Dan Zajdel - Vice President of Investor Relations J. Brett Harvey - Executive Chairman Nicholas J. DeIuliis - Chief Executive Officer and President David M. Khani - Chief Financial Officer and Executive Vice President Timothy C. Dugan - Chief Operating Officer James C.

Grech - Chief Commercial Officer and Executive Vice President of Energy Sales & Transportation Services.

Mitesh Thakkar - FBR Capital Markets & Co., Research Division Holly Stewart - Howard Weil Incorporated, Research Division Brett M. Levy - Jefferies LLC, Fixed Income Research David Gagliano - Barclays Capital, Research Division Joseph D.

Allman - JP Morgan Chase & Co, Research Division Neil Mehta - Goldman Sachs Group Inc., Research Division Andrew Coleman - Raymond James & Associates, Inc., Research Division Lucas Pipes - Brean Capital LLC, Research Division Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division Jeremy Sussman - Clarkson Capital Markets, Research Division Brandon Blossman - Tudor, Pickering, Holt & Co.

Securities, Inc., Research Division Luke McFarlane - Macquarie Research.

Ladies and gentlemen, good morning. Thank you for standing by, and welcome to CONSOL Energy's First Quarter 2014 Earnings Conference Call. As a reminder, today's call is being recorded. I would now like to turn the call over to Vice President of Investor Relations, Mr. Dan Zajdel. Please go ahead..

Thank you, Tom. Good morning to everybody, and welcome to CONSOL Energy's First Quarter Conference Call. We have in the room today Brett Harvey, our Chairman and CEO; Nicholas Deluliis, our President; David Khani, our Chief Financial Officer; Jim Grech, our Chief Commercial Officer; Tim Dugan, our COO of E&P.

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

We will begin our call today with prepared remarks by Brett Harvey and David and Nick. Tim and Jim will then participate in the Q&A portion of the call. With that, let me start the call with you, Brett..

Sure. Thank you. Again, it's good to be with you. It's always good to share in the value of this company, and we had a good first quarter. But I'd like to step back a little bit. On April 17, CONSOL was 150 years old. Abraham Lincoln was the President.

And you might say, "Why is that relevant today?" Well, it's relevant because good assets, with the right strategy, are timeless. As people demand energy, we have the right energy. In April 1999, we went public, as a public company, and we -- our size in terms of market cap is about 10x what it was then.

That's good news for our shareholders, especially those who have been with us for a long time, and it's good news going forward because these assets are timeless in terms of demand for energy, and they're red, white and blue energy as well. I've been the CEO since that point in time. Now it's time for a change.

We have a very strong management team, and we're ready to move forward for the next 150 years. From my perspective, as this changes to a new CEO, I want to thank the analysts, the shareholders and the colleagues for the opportunity of being the CEO of these great assets, and I want to let you know that this company has never been in better shape.

Now Nick has been chosen to lead the company. He's very capable. He's ready to lead. And let me tell you, this is a good investment, and this company is ready to move forward. So with that, I'll turn it over to you, David. Or Nick, I should say..

Thanks, Brett. CONSOL Energy, as Brett said, is best in class with natural gas and coal assets, and those assets have vitally strategic positioning relative to the growing markets and demand centers that we see out there.

Our values of safety and compliance and continuous improvement, they're as critical today as they were when we established at that time our new corporate culture and identity over 15 years ago when Brett first took the helm. And we have a new generation of management within the company that Brett spoke about.

We've seen the positions of CFO, Chief Commercial Officer, our Chief Legal Officer, the Chief Operating Officers on both the coal and E&P segments, those have all changed over or elevated within the past 18 months.

And they've changed over to individuals that have the experience and skill sets that are needed for where we're heading, which require a somewhat different set of skills and what was needed based on where we've been historically and the success that we've had historically considered as well.

Today, we've got a management team that recognizes change is constant, and continuous improvement is a must for anyone who's hoping to be best in class and within the industries that we operate within. And I can assure you there's a sense of urgency.

Our actions over the past 18 months speak to that urgency and our drive to achieve best-in-class performance and to hold on to it.

As shareholders, you should expect more of the same in the future and the implied valuation of these best-in-class assets that demonstrates potential for additional shareholder value creation, and the management team is well equipped and suited to execute a game plan to unlock it.

When we look at the company, increasingly, we see 4 key areas that constitute and drive our valuation, and I'd like to cover each of these and shine some light on what our plans and expectations are moving forward. And I'll stick to the big picture on each of these, and Dave Khani will discuss things in more detail in a few minutes.

Now the first area, of course, is the E&P segment itself. And our 2014 production guidance and production growth beyond into '15 and '16 contemplates 30% annual growth. And just about all that growth is going to come from the Marcellus and Utica.

And with growth, of course, comes capital, and this year, we expect to invest about $1.1 billion into the E&P segment. That could be as well as $900 million if gas prices stay above $4 with our carry and our joint venture.

With all that growth and all that capital investment, it's critical that we develop our fields in the most efficient manner possible. Unmanaged production growth for its own sake, the path to destruction of shareholder value, as we've seen many times in the energy space.

But the flip side to that is that methodical and efficient growth can add tremendous shareholder value and NAV accretion if the growth occurs while embracing lean manufacturing and continuous improvement techniques. In that flip side case that I just mentioned, that's exactly what we plan to do in the coming 3 years.

We want to grow production at the 30% clip rate, but we're going to do so where we measure and improve upon every key performance metric that could be traced back to NAV.

That means we're going to obsessively track and relentlessly improve on things like permitting cycle times, optimal pad layouts, drilling rates and costs and the completion rates and efficiencies and things like midstream compression and processing designs.

It also means we're going to need to employ a multi-disciplined approach to the major development subfields within the Marcellus and the Utica and elsewhere to make sure we're capturing all the key performance metrics within that development chain and that the overall plan of attack is optimized for total NAV, not just optimized for 1 link in the development chain.

That's why we recently centralized and organized all of our E&P disciplines beyond field maintenance into asset teams who will not only develop their optimal plan of attack, but they're also going to compete for capital with one another to make sure we're allocating one of our most precious resources, capital, to the best places.

It's already seeing in a very short period of time how this new structure and approach can pay dividends, and we expect the new structure to pay even more dividends as we begin to chase down the numerous stack play opportunities within the Marcellus and Utica footprints.

The second area of the company that drives NAV, that's the Bailey complex in Southwest PA. The complex has become the envy of the industry. It's 5 longwalls now, with our new BMX Mine added to the mix. It's producing the highest BTu coal in the nation and the lowest sulfur coal in the Northern App basin.

It's served by dual-rail lines for relatively short hauls to what are the must-run flagship coal-fired power plants that are in the Eastern United States. We've invested billions into this complex over the past decade, and that investment has now created a new beginning for the Bailey and Enlow Fork Mines through their overland belts.

It's created an operating team that's second to none in the industry and a frac plant that enjoys economies of scale that we haven't seen before. That security supply is becoming increasingly important in today's thermal markets.

And on top of all those great attributes, the complex is going to require maintenance production capital in the range of only $4 to $5 a ton for the coming years. You add all these things up, they result in production levels, costs and margins that produce significant free cash flow, and the first quarter was a great example of that.

We expect to post more of those types of results in the coming quarters. The third area of the company that drives our valuation, also on the coal segment side, that's our Buchanan low-vol met mine in Virginia.

And like the Bailey complex, our capital investment over prior years and the operating team that's in place there today, they've resulted in the best low-vol coal mine in North America.

Unfortunately, the current international market for low-vol coal is, for lack of a better term, is horrible, which is resulting in netback prices to the mine that don't create shareholder value. And as a result of that, we've already scaled back our 2014 production guidance at the mine to the 3.6 million- to the 4.2 million-ton range.

That's well below, of course, the mine's production potential. So as we scale back production, based on current market not improving, that will cart us our normal course of discipline that we exert in the market. So please recognize 2 things in this situation.

The first is that CONSOL will not hesitate to pull back and scale production back if the market prices don't provide the opportunity for fully loaded margins. And then second, we'll be well positioned and poised for a market rebound when it occurs. And the market rebound will occur, it always does. So we like the rest of the U.S. supply mix.

We're price takers in the global metallurgical market, not price makers. So the trick is to focus on what we control at safety, efficiency and cost and not waste the valuable asset in down markets by giving it away for the sake of hitting a production bogey and to be prepared to move quickly when the global markets rebound.

The fourth and final area of the company out there that drives valuation is, for lack of a better term, everything else beyond the Marcellus, Utica, Bailey and Buchanan. And with CONSOL Energy, this everything else or other is substantial and is largely unappreciated -- or underappreciated within our share price.

So there's a couple of things to update you on in the other category. First, there's what we're doing with our E&P midstream assets. Our midstream assets currently consist of our stable but lower-growth legacy pipes and processing facilities and the Virginia CBM fields and, also, our high-growth pipes and processing facilities in the Marcellus JV.

Now the different expected future growth levels for these 2 midstream assets, they create different opportunities for value creation. So for example, with the Marcellus midstream, we own and operate within our JV. We see tremendous growth. We saw 100% -- nearly 100% year-on-year growth in production for first quarter alone.

And it's important for us to retain strategic control of the asset moving forward to make sure those production growth plans are not compromised. So we're looking to identify a path there that unlocks the value of the Marcellus midstream but also does so in a way where future growth is recognized and not placed at risk.

We continue to work diligently assessing our alternatives, and we expect an announcement on that path that we select for what portion of our midstream assets it pertains to by midyear, with the transaction consummated sometime in 2014. In Other, there's also non-core asset sales beyond what we're looking at for midstream.

And historically, over the past couple of years, we've monetized hundreds of millions of dollars each year in non-core asset sales, and we expect to do the same this year as well. These monetization opportunities may be operating or nonoperating assets, and they might be found in the coal, gas or other areas or segments of the company.

So stay tuned on developments here as they unfold. Now before I turn it back over to Dave Khani, I want to conclude with the thought of timing and rate of change. As we said earlier, things are moving quickly at CONSOL. If you look at the Marcellus alone, it's a great illustration.

We finished 2013 at a daily run rate over 70% higher than where we finished 2012. Our first quarter 2014 Marcellus production was almost 100% higher than the first quarter a year earlier, and now here comes the Utica. All of that E&P production growth contributes more and more to cash flow, to EBITDA and to earnings.

Then you look over at the Bailey complex, that 5 longwalls that require only maintenance production capital, that complex is going to be a free cash flow generator and major earnings contributor for the coming years.

Add on to these areas the monetization of non-core assets and the hundreds of millions of dollars each year and a way to unlock -- finding a way to unlock that inherent value of our midstream. And then you top it off when the lowball met markets rebound to a point where Buchanan can flex the production capacity and cost structure that it enjoys.

This buildup of our major segment contributors not only de-risks the ability to grow our E&P segment, it also results in improved credit metrics, as well as options to boost shareholder return in the not too distant future.

But first things first, a steady execution in 2014 and 2015, those are required to place us in the future position with those enhanced options for shareholders and to continue, of course, to grow NAV in the meantime. And with that, I want to turn it over now to Dave Khani..

production, prices, underutilized FT [ph], cost reductions and better management.

Before I go through these items, the workflow diagram and table on -- below on Slide 5 are an attempt to reconcile the differences between the 2 quarters and show you that we increased our first quarter numbers by basically $116 million from essentially breakeven in the fourth quarter after stripping out the nonrecurring gain in sales -- on sale and tax impact.

As you can see from this workflow diagram, both sides of our business showed market improvement sequentially. Now let's go through the key drivers. If you look on Slide 6 and beyond, you'll see that our oil and gas production is up 23% year-over-year and up 14% on coal.

For coal, we raised our 2014 production forecast in our operation release based on a stronger domestic outlook. For our E&P business, our Marcellus production is now the largest component and remain on plan despite losing half of Bcf of conventional production due to pipeline downtime at third-party.

The pipeline is back online, and we expect to resume some of this production and will catch up there. The second key point is driving prices. We've captured higher natural gas prices and believe we have the highest unhedged realization among our 4 largest Marcellus peers at $5.71 per Mcf.

Our marketing team and existing current transportation capacity enabled us to capitalize on certain first quarter key pinch points in the Northeast. As a result, our year-to-year sequential E&P margins increased by about $1.10 and $1.20 per Mcfe, respectively.

In addition, we've added approximately 40% to our 2014 hedge position in the last 4 months to lock in higher natural gas prices for the rest of the year. We believe we've captured the run-up in prices better than most in our Marcellus peers based on timing and price. Moving over to Slide 8. A couple of key points on coal.

With the cold weather, we have sold extra coal into the spot market at favorable prices and began discussions to contract our 2015 volumes and beyond. Number two, despite our extremely weak met coal markets, we posted a $21 per ton fully loaded margin, which is flat year-over-year but up from $16.80 per ton in the fourth quarter.

Within the first quarter, we contracted about 5 million tons for the rest of 2014 and about 600,000 tons for 2015. Jim -- Tim could talk more about what's to come. Number three, the reduction of underutilized firm transportation capacity.

I'll remind you that last year, we paid somewhere between $30 million and $35 million in underutilized firm transportation capacity costs and expect to reduce this figure throughout the next several years as our production grows.

With the cold weather, we were able to optimize our firm transportation and add an incremental $11 million in the first quarter over the last year's $3 million benefit. Four, cost-cutting. We've implemented our $65 million cost reduction to our plan and began realizing part of this in the first quarter.

This will get factored into G&A, coal operating costs and other administrative expenses. Over the past year, we've reduced our average corporate headcount by about 20%, and if you go back 2 years, by 30%. We believe we are rightsized in our coal and gas business today. Now let's look at unit costs for both coal and gas on Slide 10 and beyond.

For coal, we've reduced our cost by about $6 [ph] per ton or about 90% of what was driven by increased volume and mix shift towards our lower-cost Northern App mines. The remaining 10% of the cost reduction was driven by specific nominal cost reductions.

We have more work to do here and hope to keep costs relatively flat over the next year, with volume being a major factor. We went over the gas side of it. Sequentially, total gas and Marcellus costs were up $0.08 and $0.07 per Mcfe, respectively, primarily due to the increased DD&A rates, which were up $0.11 and $0.20, respectively.

We would expect their DD&A rates to come down as we capture the production associated with our JV carries, execute on our SSL, RCLs on all of our production, as well as drive our overall cost per well down. Fifth key point, vendor streamlining and inventory overhaul.

We have created a plan and will implement a reduction in the number of vendors and inventories at our coal mines and gas sites beginning in the second quarter. This year, we expect to spend about $3 billion in goods and services to support our coal and gas business.

We're at the early stages of recognizing this benefit but should lead to millions of dollars of reduced operating costs of working capital and strong -- stronger performance metrics. Now let's move to capital spending on Slide 11.

For 2014, as Nick has mentioned, we expect to spend about $1.5 billion in capital or about $1.1 billion tied to our oil and gas operations. Two key points and one which Nick had made already, which is we are going to maintenance mode on our coal side and we're running at $4 to $5 per ton, up for producing ton.

Second is we're starting to make subtle changes in our lean manufacturing process and hope to bring down our oil and gas capital over the next several quarters, keeping the same activity in place. Our goal is to reduce the capital intensity of our business to drive higher returns on capital employed. Now looking at Slide 12.

With strong execution noted above and capitalizing on the winter weather and the recent financing, our cash flow improved during the past 3 months, helping us maintain strong liquidity.

We started the year with $2.1 billion of liquidity, which still stands today at the same level at the end of the first quarter, and we expect to maintain most of it by year-end 2014.

While we continue to reinvest our E&P business to grow production and improve our liquids representation, there are several ways we expect to maintain our strong liquidity over the next several years.

First, our cash is sitting at $314 million at the end of the first quarter, down only $13 million from year end and essentially went to pay off our dividend. Second, our coal will generate free cash flow with our BMX now online starting mid-March.

Third, we filed a cash tax refund of about $115 million, and we expect to receive that in the second half of this year. Fourth, we expect to receive $200 million of Marcellus carry, which started on March 1 and should begin reducing our capital line in the second quarter.

We can receive up to $400 million per year, and we have $1.9 billion still left on the total Marcellus carry. Fifth, we have locked up about 75% of our forecasted gas volumes in 2014 and essentially sold out for most of our domestic thermal coal. Sixth, sale of non-core assets, operating lease and infrastructure monetization.

We recognize about $125 million in this bucket of the $100 million to $300 million we expect for this year. This includes $46 million for the DTI land acquisition that we received for Noble's 50%, as well as $75 million for a longwall operating lease.

Looking forward, we expect to capture our midstream MLP sale, as well as other non-core assets sales that Nick also highlighted. With all these actions and driving the capital intensity down, our internal goal is to be able to grow our E&P business while maintaining our current debt levels. Moving over to Slide 13, the net cash impact.

Slide 13 sums the first quarter investments and overarching cash flow impacts. For the quarter, we invested $451 million and generated cash from operations and asset sales of $462 million. We believe our credit metrics will improve dramatically by year end as our debt levels remain relatively flat and our EBITDA and cash flow rises.

There are few companies that can post growth capital while maintaining strong liquidity in this relatively weak energy environment. Slide 14. We have reduced the operating risk and leveraged through the sale of 5 mines and improved profitability in our oil and gas operations. This should improve our cost of capital over time.

Last year, we've reduced our legacy liabilities by about $2 billion, greatly improving our fully loaded credit metrics, as noted here on Slide 14. As the leverage has declined, we shifted our focus on implementing our 3 major financing items in the first half of this year, which I'll describe now.

The first one, we executed a new 5-year $75 million operating lease for BMX during a very low interest rate environment. Second, in April, we announced a tender of our 2017 maturity 8% coupon bonds, and we'll replace them with a new 5 7/8 8-year note that was nicely oversubscribed. This will save us about $26 million in annual interest expense.

And last, we're undergoing a new $2 billion oil and gas reserved-based credit facility maturing in 2019. We already have $3.5 billion in commitments in the book, and this should save us at least $3.5 million a year annually. So once all closed, we'll have reduced our long-term debt to cost of capital by 1%, down to about 6.9%.

We will have improved our flexibility with more oil and gas covenants, and we'll have termed out our maturities. Post-closing, our first major tranche of debt that comes due will not come due until 2020. We do have still more works -- still have more work to do over the next couple of years.

So in summary, last year, this management team focused on driving shareholder value and was not going to wait for the commodity price to dictate the pace. For 2014, the commodity price provides a modest tailwind instead of a headwind, but we should be measured by the value we generate in good times and bad. Now I'd like to open it up to questions..

[Operator Instructions] Our first question today comes from the line of Mitesh Thakkar representing FBR Capital..

My first question is just on the coal side, excellent cost performance there.

How should we think about just the consistency of this cost performance and any impact the operating lease might have on that?.

The bigger picture on cost for the Bailey and Buchanan complex, you saw 2 things. If you look at the Bailey cost performance this quarter, one was a production benefit because the market was there to take the incremental production. So you had an economies of scale effect.

And the second part was what I'll call a structural cost efficiency improvement that Dave spoke about in his comments. Moving forward, of course, we expect the structural cost savings to stick and stay with us through different market cycles, and then the degree of the cost that we see moving forward will also be driven, of course, by market demands.

So I think if you look at those 2, probably half was due to structural changes that will be with us in up and down markets, and the other half will be a function of how much coal we can ship in the short term because of market demand. On the leasing question, I'll turn it over to Dave on [indiscernible]..

We'll come back and give you the impact of leasing offline. We don't have that right in front of us..

Okay, great. Just moving to the gas side. You mentioned reducing capital intensity on the gas side.

Can you talk about some of the initiatives and kind of timings around that a little bit?.

Well, I think there was a lot of capital efficiencies already in place. I'm sorry. This is Tim Dugan. When I arrived here with some of the reductions we've seen in the last couple of years and our drilling capital reducing our cost per foot by almost $175 a foot, I think we'll continue down that path.

We still have more efficiencies to gain, further cost improvement to realize with the technology, just repositions and cycle times all across the process from planning through our drilling and completion production side of the business..

So then is there a way to quantify it on the basis of effectiveness for like dollar per stage or something like that?.

Well, I think we'll continue to see a reduction in our cost per foot on the drilling side. I'd say we were -- I think in the first quarter, we averaged $198 a foot when you consider the severe winter we had. That compared to the $190 a foot we were at the last quarter of last year.

That's really a good number, and we'll continue to see that go down as we drill longer laterals. We recently TD-ed a well that was over 10,000 feet. We saw our cost down about $177 or $178 per foot. So we'll continue to see those reductions as we gain efficiencies, drill longer laterals.

And then on the completion side, with our RCS, SSL, we're doing smaller stages, more stages. So we're seeing an increase in cost there, a decrease in our cost per stage but an increase in our overall cost. But as we improve on the number of stages per day that we execute on, we will see -- we'll minimize that increase.

We see an increase of about -- just on a frac cost, about $1.2 million with the RCS, SSL for a 5,000-foot lateral. But the actual increases will be much less than that as we improve our stages per day, and we can take advantage of efficiency and reduce our rental costs by cutting the entire completion time..

And we'll provide more information at our Analyst Day in June..

Our next question is from the line of Holly Stewart with Howard Weil..

First, maybe this morning on the Range call, they talked about drilling their first Utica well in Washington County. I don't believe you've disclosed much on your Utica potential in West Virginia and Pennsylvania.

Can you maybe quantify? And then is there any plans for testing in the near term?.

Our near term in the Utica, we continue to be excited about our acreage position in the JV. We've got about 30,000 net acres in the core area in Guernsey, Belmont, Harrison and Noble County. Our focus in the JV continues to be in Noble County. We drilled 8 wells last year. We'll drill another 13 this year that will operate.

We continue to feel good about that area. Over in Monroe County, where we got 11,000 net acres that we will operate solely, we'll be drilling 2 wells there this year. That's an area where we have stack play potential.

We will drill a Utica well and a Marcellus well, a dry Utica and a wet Marcellus, and that is moving over towards the acreage that Range was talking about. So we think that will be a good test of that acreage..

And then also, Holly, keep in mind, too, with opportunities as we continue to delineate Utica eastward, we get into Greene and Washington Counties, those footprints and Utica there, we control and operate 100% of. It doesn't fall within either JV..

Okay.

But no split yet of what kind of acreage potential you think you have in Pennsylvania and Washington and West Virginia?.

We'll have that for the Analyst Day..

Okay, great. And then maybe just some -- David, I think you referred to it on the free cash flow. It looks like probably minimal free cash flow for the coal business in the first quarter, just given BMX wasn't up to the good run rate yet and there was growth capital there.

Can you maybe give us just a good annualized free cash flow number given the maintenance capital detail for coal?.

Well, if you think about the $4 to $5 for the capital number, okay, and you think about the sort of -- maybe the 20 -- sort of roughly $25 per ton cash margin, okay, so you should maybe think about a rough $20 per ton free cash flow number as a good sort of benchmark there..

Our next question comes from the line of David Gagliano with Barclays..

Just before I ask my question, I did want to use this opportunity to congratulate Brett. I've had the opportunity to cover this company since it became public 15 years ago, and I did want to congratulate you for successfully navigating CNX through what's been an extraordinary 15-year period.

It seems to me the share price performance over that period versus the peers speaks to your success during that time. So again, congrats to you, Brett, on a phenomenal tenure. I just -- I actually just have 1 quick gas-related question. Only about 4% of your energy volumes were liquids-related this quarter, obviously, mostly NGLs.

Can you just remind us again how we should be thinking about the liquids-related contributions relative to the total production targets for the remainder of '14, '15 and '16?.

Sure. I will give you '14 and '15. '14 should be between 5% and 8%. So you'll see it pick up not just only from the Marcellus but also from the Utica. We're getting some contribution today. You -- and then in 2015, we'll be somewhere around 10% to maybe as much as 15%..

Okay. Okay. And then just one coal-related question tied to the cost performance on the thermal side.

Given that this occurred during a period when BMX was still ramping, are there reasons to expect unit costs actually decline on the thermal side further? Or what are the offsets here for unit costs to overall be kind of flattish over the next few quarters?.

David, if you've seen historically, our quarters within a calendar year are lumpy on the coal side because of things like miner's vacation and holidays in the fourth quarter, so miner's vacation and the summer holidays in the fourth quarter versus first quarter.

First quarter is typically our best, but as you said, you've got an impact to your BMX moving forward, where it's on a regular full quarter run rate instead of a startup that we saw in the first quarter.

To go back to the first question, the cost performance that you saw this quarter out of our thermal side, roughly half of that was due to market and production being able to meet markets, so the economies of scale. That will be a function of what we see on demand hold for coming quarters.

And on the other half are structural in nature that should stick and be with us no matter what the market or market demand is within the quarter. So where that washes out, I think it bodes well compared to historicals.

And it's not just the BMX impact that you bring up, there's also a lot going on in Enlow Fork, with a lot of ceiling projects now that are underway that basically removes 75-plus percent of the current mine that needs to be maintained and controlled now that the overland belt is up and running.

So there's really 2 big drivers there that should stick moving forward. And the quarters that they unfold through '14, I think you'll be able to see that just because of the enhanced lumpiness there with what we do operationally. And Jim Grech, I think, has some thoughts there, too, on market..

Yes. David, as Nick mentioned, part of those costs are driven by the volumes at the Bailey complex. And as we sit here right now, the Bailey complex for 2014 is essentially sold out. We have a couple of deals we're trying to close out here in the next week or so, which will, as I said, essentially have the mine sold out.

We will have some production here and there as it becomes available, as maybe have some weekend production that we haven't sold yet or we get some better-than-expected efficiencies. So with the mine being essentially sold out, the volume should stay strong at the Bailey complex, and that's a very important part of the unit cost or the volume.

So we're optimistic on that end as far as maintaining the volumes to keep the cost lower..

Yes. And, Dave, I'd just say the mix shift will continue to shift more towards Northern App as BMX has the full quarter and as well as Buchanan's scratched back a little bit. So you'll have a lower cost from that. The inventory management and project will start to bear some fruit, and will start to take some of the costs out of the equation as well.

So we have some things, first things, to sort of quantify for you..

And next we'll go to the line of Joe Allman with JPMorgan..

Nick, could you talk about any new developments in the frac designs and any well results that are benefiting from the new frac design?.

I could, but I think you really want to hear from Tim on that one because he can do a better job of talking about it. So I'll let Tim cover what we're working on there..

Well, we've talked about RCS and SSL and the successes that we've seen from that in Southwestern Pennsylvania in about 13 wells last year with the RCS, SSL. We're expanding that this year. We've got 39 planned for the first half of 2014.

And going forward, everything in Southwest PA will be done with the reduced cluster spacing in shorter stage lines, and we're expanding that to Central PA and Northern West Virginia, where we'll still be doing some testing there, but we expect similar results there.

Now that doesn't -- now that's not the only benefit we're going to gain in our completions. We're still -- we are constantly looking at how we can improve our completion.

Looking at our sand, our profit schedules, our sand concentration, the additives we use, the rates that we pump at, so looking at -- right now, we're averaging about [indiscernible] stages a well. We're looking at that, what the optimal number of stages are and the optimal size.

And we know that the shortest stage lines certainly have provided a benefit, but we will continue to look and optimize every aspect of our completion..

Okay, great.

And then a separate question, the inventory that you have of wells waiting on pipeline or waiting on completion and/or completing, could you just go over where that inventory is and what you expect going forward?.

I think, right now, we've got about 30 wells that are in inventory. There are -- some of those are sitting on pads, where we've got a drilling rig drilling additional wells there. We've got 3 fractures running.

So we're really -- our goal is keep our inventory down, keep completions up with drilling and maintain a low number there so that we can -- as we reduce our cycle time, we will be getting wells turned in line quicker..

As of right now, there's nothing extraordinary, just no unusual number of wells running up pipeline or anything?.

No..

No..

Okay. And then last question for David. David, I think you mentioned $125 million from non-core asset sales, and you mentioned another number.

Could you just clarify what you're expecting in terms of non-core asset sales?.

Yes. We said, traditionally, we will have between $100 million and $300 million a year. Right now, in the books, we have $125 million. And so as we execute our midstream, either MLP or sale, that number will go up from the $125 million level.

And then we have other non-core asset sales, either reserves, acreage or things like that, where we will prune that are either way outside our 10-year plan or we can find better value with somebody else..

The question is from the line of Neil Mehta representing Goldman Sachs..

First on the E&P side, can you talk about how you think about long-term basis differentials, particularly in Southwest PA?.

Well, Neil, this is Jim Grech speaking. And in the long-term basis differentials, our view of them is they're going to be extremely volatile. As we look out over the next 3 to 5 years, you'll see a lot of pipeline capacity coming online into the region. We also see a lot of production capacity coming online in the region in the same timeframe.

So you're going to have those mismatches of timing of production increases and pipeline take away capacity coming online to move the gas out. So again, it's very volatile. The weather can increase that volatility, as we saw here in the first quarter. So in response to that, what we're doing, our plan is to get some -- as much diversification.

And where we sell our gas right now within the basin and without -- out of the basin right now, we're about 2/3 of our gas gets sold in the basin and about 1/3 of it we export out of the basin. And we're working towards making that a 50-50 split in the basin and without of the basin, just to give us that diversification in pricing..

It makes sense. And then another question in terms of the macro here is on NAPP pricing. Can you talk about where we are from the inventory perspective in Northern App? And then on more of the negative side, how you think about the potential impact of some of the new supplies that's been announced over the next couple of years..

Neil, on an inventory right now for Northern App, if you take a look at the PJM market, the coal inventory, we just announced February inventories of just over 12 million tons. And the -- that's the lowest they've been since 2001. So very, very low coal inventories in the PJM.

Looking to East Central, the inventories there are about 18.7 million tons, that's the lowest since 2005. So as you go through these markets, they're all at inventory levels -- low inventory levels that we haven't seen in a very long time. Now in response to the second part of your question, there is some production coming online.

There's also production going off-line. And so you have to balance that out, and you also have to balance that out with the other markets that we compete with in the Central App. And there's still more production we forecast coming off-line there. So we think that there is going to be still very strong robust demand for Northern App coal going forward.

Even though there is some production coming online, there's also production coming off-line in our basin and other basins..

Makes sense. The last question is we were all very impressed with the realized gas pricing in the first quarter, especially given that you had a sizable hedge position going into the quarter.

Can you talk about how you were able to opportunistically hedge in the first quarter and the dynamics of your hedge book?.

Yes. I'll just say on our hedge book, it's not structured any different, really, from quarter-to-quarter. We didn't -- whatever we put on in the first quarter, we sort of flow through the rest of the year.

It really is -- it comes down, and Jim could talk down to this, is our firm transportation capacity and our ability to arbitrage different locations..

And, Neil, what happened in the first quarter on the realization is our gas marketing group did a really good job of moving our gas based on some legacy FT that we have into the markets where we get the better realization. And one example of that is we got a sizable amount of our gas moved to the petco [ph] M3 market.

And on average, the first quarter basis in the M3 [ph] market was $3.26, where if you look for the rest of '14, it's running at a $0.50 negative. So our gas marketing group was able to flip to gas using our FT to get it to the markets where we got the best realization, and that resulted in the gas prices that you're talking about..

Our next question is from the line of Andrew Coleman representing Raymond James..

This thing about cycle times is a little bit touchy and, I guess, going back to what Joe was asking about. So you guys have 9 rigs in the Marcellus and 4 in Utica.

I guess did you have a view on, I guess, what that rig count could go to as you trend it through the year? And, I guess, can you just reiterate what, I think, Tim said on cycle times, days to drill and completing tie-in?.

Well, I think we'll have a better view on rig count. I mean, we have an idea. If we look at what we planned on and when we put our '14 plan together, I think we assumed that the rig count would probably roughly double next year.

But when you look at the efficiencies that we're going to gain, cycle time reductions, we will be able to do more with less rigs. And I think we'll have a much better idea of that probably midyear, early third quarter. But we do expect to be able to do more with less [indiscernible] cycle times.

When we talk about cycle times, too, we're also talking about planning, improving our planning process, reducing that entire cycle time for permitting, land work and all of the engineering and planning that goes into the wells for completion and drilling at this point as well..

Okay.

And are you seeing -- or, I guess, how much of your wells are being drilled on pad versus individual at this point?.

Everything we're doing is pad..

Okay.

Are those 4 well pads or bigger?.

We're probably averaging about 6 wells per pad..

Okay. All right.

And then thinking about your firm transportation agreement, I guess, can you give a range of how much excess capacity you all are looking at as you transit through the year, as you all have enough capacity to kind of cover this year, plus have some visibility over your 3-year plan?.

Yes, Andrew, as we stated in the press release, or the earnings release, that we -- we're in fairly good shape for the next 3 years. We have a couple of spots where we need to fill in, and we're actively doing that with some direct sales to our customers.

And as we get out beyond that timeframe, we are -- have activities in process right now, both looking at long-term FT on pipeline or having direct sales with customers that have FT. And that's how we plan to fill out our book post-2016..

Okay.

And then, I guess, in the intermediate period, if you find that you have excess capacity, how does it work? Are you able to monetize that on short-term contracts or through a nominations process to take advantage of when you own the capacity in an area that's pretty tight?.

Yes. The answer is yes to all of those different options. We look at either releasing it if we can flip our gas, another FT that we have, the other markets where we get a better realization or if we're in an area where we're not utilizing all the FTs, then we release it to people that have a need for it.

So it's on a case-by-case basis, but we're -- every day, our marketing group is looking at how to optimize the realization by using the FT that we have in place..

Okay. All right. I'd like to sneak one more in.

Just looking at capitalized interest, it looks like it was about $10 million-ish for the quarter?.

I'll have to come back to you with the answer on that..

And we'll go to the line of Lucas Pipes with Brean Capital..

And, Brett, I also wanted to take this opportunity to congratulate you on your successful tenure. 15 out of 150 years really makes a difference..

Thank you..

My first question, Nick, for you. You mentioned the internal competition for capital.

Could you maybe elaborate a little bit on what your key metrics are when you determine where to allocate the capital and how quickly you can manage to adjust depending on how that all shakes out?.

I think the bigger items that try to balance production growth and capital budget is there's 2 items that are growing production to drive NAV, as well as liquidity, making sure we do that in a major and methodical manner. We're -- but we're also not running into liquidity issues on the other extreme.

Now within that, once we set, say, a 30% production ramp, like we have for the next 3 years, where we feel we've got the liquidity to meet that and fund that, then it comes down to where is that production growth going to come from, not just, of course, within Marcellus and Utica, but drilling down into Marcellus and Utica subfields themselves.

And we've grown in this whole mix now the stack play opportunities and the sequencing of how we approach a Marcellus and/or Utica and/or Upper Devonian. It's even more complex with opportunity but making sure we separate all of those issues out and come up with the right answer. I tie it back to what Tim said earlier.

A lot of this is about cycle times, and a lot of this is about overall efficiencies and then how those efficiencies and cycle times translate, manifest themselves into rate of returns and NPVs. So as far as the topic again, we've got a 30% production ramp over the next 3 years. We've got the asset base to do that. We've got the liquidity to fund it.

Now we drill down. We know it's going to come within the Marcellus, Utica, Upper Devonian plays that we see in Northern Appalachia.

Now you drill down even further, you see the cycle times and efficiencies coming up with the key performance metrics within those production ramps of greater return and net present value, and that then will determine what we drill first and then what we drill later..

That's helpful. And on the coal side, a quick follow-up. Kind of looking ahead into 2015, we have some regulatory changes coming.

And do you have a sense at this point on whether this will lead to increased utilization of the coal fleet that remains behind? Or do you think most of that will go to natural gas?.

Well, Lucas, the coal question and looking forward to coal consumption, to us, you have to look at that and also look at what's going on in the gas market. And I'm going to start with where we're at right now and then get to 2015.

Right now, we have these very low inventories in the gas markets and the coal markets, and we think they're leading indicators of a trend that's going to potentially put us on a path of a multiyear trend of coal, gas and power price volatility, which will take us beyond 2015. And we don't see any quick fix to rebuilding the coal or gas inventories.

The gas markets are looking to coal generation to bail them out. And the coal markets, frankly, need gas generation to help bail it out to get its inventories built back up again. And so when you look at how we could get those inventories built up for 2015, Utica production increase as well, there's no quick fix with production increases.

They're gas wells. If you start from scratch, you have about a 2-year lead time before production starts flowing. Coal, there is some incremental production, but if you're going to put a new mine in, you got 5 years plus of permitting if somebody was to build a new mine.

So then let's just say that incremental production is there, let's look at the coal side of things, railroads, lead long times to get more equipment built, train crews, complete track addition. In the gas side, it takes at least 3 years to get a FERC-regulated pipeline in the ground, so there's no quick fixes there.

So again, building towards 2015, maybe there's some incremental production out there to help rebuild the inventories, but the other half of the story is being able to move those commodities to market. So we'll look at going into the winter of '15 with potentially low coal and gas inventories.

Then we're going to come into, as you've mentioned, Lucas, 2015, the NAPP's regulations are going to hit. We're going to drop coal-fire generation. When we get to 2015, with these low inventories, potential inventories, we're going to be looking for more gas generation to pick up the load.

That gas generation may not be there, so then you're going to turn to the coal power plants that are still there. Nick mentioned to them -- mentioned before the large must-run coal power plants. Their capacity factors are going to have to go up. So when we look through -- out to 2015, we got low inventories.

We see a very tough road ahead for coal and gas to rebuild the inventories. We see increased demand on the remaining coal generation, and it's going to put a real pull on the gas markets as well.

And then we think that may carry right into 2016, '17 when the LNG exports are going to start, again, pulling gas off our shore and increasing the demand for it.

So our outlook for coal generation, even post-NAPP [ph], is still a very bullish one for the remaining generation that's around and we think we're well suited with our mines and where we are geographically to serve those plants..

That's extremely helpful. I appreciate the detail. That sounds pretty bullish.

Now on your thermal coal production guidance for this year, would you say that's roughly full -- assuming full capacity utilization off your key NAPP longwall mine? Or is there a little bit of room left?.

Lucas, that statement I made about it being essentially sold out, if we say we can on average run 2 weekends a month overtime, that's running really like 1 to 1.5 weekends a month as it is. So there may be a little bit of space there, but that's really -- things have to go extremely well in our mines for us to pick up that extra production.

So like I said, we're essentially sold out on our thermal coal out of the Bailey and Miller Creek complexes. As we go along and we have some good production efficiencies and we free up some more tons, then we'll bring that up to market..

Our next question is from the line of Neal Dingmann with SunTrust..

Say, Nick, a question on -- you mentioned here in the press release about your 2-well -- your 2-, 3-well Utica pad. I'm just trying to get a sense of a couple of things around that. One, it does sound like you're working on some of the infrastructure.

I guess, not just on those 2 pads, but kind of going forward, just if you or the guys could comment about infrastructure as you bring these wells on, if you'll have to continue to choke back any other wells.

And then secondly, just trying to get a sense of just how big these wells could be once the infrastructure does arrive here in the next quarter, about how much you might see these wells step up..

I think -- our JV acreage over in Noble County, we've just recently turned 6 wells, 2 3-well pads in line, and they are flowing into constrained pipeline right now. We expect that to free up in June as Blue Racer lays additional lines. But we don't think -- we don't expect to have any restrictions once we get that line in.

And then when you move over into Monroe County and we're going to drill a Utica and a Marcellus well in the same pad, that pad is kind of book-ended by some nice results from a couple of our peers, to both the north and the south.

I think you've all probably seen the rates that they advertised, about -- they were all -- both in excess of 30 million a day. So we're excited about the potential there and we expect similar results..

And how do you all foresee -- I mean, I guess, what does CNX do from a choke perspective? I mean, there's obviously one peer that tends to open these wells up, down in the south. There's others that talk about a much tighter choke management. I'm just kind of wondering, internally, how do you all think about that..

Well, we believe in bringing them on in a managed way, but we don't keep them choked back. We think we have a progression to opening the wells up, controlling the fluid rates and then managing the gas and the pressure decline as we bring them on.

But we're not a firm believer in leaving wells choked, but we're not a firm believer in ripping them wide open..

Our next question will be from the line of Jeremy Sussman with Clarkson..

Just 1 question.

When I think of the BMX Mine, I guess, first, is it lower cost than the Bailey and the longwalls? And secondly, as this ramps up to full production capacity, could we see costs come down even from the solid Q1 numbers that you put up?.

The BMX Mine should be at least as cost competitive as Bailey/Enlow recognized and is effectively a brand-new coal mine. So all the infrastructure call out by [ph] from the longwall is the simplest, smallest footprint of the 5 longwalls now that we operate in Pennsylvania.

Now what that again means with unit cost for the thermal complex moving forward into '14, there's a number of things going on, as Jim Grech's commentary on the market, the operational variance that we see quarter-by-quarter within a calendar year because of labor scheduling of vacation periods, as well as maintenance periods in the summer and those types of things.

And typically, first quarter is a stronger quarter for us because of all those above reasons. But as you look at '14 and we start to unroll the quarterly result on cost, we'll do 2 things.

One, we'll tie back how that changed sequentially from, say, first quarter to second quarter on our next call and what those impacts that I just mentioned were positive, negative.

And we'll also trace that back to prior year same quarter so that you can do an apples-to-apples comparison with it as well to take out the impacts of scheduling and workforce issues..

And we'll go to the line of Brandon Blossman with Tudor, Pickering, Holt..

Nick, just real quick, and these are all follow-up questions, the 30% year-over-year growth for the next 3 -- at least the next 3 years, it sounds like that's pretty much -- I don't want to use set in stone, but pretty much fixed in that short-term changes, and the underlying commodity prices probably won't have a material impact on that.

Is that a correct read?.

I think that's a good read..

Okay, great. And then, Tim, I know everybody has asked this question in several different ways, but kind of subjectively, where do you see days to drill, rig efficiencies, well costs and production levels -- how about giving a sports analogy in terms of innings.

Are you halfway through that process or more than halfway through?.

Well, right now, we're -- our drilling days in the Marcellus are running around 22 to 26 days. I expect we will get that down below 20 days, grow the numbers out there, but I would expect it would get down 17-, 18-day range. Flip that, we're looking at our rig move efficiency.

We probably -- last year, probably average rig move -- average rig move was 14 days. We'll get that down below 10 days. So we're -- I think we're about -- we've identified what we need to do. We're putting a plan together to get there. We've already seen some positive results. We've seen rig moves occur in 7 days.

Now we have to work on repeatability and doing that consistently. And the same with the drilling. We've got some fantastic drilling results. It's just working on making it more repeatable and being on a consistent basis. So I think we understand where we need to go, and we're on our way there.

We're certainly not there yet, but I think we see a pretty clear path forward. At the same time, efficiency is applied to our completion. We're reducing the cycle time around our completion as well by doing more stages per day..

Well, very helpful. I appreciate all that color. And then on service costs, Tim, it sounds like you're actually looking to drive down costs at the margin.

Are you seeing any inflation there on the horizon?.

No. I think -- I mean, the efficiencies are going to drive our costs down. I think it's important that we make sure that we're paying market rates for the services that we contract out but the efficiencies that we can reduce our drilling days, reduce our completion days.

Just the money we save in rentals alone on the drilling side and the completion side, I will say this is a tremendous amount of money. Plus, once we -- when we can consistently complete wells, complete more stages a day, that gives us an opportunity to reduce our cost structure around our completion and the same with drilling.

As we reduce our drilling days, we can look at all the different services, our rig contracts, and manage those appropriately..

Operator, I think we have time for one more question, if there are any other questions out there..

Our final question today will come from the line of Luke McFarlane with Macquarie..

So I just want to focus first on the Buchanan Mine.

I was just wondering -- I mean, can you quantify how much your costs, do you think, will be affected and then maybe talk to us about what you need to see from a pricing standpoint to get those tons back in the market?.

On the pricing, Luke, we'd like to see what happened in the market to get some positive momentum on the pricing, to see it -- it's been trending down, down, down. And we think it's hit bottom. We've seen a little bit of bounce off at the bottom here with these prices.

And once we feel that we're on an upward trajectory with the prices, as Nick said earlier, we can jump back into the market as aggressively as we want. So right now, at these prices, obviously, we've pulled out earlier in the year and late last year as some of the higher BMA prices in the $130s we were back -- we were in the market.

So as we see the prices trending upward, we'll make a decision at that time to jump back into the market..

Okay.

And do you think any of those tons will be sort of remarketed into Europe or domestically?.

We are trying to increase our domestic footprint, and we've had some success there, domestically, Luke. But as you know, as good as anybody, it takes a little bit of time to break into blend to increase the amount of coal in a blend and in a met blend. So we're working on that.

We're more optimistic that we'll have more domestic coal for Buchanan next year than this year..

Got it.

And then just my last one, very quickly, is in terms of your lateral lengths, is there -- like where do you think the efficiency is sort of in between drilling along the lateral length and actually shortening the time of a completion cycle? Like is there a certain distance?.

We're still -- we drilled as far as 10,500 feet. So we drilled some long laterals. First quarter, we're averaging about 7 -- 7,770 [ph]. So we're increasing our lateral lengths overall. I would expect that you'd see our average lateral length settle out somewhere in the 7,000- to 8,000-foot range. But we will drill longer laterals when we can..

Yes. And then, Luke, I'd say from a well count, the lateral -- the number of laterals as well, I think we've kind of set ourselves on somewhere around 5 or 6 per pad is more of an optimal as well..

Okay. Well, that concludes our call for today.

Tom, could you please instruct the listeners on how to access the replay?.

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