions of dollars of both capital and lower operating expenses.

Capital: we expect to spend about -- I'm sorry. We spent about $305 million on our E&P business in the second quarter and about $570 million in the first half in total. For coal, we spent $63 million in the second quarter and about $250 million in the first half. Unless we acquire additional land, we expect our second-half capital to run modestly below the first half.

For liquidity: we maintain strong liquidity at $1.9 billion, down slightly from the $2.1 billion at the start of the year. We expect to maintain this level of liquidity through the remainder of the year. With this and improving cash flow, our credit metrics continue to meaningfully improve each quarter.

So in summary, our liquidity, strong asset base, intense focus to drive improving returns, and measured growth should enable us to improve our net asset value per share through this relatively weak natural gas and coal environment. As Nick highlighted earlier, this management team is very focused on driving net asset value per share. And we have the asset base, the process, and the team to take care of both our debt and equity stakeholders.

With that, I will open it up to questions.

Greg, would you please instruct the callers on how to queue up for questions, please?

(Operator Instructions) Neil Mehta, Goldman Sachs.

Can you talk a little bit about gas basis? Where did it -- what was the number for the second quarter? And how has it been trending in the third quarter? And more importantly -- and I know you have provided some updated disclosures here on some of the slides, like 117 --what are you doing to mitigate this risk?

In the second quarter our basis ran on average in the negative mid-40s. I don't have the exact number for you, but to give you a range, of $0.44 to $0.47.

And looking forward at the pricing for the third and fourth quarters, you have the basis, but you also have the gas strip price; you have got the liquids uplift; and you have our hedge impact. So when you put all four of those components together in the pricing, and we forecast out using today's market prices, we have about a 3% to 5% variance from what we posted in the second quarter looking out into both the third and fourth quarter. Again, Neil, take into account gas price, hedge impact, basis, and liquids uplift. So you put all those together, and we are in that 3% to 5% range.

Perfect. And our expectation is natural gas prices will rally back well above $4.00. But if we stay below $4.00 for three consecutive months, the carry is temporarily shut off. Can you talk about, in that scenario, how that would impact your 30% production target? And if you are committed to that 30% growth rate, is it fair to assume that you wouldn't have to issue equity to achieve that?

The 30% three-year production ramp is something that we are definitely committed to. We feel that is the quickest and highest accretion to NAV per share that we can do with our operating cash flow currently -- which, of course, is driven by Marcellus and Utica. So that is a constant with or without the carry or sub-$4.00/north-of-$4.00 gas price.

On the idea or concept of issuing equity, right now looking at the NAV per share decision tree, the thought of issuing equity is something that is not attractive in the least to us at any point in the foreseeable future. So that is an option that -- if it's got a ranking, it's got to be last, if it even has a ranking. In terms of the specifics on managing through carry and the rest of the year, I can turn it over to Dave for a little more detail.

Yes. When we set the 30% production target, we tried to find that middle ground where we could live with the volatility of gas pricing as well as factor in the improving rates of return, either through uplift of EUR or declining costs per well. So we tried to find that middle ground.

And we clearly have the asset base and the ability to grow at a much faster clip, but we wanted to have that measured growth so that we don't have to jerk our program up and down, like we did in 2012. That wasn't helpful for us. We missed out on the learning curve and some of the cost efficiencies. So we are going to try to be very consistent looking out.

I think the other thing to think about is we measure our rates of return not on sort of a quarter or annual basis; we are looking at probably more of a three-year kind of period to what generates most of our NAV per well.

Perfect. And last question for me is: can you talk through the potential for monetizing some of your mineral rights for both gas and for coal, as you have seen some of your peers have done? Is that in the opportunity set as you think about restructuring and capital allocation?

Yes. We are studying it intensely right now, and it is in our opportunity set. And the question is how do we best monetize it. Because we have -- we are effectively a 150-year-old company sitting with a fairly sizable fee position in coal and a pretty meaningful position in gas.

Great. Thanks, guys.

Brandon Blossman, Tudor, Pickering, Holt.

Did I hear a slight change in the color around the MLP? It sounds like an IPO is definite go versus what you had talked about as a possibility in the analyst day?

Are you talking about for our gathering system?

Yes.

Yes, we have actually made a very definitive statement at the analyst day that we were going to IPO. And we filed a document, an S-1 document, which we will probably make public some point in August. So we are all going ahead.

Okay. Good. Utica results -- pretty impressive results released in the ops update. Can you give some color around how those results match up to your type curves that you laid out in the analyst day? And what's your expectations around those type curves on a go-forward basis?

This is Tim Dugan. I think they match up fairly well. We are pleased. The liquids production is higher than what we had originally anticipated.

So these are strong wells. We have got them flowing now, and they are holding pressure very well. We have got the next strip of wells out in Noble County scheduled to come on this week. We will have two wells on our Noble 30 pad coming on by the end of this week and one on our Noble 16 pad. So we should see some increases in production. But we are excited about the results that we've seen -- the first three Noble 19 wells averaging 23 million cubic feet a day with their equivalents with their initial rates.

So fair to say that you are biased upward against your type curves currently?

Yep, they look very strong. So yes.

All right. Thank you.

Caleb Dorfman, Simmons & Company.

I guess first question is sort of a follow-up on one of the previous questions. With the potential for gas prices remaining soft throughout 2014 and into 2015, do you think that you would alter your drilling emphasis within the Marcellus more to Southwest PA, where the rates of return are higher, and away from central PA and northern West Virginia?

I think, looking again at the three-year 30% ramp, there is a drill plan behind it, of course, that has got contributions across these different subfields. The asset team structure that Tim's team had put together looked to that very issue. But if there are shifts, they will be marginal shifts within those subfields, and it will still equate to a 30% annual production ramp.

Okay. Then a question for Jim Grech. Obviously, basis differentials are an issue on the gas side of business, but it also seems like they could be an issue on the coal side of the business. Have you heard from any of your customers who have exposure to Marcellus gas that they are starting to run their gas plants harder in lieu of their coal plants, or is that not an issue yet?

Caleb, that hasn't made its way to us yet as far as running gas plants harder than coal plants now. What we have noticed from the customers is a -- where there is more of an urgency to be buying coal at the moment for 2015, though some of those decisions for some of the customers are being put off till a little bit later in the year.

Now, with that said, we have been very successful in contracting for 2015, and we feel very comfortable with our position going into 2015. But as far as the -- flipping the generation, we haven't heard a lot of it yet. Like I said, the only thing we have been noticing is maybe the customers being a little more hesitant, still saying they are going to buy for 2015, but waiting a little bit longer to make those decisions on the coal side.

Great. One final question. I know that you in Q2 -- and then, I guess, looking into Q3 -- there is the geological issues and then the operational issues. If those weren't occurring, would you have had the demand to sell more coal throughout the summer.

Yes, Caleb, our demand has been very, very strong for our coal -- the Bailey complex coal. So any ton that we produce, we have a customer on the other end waiting to take it.

Thank you very much.

Holly Stewart, Howard Weil.

First, I guess, I will go to basis differentials, also. I think as you all pointed out, you have probably had one of the better differentials thus far. Were you able to remarket some of your unused capacity? And if so, could you provide what the benefit was during the quarter?

Holly, what we do is we look at the amount of optionality that we have in our portfolio, and about 20% of our portfolio is on daily pricing; and to the extent that we can, depending on what is happening in the market, flip that between different markets, our gas marketing team does that. As far as quantifying the amount of flipping around that we did, or jumping from market to market, I don't have that number for you, Holly.

But I can tell you that we actively do it. And with 20% of the market on a daily pricing, that gives us that optionality to try to find the best home for that gas.

Okay. Well, then, maybe moving to ethane, I think you guys pointed out several different long-term options in the press release with what you are going to do with ethane. What are you actually doing with ethane today? It sounds like some of it is being blended into the stream. Just thinking bigger picture on treatment of ethane over the next few years.

Holly, right now, most of our ethane is ethane rejection. There is -- we do have some release capacity that we have on the ATEX line to Mont Belvieu that we were using -- it is about 2,000 barrels a day -- and are using that for the next several months. But in the near-term, all of our ethane is being sold for heat content.

Now, as we go out, though, into the future, we are building optionality into our portfolio on different fronts. One is if we wanted to increase the amount of ethane rejection, we have our line that we have of those 5,000 barrels a day from Majorsville down to McQuay, our ethane purity line, where we can take ethane down and blend it with the dry gas down at McQuay. So that's the one option that we have through the net pipelines coming online this year.

Then as far as selling the ethane, we have several different markets we are looking at. One is we have our announced contract with INEOS, which gets us into the export markets. And that will start up in 2015. We have the announced deal that we have with the Shell cracker. And we are also talking to other facilities of that type and expanding our presence in that market.

And then, again, on the ATEX line to Mont Belvieu, we are looking at picking up some more release capacity in the future for having that optionality, as well. So we want to have a portfolio that lets us maximize the realization we get from ethane, whether it is ethane rejection, or taking it to the export market, or taking it to the domestic market.

Okay, but no real -- like, from a contract standpoint, no real need to continue to -- or to put ethane into your barrel at this point? You couldn't change the mix, I guess, of your barrel at this point.

That's correct, if you are talking about the ethane rejection side of it. No, there is no commitment for us to do that. That is entirely at our discretion, or to take it and sell it to one of these other options that we have been developing.

Okay. That's helpful. Thank you.

Lucas Pipes, Brean Capital.

I really appreciate the sense of urgency to boost the NAV per share. And when I think about your production growth on the gas side, kind of all else equal, your credit metrics should improve. So in light of this, would you consider adding on more debt to further advance your NAV per share? Has that maybe even shifted since the analyst day, that thinking?

The answer is, right now, no. Obviously, today we are out in the marketplace, but we are just trying to lower our cost of capital. We are not adding on.

If we wanted to, we would have just added on. I think we have a lot of different levers that we are looking at pulling here, from non-core asset sales to the MLP to other things that we could do that are probably more NAV accretive than issuing debt.

That's helpful. Thank you. And maybe to shift to the thermal gas side, more from a macro perspective -- obviously the environment has changed a little bit since the last update. Could you maybe share your thoughts on the market with us, inventories on the coal side, kind of your outlook on the basis more broadly going forward? I would appreciate your thoughts on that.

On the coal side, Lucas, I would like to start with our mine inventories. And our mine inventories are running between 350,000, 375,000 tons at the mine right now -- maybe even a little lower than that today. And that is much lower than our typical 500,000 tons plus.

So our mine inventories are very, very low. And I will go back to the comment I made earlier. If we have a ton of coal there, our customers want us to ship it. So that inventory -- I just consider that working inventory that we have.

As far as our customers' inventory on the coal side, again, we were getting very strong demand from our customers to ship coal for this year. We have done very well for contracting our coal for this year and for next year. And I think, again, that is a sign of the inventory situation or the concern about inventories next year at the coal consumers.

And a couple of numbers on that, above and beyond what was in our earnings release about our coal position, and as that would relate to inventories: by the end of the third quarter, we project to have about 24 million tons of our portfolio sold next year. And that is the sales and also the coal that we have that's sold but not priced and collared coal. All of that type of coal.

You add that up -- we think we are going to be around 24 million tons by the end of the third quarter and about 28 million tons, if not more, but 28 million tons by the end of the fourth quarter. So going into next year, we are going have maybe about 2 million tons of Buchanan and about 2 million tons of Bailey left to sell going into next year. Not a lot of coal.

Again, that is strong demand. I think that we are -- that strong demand we are getting, I think, is a sign of the inventory concerns at our customers and them wanting a reliable supplier.

On the gas side, you asked about our basis outlook, and volatility is the key word. On basis we saw some of the markets that we are in have a very strong positive basis over the winter, and now they are in a negative basis situation. Again, if you can predict the weather well, then you can probably predict what the basis is going to be.

Our view is: a lot of volatility. And when we see what we think is attractive basis or attractive NYMEX strip in the marking, we hedge it off, take that risk off of the table.

Great. That's very helpful. I appreciate it. Thank you.

Andrew Coleman, Raymond James.

I wanted to ask about the PV-10 that you all had in the release. That's a 5.731 TCF. Is that -- that's not a number for June 30; that's the year-end 2013 number. Did you have a number for June 30 that would incorporate the moving gas price from the year-end number?

What we did was we took the year-end 2013 reserves at 5.7 Ts that you noted, and we just updated it for a June 30 look-back, as if we did the same process for the normal PV-10. What we didn't do was we didn't update the reserves for midyear. We normally do that, a full-blown reserve analysis, once a year. So it effectively is a look-back -- so that average 12 months, but starting at June 30, 2014.

Okay. So it's got a little bit of upside, then, in terms of the additional MCF or barrels a day you could book from the higher gas price for the last few months.

That's right. There's RCS, SSL uplift. There's the normal production uplift as you watch the wells, because we normally get that; as well as all the PUD bookings and everything. And the Utica, which is very limited booked right now.

And so as that activity turns, we will be able to book more of that. So I would expect to see a very different number for year-end.

Okay, great. And the second question was -- I guess when you think about hedging, it's smaller than hedging all natural gas. What size does the market need to be or does CONSOL's production need to be where it might look at trying to lock in any of your [30 hedges on ANE] on the NGLs or any on the liquids side?

Well, the liquids market is a tougher market to hedge. It is less liquid in general from a hedging perspective. And so you really can't get a lot of duration on it. So the best way you could do it is through probably more direct sales.

And that would be -- I would say that is probably our method right now, as we get more sophisticated and figure out how to do it and unlock, we may be able to come up with a better way to give us some limit -- capture the upside as well as limit our risk or drop our VAR.

Okay. Thank you very much.

Michael Dudas, Sterne, Agee.

Tim, could you comment on maybe service cost issues; and any trends that you have seen through the first half; and how it's going to play out, given the ramp-up of activity in the region?

Well, we have been -- we have renegotiated some of our service contracts and some of our pricing, and seeing a downward trend. But with activity picking up, some services will get tighter. But so far we have not seen enough worth a movement in pricing.

Looking out at your gas transportation diversity that you talked about here on the call, are you still active with some discussions looking at some of the Gulf Coast markets as you are trying to play things out over the next couple of years? And is that something that can be moving at a better speed?

Yes, Michael. Jim Grech here. We are looking at the Gulf Coast markets and the Southeast markets, as well. And we announced at the analyst day a smaller sale, but maybe indicative of something we're going to start looking -- taking a harder look at was the 50,000 a day sale that we had to [Chaner] down to the West LA markets for LNG export.

But as far as the diversification, what we find here the last few days, which we didn't have time to put into our earnings release, was our Memorandums of Understanding to be an anchor shipper on the Nexus pipeline. And that doesn't go down to the Gulf. That gets us up directly into the Michigan markets and also with the potential for the Canadian markets and Chicago markets.

So we have that in place. We are very optimistic about that pipeline being built. It has a substantial existing infrastructure to build off of and has a very strong end-user commitment on the other end of the pipe. So we feel really good about that, adding that to our portfolio, giving us that diversification up to the Midwestern markets. And we still are in active discussions for the Southeast, and also for down into the Gulf as well, Michael.

Excellent, Jim. My final question is regarding the MLP. I'm pleased to see it seems like that is going to be coming at a probably much quicker pace than I have seen others in the market. So congrats, hopefully, on that.

But I think, for Nick, you talked about the race and looking at the net asset value opportunities, et cetera. I guess nothing has really changed from the June analyst day, but is there things that you have seen just in the last few weeks, or progress maybe on some of these other asset sales that gives you the confidence that maybe you are going to get to run faster and get to that magic point of free cash for the business?

I think it's two things that give us confidence. One is: what's our view on the likelihood of executing on what I will call our base plan -- whether it is base production, base costs, base realizations for E&P and for the thermal segments? And we are just as confident, if not more confident, on our ability to do that through 2014, 2015, 2016 than we were, say, six months ago. So our confidence level in base plan, I will call it, has gone up, which is great.

But the other side of it is: what types of opportunities do we see incrementally to improve off of that base plan? So whether it is the unit costs in the Marcellus, or whether it is the marketing opportunities for Bailey, or what Buchanan has displayed through a really tough downward trend in the market trough, and all of this other, which would you mentioned.

And when we look at the incremental opportunities to make improvements off that base plan, there's more and more of those options and opportunities coming on the table -- which, again, in our mind, you think of it as a breakeven point in time to our base plan or some point in time where we go free cash flow positive. And from what you think you can improve off of that, that brings that time forward. So it is those two things in general that have created a sense of urgency and excitement to keep driving.

Thank you, Nick, gentlemen.

Joseph Allman, JPMorgan.

Good morning, everyone. This is actually Dan Li calling in for Joseph Allman. My question is around the recompletion. Can you guys talk about the cost that's associated with the recompletion efforts, and over what time period you guys expect to drill out those 100-plus identified locations? And if there is any update on the reserve uplift that you guys expect from the (technical difficulty) recompletion?

Well, we have done six re-completions to date this year. We are still in the early flowback stages on all six of them. But so far the results are promising. The actual results -- we have seen initial rates between $3 million and $6 million a day, which exceeds what we saw from the initial recomplete that we had shown at analyst day.

So we are very pleased with what we have seen. We have seen good pressure. It looks like we have contacted some new rock with the recompletion, so that confirms both the RCS and SSL and the effectiveness of it. So moving forward, we do have approximately 200 of them out there. And we are looking at -- we're evaluating those candidates and prioritizing them. But we don't have a specific schedule for them right now.

Okay. And is there -- do you guys have an estimate of how much each recompletion costs?

Right now we are looking between $1.8 million and $2.2 million per re-completion. There is a range there because as we work through these efficiencies and we continue to get better at what we do, those costs will come down.

Okay. And were there any ultimate EUR uplift updates that you guys are seeing from the recent recompletions?

We haven't put any numbers like that out yet, because we are still in the early phases of the flowback and initial production.

Okay. Great. That's all. Thank you.

It might be a better question for the next quarter.

Mitesh Thakkar, FBR Capital Markets.

Good morning and congratulations on the good cost control. My first question is on the coal side. On the met side you mentioned that you are planning to ship some tonnage from the export market to domestic market. Can you give us some quantification around it? And how should we compare it against, let's say, your 2011 or 2012 volumes in the domestic market? And then whether it is going to be the high wall or low wall product?

The shifting of the tons, Mitesh, that we are talking about is getting mainly the low-vol coal from the export markets back into the domestic market. And we said we have about a 50% increase in those tons that translate to really -- we have been a little over about 1 million, 1.1 million tons in the domestic market with the low vol.

And so what we're seeing is that that is going to get up to 1.5 million, 1.6 million tons in the domestic market with the low vol. Hopefully our than that, but our estimate right now is right in that range.

And you asked about, previous years and future years. In total in 2013, we had about 7.4 million tons of export coal. And that was all types that was low vol, high vol, and thermal. This year we are about 5.6 million tons of export coal. And then looking forward to 2015, we are seeing some strength. We are expecting to see some strength with the export thermal and export high vol markets. We are getting some good customer discussions ongoing in Europe. We have been making some very good inroads there with our coals, and so we are expecting that to rebound some. But next year on the low vol side, again, the focus is to bring more of that coal back to the domestic market.

Great. And just a follow-up question, but on the gas side. When you think about your position in the Marcellus and Utica, are you seeing any opportunities where you could probably swap some of your assets out, which are probably not core to you, and maybe look elsewhere in some of the other basins, like Permian or Eagle Ford, where you can get some sort of diversification from a basis standpoint.

And I know it is a transient issue, but just longer term how to think about that; and whether you will just go out and buy something from the cash flow that you are probably going to get from the asset sales?

I think that when you look at our E&P opportunities, we look at the Marcellus and Utica, because that's core to what we do. Appalachia's core to what we do. Outside of Appalachia, not a lot of interest, to say the least, with acquiring positions in other basins. We think, again, going back to NAV per share, the best way we trade value on that metric is the deployment of that capital into Marcellus and Utica.

That being said, there are acreage footprints within the Marcellus and Utica that don't currently fall within our drill plan, and looking at those as other opportunities to trade for acreage within our footprints in Marcellus and Utica or to monetize to third parties that do have plans for those areas. That is something that we look at and we assess on a regular basis.

So there is going to be what I will call acreage footprint opportunities in the Marcellus and Utica for us to monetize. Whether we do that through trade or sale remains to be seen. But our focus remains on Marcellus and Utica and not basins outside of Appalachia.

Okay. Great. Thank you very much, Nick.

Neal Dingmann, SunTrust.

Say, Nick, maybe the first question, just on units on takeaway. You guys continue to be in quite good shape, maybe even better than others. Just your thoughts on a go-forward basis: how do you stay in front of that as you see obviously that being built out?

This is Jim Grech. In the Utica we have two things that we need to stay ahead of, and that is not only the takeaway but the processing capabilities. And on the processing, we feel we are in excellent shape as far as having the contracts and the facilities in place to do the processing of the wet gas.

And on the takeaway, again, as you said, we are in very good shape with the pipeline portfolio that we have. And the Nexus pipeline that we said we've signed up for as an anchor shipper, again, is another potential outlet for our Utica gas to go up to the Midwestern markets.

Okay. And then just lastly, on the Utica, as far as -- do you think you've reached -- I know that there is still a lot of, I guess, on the drilling and completion side differing with how you do the completion method. Utica -- and you didn't mention as far as how far out you would take these laterals. Your thoughts on -- if you get this optimal area, is it -- do know how far out you will take these, how many stages, et cetera? Or will you continue to be -- have some science done, maybe, for the next quarter or two or so?

I'm not sure I caught all of that, but we are continuing to test our completions design. We are very satisfied with the results we have gotten from the RCS and SSL, but there is still work to be done. Right now we are at 150-foot stages. We are looking at sand amounts.

We have run some tests in the Utica with the increased sand amounts. We have got some wells coming on here in the next few weeks to a month or so that will incorporate some of those tests. So we are anxious to see those results.

We do expect to drill long laterals as we do more drilling in the Utica. The wells we have done in Noble County so far -- they have been shorter than our average Marcellus wells, but that has been more due to lease limitations.

Got it. Thanks, guys.

Evan Kurtz, Morgan Stanley.

Just a follow-up on the met coal comment that you make in your press release about growing volumes by 50% on low vol next year. I was just wondering -- I mean, it seems quite early to actually be talking to customers about 2015 contracts. I was just hoping you'd provide a little bit of color. Do you have target customers lined up for that coal, or is this something that you plan to think about as you go into negotiation season?

Well, Evan, on the metallurgical coal market, it takes a while to break into the blends of customers that you haven't been in for a while or haven't been in at all. So what we have been doing is we think we have a couple of advantages on that in the marketplace.

We have an R&D group here at CONSOL that has its own coke testing lab and facility. So we have had those R&D people going along with our salespeople out to the domestic customers and testing different blends of coal with our own facilities. And we have been getting a very good response from the customers as far as incorporating us into their blends for next year.

So when we say we see that 50% increase, we think that is our starting point as we work our way back into these blends or get into these blends for the first time. So we have specific customers we are talking to. We have either contractual commitments that we are in the process of signing, or we expect to get culminated here by the end of the year. So, yes, you have to start early if you are going to break into a new market, and that is what we have been doing.

Great, thanks. And then maybe one other on crossover coals moving back into the thermal market. At this point it would seem like it would make sense to sell as much of your lower grade high vol into the thermal market as you possibly can. I just wondered if you can maybe provide some insight.

Is that what you are doing? Is that why we have seen the guidance shift a little bit this year? And maybe if you could highlight some of the -- what sort of seaborne price you might need to see some of those tons shift back into the met coal market, that would be helpful.

Evan, in our forecast in the earnings release for this year on the high vol coal, we took 0.5 million tons approximately out of the forecast. And that went into the thermal domestic market. So we have pulled some coal back and brought that into the thermal domestic market.

Now, looking forward -- again, we are getting some that R&D and testing of coals; we have not only been doing that domestically, we have been doing that internationally, with a good focus on Europe. And we are getting some -- what we think some good responses on that coal potentially for next year for the high vol to get it into those markets for next year.

So in response to your what price it would take, with our Bailey coal, we could send it to 22 different countries in thermal markets, low-grade met markets, PCI markets. And our job is to get the best revenue and realization for our shareholders that we can. So there isn't a set price, I would say, to get us in the export market. We go between all the markets that we can access and pick out ones that we think give us the best realizations in the long-term for our shareholders.

Okay, great. Thanks so much.

Mike Scialla, Stifel.

Neil asked you about the well configuration in that Utica, including the lateral length. I was curious -- on the Marcellus, you seem to be getting better wells with the longer laterals. Have you found a length there where you see the EUR per foot go down to where the incremental length is not worth the additional cost? And if not, is acreage configuration -- or is there some other limiting factor that would prevent you from going beyond the 8,000-foot average that you planned for this year?

No. That is something the asset teams are looking at, what the optimal lateral length is from a completion standpoint, drilling standpoint, reserve recovery. And we don't necessarily have an answer for that yet, but we think 8,000 is in the range. But we don't have a definitive answer. We have drilled longer laterals, and when we have, that's usually due to lease considerations, making sure we don't strand acreage or resources. So -- but that's our thinking right now.

Have you seen any difference between the wet and dry areas in terms of that lateral length? Is there a preference to go longer in one versus the other?

Well, certainly in the dry. There's less concern with handling liquids later on in the life of the well. The longer lateral lengths are less of a concern.

Then you have got the consideration of whether the wells are updip or downdip. That certainly plays a role. So there's a lot of factors that go into it, but so far we have not seen significant differences in lateral length between 8,000 or, say, 10,000 or 11,000 feet with either wet or dry as far as a breakover point or variations in results.

That's all I had. Thanks.

Greg, we are going to have time for one more question.

Kuni Chen, UBS.

I had a quick one on the Illinois coal basin. You know, you have seen some deals in the space recently with valuations in the $2.00 per ton type of range. For the reserves that you have there, is there any reason to think that that would go for any kind of premium or discount over other transactions that you've seen?

Yes. Obviously, this is greenfield reserves. And so it is hard to give you a dollar per ton. We are going to let the process work its way through.

But I will tell you, we will find a way to maximize the value, either through selling it in one piece or breaking it up into multiple pieces that -- where it makes sense for multiple buyers. So you will just have to kind of stay tuned. It is a process that we're going through right now. And hopefully we will have some good results third quarter, fourth quarter.

Okay. Great. Thanks a lot.

Okay, great. That concludes our call. Could you please instruct the callers on the replay information?

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