CNX Gas Corporation Q2 2008 Earnings Call Transcript

CNX Gas Corporation (CXG)

Q2 2008 Earnings Call Transcript

July 30, 2008 10:00 am ET

Executives

Dan Zajdel – VP, IR

Nick Deluliis – President and CEO

DeAnn Craig – SVP, Asset Management

Randall Albert – SVP, Emerging Business Units

Analysts

Scott Hanold – RBC Capital Markets

Shneur Gershuni – UBS

John Boland – Maple Capital Management

Presentation

Operator

Good morning, everyone and welcome to the CNX Gas second quarter 2008 results conference call. I will now turn the call over to Dan Zajdel, Vice President of Investor Relations. Please go ahead, sir.

Dan Zajdel

Thank you, John. Good morning everyone, and welcome to the CNX Gas Corporation's Second Quarter 2008 Conference Call. With me today are Nick Deluliis, President and CEO, and the CNX Gas management team.

Before we begin, let me remind everyone that various statements that we make during this call, including the guidance we give and other statements that express belief, expectation or intention are forward-looking statements under the Private Securities Litigation Reform Act of 1995. Actual results could differ materially from these forward-looking statements.

Information regarding the factors that may cause such differences is contained in our annual report on Form 10-K, which has been filed with the Securities and Exchange Commission. The SEC permits oil and gas companies in their filings with the SEC to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally produceable under existing economic and operating conditions.

We use certain terms in this conference call such as unproved resources or reserves that the SEC's guidelines strictly prohibit us from including in filings with the SEC. We also caution you that the SEC views such unproved resource or reserve estimates as inherently unreliable and these estimates may be misleading to investors unless the investor is an expert in the gas industry.

After the remarks by Nick Deluliis, we will turn the discussion over to the callers for a question-and-answer session with Management.

Now, I would like to introduce Nicholas Deluliis. Nick?

Nick Deluliis

Good morning, everyone. CNX Gas just completed another consecutive quarter that resulted in record performance both operationally and financially. It's something that all of our employees can be justifiably proud of. And most importantly, we delivered these record results by continuing to work safely. Another quarter passed in the company without an employee lost time accident with our streak eclipsing 3.1 million man hours and spanning 14 years. And our contractor safety incident rate continues to be a fraction of the average within the industry.

We posted record net income of $64.3 million and we also posted total company record production of 18.8 Bcf for the quarter. The production is a great cumulative result of what's more important as we accomplish our results through strong performance from all of our produced in place. So, individually, we had record production from Virginia CBM operations, and the Mountaineer CBM operations, Nittany coal bed methane as well as from our emerging Chattanooga Shale program. As a shareholder what you want to see from the growth company like ourselves is focused on internal and organic opportunities.

Let's talk first about the Chattanooga Shale, CNX Gas with the industry leading the shale by drilling the first four horizontal shale well in that play last December. And if you recall that well had an IP rate of about 3.9 million cubic feet per day which we still think it's a Tennessee state record. Based on that result we then committed to follow-up exploration wells and a follow-up exploration program, the result of which we've summarized in the release this morning.

And since our first quarter earnings call, we also worked quickly to consolidate our acreage position with regard to that shale play. So we effectively doubled down on acreage in the Chattanooga Shale going from about 132,000 net acres at year-end to 235,000 net acres today. Part of that consolidation was due to the buy-out of our 50% partner in the Knox Energy joint venture and we've also allowed our farm-out agreement with Atlas America to expire. So though we enjoyed sharing our early exploration risks, and successes for that matter, with Atlas and our Knox partner, today, we are in a position that we are confident enough to go to loan on future drilling and future development.

Now speaking of drilling horizontals in the Chattanooga, it's important to realize because the shale is only 3500 foot deep, we can drill these wells with what I will call standard truck-mounted Appalachian rigs with a hook-load capacity of 185,000 pounds. Since these are the rigs we are using for Virginia and Mountaineer or coal bed methane operations, we have obtained immediate optionality with our rig fleet, we can position our rigs throughout our acreage to projects that give us the highest NPV and then back to our lower end MPV areas and so more rigs arrive. Yet another economies of scale advantage we enjoy for our large Appalachian on conventional footprints.

Now, the rig optionality advantage with regards to Chattanooga Shale is illustrated by the increased efficiency in the Mountaineer coal bed methane play that we mentioned in the release this morning. So it's the rigs in Mountaineer now require 10 to 12 days instead of 20 plus days to drill the well, horizontal CBM well.

We need fewer rigs to complete our Mountaineer program of 100 wells this year. We can either drill more Mountaineer wells or take the excess capacity from that fleet and drill the Chattanooga horizontal wells to further delineate that acreage. Currently, our plans to do a little bit of both the thing continue to progress well with regard to the Mountaineer coal bed methane play.

So this is how we can now drill ten additional Chattanooga wells in 2008, we will shift the rig approximately two to the Chattanooga Shale while still meeting our '08 Mountaineer coal bed methane program.

Our legacy CBM position in experience with regard to CBM it lend itself well to developing shale expertise. We won't have to spend a bundle of money in times, learn how to drill horizontally in the shales because we cut our teeth on horizontal drilling in Mountaineer where we drilled about 100 horizontal wells over the past three years. Accrues and directional drillers have successfully capped the drill bit in six feet thick or less, coal seams that rolls up and down if we can do that we can certainly keep the drill bit in a 50 to 100 feet thick shale seam. And we are demonstrating that now again within the Chattanooga Shale.

Our ability to ship proves and rigs between CBM and shale plays also highlight the holistic philosophy of the company that we believe it's different from nearly every other producer out there. We are a developer of unconventional gas and we set a development program to optimize the MPV as a firm.

(inaudible) comes from a coal seam or a shale formation. What we do care about is it from an MPV perspective we go after the most accretive projects first and as we develop that we – develop at a rate that hopefully accelerate MPV without sacrificing efficiency. So at the end of the day the BTUs so the same from coal bed methane shales and conventional we have higher margins from CBM and shales and we're not going to feel guilty of our development in the CBM fields first.

The good example this is the Mountaineer play. This horizontal coal bed methane play and southwest Pennsylvania, northern West Virginia. So it's basically a science/exploration project. We did know it successfully engineered the gas out of the ground in a way that would make for our shareholders. In May of '06 we brought in our first dedicated rig and by September of '06 we proved we could consistently add value from the play.

So if we fast forward it to today, you see we have seven rigs run in the Mountaineer, and we are producing over 30 million cubic feet per day of sales under the meter. Our total cumulative investment including processing and gathering there is about $300 million. So when you compare this accomplishment which is not a projection for tomorrow, but reality today. The some of the excitement we see regarding Marcellus is no doubt we created hundreds of millions of dollars for our shareholders with our Mountaineer play to-date and we are going to be doing even more down to the road. But as much as the Mountaineer CBM play by itself a success story we wanted to disappoint those on the call that our second focus on the Marcellus.

You will recall that about half of our Marcellus acreage lies directly underneath our Mountaineer CBM play, and now, you can think of the advantages that it gives us. First and foremost, it gives us immediate what I will call goods on the ground with regard to development of the shale. We have nearly a 100 employees working out of our Waynesburg office which already operates the Mountaineer play and we would also have infrastructure whether it's roads or well pads or metering facilities that are in place to serve both plays. That is again Mountaineer coal bed methane in the Marcellus on conventional shale as they are developed.

So, our Appalachian legacy gives us those advantages, it also gives us a leg up in dealing with regulators that we have worked with on the coal and coal bed methane side for decades. So shouldn't take us here is the figure out how things need to get done regulatorily up here for compliance with the rules. So how all that culminate in the value for us? In today's release you saw that we had flow in production into the sales meter from our first Marcellus well two weeks after was scrapped. How did we do it? The site pad was only 200 foot from our Mountaineering gathering system and for our Marcellus Shale results continue to justify capital and we believe that it will and we can assure you that the capital again is going to be used efficiently.

And when you look at the (inaudible) Major of how efficiently we use capital within the company, our return on capital employed, you saw a very strong result for the quarter. Our annualized after-tax return was 25.9%. When all the results were in we think this is going to be one of the industry's highest. You won't hear too many companies putting this number on the front page of their earnings release, but its players within the capital intensive industry we should be doing just that.

We also took advantage of the second quarter run up in gas prices, the lock-in much higher volumes, a stronger prices for both 2009 and 2010, the use of a discipline latter approach continues to give us one of the industry’s best hedge books, we are not trying to time the market since we're not that smart, and we're also not going to lay in panic hedges as prices fall. No need to, because again, we're one of the lowest cost producers and the market is going to correct itself its capital constraints for higher costs and over-levered producers scale back potentially on growth plans.

So looking ahead for the rest of '08 you saw that we increased our production target to 73 Bcf, this was primarily on the strength of our existing CBM operations and for Virginia, we reduced the number of days, it takes us to bring wells on line, and we also conducted an extensive work over program. We're especially aggressive in replacing pumps on some wells and removing scaling from others. This aggressiveness increased our unit cost by about $0.06 per Mcf in the quarter, but it also meant that our legacy CBM production that is the production from our pre-2007 wells in the Virginia field, actually increased quarter-over-quarter. So we want to see if we can continue to work at a accelerated pace for an extended time without running into bottlenecks before looking or changing guidance on the production side for 2009 and 2010.

And we also remind you that we look at the production guidance whether it's ’08, 2009 or 2010, the numbers assume no meaningful contribution from the shales. So yes, we took a significant step with the Chattanooga Shale in the second quarter, and we expect to take the same sort of steps with the Marcellus Shale this quarter and the Huron Shale by year-end. So we're going to much more about our 955,000 net acres of eastern shales over the next few months. It's still early but so far we like what we see.

And lastly, we remain convinced with CNF Gas represents the premier hoarding in the E&P investor space. Investors get tried and true low beta CBM player that in fact is the largest gas producer by revenue in Appalachian basin, adds it is the potential for our shale plays which continued on full favorably. And you see that the risk-reward trade-off for our stock is as favorable as it ever been.

Thank you for your time and attention this morning. I'm going to turn it back over to Dan.

Dan Zajdel

Thanks, Nick. We're ready to take questions, John, from the audience. If you got into this call as a member of the media I'd ask that you hold your questions until after the call when I speak with you individually. John, could you please instruct the callers on the procedure for asking questions.

Question-and-Answer Session

Operator

(Operator instructions) And first we'll line up Scott Hanold with RBC Capital Markets. Please go ahead.

Scott Hanold – RBC Capital Markets

Thanks. Looking at production growth – and Nick, you indicated that there's not much contribution assume from the shale, can you give us sort of a better sense of what sort of the capital investment and maybe well drilled in, the focus on the shales will be here over the next year to, to kind of give some sense of how much upside could there be or will there be any sort of cannibalization, I know is that you indicated that some of these CBM projects are there pretty good rate to return, but the shale start actually really coming in a lot better than expected, would you cannibalize of some of these coal bed methane projects?

Nick Deluliis

Sure, Scott. With regard to the sort of the ranking of which project gets the rigs and the capital and the people focus it does go back to the net present value ranking that we spoke about in the comments. So, we see a shale play come in through the exploration program over the next year, that just looks to be the best NPV, best rate of return project out there within our portfolio because the first in the line and that's just again the way that we go about our decision-making. We don't think that if we do have successes in the shales that at this point we're in trouble with regard to things like rig capacity, or other resources in terms of having to take away from the CBM operations or their drilling programs that comprised of three-year production guidance. So from that perspective, we do tend to look at the shale as pure incremental to production to capital and to other resources within the company. Now, with the plans over the next year or 18 months with regard to those well, again, we got the $80 plus million exploration capital that was putting to work that's already paid dividends within the Chattanooga Shale and again, it's early with the Chattanooga Shale, but as I said we like what we see, we think we've got a bid of a blanket play with regard to that as much as the shale play could be for that matter, and we like the economics. We think from F&D perspective, without getting an IP rates in EURs or all those other things we think that overall efficiency capital on the Chattanooga Shale is going to be somewhere between Virginia and Mountaineer, a little bit better than Mountaineer, little bit higher with regard to F&D costs in Virginia. But again I want to stress thoroughly we will see, so far so good. Marcellus, there with regard to that first vertical well we've seen again, so far so good. Very accretive from economic perspective, we got some obvious synergies that we spoke about, so with regard to where we're out on those two, it looks again like we continue to allocate exploration capital resources and those production parallels and numbers come in from a rate of return in NPV perspective, think of it is incremental.

Scott Hanold – RBC Capital Markets

Yes. There seems to be a lot of synergies in the Mountaineer areas, especially if you're seeing those kind of results in the Marcellus and I'm just trying to get a sense of how much could CapEx – it sounds like obviously coal bed methane you still obviously committed to grow in that as you have current plans for, but how much could CapEx increase here in 2009 to really accelerate some of the shale plays and obviously you guys are from a financial perspective have always talked about recapitalizing the company obviously, don't have a whole lot of debt here, so is that something you're looking at is the opportunity here to sort of recapitalize company and accelerate some of these projects?

Nick Deluliis

Again, it's a success in the Chattanooga, and Marcellus continues to be confirmed through additional drilling. It would be NPV positive. There's no doubt about that which means we would want to layer that incrementally into our capital and production and drilling plans. We've got the financial wherewithal to do that, but right now, we don't want to commit to certain capital expenditure increases or production increases so we can basically bank on a certain level of the contribution from that in terms of the production. So what we're telling you there is if we do increase CapEx because of “success in the Chattanooga Shale” we will also couple with that an increased drilling number and an increased production number to go with it. And right now, I think we're good with regard to the CapEx numbers you see there the – what is that 552 million for this year which is an increase from the 470, but that was largely driven, it's not totally driven by acquisition capital in the Chattanooga, Marcellus and a couple of the coal bed methane plays.

Scott Hanold – RBC Capital Markets

Okay. One last question, on the work over, sounds like that provided a nice uplift in production, what is the opportunity to kind of continually run at that higher level here going forward? Can you sort of sustain that over the next couple of quarters or will there be sort of a limit to that?

Nick Deluliis

I think that it's becoming an increasingly important area of our portfolio because we keep drilling more wells in Virginia. You go back as little as three years ago, we're sign out – there has been a substantial increase in the number of wells drilled in the legacy time period of those wells whether they prior to it's been out of or post of it is increase as well. So it's a bigger and bigger issue for us. We did accelerate that activity besides this quarter, that is the second quarter versus prior period and there is still probably two or three quarters left of that accelerated pace. Now, whether it gives us the positive results that we've seen second quarter compared to prior periods that remains to be seen. But again from an NPV perspective, that's about some of the best money and effort that we can spend within the company. And I'll also point out – and we talked about this through prior times, too, that keep in mind, the technology that's available today with regard to fracking, and with regard to knowing what zones you're completing and what zones you're not completing, that come a long way since 5, 10, 15 years ago when many of these wells were drilled. So, there is also sort of a technology swan into the addition to the fact that we got thousands of wells in Virginia that have the capability or potential for workovers.

Scott Hanold – RBC Capital Markets

Okay, thanks a lot. Appreciate it.

Operator

Next in line of Shneur Gershuni with UBS. Please go ahead.

Shneur Gershuni – UBS

Hi, good morning, guys.

Nick Deluliis

Good morning.

Shneur Gershuni – UBS

I was just wondering if you can sort of comment on the usual challenges that the people commenting on with respect to Marcellus, with respect to gathering and water permits and whether you see this a long-term challenge or something that really effects you or not within the play?

Nick Deluliis

I think that all those issues that we're hearing about I think they're real. They need to be dealt with and managed, and there is obviously an efficient way of managing it and may be not so efficient way of managing it. They're very similar if not the same issues that we face with regard to starting up the Mountaineer coal bed methane play, three to four years ago, depending on where you start the measurement point from. So again, that gives us a certain leg up, or a certain advantage with regard to either know-how and expertise because of our experience there or with regard to hard assets, whether it be the gathering lines or the processing equipment or the drill rigs fleet, et cetera. So I think they're real, they need to be managed, they definitely impact the capital requirements for project moving forward, they also impact maybe more importantly, the timing with regard to bringing projects online and bringing production into the flow meter, which is where of course you start to make your money. The best example or illustration I can give you of the culmination of those advantages that we feel we hold because of the Mountaineer coal bed methane experience is what we talked about this morning, where we droved our first Marcellus well and within two weeks of fracking it, we're selling that production today into the meter at very economic and accretive rates of return. So it's real, each little step or link in that chain of development for Marcellus has its own unique characteristics and challenges. We think we're in a very good position to manage that moving forward.

Shneur Gershuni – UBS

How receptive is the board to positive MPV projects to green lighting them and so forth. You need to do a little bit more gathering capital investment and so forth. What's your take on with respect to the board, will they really allow you to lever up if it will give you some serious MPV positive projects to tackle on so forth?

Nick Deluliis

The good news is we've got three years of experience under our belt as a standalone company operating and working with our board of directors. I can tell you honestly, over the past three years, I can't think of a single issue that we felt from an MPV perspective or from a management perspective that made sense for the company that was denied. So I think their last step with regard to our philosophy that we have applied our decision making and I think if we make the case to them that there is accretive economic rates returned and NPV tied to them, the Marcellus Shale play or Chattanooga Shale play, they will be willing, and have been willing to historically to push down on the gas pedal, upon intended to get more than what we currently have planned. So, I'm very bullish on that. And it's up to us basically as management and to make that case to the board and I think they will obviously do the right thing because they have done that for the past three years.

Shneur Gershuni – UBS

Okay. And one final question if you don't mind. I'm just reading this some press reports and so forth, but another large player in the play has questioned the lack of frac barrier, which may cause efficacy issues in addition to infrastructure water from the challenges, and there is sort of talking about lower EURs as a result. Is that something that you would agree with or you think it's a challenge or you think it's just a local issue for that one specific area?

Nick Deluliis

What was the constraint that they mentioned?

Shneur Gershuni – UBS

They mentioned a lack of frac barrier causing efficacy issues that could lead to lower EURs

DeAnn Craig

We have not experienced that yet, but again, we've only done the one Marcellus well and we have more work to do. But, again, this first well is something that we have not encountered.

Nick Deluliis

I think the other thing Schneur that it comes down to what you assume the EUR is.

Shneur Gershuni – UBS

I guess that was my next question for you. What's your assumed EUR? I know that you haven't had a chance to model yet, but in attacking this well has been the capital on, there have to been some sort of plan that you're hoping that you're going to have at least the base you're, I was kind of wondering what kind of – how you were thinking when you decided to outdate capital to it?

Nick Deluliis

Currently, this first well that we've drilled, we got some data that we placed in the release with regard to it, and then we commented on this morning. We can tell you that today that the production flowing into the meters has increased quite a bit since when we first placed it in the meter, just about under a million a day, about 850,000 a day. There are constraints there with regard to our compression and processing that's holding that back with the back pressure issue. But that IP rate that we think we're seeing and that we think will be sustainable is very much in line with what we assume and we need it for an economic rate of return. And we have the EURs that we've assumed or heard from others out there in the basin, probably generally speaking we're lower, but from an MPV and IR perspective, we like what we see. And if our data indicate that they should be increased over time then we will increase it. Let's start from a relatively conservative point and go away up as opposed to go the other way around. That sounds great to me. Thank you very much, guys.

Operator

(Operator instructions) And we'll go to the line of John Boland with Maple Capital Management. Please go ahead.

John Boland – Maple Capital Management

Great. Tank you. Good morning, guys. I was wondering if you could just shed few quick comments on the cost side of the equation. You seemed to have gone up rather sharply year-over-year and I was just wondering what's driving that, what kind of resolution we may have and what we can expect going forward?

Nick Deluliis

I think the unit cost issue – I'm comparing quarter-to-quarter, second quarter of '07 versus the second of this year. I think the unit cost issue is pretty straight forward. If you look at it on a unit cost basis, if you look at stock-based compensation and short-term incentive comp, that's a 15% unit cost increase quarter-on-quarter. Okay. With regard to – we put that in our G&A line. If you look at some legal fees and really we call it legal fees, but in essence, it's the registration fees for our carbon credits on the Chicago Climate Exchange, this second quarter versus last year. That's a $0.06 to $0.07 increase again also in G&A. So those three items right there it's over $0.21, $0.22 of unit cost increase, all of that in G&A, quarter-on-quarter compared to '07 to '08. Very explainable and good news, I mean the reason the comp increase on a unit cost basis is because we're ahead of our plan that's the production guidance increase, the share price has appreciated, that's good news obviously for shareholders. So those are the things that you necessarily would not want to see. The other big driver of unit cost in the quarter are things like severance tax which we break out under our table 2 within the earnings release. That's up because it's a percentage of realization and when realization goes up, you're going to pay more in severance taxes. You don't mind seeing that either. That's the same as the incentive comp issue and that's up about $0.07 quarter-on-quarter compared to the two years. And then the last thing, of course, is the workover program that we spoke about in the comments and that again will fall under production costs and be able to with regard to listing. So, we feel good about the unit costs, we think we know what's driving them, we think they're explainable. And the fact of the matter is that we weren't hitting our production target and the share prices down quarter-on-quarter and we would have had lower G&A, but that's not what we want to see with regard to shareholder value.

John Boland – Maple Capital Management

Okay. And then just one quick question on the New Albany shale. I noticed the oil production out there. (inaudible) little bit of a surprise. What kind of – what are your expectations on that play?

Nick Deluliis

I will throw it over to DeAnn Craig and Randy Albert, but let me just give you the big picture perspective on that play. We see – or I think of it as two different types of opportunities. The first type of an opportunity is very similar in some ways to maybe our coal bed methane plays. What I mean by that is somewhat boring, (inaudible) bylines, but extremely profitable, high rate of return, high MPV project. And that goes back to the nature of how we consolidated that footprint out in the mid continent area. This largely came from CONSOL Energy and Peabody Energy through the spin out in the acquisition of the Peabody gas rates. And again, coal companies historically for decade didn't want to develop or see development of those shallow conventional oil or natural gas deposits because of that not being their focus and wanting to go after maybe down the road some of this coal seams. So if you look at the development that has occurred many of those pockets we're literally surrounded by historical wells being drilled, but then you got this relatively Virgin area, it's been undrilled from a shallow oil or gas perspective because again, that was never the focus. So that one sort of one portion of that play and that goes back to the well oil data that you just spoke about. The other side of the play is sort of in many ways a mere image of what I just spoke about which goes to the New Albany shale. And the way I think about that great upside, great potential, also some big challenges because it's much more a complex issue, especially with regard to permeability and that what you would see with shallow oil or shallow natural gas. That's a much longer-term issue and project and opportunity, but also with a lot of upside. Now, what I would like to do now is just maybe turn it over to Randy and DeAnn, Randy can talk about that first phase, DeAnn can talk about what we're doing on the second phase of the New Albany shale.

Randy Albert

Yes. We drilled the first oil well out there as a new Albany shale well and we found an old boons [ph] and we came up back up and did an all set tool and call roughly a thousand barrels of the oil today. We're permitting and getting ready to do some offsets to that well. Very shallow, very economical production at yesterday's prices. So we look forward to written off. I will turn over to DeAnn to talk about the expiration.

DeAnn Craig

There are two parts to our acreage position. The first part we are aggressively developing prospects for shallow oil and gas in the Peabody acreage that we have acquired and that continues. The second part, if you remember the New Albany, if you look at the SMI [ph] log, has its much fastest place as the Marcellus. It's just the permeability issue. We're participating in the Rupsea [ph] project which the government, DOE finally signed off on and the first meeting is August 14. In case you're not aware of that project, it's industry, it's academia and it's companies looking to unlock the New Albany. And so again, August 14, two of our team members are going to go and start working on that. No slower than we'd like, but quite frankly, we're quite busy with the Marcellus and the Chattanooga and it's going to take a little more homework on the New Albany.

John Boland – Maple Capital Management

Thank you.

Operator

And with there are no further questions in queue, I will turn it back to the presenters for any closing comments.

Nick Deluliis

Thanks, John. Thanks and I will say that I will be around later in the day if anyone has any further questions. I'm at 412-200-6719. Thanks very much. And John if you can just give the replay information.

Operator

Certainly. Ladies and gentlemen this conference is available for replay that starts today, 12.00 p.m. Eastern Standard Time and will last until August 6 at midnight. You may access the replay at any time by dialing 800-475-6701 or 320-365-3844 and entering access code of 922808. Those numbers again, 800-475-6701 or 320-365-3844 and the access code 922808. That does conclude your conference for today. Thank you for your participation. You may now disconnect.

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