Ranger Oil Corp (ROCC) 2007 Q2 法說會逐字稿

Greetings, ladies and gentlemen and welcome to the Penn Virginia Corporation second quarter financial results conference call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. During that time, please limit yourself to one question and one follow-up. (OPERATOR INSTRUCTIONS) As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. James Dearlove, President and Chief Executive Officer for Penn Virginia Corporation. Thank you, you may begin.

Thanks, Joe, good afternoon. Welcome to the report on the second quarter of 2007 by Penn Virginia Corporation. I'm joined here in Radnor today by Frank Pici, who our CFO, by Baird Whitehead, who runs our Oil and Gas subsidiary. In Kingsport, Tennessee we have Keith Horton, who runs our coal business and Forrest McNair, who is the Controller of all of our PVA entity -- or PV entities and Ron Page is in Houston and he runs our midstream business. So among us we'll try our best to answer questions you may have. What I thought I would do is to paraphrase the release, I know it's quite long, there's reasons for that, but let me just go through it here and really take any questions you have at the end.

For the seventh consecutive quarter, PVOG set records for production, in fact, in the second quarter production was over 10 Bcf equivalent or 110.5 million cubic feet a day. I guess we feel that breaching that hundred million cubic feet a day barrier for an entire quarter is an important milestone in a company the size of Penn Virginia. I surely congratulate Baird and his whole team on achieving that. Second quarter production was 34% over the second quarter of 2006, and it was 15% over the first quarter 2007. Operating income, this is for all of PVA now, PVOG plus our interests in the MLPs, was $57 million compared with $49 million in 2006 quarter-to-quarter. Operating income -- income components, PVOG was up $11 million or 46% over 2006, which was due to that increased production I just mentioned as well as a 7% increase in our realized natural gas prices. Second quarter operating income from PVR which is our coal and midstream natural gas MLP, actually decreased a little bit compared to the second quarter of 2006 by just under $2 million and we'll explain a little about that as we go along here. Also impacting operating income was an increase in corporate expenses of roughly $2 million.

2007 second quarter net income was just under $24 million versus $18 million in 2006 in the same quarter. That increase was primarily due to what I said above about operating income and the effects of changes in valuation of certain non-cash unrealized derivative positions, if I said that in English. Operating cash flow was $78 million, a 13% increase over 2006, same quarter. If I look at PVOG for a minute, at the operating income from that segment of our business, it was $35.7 million, again up significantly over the $24.4 million from the second quarter of 2006, and as I said, the improvement came because of a large increase in production and a modest increase in price. Expenses were up almost 35, 36%. And really that's just the cost of doing business. That was an increased oilfield service expenses, increased production, increased water disposal costs, increased compression costs, the normal things, I don't think there was anything out of the ordinary.

Taxes in G&A increased mostly due to production increases and that's detailed -- there's more detail on that in the release. DD&A increased again due to production increases and a slight change in our depletion rate, just depends what's depleting and where. Exploration expenses were up slightly in absolute terms but they were lower in terms of unit production, if you look at things that way. So that sort of sums up some of that. We also put out an operations release simultaneous with this release I'm speaking from right now. Let me just turn to that a little bit. As I said earlier, not only was our year-over-year -- year-to-year 2007/2006 production up significantly but sequentially we grew as well from the first quarter this year to the second quarter of this year. That was -- production increased particularly in this quarter, was in large part due to the successful exploration efforts we've got going in South Louisiana. Certainly our programs in the Cotton Valley and Selma Chalk contributed as well, as did the mid-continent, I think the real driver was South Louisiana. They're sort of mixing the two releases together but as I say it's all there to read and it's on our website.

CapEx was approximately $112 million for the quarter. That included $86 million for drilling, $21 milling for leasehold and property reserve acquisitions and seismic, and another $5 million for facilities. That represents about 62% of our non-acquisition Oil and Gas budget. We surely expect in the second half of the year, and going into 2008 and beyond, to see the results of that -- spending that money, particularly on drilling. I'm sure that you'll ask questions and Baird will cover it far better than I, but just to whip through the regions, in the Cotton Valley, we drilled 28 wells, 19 were net to us with 100% success. Production was up just a little bit, about 3% over the first quarter and considerably over 2006. But that's just showing the ramp-up that's been going on in the Cotton Valley. Early in 2007 we had some delays as we tested new completion techniques and we had some weather related issues, particularly all that rain. However, in the last month or so, I think our completion activity has increased and so we'll look for the Cotton Valley to ramp up a little bit over time.

We've got five rigs running, and I think that the 20-acre spacing test we say in the release we expect to drill five to ten of those experiments this year, starting in the third quarter. And our horizontal program in the Taylor and the lower Bossier we expect to kick in sometime in the second half of 2007 as well. We made a small acquisition some $20 million in East Texas. It's not contiguous to what we've got, but it's close enough and close by and similar sorts of assets with some production and some leasehold there. In the Selma Chalk, we drilled 22 wells, they were all successful. Production's up just a little bit over the first quarter and about 17 (indiscernible) in the second quarter '06. We had other issues there too, having to do with gathering and compression, but certainly that's resolved. And we expect production to increase the second half of '07. We're quite pleased with some horizontal tests we've done there, both in Gwennville and Baxterville fields. We think in the long run they'll lead to higher EURs and higher production.

We made a small acquisition in May in the Mississippi, in the heart of our Gwennville field, bought some reserves and some leasehold, so we'll see how that all pans out, but it's right in the middle of what we do and we're quite pleased to have acquired it. In the Mid-Con we drilled 13, 14 -- 13 out of 14 successful wells, we've got a couple rigs running in the CBM, one in the Granite Wash, it was a modest increase in production quarter-over-quarter. The Fayetteville, which we include in our Mid-Con, we drilled five wells, including wells drilled in the fourth quarter of '06, and the first quarter of '07, all are on production. We'll drill about five more this year before we decide where to go with all that. Appalachia's proceeding along, seven gross wells, about two-and-a-half net to us of the horizontal CBM. Production was down slightly from the second quarter of '06, and up over the first quarter of '07 by 7%. The issue we've talked about before, was water disposal, that's behind us now. Some wells that were shut in are coming online, that's why you're beginning to see, I think, a little increase between quarter one and quarter two.

We've got two horizontal rigs running right now. The issue in Appalachia really isn't water, it's getting permits. That's coal country and you've got to work with the coal companies to get those permits. The Gulf Coast has been -- has gone gang buster for us here with those wells, Cotton Land 1 and 3, this exploration success is very pleasant, it's also somewhat, puts you on a little bit of a treadmill because those wells have a very steep decline so you've got to keep going. I'm going to let Frank, in a minute, talk about guidance and whatnot. If you're sort of following the release, I'm going to divert a little bit and go a little out of order.

In December of 2006, before I talk about PVG and PVR, let me just do this. In December of 2006, you may recall we took all of our interests in PVR, LP units, our GP, general partnership interests and IDRs and put them into a new MLP called PVG and sold that to the public. We sold 18% of it to the public. Our principal motivation in doing that was to more clearly value our MLP assets, by if you'll allow me the phrase marking them to market. Every day you can see what the market thinks they're worth. Therefore, maybe have a better feeling for what the value they impart to PVA is. While PVG has been very successful, it's virtually doubled its price in nine months, we believe there's still some confusion in understanding PVA. It is, in our opinion, totally impractical from a tax and strategic perspective to spin off PVG. However, it is possible to add some clarity.

And deep in the financials, you'll see two pages that are labelled, "Conversion to non-GAAP equity method," which shows the way PVA would look if its investment in PVG were treated that way, purely as an investment from which we receive a steadily increasing cash flow with no risk to PVA's balance sheet. As you can see, if you look back there, PVA will look a little smaller if you keep score by revenue, but if you keep score by net income, the net income doesn't change, and more importantly, I think, it makes it clear what's going on on the debt side. Unfortunately, a lot of investors and even some analysts lump together PVR and PVA's debt even though they're totally separate and nonrecourse from each other and come to the wrong conclusion when they're calculating various ratios like dollars per Mcf, et cetera, in terms of valuation. So we won't talk about that every quarter, but it's new this quarter and I wanted to point it out to you.

So let me get back on course here and talk a little bit about what's going on in PVR. As you know, PVR has two components, one is coal. In the second quarter, the operating income from coal was about $17.5 million, which was down about 9% from what it was in 2006. And down a little bit from what it was in the first quarter of 2007. Revenues were up slightly, royalties were down slightly, if you look at these quarter-to-quarter comparisons. Production and royalty rates were virtually flat. For all intents and purposes, they really didn't change. Expenses were up, though, a little bit, about 27%, or $2.2 million. It's fairly easy to explain that. Over half of it, $1.2 million, is simply an increase in operating expense. And what happens is when some one of our operators moves on to a sublease that we have, that means they're paying us some money for our lease, but we're paying somebody else who we've taken that original lease from. We have to expense that and that's where it shows up, and that's what happened to us. And that just happens, I mean, people move on and off of these sublease properties and that's why you see the variation you do in that expense line.

Another $600,000 of that increased expense was DD&A which was basically due to a modest increase in production, and had something to do with where the coal came from. There was another $300,000 increase in G&A expense and that was almost all driven by the activity that Keith Horton and his guys put forth looking at acquisitions. We made a couple of small acquisitions, and we're looking at several others, which I really can't comment on but we're looking at. Looking at Midstream, Natural Gas Midstream business, the operating income was basically flat, if you look back to the same quarter in 2006, throughput volumes were increased 17% to 187 million cubic feet a day. The increase was due to pipeline system that we purchased in the second quarter of 2006, as well as a successful drilling program in and around the areas that we service, and a successful marketing program that Ron and his people have been able to go and lure customers to our asset base.

Gross margins in 2007 were down a little bit as higher volumes sort of offset, were offset somewhat by the higher cost of gas. Frack spreads early in the second quarter were compressed compared to the same quarter in 2006, but they were ahead of the first quarter. In late July, and into early August frack spreads are at a virtual all-time high. Again, I don't know what the price of oil did today but $78 oil or whatever it is, and 6.5 or $7 gas gives you tremendous frack spreads. So we're going to do some things to lock some of that in. Importantly to us, and then I'll turn this over to Frank, PVG declared a distribution increase that will be effective August 20th of this year. They'll pay a quarterly distribution of $0.28 a unit or $1.12 on an annualized basis. That's an increase over the dollar or the -- it's an $0.08 increase on an annualized basis over where we were at the end of the first quarter. What that means to PVA in the third quarter of 2007 is about $9 million on a pre-tax basis. So Frank, I think what I'll let you do, if you would, is talk about the capital structure and hedging and the guidance.

Okay. Thanks, Jim. Good afternoon everybody. On our hedging program for the quarter, I think we mentioned in the press release that we had a derivative loss of just under $1 million dollars, which is down from the prior year's quarter, but more importantly, the cash settlements were a net payment of $1.8 million. You really need to look at that in two pieces because we've got hedging programs at both the Oil and Gas company and at down in our Midstream business. That 1.8 is made up of actually a net receipt to the Oil and Gas company of about $0.4 million offset by payments of about $2.2 million in the midstream hedging. If you were on the PVR release, I mention that had $2.2 million brought our realizations net of hedging on the Midstream side down to about $1.01 in Mcf processed.

On the Oil and Gas side, the receipts we got actually increased our net realizations on the gas sales by about $0.04 over what's reported in the gas sales on the income statement since they show up in the derivatives gain or loss line in the income statement. But in any event, we've got an active program. We will be probably adding some midstream hedges on as we get into a little further this year with the rich frack spread environment we're in and we'll probably extend those into '08 and possibly into part of '09 as well. With respect to guidance for the year, rest of the year and really our full-year guidance, since we don't give quarterly guidance, if you look at page 14 of the release, I'll just give you a couple of the highlights of things that have changed a bit. Starting at the top of the page with production, our equivalent production we now have at 39 (inaudible) I think as Jim might have mentioned in his recap of the operations release. That is up a little from the last earlier guidance and that's really a result of the -- our results to date in the Gulf Coast and other places and also the acquisitions that we've made.

When you look at operating expenses, no major changes there. We did bring our DD&A rate down just a little bit, about a nickel on both ends. Our capital expenditures in Oil and Gas program has gone up from about $3.20 to $3.55 in our previous guidance to $3.80 to $4.05. Once again, that factors in the acquisitions we closed in early July. Since we don't budget those, we basically increase guidance when we make them, and we made some tweaks with respect to swings between our development drilling and exploratory drilling, we've actually bumped up our exploratory drilling just a little bit in terms of dollars. On the PVR side, on full production, the coal royalty tons, we've increased that range a little as well as a result of the Illinois basin coal acquisitions that is we closed here early in this quarter. We've also reduced the average royalty per ton on the coal side slightly to -- also to factor in that Illinois basin coal, which has a slightly lower effective rate on it. And in the capital expenditures we've just adjusted those as well for acquisitions that we've completed to date.

Looking at debt, debt levels, we've increased the debt levels in the guidance both for PVA and for PVR, and once again those are primarily driven by the acquisition activity we've had, we've also tried to reflect the current interest rate environment as best we can estimate it in this revised guidance. So those are the primary things that have changed and I'll put it back to you.

Thank you very much. Joe, I think what we'd like to do is open it up to questions if anybody has any.

Thank you. Ladies and gentlemen, we will now be conducting a question-and-answer session. (OPERATOR INSTRUCTIONS) Our first question is from Scott Hanold with RBC Capital Markets, please state your question.

Thanks, good afternoon.

Hi.

Can you give us what your current production is running at right now?

Scott, this is Baird. We're, today, you've got to remember it's strictly an estimate, but about 116.

Okay. And then specifically with the Gulf Coast, where do you see that going in the year-end, absent any additional exploration success?

If you exclude the Cotton Valley -- and when we talk about the Gulf Coast, we include the Cotton Valley -- exclude the Cotton Valley because we have some subsequent drilling in (indiscernible) field, we have a few development wells in our (indiscernible) field we plan on drilling. We expect the Gulf Coast by itself to grow throughout the remainder of the year.

Okay. Okay, good. And then turning to the Cotton Valley, you guys will be initiating 20-acre spacing soon. When you look at some of the rates we'll be seeing, what kind of rates would we need to see to say, yes, this appears to be successful or is it something that will take a little longer to evaluate?

Yes, I mean, the rates would need to be consistent with the offset wells. Because we're going there and the plan is to drill our 20-acre space wells, and the sweet spots, the sweet spots being better areas of course. So if you had rates and pressures that were consistent with those wells in those sweet spots, then it would give you some encouragement that the 20-acre spacing idea is working.

Okay. Thanks. And actually just one last question here. New Albany shale, I guess it's been a while since you talked about that a whole lot, can you give us a sense of where you think that may go and give us an idea of maybe where your acreage is relative to some of the activity that's been happening out there?

Well, we've got two different prospect areas, roughly 35,000 acres. Our stuff is in Illinois. I think the hotter areas right now tend to be in southwest Indiana, western Kentucky. We've got our own, we are try to get out of the way of the rest of this stuff and try to develop our separate geological idea as to new Albany, the plan is to get in there and drill the vertical well we drilled last year, in which we took a core and gathered some reservoir information and drill that thing horizontally the second half of this year.

Okay. Thank you.

Thank you, Scott.

The next question is from Richard Tullis with Capital One Southcoast please go ahead with your question.

Thank you. Congratulations on a great quarter, gentlemen.

Thank you, Richard.

Just a couple quick questions for you. Give us a little more detail, if you would, on the Cotton Valley, where it stands now as far as the -- clearing up the backlog and the current production rates, things like that.

Well, for reasons that were pointed out in the press release, we fell behind because of weather and because we started treating these wells a little bit differently. We started treating the Taylor by itself, because we discovered that the Taylor was not getting treated when it was commingled as part of an overall treatment, overall larger interval treatment. So we have learned some things, we have ramped up our completion activity here the last month or so. I think our average Cotton Valley production for the second quarter was almost 18 million a day. Today we're running about 23 net.

Okay. Good. How are your costs looking there right now, what's your average cost per well?

Well, drilling completion costs, they stayed right around $2.1 million, $2.2 million, drilling complete. It really has stayed there for over the last plus or minus six months.

Okay, good. Good. Do you have any well data on the Fayetteville, the production you have there? I know it's not a whole lot, but what's the total production for those, I guess it's five wells?

Richard, it really is premature for us to discuss that. We want to get our acres tests. We have got a gambit of results so far between the wells we drilled and the wells we participated in with Southwestern. We've had rigs that some of the southwestern wells have been press released at, we've had some wells that are much poorer than that. It is a statistical play, there will be sweet spots -- there are sweet spots in any of these other unconventional plays that the industry deals with. So we need to get our 14,000 plus or minus acres tested after which I think it will probably be more appropriate for us to pick areas it makes sense to develop in and probably at that time it will make a lot more sense in talking about results.

Okay, fair enough. One last question. For your Cotton Valley horizontals, what are you expecting on the cost side? What's your range there?

I'd say it's going to be probably between $4 million to $5 million. We're going to drill our lower Bossier well first, probably sometime around the third quarter. We're having such good success with the vertical wells down in Phase II with our area with GMX, which is actually closest to Carthage that -- those wells are better than what we have as you go farther north. So if the Cotton Valley's going to work horizontally, it's going to work down there. But I can tell you, the vertical results down there are outstanding. And you really have to be convinced that horizontal results are going to make a lot of sense before you proceed with that. What we're struggling with right now is to figure out where within that overall Cotton Valley interval to drill the horizontal section. Because things sort of change as you go toward Carthage and we'll be making a call on that here soon but that's what the issue is right now.

Good enough, thank you so much, appreciate it.

Thank you.

The next question is from Irene Haas with Canaccord Adams, please state your question.

Hi everybody, I have a macro question for you, we're looking at natural gas storage this week, things continue to look pretty full, and there doesn't seem to be any excessive hurricane weather, so it's getting to be that time of the year one can get concerned about how third quarter gas price is going to shake out, and there are some Rocky producers already shutting down, curtailing. You have recently raised your guidance, I was wondering if you have any sort of cushion built within there that you might end up having to curtail some production and thoughts of that nature?

I don't think -- I think the short answer is no.

Irene, sort of similar to last year and the storage issue, we did not have, except in one very small example, any pipeline pressures or any requests to shut any of those pipelines, because of storage issues, it doesn't mean it will not happen this year but we have not -- we did not experience that last year and we have not incorporated any of those kind of disruptions into this new guidance.

So you feel most of your property would do okay, say, in a $6 gas price environment?

Yes, I mean -- if you look at our economics on it, we have a slide in our presentation, $6 gas price is -- the things we're drilling, still make sense to continue to drill.

Right. And how about at $5, I mean, how would that impact? How long would it have to last at that level before you have to reconsider?

Well, I -- I mean, it would have to be -- if we were convinced gas prices were $5 for some extended period of time and extended being, pick a number, a year.

Okay.

If it was a long-term forecast at $5 was here to stay, then you'd have to rethink some of the things you drill, no question about it.

You know, if that were to happen, though, since you're asking a macro question, it would seem to me that there's a lot of other folks out there who would be in a lot worse shape than we would, a lot quicker. So having that $5 price endure for any extended period of time seems unlikely. Now, I suppose bad things happen, but it seems unlikely.

Okay. That's fair. Thank you very much.

Thank you.

Next question is from Biju Perincheril with Fortis. Please state your question.

Hi. Quick question. The wells that you drilled in the 100% acreage in Cotton Valley, can you discuss the rates that you're seeing for those wells?

Biju, we're encouraged with what we're seeing so far. We've got almost all the wells we have up there, 16 or 17 of them, we have a mixed bag because of the 28,000 acres that we have spread over an area, but we are seeing areas that the wells are acting as they do down in the Phase I area, which will justify drilling some development wells around it. So at this point in time, we're getting a lot more comfortable with some of the areas up in the 100% acreage.

Okay. Rough -- I mean -- in that area that you are comfortable with, what is your inventory to drill and how many are you planning to drill this year?

Well, I don't have that number handy. It would be a lot because the acres in itself is substantial and will support a lot of wells, even if you want to make a swag, say half of it's not productive, on a 40-acre spacing, you would justify a lot of drilling.

Okay.

We're seeing initial rates of a million a day in line of some of these wells and we are getting more comfortable with the results.

In terms of how many wells, I guess we have one rig up in that area, Baird, out of five?

Yes.

And what spud to turn on or how do you equate --

Since we've got some pipelines laid now we're getting some of these wells, it's acting time-wise the same as we have down in the GMX area, Phase I and Phase II.

So you'll maintain that one rig for the remainder of the year and maybe accelerate that in '08?

We may yank a rig, we may yank a rig and put another rig in 100% acreage, yes, or pick up an additional rig. At this point in time we don't have the money to do that within gas but there may be switching around of rigs.

And then in Appalachia, are all the wells, the horizontal CBM wells are they all back online now?

They've all been online since the end of March.

Are any of them dewatering still?

Yes, I mean, there are still some wells that are making some some water, there are some wells that have dewatered or continue to dewater, and rates on a few of those are up over 2 million a day after dewatering. So it's a mixed bag, as you would expect, but we have no reason to expect these wells aren't going to act the same as some of the earlier wells we had drilled in that play. It's just going to take a little bit of time to get to the peak rate.

Right. I just wanted him to understand some of them were still dewatering, that's all.

Great, thank you.

Thank you.

(OPERATOR INSTRUCTIONS) The next question is from David Snow with Energy Equities. Please go ahead with your question.

Yes, I'm wondering if you can give us some idea from the standpoint of just a resource feel, what the Selma Chalk horizontals might do in Bcf's a well?

I'll give you a range. At this point in time it's too early for us to say a specific number, but in the Baxterville area, probably based on what we know right now, probably 1.5 to 2 Bcf range and when we go to Gwennville, probably B-to-B and a half range.

A B to what, how much?

1 to 1.5 B's in Gwennville and 1.5 to 2 B's in Baxterville -- remember these are just two wells we have.

What do those cost?

They were a little higher on the first couple wells, as you get up on the learning curve you would expect those costs to go down, but I think the one we drilled, which is the second one in Baxterville, our costs were around $2.2 million, $2.3 million, and we expect to make improvements going forward.

Okay. What would you do to those, what spacing?

Well, spacing, per se, is we would position those horizontal so as we can track along the laterals, that would at least equate to a 10-acre spacing type vertical program.

Okay. Thank you.

Okay.

The next question is from Ray Deacon with BMO Capital Markets. Please state your question.

Hey, Baird. I had a question on the increase in exploration capital for this year, it sounds like the bulk of that is going for the Gulf Coast. Is that right? And could you maybe just run through how many net wells you'll drill in which areas for the next couple of quarters?

There's a little bit of money because of (indiscernible) dividend. There was a reclassification of some of our Fayetteville shale wells from development to exploratory, skewed that, the number of wells to some extent because of what we're trying to do up in the Fayetteville. But we have the one well we're drilling in Castilion right now. We have an additional well to drill. We have one wild cat to drill tentatively in Mystic Bayou. We have a wild cat to drill in our (inaudible) field, which is a fairly shallow, inexpensive well. That is the bulk of the exploratory program at least in the Gulf Coast going forward. We have a few things to do in Appalachia. We have an exploratory horizontal CBM well, of course a Devoni shale, we're calling that exploratory at this time for apparent reasons. So I think that's probably a pretty good summary of what we have left to do.

Got it. Got it. Is that Devonian shale well, you think by next quarter you'll have some results on that?

I'd say it probably would be toward the end of the year, Ray. We drilled the well vertically, we drilled it down through the Marcellis, we gathered some technical information, as you would expect. We had the lower Huron -- we had the (indiscernible), the Marcellis, we drilled this we will through the Marcellis -- so we're trying to figure out right now if it makes more sense for us to drill horizontally in the Marcellis versus the lower Huron, which we set out to do initially. We tend to be a little bit optimistic about the Marcellis at least based on what we've seen on the first well, but that's very early in its evaluation.

Right. Got it. Okay. Thanks very much.

Thank you, Ray.

You're welcome.

The next question is from Scott Hanold with RBC Capital Markets. Please go ahead with your question.

Hey, Baird, just to follow up on that comment you had on the Devonian shale well, can I infer from your comments that I guess based on the technical data you've collected on the vertical well, you're encouraged by what you've seen so far?

Yes.

And sticking with Appalachia, as far as those permits are going, you said it appeared that you're having trouble getting the permits you need for your drilling inventory. Can you give us an idea of what you have in hand and potentially when you would expect to get some additional permits in place to allow you to ramp activity up there again?

We sort of go back and forth between two rigs and three rigs, depending on how many wells we have in the inventory. To be honest with you, we sort of work well-to-well as far as having enough permits and inventory to either lay a rig down temporarily, until we get a permit in hand. So we don't have a handful of drilling permits that we can add additional rigs. It's sort of week-to-week type thing.

Is that sort of how this area's going to go going forward, look like, or do you think there's going to be some change to your ability to sort of build an inventory out there?

We're trying to build an inventory. We're trying to get out of the way of the coal companies, to be honest with you, trying to get up into Raleigh county, which doesn't probably mean a lot to you, but it's more out of the way of some of the active coal mining. We're also trying to come up with some global agreements with the coal companies so we don't have to fuss with them all the time.

When you sort of move out of the way of the coal companies, is there any difference in the wells you're drilling or the geology or the coal out there that would make the productivity of a well any different?

Not at all.

Okay. All right, thanks again.

You're welcome.

The next question is from Ray Deacon with BMO Capital Markets.

I guess for Frank, I just had -- want to make sure I understood the rationale for doing this, the conversion to non-GAAP equity method. You're just basically showing in that as-adjusted column what the PVOG would look like on its own, is that basically right?

Yes, basically, Ray, except just boiling down everything that comes through from PVR and PVG as though it was an equity investment instead of all the single-line full consolidation.

Got it.

So there's a line on the balance sheet that says investment in equity investment, and then there's a line on the income statement that says equity earnings and those are just the boiled down lines of everything coming through from PVR to PVG. It's also giving us a more pure look at our cash flow stream. It doesn't give you the distortion that you get when you try to factor in the -- all the cash flow items coming from the partnership, which we don't really get a full piece of. We only get our share in terms of distributions when you boil it all down. So that as-adjusted column is giving you a more pure look at how we have our investment in PVR and PVG.

And will you do this every quarter? From now on?

Yes, the plan is to show it in each quarter's press release.

Okay. Got it. And is there a -- I know you've been addressing this in many gyrations, but is there anything new you've heard, I feel like I've heard some things about tax issues and forming MLPs, maybe there's a way for some of the tax impact, is there any change in your thinking as far as how you might be able to demonstrate the value of PVOG given what PVR's done this year?

I'm not sure I understand your question.

Drop down, not really there's been a structure that MLP's that used for several years, we, in fact, used a similar structure when we formed PVR back in 2001. But that's really way to put some debt down at the partnership level. It's a way to defer some of the taxes, but there's not really a magic bullet that we're aware of.

No, I don't believe that there is.

Okay, got it. You still don't feel like you have, because a lot of your ENPS that you still see a lot of growth there would not make sense to drop those down to the PVR level?

No, we don't believe that it would. And again, because they're separate public companies, what are you really doing there? If you were going to drop them down at all, you'd probably want to drop them down into something that is brand-new and we just don't have enough mass or the right mix of assets at this point to do that.

Right. Got it it. Thanks a lot.

At this time, I'm showing no further questions in queue. I'd like to turn the call back over to management.

Thank you, Joe. And thank you everyone on the call. Again, we'll do it again next quarter.

Thank you. This does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation.