CNX Gas Corporation Q4 2007 Earnings Call Transcript

CNX Gas Corporation (CXG)

Q4 2007 Earnings Call

January 29, 2008 11:00 am ET

Executives

Daniel J. Zajdel - VP Investor and Public Relations

Nicholas J. DeIuliis - President, CEO

Mark D. Gibbons - CFO

Stephen W. Johnson - General Counsel

DeAnn Craig - SVP Asset Assessment

Randall M. Albert - SVP Emerging Business Units

Analysts

Scott Hanold - RBC Capital Markets

Rehan Rashid - Friedman, Billings, Ramsey & Co.

Raymond Deacon - BMO Capital Markets

David Heikkinen - Tudor Pickering & Co. Securities

Pavel Molchanov - Raymond James

Presentation

Operator

Good morning, everyone, and welcome to the CNX Gas fourth quarter 2007 results conference call. I will now turn the call over to Dan Zajdel, the Vice President of Investor and Public Relations. Please go ahead, sir.

Daniel J. Zajdel - VP Investor and Public Relations

Thank you, John. Good morning, everyone, and welcome to the CNX Gas Corporation fourth quarter 2007 conference call. With me today are Nick Deluliis, President and CEO, Mark Gibbons, Chief Financial Officer, DeAnn Craig, Senior Vice President Asset Assessment, and Randy Albert, Senior VP Emerging Business Units.

As you know, earlier today CONSOL Energy announced that it intends to commence an exchange offer to acquire all outstanding shares of CNX Gas common stock not already owned by them. We also issued a press release announcing that our Board of Directors has formed a special committee of independent directors to consider CONSOL Energy's offer. We do not have any comment on CONSOL Energy's announcement at this time, and we will not be answering questions concerning that announcement on this call.

Before we begin today's call, let me remind everyone that various statements that we make during this call, including the guidance we give and other statements that express a belief, expectation or intention are forward-looking statements under the Private Securities Litigation 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 10K, which has been filed with the Securities and Exchange Commission.

The U.S. Securities and Exchange Commission 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 producible under existing economic and operating conditions. We use certain terms in this conference call such as unproved 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 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 and Mark Gibbons, we will turn the discussion over to the callers for a question-and-answer session with management.

Now I'd like to introduce Nicholas Deluliis. Nick?

Nicholas J. DeIuliis - President, CEO

Thanks, Dan, and welcome everyone.

CNX Gas has just entered its fourth calendar year at the start of 2008, and looking back in 2007, we feel we finished one of our strongest operational quarters in what was overall a great year.

And there's a number of reasons as to why we feel this way that we'd like to cover with you today, but first let's get to the big picture. On the production side, we were obviously hindered by the Buchanan mine issues. Annual production of 58.2 Bcf would have been approximately 62 Bs if the mine issues did not occur. Net income of $0.90 per share for '07 was impaired by about $0.11 due to the coal mine issues.

So okay, the coal mine issues hurt, but when you look over CONSOL's recent updates regarding the mine situation, it looks like those issues are pretty much behind us and them. CONSOL restarted the ventilation fans at the mine on January 20 and re-entered the coal mine yesterday. Everything looks so far good, and we have already seen some limited rebounding of gob gas production. We should be back to full and normal levels of gob gas production by the end of February, and that will not only help production but also improve margins, cash flow and, of course, earnings.

So there's good news all the way around regarding the mine situation, but there's even better news about the year 2007's performance that spills into 2008 and beyond. And first and foremost, we maintained our spotless employee safety record with eclipsing 2.7 million man hours with no lost time accidents in the employee base. And we did that with an employee count that's today nearly triple what it was when we started out in 2005.

We set new drilling records in Virginal coalbed methane operations with 294 wells in '07. This easily exceeded the planned target of 278 wells, and it's even more impressive when you consider that our [inaudible] fleet was deployed in late summer to help combat the Buchanan mine situation with CONSOL Energy. We would have been able to drill even more frac wells in the Virginia field but for the mine incident. And we want to drill about 300 wells in Virginia this year, and we see no reason why that should not occur.

And our Virginia field continues to surprise us with regard to new opportunities for further value. Two great examples of this we summarized in our earnings release. The first was horizontal coalbed methane wells drilled into single coal seam and some of the less promising center coal seam areas of our field. The results from these three horizontal wells which have been producing for between one and three years show the economics are in line with vertical wells in Virginia at about three times the capital costs and about three times the gas profile. So that means we've effectively added future drilling locations to the most marginal area of the Virginia field with the same economics of the vertical program in our better areas within Virginia.

The second example of upside that continues to unfold in Virginia is the potential for 20 acre infill drilling. Much of our Virginia field was originally drilled on 80s and downspaced to 40s, and that's already been approved by the Oil and Gas Board and it's been proven to be economic. About 60,000 acres of our field was drilled originally on 60s, and we're in the process with downspacing those to 30 acres, which also look to be economic. When we look at data from wells that were drilled on less than 30acre spacing  and we have such data from wells in our field that have been producing for years - we see potential with regard to both PV-10 and incremental reserves for these new locations.

Now we want to caution that a lot needs to happen in the assessment phase with regard to Oil and Gas Board approval and obviously the final drilling program stages before this becomes a reality, but the potential does exist and the preliminary data do look promising enough at this point to warrant a methodical approach to assessing the opportunity.

Now if we leave Virginia and we move to Mountaineer, we set new drilling records in Mountaineer in 2007 with the coalbed methane operations with 62 wells. This handily beat the plan target of 57 wells, and when you consider we had a late start due to extended dewatering at our new locations earlier in the year, you begin to really get excited when you think about our chances for drilling 100plus wells in Mountaineer during 2008.

The production target for Mountaineer in '07 was missed, but that's largely due to the extended dewatering I just spoke about along with the delays in bringing drilled wells online into production due to some land and processing issues. But we ended '08 with our legacy production in line with what we need to achieve the field target, and overall production company targets I'll speak to in a few minutes.

In the well profiles, in Mountaineer they continue to meet or exceed expectations on average as we enter newer subfields within Mountaineer. The most promising of these is the Fallowfield region, where our first wells have begun producing into a new processing facility and one horizontal well is producing just shy of 900 Mcf B, which is an all-time record for Mountaineer and which is also promising for the Fallowfield area overall.

We rolled out the Nittany coalbed methane operations ahead of schedule on November 1 of last year, and we also exceeded the plan there by drilling 14 wells during the year. The well curves we are seeing so far have easily beaten the type curve in our economic projections, and we're going to reassess those curves midyear to incorporate the new data from these wells and to refine our projections for the overall field.

When you look at 2008, we've got a production target of 72 Bs. Just under 60 Bcf is to be from Virginia coalbed methane operations, about 10 Bcf of that will be from Mountaineer, and about 3 Bcf will be from Nittany. We backed down our original production target of 73 Bs by 1 B, and that reflects the full start of the Buchanan mine from first of the year as the original assumption to late February being the current assumption. Our legacy run rates at the end of '07, when you look at Virginia frac wells, Mountaineer and Nittany are where they need to be to hit the 72 Bcf targets.

Now, as great as the operational developments have been across the producing fields, we're even more excited about our record 2008 capital expenditure program of $470 million, including standalone exploration being $88 million of the $470. This budget includes $208 million in capital for record drilling in our three coalbed methane plays I just covered. Those are Virginia, which are going to be about 300 wells vertical, Mountaineer, about 100 horizontal wells, and then the Nittany coalbed methane play, 100 vertical wells. If you add that up, that's a total of 500 coalbed methane wells, a 35% increase from our '07 well count in these same areas, which was 370 wells total.

Our supporting infrastructure of $129 million is up only 25% in '08 over last year, so some of last year's investment in midstream is going to benefit our project economics in '08 and beyond. But one of the most important components of the '08 capital expenditure program is the $88 million for the exploration budget. And we separated our exploration budget into two pieces, what we're calling coalbed methane exploration and shale exploration.

The $27 million for coalbed methane exploration, that's going to include funds for testing our extensive Illinois basin acreage, but also funds for drilling within new areas of our three existing coalbed methane plays. This is where much of the upside for things like the horizontal coalbed methane wells in Virginia, the 20acre CBM infills in Virginia, and new areas in Mountaineer such as Fallowfield get identified and evaluated. It becomes the incubator effectively for future capital deployment in our more established plays.

And we're most enthused about the $46 million we've allocated to testing the shale plays. In the capital budget release, we provided you last week with an update on our shale acreage and the scope of our position is huge - 160,000 plus acres of Marcellus, nearly 200,000 acres of Huron, 130,000 plus acres of Chattanooga, and 300,000 acres of New Albany shale.

And within the industry, as most of you know, the buzz right now that's being created by producers in the region is that of the Marcellus shale. Some analysts have even said that this could be the hottest emerging gas play in the U.S. right now, and others, frankly, are a bit ahead of us in testing the Marcellus and they posted impressive preliminary results. But we've got acreage in close proximity to theirs, and we're going to quickly close the knowledge gap. Our strategy in the Marcellus is going to be to drill several vertical wells in our key holdings. We'll also be drilling in one area with a partner who has been successful in other shale wells. We want to assess our economics with verticals first because we're not sure that we need to commit to more expensive horizontal wells at the outset.

Basically the same can be said for our Huron acreage in Kentucky and Virginia. We bump up against established players within our acreage, and we'll be drilling verticals in the Huron in '08 and assessing those prior to bona fide drilling.

Both the Marcellus and Huron shale plays provide us with an interesting opportunity relative to the peers in those plays. Because we're off to a late start in these areas and because the peers have focused substantial resources to optimizing these opportunities, we have a bit of a free option on the development. By being six months to a year behind the curve, we stand to learn from others' mistakes and others' successes, and this should improve our all infield economics and NAVs looking forward.

Now, the Chattanooga shale story is a little bit different from the Marcellus and Huron. For years we participated in the drilling of verticals that penetrated the shale, and the results for the most part have been modest at best. We then decided to try a horizontal well because the shale is often only about 50 foot thick, and as we said in today's release, this first horizontal well has sustained production of 300 to 400 Mcf per day, and that's with gathering pressure limitations collaring flow rate. Open flow tests indicate it's just under 4 million cubic foot per day, and obviously we don't need this much production for these wells to be profitable, so when we look at 2008 we expect to drill another four horizontals to see if we can replicate this result. With a concentrated footprint of over 130,000 acres there, this could be meaningful for us, and from a project economics perspective, keep in mind we already have some surface infrastructure in this area although it would need some upgrading if we end up consistently duplicating the well results we just saw.

In the New Albany shale, through our testing and the results of others, we think we've identified some areas with greater potential. We'll be looking to drill more verticals in these areas on our own, following up with horizontals, or we'll try to partner with successful players in specific areas. We don't want to say much about this area just yet for two reasons: first, we're still executing exploration plan and data assessment, and secondly, our findings have so far led us to concentrate efforts in certain areas within the basin and we don't want to make it more difficult for ourselves with regard to other producers trying to acquire rights in those specific areas.

Then beyond coalbed methane and shale plays, we've got the deepest horizon of all within our portfolio, the Trenton Black River. We believe that all of our 480,000 plus acres of Appalachian shale contains the potential for TBR formations as well, and we'll be participating in at least one TBR well in '08. This follows the successful participation we had in '07. Because of a confidentiality agreement with one of our partners in the TBR, we can't say more about that effort at this point in time.

And then lastly on the exploration side we're getting into the oil business, and we'll be testing for shallow oil in our Ohio Buckeye acreage position and on some of our Illinois basin oil and gas acreage. In both of these areas, others have produced oil from shallow formations for years. Now we're going to test our acreage, and we're certainly excited about those prospects.

So just to remind you have far we've come since our inception in mid '05, in that year we had $100 million capital budget. We were basically a company with one successful play, Virginia coalbed methane. And we drilled 173 wells in that play, and we thought we had an official control acreage position of about 1.1 million acres.

Today, we've got 3.8 million gross acres of control, which would also be our net acreage position if you counted our TBR acres as being separate from our shale positions, which they certainly are separate opportunities. And we'll be drilling 500 development wells. We've got a separate exploration budget that nearly matches our entire 2005 development capital budget.

So CNX Gas has come far in two and a half years, but our feeling is that we've only scratched the surface. Even in Virginia, where we've drilled thousands of wells, we've learned quite a bit. In '05, our standard spacing was on 80 acres. Today we're drilling on 30-acre spacing and we're investigating the possibility of drilling on 20-acre spacing. We've also had success with horizontals on acreage that we thought might be too poor to drill with verticals in Virginia.

Virginia operations, when you look at it, it continues to be the field that keeps on giving, and with the potential for Huron and tight sands directly beneath the coalbed methane in Virginia, we've got the real possibility of owning 100% of a tremendous resource across different vertical horizons.

Then when you look at the newer plays on the coalbed methane side like Mountaineer and Nittany and you see how those have unfolded over the past couple of years, you see the same dynamics that we saw with regard to Virginia and those areas currently in the near future.

So the story at CNX Gas remains what it was at the inception in 2005. We're going to accelerate the monetization of the tremendous asset base we were deeded and that we grew, and that's exactly what we're doing.

So thank you, and now I'm going to turn it over to Mark Gibbons, our CFO, for a discussion of the fourth quarter financial results. Mark?

Mark D. Gibbons - CFO

Thanks, Nick.

I'd like to spend a few minutes discussing unit costs. When it comes to analyzing our fourth quarter results, we see once again we're affected by the deferral of our lowest cost volumes at the Buchanan mine. Total volumes deferred in the fourth quarter were 2 Bcf, and that was up 1.5 Bcf from the third quarter.

So how does this affect us? The first way is obviously that the unit cost increase simply because there were fewer volumes over which to spread them. Also we estimate mine-related volume costs of only about $0.50 per Mcf in lifting. So naturally, not having these volumes means were left with higher average costs of production.

All in all, before field remediation efforts and assuming we had the 2 Bcf, our unit costs would have been $3.49 per Mcf. This is still higher than historical levels, so why is this?

As we said in our release, we took extra field maintenance action in order to replace some of our deferred volumes in the mine. This came in at about $0.10 per Mcf, but it kept our volumes to a more respectable level.

Second, we had some extra road maintenance expense associated with Mountaineer, the Mountaineer production, that cost us about $0.06 per Mcf.

And third, we had a timing issue associated with some property taxes that all fell in the fourth quarter that cost us about $0.05 per Mcf.

Pull out these items, and you're closer to a $3.28 unit cost run rate.

Now DD&A was the only other area where we saw some meaningful cost increase. This category - and on the production side in specific - was up $0.10 quarter-over-quarter. As we added more investment to our Mountaineer field, we have higher F&D costs which translates into higher DD&A.

On the revenue side, our average sales price was flat over last year's fourth quarter at $7.10 per Mcf.

Moving on the cash, CNX is one of the few essentially debt-free companies in the industry. This is no easy task given how we grew our acreage footprint and our capital spending in 2007.

Nick in his comments looked back at our operational successes over the past two and a half years. I didn't have to remind him, but I would like to remind you that we started out with a whole $7,000 in the bank. Today, we're at $32 million and with a much bigger operation to run. I'm proud of the fiscal discipline that we've exercised that has enabled us to maintain this sterling balance sheet.

Our development drilling program coming up here in the next year should be fully funded by our operating cash flow. We might have to dip into our credit facility in 2008 to fund parts of the burgeoning exploration program, but this will in part be dependent on prices and the initial exploratory successes. More success with the drill bit means we have more short-term cash requirements. Here's to hoping we have more short-term cash requirements.

On the hedging side, you've seen our table in the release and all I'd like to say about that is we're going to continue to stick with our ladder approach in hedging more volumes only when prices are right.

With the mine issues soon behind us, I look forward to updating you on the next call with numbers that begin to reflect what you've always know CNX Gas for and that is the safest, lowest cost and among the highest ROC companies in the industry.

With that, let me turn it back to Dan. Dan?

Daniel J. Zajdel - VP Investor and Public Relations

Thanks, Mark.

At this time, Operator, we'd like to open the conference call to questions. Could you please see if there are any questions out there?

Question-and-Answer Session

Operator

Certainly. (Operator Instructions) And first we'll go to the line of Scott Hanold with RBC Capital Markets. Please go ahead.

Scott Hanold - RBC Capital Markets

Good morning.

Nicholas J. DeIuliis - President, CEO

Good morning, Scott.

Scott Hanold - RBC Capital Markets

It sounds like you guys got a lot going on here operationally and elsewhere.

Looking at I guess your shale assets which it seems like you're going to really start to take a hard look at here over the coming year, can you kind of give us a sense - I know you'd indicated you're going to be drilling some Marcellus as well as lower Huron wells and Chattanooga wells. What's sort of the timing of those, and can you kind of give us an idea of like how many of each type of well you're going to be drilling?

Nicholas J. DeIuliis - President, CEO

Yeah, I'll turn that over to DeAnn Craig.

DeAnn Craig - SVP Asset Assessment

Yes. Hi, Scott.

Well, with the success that we're having with Chattanooga, immediately we've got programs for a minimum of three more wells very near term.

New Albany, we actually just recently TD'd the vertical portion of an exploration well, and we're looking at how we're going to be going horizontal and what kind of appropriate stimulation program we're going to have there. And that will determine how many and how soon those wells will be.

Marcellus, we have one drilling now. Again, we're looking at that and that will determine the two or three more that we're hoping to go ahead and do this year.

And then I know I'm leaving out the Huron, and right off the top of my head, we do have several Huron wells planned this year, but they are going to be a little bit later in the year.

Scott Hanold - RBC Capital Markets

Okay, so--

DeAnn Craig - SVP Asset Assessment

Chattanooga is very busy right now.

Scott Hanold - RBC Capital Markets

Okay, so we should start hearing some news as far as some of the results of some of these shale plays by around midyear, is that a fair statement?

DeAnn Craig - SVP Asset Assessment

You know, I'm going to go ahead and get those results before I go ahead and commit to that. Right now, particularly on the Chattanooga what we're doing, not only are we going to be looking at the area that we are in, but we're really branching out just to see the extent of the fairway and the extent of our model.

And so, you know, depending on what happens, it might take us a little bit longer before we tell you a lot. If it's really good, we've got other things we've got to do, right?

Scott Hanold - RBC Capital Markets

Okay.

Nicholas J. DeIuliis - President, CEO

Scott, that's similar to the situation in New Albany we spoke about, which - you were doing the engineering assessment and the operational drilling technique assessment and then once we see what those conclusions are, that's also going to drive our M&A and business development effort within those basins.

So, you know, expect results across all of those throughout 2008, but the timing of those, we've got to think that out with our business development and M&A effort.

Scott Hanold - RBC Capital Markets

Okay. And what is sort of the thought on the New Albany? You've obviously drilled some wells there. Are you still encouraged with what you're seeing up there? Obviously, you're going to invest some more capital. If you sort of look at what your thoughts were a year ago versus where they are now, are you more excited about the opportunities in some of the other Appalachian shale plays like Marcellus and Huron and Chattanooga versus the New Albany?

DeAnn Craig - SVP Asset Assessment

Well, I would just say that with the New Albany we certainly learned a lot and we have a very good idea where the fairway productivity area is and we can continue to focus on that area and maximize where we want to be.

That, in my mind, is a big step from where we used to be and certainly will create greater shareholder value. I'm very excited about what we're looking at in particularly one area.

Regarding the Marcellus, you know, there is so much excitement about the Marcellus. I think it would be very difficult for anything to ever reach that excitement level. That certainly is a big thing here. And we've got our own location right now, and we're pleased.

Scott Hanold - RBC Capital Markets

Okay. On some of those shale plays like the Marcellus, Huron and Chattanooga, do you all own the land in fee on some of that stuff or do you still pay the royalty on some of that stuff.

Nicholas J. DeIuliis - President, CEO

Well, with regard to the surface, typically we do not have the surface ownership, Scott, so we have to work with the surface owner. But with regard to the acreage positions, a lot of that is owned in fee. It just depends area by area.

The other thing, too, just to give you my perspective over the last three years on the shales in general, you can look at New Albany in particular, what we knew about New Albany and our thoughts on New Albany six months before DeAnn came versus today, which has been about six months since you've been here, it's been a whole sea change in terms of that understanding.

And we've quickly come up on the learning curve. I mean, the more questions we answer, the more questions are raised. But you've got to feel good about the learning curve overall in terms of what we've done in just the past year.

Scott Hanold - RBC Capital Markets

Yeah. And are you guys going to be operating all these shale tests you're going to have in the Marcellus and the Huron and such?

DeAnn Craig - SVP Asset Assessment

We're going to go ahead and do what makes sense. Because particularly if you are looking at horizontal wells, you know, there may be times that it actually makes sense to be able to go-- with the faulting considerations, it may make a lot of sense to partner with somebody else.

And so whatever is best for the well and the development is how we will go ahead and proceed.

Scott Hanold - RBC Capital Markets

Okay. And it sounds like you're going to try to become a little bit oilier here by testing some shallower oil zones in the Illinois basin. Can you give us a sense, has there been successful drilling by other operators in and around the area you guys are going to be testing that?

DeAnn Craig - SVP Asset Assessment

There are areas where we have acreage that have been surrounded by others, but for a variety of reasons, this acreage has not been tested. And so what we're trying to do is develop the prospects, and then proceed from there. But we are in fact encouraged.

Scott Hanold - RBC Capital Markets

Okay. And one last question, year end reserves, any thoughts on that, when we're going to get that number and directionally, how does that look?

Nicholas J. DeIuliis - President, CEO

Directionally, we're not going to have any comments. We're in the process of doing that right now, and we will probably have something around the second or third week in February. We would like to get the reserve report out a little bit prior to the issuance of the 10-K.

Scott Hanold - RBC Capital Markets

Okay. Thank you.

Nicholas J. DeIuliis - President, CEO

Yep.

Operator

The next question's from the line of Rehan Rashid with FBR. Please go ahead.

Rehan Rashid - Friedman, Billings, Ramsey & Co.

Morning, Nick.

Nicholas J. DeIuliis - President, CEO

How are you?

Rehan Rashid - Friedman, Billings, Ramsey & Co.

Good, good. So definitely, like the Capex bump year-over-year, I think I've got maybe a multi-fold question on that front. The first one would be how much from an organizational capability standpoint - is $470 the max number you can spend and maybe also give me a feel for and call it in three to five years, if you can look out, would you be able to ramp up your Capex even as much as you have over the last couple of years.

Nicholas J. DeIuliis - President, CEO

Yes. That's an interesting point about the company. If you look at us starting '08 compared to when we came out in '05, you look at the development side of our capital program, basically what we're drilling to get immediate production.

You've seen a very impressive [inaudible] growth rate but more importantly, when you look at '08's capital budget, you look at the well counts across the big three areas of Virginia, Mountaineer and Nittany - all of the coalbed methane plays - 300 wells in Virginia, it's very doable. We damn near did that this year, as I said, with a lot of those rigs in the summer deployed to assist in the Buchanan mine situation.

You look at 100 wells in Mountaineer, that's a big step up from 62 that we did in '07, but 57 wells were the original bogey for Mountaineer last year. We obviously exceeded that with 62. And when you look at the overall Mountaineer operations  and we've got Randy Albert here today - it's just amazing with regard to what that operation has done from a personnel perspective, from a drilling perspective, and from a land permitting perspective in a very short period of time.

So if you would have said a year ago, the end of '06, we'd be drilling over 100 wells in Mountaineer in '08, I would have probably told you the chances of that were pretty slim. We think we've got a really good chance of exceeding that, not just hitting it.

Nittany - heck, Nittany two years ago didn't even exist. We drilled 14 wells, I believe, last year in Nittany. Results look really promising. We're ready to go with 100 wells there. Now, these are verticals. They're not horizontals like in Mountaineer, and from a drilling perspective in Nittany, we see no reason why we can't drill 100 there.

So operationally and from a personnel perspective and a drilling perspective, the capital portion that's development drilling within our $470 million, we feel really good about that, which means we feel really good about the 72 Bs that the production guidance is predicated upon.

The other side of it, the exploration side, that's where we've had to come up the learning curve, whether it was bringing on DeAnn or beefing up our engineering team, with regard to stepping outside of basically those three core area that are development drilling.

And that's where I think the real limiting stuff with regard to that is not so much going to be personnel, it's going to be more data analysis  acquiring the data and analyzing the data, seeing what it means and then reacting off of it. And that analysis might be both what we're doing internally with our own acreage position and drilling and testing and exploration, and it might also be with regard to what the outside folks are doing or other peers or other producing partners in these basis.

And the last comment on Capex with regard to the balance sheet, the question comes up, "Well, what's that going to do to your operating cash flow and debt ratios and whatnot?" The way we look at it, the production tracks; the capital  which means the cash flow tracks the capital - we really don't see an instance through our three-year production guidance where we wouldn't be able to fully fund our development drilling from operating cash flow under current gas prices.

Then the issue comes down to the exploration side and how we fund that.

Rehan Rashid - Friedman, Billings, Ramsey & Co.

Thank you. If I can stay with Capex for a second, so the 100 Bcf in 2010 number, would it need any material exploratory success from where you stand today?

Nicholas J. DeIuliis - President, CEO

If you look at '08 to 2010 on those production numbers, '08, we're assuming zero from any of the shale plays, so obviously that would be upside. It's basically all Virginia coalbed methane, Mountaineer and Nittany coalbed methane plays. It's 300, 100, and 100 wells.

When you get out to 2010, we do assume that there's going to be some limited success across those shale plays. We do not assume bona fide economic drillable locations across all of those plays or all of those fields. When you look at the effective risk success rate that we'd need to get the 100 Bcf, I think it's very reasonable.

Rehan Rashid - Friedman, Billings, Ramsey & Co.

And the midstream Capex of $127 million for Nittany, is that essentially a onetime event or would you expect proportionate kind of midstream expenditures as you go forward as well?

Nicholas J. DeIuliis - President, CEO

Midstream is always going to be lumpy, and it's basically going to be lumpy on the front end of these plays. So last year when we were ramping up Mountaineer, you saw a lot of midstream capital. You're seeing some of that this year as well as these new sub areas come into play in Mountaineer. And for Mountaineer, it's not just for gathering; it's also for the processing. Mountaineer's the one of our three coalbed methane plays that is not pipeline quality.

Nittany's the same deal. New start-up area; we've put in some capital for gathering and compression and whatnot. Now over time, when Mountaineer and Nittany start to go out into the manufacturing mode and drilling these vertical and horizontal wells, that's where you'll see the percentage of midstream drop off significantly compared to what it was in '06, '07, '08.

Rehan Rashid - Friedman, Billings, Ramsey & Co.

Conceptually speaking, then, to get to that 100 Bcf number for '10, you would not end up spending much in '09, '10 or midstream, so maybe worse case scenario, you keep the '08 Capex flat while delivering the production growth, or you'll have to take the Capex up some more as you go through '09, '10?

Nicholas J. DeIuliis - President, CEO

Again, the interesting thing here is the more operating cash flow we have and the more success we have, the higher Capex will be. If we have success in the Marcellus exploration program, as an example, we're going to turn that into development drilling and you're going to see the Capex number go up. In the short term Capex goes up, but then here comes the production from it.

So I think the way to think of this is if Capex goes down over time, then that would mean that we're not seeing as much excitement on the shale front with regard to those opportunities. If Capex goes up over the next two to three years, that's good news in that we see economic plays and we're going to go into manufacturing mode.

Rehan Rashid - Friedman, Billings, Ramsey & Co.

Just two more questions on the same subject. In 2010, what kind of Capex would you need for that 100 Bcf?

Nicholas J. DeIuliis - President, CEO

We don't put out that view on Capex right now, but again, I think the thing to assume is the development drilling Capex for '08, '09, 2010, we should be able to fund that within our operating cash flow under those production bogeys and gas prices.

Rehan Rashid - Friedman, Billings, Ramsey & Co.

And if you look at the exploration program for this year, it got $88 million, leave land out - how would you kind of characterize the risk exposure here, or how would you risk the $60 million or so that you're spending?

Nicholas J. DeIuliis - President, CEO

I look at it in terms of three categories, okay? And we'll go from lowest risk to highest risk.

The lowest risk area of the exploration program would be things like new areas within Virginia coalbed methane or within the Mountaineer play or those types of opportunities. We're already going into development or manufacturing drilling, and now we're looking at new sub areas within those plays across, say, the 600,000 plus acres of Mountaineer or the 300,000 plus acres within Virginia. And we've given you some specific examples of that in the earnings release. That has a very short lead time, and I think we're much more up to speed, comfortable and I think more knowledgeable on what you should see there moving forward, but there is still uncertainty.

The second component is going to be with regard to things like the shales, whether it's Marcellus or Huron or New Albany, and there we've got significant footprints across all of those, including Chattanooga, where, if we see what we think the potential is through the test exploration program, then we can go into full development plays and make them look like a Mountaineer or a Nittany or a Virginia. And you know what's on tap with regard to that.

The third group is something that often gets lost in the shuffle, and it's something, frankly, we haven't done historically. And the examples here are the Bakken wells that we participate in with Marathon up in North Dakota with the oil production, the Trenton Black River well that we participated in last year and we plan on participating in another this year in upstate New York with our unnamed partner, and the opportunities like the PRB coalbed methane where these are areas that maybe either we don't have the extensive footprint that we do in the shales and in those big three CBM plays, so even if we see them being economic, we don't have enough critical mass there and we partner with folks that do, i.e., Bakken Shale with Marathon, or we've got the footprint but it's either so far afield or for whatever reason from a technical perspective, it would just take us too long to get it up and running. So there we find a better NAV route to monetization. That's where you look at JV'ing or leasing or selling or swapping that for other assets. That's an example of the PRB, where we look at the prospect, it looks really exciting - 300 Bcf of gas in place - but it's a PRB, and we don't have a legacy or a history within the PRB. It would just take us too long and devote too many resources to get that up and running. We think there's a better route with regard to sale or swap.

Rehan Rashid - Friedman, Billings, Ramsey & Co.

I have one last question, I promise. Based on your thought process and extreme focus on return on capital employed, is there an F&D number that is a corporate goal that you want to stick with the next several years?

Nicholas J. DeIuliis - President, CEO

F&D we treat very much as a result instead of an objective, and what we look at field by field and play by play is we look at the all in, after-tax rate of return, all in NPV, and if those things are above our cost of capital or causative with regard to a discount around our risk-adjusted cost of capital, we go ahead. And that's an accretive opportunity for the shareholders in the long term. If it's not, or if there's a better alternative for making it a higher rate of return or higher NPV, we go that route.

Rehan Rashid - Friedman, Billings, Ramsey & Co.

Okay. All right. Thank you.

Operator

(Operator Instructions) And next we go to the line of Adam O'Laughlin with BMO Capital Markets. Please go ahead.

Raymond Deacon - BMO Capital Markets

Yeah. Hey, Nick, it's actually Ray Deacon.

Could you comment on the lease operating costs going forward? I guess where you'd expect those to normalize at once Buchanan comes back online in late February, I guess.

Nicholas J. DeIuliis - President, CEO

Well, Mark had some of that in his comments, and the short answer to that, Ray, is that when Buchanan comes back up to the full and normal gob gas production, we should see an normalization back to something we saw in the early parts of '07 or back half of '06.

Raymond Deacon - BMO Capital Markets

Got it.

Nicholas J. DeIuliis - President, CEO

Now you will have some other competing factors, like Mountaineer coming up and Nittany coming up into its own will result in some short-term higher unit costs for those plays as we get economies of scale, but again, they'll be short-term in nature. I'd expect unit costs to drop off as Buchanan comes back.

Raymond Deacon - BMO Capital Markets

Got it. Got it. Did I hear right? You said those sort of $0.50 LOE gas at Buchanan, is that right?

Nicholas J. DeIuliis - President, CEO

That's in the ballpark.

Raymond Deacon - BMO Capital Markets

In the ballpark, okay. And I guess just with the reserves coming out in the second or third week of February, will you attempt to quantify given what's going on with CONSOL, the low-risk probables you see in the 300,000 acres in Virginia and Mountaineer, 600,000 acres there, or are you not going to do a 3P number this year?

Nicholas J. DeIuliis - President, CEO

We'll take the normal course of plan for '08, and the normal course of plan for '08 was that the proved reserve number comes out sometime in mid-February.

Now, the other approach we've been taking - and this release is a good example of it - when we've got something that's material within the asset plays, whether it's on the proved side or unproved side, we want to let the shareholders know about it. So if something happens with regard to Chattanooga, if it's material and that we're confident in, we'd release that as a normal course.

But the release that Dan was speaking to, the normal course historically has been the proved reserve number. That's what we plan on doing in mid-February.

Raymond Deacon - BMO Capital Markets

Got it. And what is the commitment in the Bakken with Marathon? How many wells do you plan to drill there?

Mark D. Gibbons - CFO

Yeah, we're looking at a handful of wells. We have a relatively small acreage position there. We're actually drilling now, I believe, and those wells have the possibilities of some offsets. So it's probably not a play for us that individually is going to move the needle, but I think what it does from a perception standpoint is it reinforces the point Nick has been making for the last six months or so, that one way or another, we will monetize assets in a way that makes sense to maximize shareholder value, and that's what we're doing here with the Marathon deal.

Raymond Deacon - BMO Capital Markets

Got it. Got it. And I guess kind of the same question for the Chattanooga. How much prospective acreage do you think you have there? Would you happen to know what industry production is out of that shale?

Nicholas J. DeIuliis - President, CEO

Well, I can speak to the acreage position. It's just over 130,000 acres that we control. So there, unlike the Bakken, we do have a very nice footprint, and that's why we're excited, in part, about the Chattanooga. If we can replicate these results, that would be more of a development play as opposed to just monetizing it through a partnering agreement.

But with regard to the other experience within that, I'll turn it over to Randy and see if he's got any thoughts on that.

Randall M. Albert - SVP Emerging Business Units

Historically, the only Chattanooga drilling has been vertical, and the results, as Nick said in his remarks, were modest at best. So we actually drilled the first horizontal Chattanooga shale well in Tennessee, so we're breaking new ground to know what - if we can replicate that over the entire 132,000 acres, that's what DeAnn's going to try to answer with our exploration program there as soon as we possibly can.

Raymond Deacon - BMO Capital Markets

Got it. And is the takeaway capacity there to handle it if you are successful?

Randall M. Albert - SVP Emerging Business Units

There will have to be some - two things go on in Tennessee. That gas requires processing from a standpoint that it has liquid hydrocarbons in it that has to be knocked out, so there would have to be a plant built to meet pipeline specs. And we will have to have some upgrade of our facilities there, which I think, again, was mentioned in the release, to be able to handle the gas. We were sized for the modest, vertical drilling.

Raymond Deacon - BMO Capital Markets

Got it.

Nicholas J. DeIuliis - President, CEO

Which, you know, if it's successful, Ray, that's an investment that would be warranted. It's going to be [inaudible] across our other major plays.

Raymond Deacon - BMO Capital Markets

Got it. Got it. Thanks very much.

Nicholas J. DeIuliis - President, CEO

Sure, Ray.

Operator

The next question's from the line of David Heikkinen with Tudor Pickering Holt. Please go ahead.

David Heikkinen - Tudor Pickering & Co. Securities

Good morning, guys. Just wanted to try to get a little more educated on the Chattanooga shale. Can you go into some of the details of how long it takes you to drill a horizontal well, what the depths are, some of the kind of thought process of what would be an expected flow rate unconstrained by pipeline pressures and back pressures on the wells, just some of those thoughts?

Randall M. Albert - SVP Emerging Business Units

Well, the Chattanooga shale in that area ranges probably from an absolute depth, the deepest part of it in the basin's probably about 5,500 to 6,000 feet. The well we drilled I believe was about 4,500 feet to the shale. As you come up depth onto the Cumberland Plateau, it gets up to about near where part of our property would be at 2,500 to 3,000 feet. So we range from 2,500 to probably 6,500 in depth there.

David Heikkinen - Tudor Pickering & Co. Securities

Okay.

Randall M. Albert - SVP Emerging Business Units

The one well we drilled, it took us about three weeks to drill it. I think that would be average based on what we've seen - three weeks or a month to do a well like that.

As to open flow rates, I would bring you back to what we've released in our guidance. We've been very pleased with those numbers, but whether we can replicate it will be what's important.

David Heikkinen - Tudor Pickering & Co. Securities

Yeah. Just thinking about reading the pressure commentary, would you expect to try to bring pressures down and have higher flow rates? I just was trying to understand the thought of, you know, if the flowing well had pressure and the gathering pressure, why is that in the release and what the indication is for that.

Randall M. Albert - SVP Emerging Business Units

Well, it's not right now as much a pressure problem as it is an infrastructure capacity problem. We're at capacity on our compressor station and our takeaway pipes, which is creating the problems. We have to fix that. But, as Nick said, that's usually a good problem in this business.

David Heikkinen - Tudor Pickering & Co. Securities

And so what type of capacity would you be looking to expand to?

DeAnn Craig - SVP Asset Assessment

I think that's the purpose of the exploration program.

David Heikkinen - Tudor Pickering & Co. Securities

Well, what - when you put in new compression, what size compression are you putting in?

Nicholas J. DeIuliis - President, CEO

Well, I think the point is we'll do the exploration side, get a view on well curves and drilling locations. That'll set with the drilling schedule what the takeaway capacity for the compression needs to be. And until we do that, we don't want to plop down millions of dollars in midstream until we've got a feel for what that profile would look like.

David Heikkinen - Tudor Pickering & Co. Securities

Okay. So when you think about this well producing, you'll have some production profile, but each one of the wells you drill in that area will given an open flow rate, but some sustained production from the Chattanooga shale that you release at midyear is going to remain production constrained.

Nicholas J. DeIuliis - President, CEO

Correct.

David Heikkinen - Tudor Pickering & Co. Securities

Okay. And so then taking to the next step of when you think about the outcomes for the company in each of these areas, a lot of companies, as they have success, then step up their pace of drilling. Just thinking about other Appalachian plays. Would it be a surprise if six months from now you continue on this path of success that you would increase your capital spending for the shales or should we just think about it as an annual evaluation?

Nicholas J. DeIuliis - President, CEO

Well, again, as the exploration program unfolds, success in a specific play  success being defined as we think we've got an economic opportunity across a significant number of well sites within a shale or a coalbed methane play, that will then turn that one-year or two-year exploration capital earmark into a methodical development program of drilling.

So you would see the increase in capital expenditures if that play would be deemed to be promising enough to warrant further investment, and then you would see a follow-on result with regard to production and operating cash flow.

David Heikkinen - Tudor Pickering & Co. Securities

Do you react as quickly as this year you would increase, or is it something that you need more - I'm trying to get an idea of how you think about an exploration play moving into development as you're doing more of this exploration. Is it a fast move, or do you want more data? Is it slower moving? Just trying to get into your mind a little bit.

Nicholas J. DeIuliis - President, CEO

Look at Nittany as an example. That program went from non-concept - I won't even say concept - non-concept to flowing production in about 16 months. And again, I don't have the specific dates. So there's an area where when we went IPO, acreage wasn't even contemplated, well-type curves didn't exist, it wasn't even thought of.

And once we made the decision to do an investment - we saw some promising economics with regard to analogies and some data that we could draw upon from Nittany and analogies from other areas like Virginia - and we made the decision to go, basically a year and a half or under we're up and running and flowing gas into the interstate pipeline.

So every play will be different. They've all got their own little bottlenecks and issues, from land to gathering infrastructure to processing, but we've got I think a track record when you look at Mountaineer, when you look at Nittany, when you look at the exploration budgets now, when you look at the Bakkens and those types of things, we can move within the foreseeable future that an investor would look at with regard to their investment decision.

David Heikkinen - Tudor Pickering & Co. Securities

Yeah. And now, just going on the other side of selling assets, you mentioned the Powder River Basin, you entered in last June, decided it's non-core, what about Illinois coals and some of those? Can you think about that as core or noncore?

Nicholas J. DeIuliis - President, CEO

Well, you know, there's some similarities and some differences, but it's the same type of process we would use.

The similarities are that, like the PRV, in the Illinois basin we've got a nice footprint with regard to coalbed methane control. In fact, it's an even better footprint than what we've had out in the PRV.

And the other thing that we're doing with regard to the Illinois basin is we've got - that's a significant portion of our exploration program for '08 where we go out and look at portholes, we look at test wells, and again, just like we spoke about for these other areas, in the case of Nittany, if we see something that's promising and we've got the footprint, which we do in the Illinois basin, we go into development mode. And we've seen, in the case of Nittany, less than a year and a half we're up and running and flowing.

If we don't see that type of an opportunity for whatever reason, or if we don’t think we can move quick enough because it's Illinois and it's not Pennsylvania, then we look at the monetization route, whether it's the JVing with the Marathons or shopping the assets for trade or for sale in the case of the PRV.

So the Illinois basin, that is on the plate for '08 within the exploration program of $88 million.

David Heikkinen - Tudor Pickering & Co. Securities

Okay. So it's a decision you're - that's helpful. Thanks a lot.

Operator

Our next question's from the live of Pavel Molchanov with Raymond James. Please go ahead.

Pavel Molchanov - Raymond James

Hi. Good afternoon, guys.

Nicholas J. DeIuliis - President, CEO

Pavel, how are you?

Pavel Molchanov - Raymond James

Good. Question about your famous $5 NYMEX base case when you're modelling project economics. Can you talk about on all of your new shale plays and your exploration effort more generally, do those rules still apply?

Nicholas J. DeIuliis - President, CEO

Well, within Virginia, clearly it does. Nittany it clearly does. So with regard to the ongoing development program, we're in good shape there.

When you look at Chattanooga, with the preliminary data we've seen - I haven't run the numbers, but I would suspect that that would also hold as well.

Now with regard to Marcellus and Huron, again, we've seen - first off, internally we're in no position at this point to opine upon that. That's why we've got the exploration program. Secondly, if you take the numbers that you've seen externally - and that might be a big leap - it looks like they are also working at the $5 NYMEX. We want to establish that on our own acreage position with our own drilling program and exploration effort.

Pavel Molchanov - Raymond James

Let's say, just hypothetically, the initial results maybe show a $5 NYMEX, you wouldn't get to 15% unlevered IRR, would you be willing to loosen that rule in those instances, or would you just cut back on spending?

Nicholas J. DeIuliis - President, CEO

I think with gas prices being what they are [inaudible] moving out versus $5, I think there's an opportunity there where we could lock in accretive rate of returns by changing the price stack view by effectively hedging, at least with regard to the upfront capital investment for those plays.

So that's again going to be predicated upon what we see with regard to well-type curves once we do our exploration effort, which then will be factored into a rate of return under certain price stacks. So that's something that, you know, that could be very well a change that we take.

Pavel Molchanov - Raymond James

Got it. Thanks very much.

Operator

Presenters, no further questions in queue.

Daniel J. Zajdel - VP Investor and Public Relations

Okay. Well, thank you, everyone, for being on the call today. I would remind you that we have a replay of the call available this afternoon. For U.S. callers, the number's 800-471-6701 and the access code is 897180. I will be around for the rest of the day if anybody else has any questions. Thanks again for your participation.

Operator

Ladies and gentlemen, that does conclude your conference. You may now disconnect.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: [e-mail]. Thank you!