Ranger Oil Corp (ROCC) 2008 Q1 法說會逐字稿

Welcome to the Penn Virginia Corporation first 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. (OPERATOR INSTRUCTIONS). As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Jim Dearlove, President and CEO of Penn Virginia Corporation. Thank you. Mr. Dearlove, you may begin.

Thank you, very much, and good afternoon. I'm joined here -- the other speaker today will be Frank Pici, who's our CFO and Executive Vice President of Penn Virginia. I'm passing around here, looking for a statement I wanted to read about forward-looking statements, and I'm not finding it, but just let me say this: I've been advised by counsel that I should be a little more careful introducing these calls with regards to forward-looking statements, and so I just want to remind you that some of the things that we're going to say today are opinions or estimates, and while they're our best estimates and our real opinions, they are subject to error, because they're forecasting a future that we can't necessarily foresee.

We'll also refer to some non-GAAP statements from time to time, and I'll try to identify those before we do, but we think they give you a clearer picture of what you may see in trying to interpret our results. Lastly, when we talk about oil and gas, we will talk, I'm fairly certain, about 3-P reserves, meaning possibles and probables. The SEC frowns on that, certainly in certain kinds of reporting, but it's allowed in this kind of conversation, but I would remind you that those references have a certain degree of risk associated with them, and if we were to use the phrase EUR, estimated ultimate recovery, again another phrase that is very common in the industry, but it does constitute a bit of a forward-looking statement. I should also say that normally on this call, we would have Baird Whitehead, who runs our oil and gas business. He's unfortunately unavailable today, on the call are the following gentlemen, Mike Mooney, who runs our Houston office, Jim McKinney, who runs our Eastern offices out of Kingsport, Tennessee, and John Brooks, who runs the midcontinent. If we get questions that I can't answer, any one of these gentlemen in his respective area, I'll refer that question to them, and they'll attempt to answer it for you. I'm going to refer today to our press release that we just issued yesterday, and I'll also refer to some degree to the press release of the 30th of April, which was our operations update.

So let me just start. As is my normal approach to these calls, I'm assuming that you have had an opportunity to read the release. I don't read it to you, in general, I try to follow it reasonably closely in terms of its layout so you can kind of follow me, but obviously, if I miss something, you'll have plenty of opportunity to ask us questions. For the quarter, the first quarter of 2008, oil and gas production was 10.5 BCF equivalent, which was a 21% increase over the first quarter of 2007, and essentially flat to slightly down from the fourth quarter. Operating income for PVA in the first quarter was just over $60 million, that is as opposed to the $38.5 million we had in the first quarter of '07 and the $45 million last quarter. Most of this increase was due to higher operating income from the oil and gas company, and to some degree in the first quarter an increase in operating income from PVR midstream. Net income was heavily affected, as it always is, by the noncash exposure we have to derivatives. That was $3.9 million in the first quarter of this year as opposed to 4.4 in the first quarter of last year and 5.4 last quarter. And again, most of that is a result of derivative activity. In order to take that effect out, we also provide something called adjusted net income. This is one of the non-GAAP measures, but it does exclude that noncash change in the value of derivatives. That was just under $21 million this first quarter of '08 versus $16 million -- $16.5 million in the first quarter of '07 and about $12.8 million last quarter. This increase in adjusted net income was due to increases in operating income offset by the cash settlements on derivatives and somewhat higher interest expense.

As I said, I'm going to refer somewhat to the fourth -- the April 30th release, and I surely don't intend to read all of that to you, but let me just take a quick look at PVOG through the eyes of that release. The operating income for PVOG was $36.4 million, 61% over the first quarter of 2007. The revenues and net income were both up due to production increases and an 18% increase year-over-year in the natural gas prices, a very significant increase in the price of oil, although we don't produce very much oil. There is a discussion of expenses in that release and in this release that we're looking at, unit cash operating expenses for the quarter were $2.34, which is slightly -- is up from -- I'm having trouble reading my own notes here, excuse me, was slightly below where it was in the fourth quarter of '07, and maybe that's the relevant number.

We expect expenses to fall. Note our guidance for the year is $2.10 to $2.30. So $2.34 for the first quarter we have to do a little better going through the rest of the year and we fully expect to do that. Some of the components of those expenses, LOE was up, comparing the various quarters, mostly due to additional compression, water disposal, some gathering expenses, some increase in oil field service costs, obviously taxes other than income was up because prices were, G&A was up a little bit because we have more people, hence more benefits. Various stock related expenses as well. All of this is detailed in the release which is why I'm not trying to read numbers to you. DD&A was up, mainly due to a shift of higher depreciation and higher cost areas. Exploration was more or less constant.

Now as I said, I will refer to that 4/30 release. Our production for the quarter was 115.6 million cubic feet a day. It was negatively impacted by a number of things, mostly occurring in east Texas. One, the delay in east Texas of a gas processing plant. That plant was delayed due to various problems with weather and equipment. Various third-party pipeline delays, but that probably cost us we estimate a half a BCF of production we would have reported if it wasn't for those delays.

In addition, because of those delays and having to scramble around and find other outlets for our gas, we had some restrictions. That probably cost us about 0.4 of a B in that first quarter. Both of those problems are now resolved as of April 17th of this year. Also, the timing of well completions on our 20-acre spacing program in the Cotton Valley caused us to delay reporting about 2 bcf of production. What's going on there, we drill these 20-acre-spaced wells, three or four to pad. You've got to drill them all before you can get in and complete. That process slowed us down a little. Now that we're in a rhythm I don't think you will see that effect going forward. It will just carry through the year. But the combination of all of that was a little over a bcf a production.

We might have normally reported if it hadn't been for these issues which I believe are resolved. Just again, out of that release I would say, because it's become a hot subject these days, the Haynesville, what we call the lower Bossier, we're drilling a lower Bossier well as I speak, we're completing the lateral right now. I don't know when we'll finish that well but when we do we'll test it. We wouldn't expect to report results for awhile until we're pretty sure what we've got. Regardless of those results, I think it's safe to say we'll drill two or three more of those wells this year to try to again define what we have there. I would tell you that over the 62,000 net acres we have in that part of the world, since 2006 we've drilled 15 wells through the lower -- upper and lower Bossier, pretty much down to the smack-over. Just based on the tests and the logs and the things that one does in looking at those wells, we're convinced the gas is there. It's yet to be proven whether that gas can be recovered economically or not.

But we're quite encouraged that if it all works we've got a significant Haynesville presence. However, we are not going to predict anything or report anything until we're comfortable that we know what we have. With regards to those 20-acre spaced wells we drilled 27of them in the first quarter which brings our total to 39, I believe, and as far as I know there has been no apparent well interference so I would say that is working. I don't want to read you the whole release. I think of some significance is the progress in the Mid-Continent. Production was -- excuse me, 16.1 million cubic feet a day, 78% over the first quarter of last year and 23% over the fourth quarter. The Hartshorn CBM, a horizontal program continues to perform as expected. A second rig is expected there probably in the second half of the year, maybe a little before that. There's some talk -- Baird and I have had some conversation about whether we'll put a third rig there.

We are testing in the Bakken shale. I believe we spud that well. That's in Dunn County, north Dakota. That's more of an oil play. That's again a horizontal drilling. We're expecting to drill at least one other well there. In the Woodford, we're planning to drill four horizontal wells in the Woodford this year, two in each of our 20,000-acre areas, one in the Arkoma, the other in the Anadarko. Four wells have been drilled that we've had some working interest in. One last year, three this year. IP rates been anywheres from 5.6 to just under 10 million cubic feet a day so that looks like it's going to ramp up. That's one of the places we may ramp up some of our CapEx.

Just very quickly, in Mississippi we slowed our drilling down in the fourth quarter of '07 and the first quarter of '08 in order to convert over to drilling more of these wells horizontally. They're performing very well. A fifth well is performing very well. It it's over a million cubic feet a day, and that's still in the first stage of the lateral as I understand it, so that's a very good well and we'll go on doing that and slowly converting over to horizontal as we're running two rigs now and we'll see how that works out for the rest of this year.

Lastly, in Appalachia, the big buzzword is the Marcellus. If one of my kids has another grandchild I'm going to name them Marcellus. It is a hot button. We're accumulating acreage there, we're hardly a big player yet, we've got a little over 10,000 acres in Pennsylvania and New York. However, we are much more of a player in the lower Huron. We'll go on accumulating acreage. Lower huron, another member of that devonian shale series. We've got 70,000 prospective acres in West Virginia. We are drilling a well there now. We've drilled I believe three successful wells in Mason County, West Virginia on roughly 10,000 acres and we're trying to acquire more. As far as the Marcellas goes in West Virginia, that 70,000 acres I referred to, Cabot is fairly near us. They're reporting some positive results in the Marcellus in that part of the world. We're not speculating on that at all. It's fairly thin there. But I can guarantee you we'll test it.

With regard to our Gulf Coast program, we haven't kicked that off yet, but I'm talking now about south Louisiana. We expect to drill a number of wells this year and hopefully we'll be able to repeat our success of last year. What I'm trying to do here is merely convey to you how we're positioned to go through the rest of 2008. That in mind, despite the -- not despite the first quarter but in light of the first quarter we're nonetheless reaffirming our guidance and we've raised CapEx by like 5% from 475 to $500 million as the release implies that's to accommodate a run-up in drilling some additional leasing and maybe some expanded facilities. So moving on then, as you know, Penn Virginia Corporation owns 82% of an MLP called PVG, Penn Virginia General Partner holdings, something like that, I always get the nomenclature mixed up and I never write it down. But at any rate, through that, we own the general partner and the IDRs and 43% of the units in something called PVR, Penn Virginia Resource Partners, which is a natural gas midstream and coal royalty mlp. Looking at each of those segments, the operating income for Midstream increased significantly compared -- in the first quarter '08 compared to the prior year. The operating income and the coal company decreased slightly. We he don't give you a lot of detail in this report.

We just webcast, I believe it's beyond our site what we just talked about an hour ago or two hours ago to the PVR unit holders. You obviously can go and see that. The release directs you to PVresource.com. You can get a copy of that release. We just found that it becomes too cumbersome to try to go through all of that stuff again. I think the important thing about PVR is that it increased its distributions, which is certainly a sign of its board has in its future, increased from $0.44 to $0.45, or 2.3% for the quarter. As a result of that PVG, which derives all of its cash flow from PVR, felt comfortable increasing its distribution to $0.34, which was a -- roughly a 6% increase over last quarter and a 30% increase over where we were last year. So I think really that's the important thing to note about those two things, those two MLPs. PVG is totally dependent on PVR.

Let me just say, about this about PVR, why we have that confidence. Our midstream business is a gathering and processing business. This year 2008 we brought on-line one plant and we'll bring on-line another one. It's complete. It's simply waiting for a residue line to be hooked up to it. Those two plants together will increase our processing capacity at PVR by 87.5%. A fairly significant increase. Much of the -- one of those plants -- much of the supply to one of those plants comes from our Cotton Valley production. So it's a very synergistic thing for PVA and PVR, which is why I mentioned it.

Another thing I'll very quickly mention, our midstream is also acquired in April of this year a position in the Rockies. We bought a 25% non operated interest in a fairly large gathering system there. The import of that is it's immediately accretive, number one, and it gives us a window on a very fast growing part of the gas world, and we're hoping it will develop into quite an opportunity. And all I will say about coal is that as you may know, we are in an environment right now where coal prices are at an all-time high, both steam and met, and we expect to benefit from that more in 2009 and 10 than we will in '08 as various contracts roll off but I believe coal pricing is very good news for PVR. With that, let me stop and ask Frank Pici to talk to you about our capital position, derivatives and take you through our guidance.

Okay, thanks, Jim. Good afternoon, everyone. I'll just spend a few minutes going through the -- basically the derivative impact in the quarter since that's always a question we get, and then through our guidance and just a few notes on that.

As you probably know, we consolidate the results of PVR and PVG into Penn Virginia Corp so we have to include their derivatives impact as well when we get to that line item on the income statement and as you probably saw, we had a net derivatives expense of almost $26 million in the quarter, which is basically the net change in the mark to market value of our open positions at that point in time. That was split actually between our oil and gas operations, which are really the bulk of Penn Virginia corp, and the consolidated results of the midstream hedges we do in PVR. On the oil and gas side we had a $34 million recorded expense from that -- from the oil and gas positions that were offset by about $8 million of gain on the midstream side. Conversely there's actually a cash receipt on the oil and gas positions of about $0.5 million which improved our average gas price realization on cash terms by about $0.06 an mcf, about $8.26 to $8.32. On the midstream side we paid $9.5 million out on the midstream side, and PVR, of course, which impacted that, after derivatives processing margin by about $0.49 an mcf.

Flipping back to the oil and gas positions and where we are with our hedges, we're about 60% hedged based on current gas production for the last three quarters of 2008 at the average flooring -- we use collars in general on those positions. In general terms they're approximately an $8.30 floor, approximately $9.50 ceiling on that time frame. As we go into 2009, we're only about 25% hedged on present current production terms for '09 and again the the average floor and ceiling are $8.70 by about $10.50. That's somewhat fluent number. We will change positions or add to our positions in the -- in 2009 as we go through this year, as is our norm. On the midstream side, which again is reported through PVR and consolidated into PVA, PVR is about 75% or so hedged on its midstream product position in the midstream business, and that is for '08 and drops down significantly in '09 to just around 20%. So just to give you a feel for where we are there.

As we go into the rest of 2008 we've provided a guidance table near the back of the release. As Jim mentioned, and as the press release mentions as well, there haven't been many changes on the oil and gas side at all. We have not changed our production guidance. We're still in the same range we were in when we issued original guidance. As Jim mentioned, the cash operating expenses haven't changed, and we'd expect to see improvement over the first quarter expenses that we saw as -- primarily as we continued to improve our cost structure, and ease taxes on our water disposal side, we'll have a new disposal facility by somewhere around midyear that will help bring that cost back down to previous levels before our former facilities got full.

With respect to capital expenditures, as Jim mentioned, we do have a slight increase there. A lot of that is based on some additional leasehold acreage, cost that we estimated, some additional Gulf Coast drilling and a little bit of infrastructure cost in the east as well. So that's the primary drivers for that increase. We went through in the PVR release, several changes on their side. Just to highlight a few of them, on the coal royalty side we have decreased tonnage in this release, for some first quarter items that were explained in that press release, in the PVR press release that have to do with several, two or three different items, that's really the only thing that's driving the decrease in the total annual guidance. To offset that, we did increase the average royalty per ton on the coal side as we're seeing higher prices on our lessee's production. As we go through the year, we expect that to improve. That will be mitigated somewhat just by mix issues on the per-ton amounts even though the absolute amounts will go up as one of our fixed rate royalty properties in northern Appalachia comes back on line. But in total, like I said, the overall royalty rates will go up as will absolute dollars, on our co-royalty side.

On the midstream side, the biggest driver for what we think will be increased revenues there are some new supplies coming into our Beaver Perriton complex in the Texas panhandle. As a result of that we've increased guidance on throughput volumes in those systems by on average 30 to 40 million cubic feet a day as we go through the remainder of the year here. We have made a few changes there as well with respect to expenses on the capital side, on PVR, we factored in a recently announced acquisition on that side where PVR bought a non operated member interest in a position in the Rocky Mountains. A gathering system there. We've also increased some organic spending around our Beaver Perriton complex in PVR. We made a slight revision on the corporate administrative expense side, from our prior guidance to increase some consulting expenses that we've incurred in the first quarter, and we've adjusted as we always dye to kind of fine-tune a bit on our debt cost and expected interest expense.

So with that, Jim, I'll hand it back to you.

Thank you, Frank. Before I turn it over to questions, which I'm happy to do, let me just reiterate that I believe that PVA, as we sit here today, on May 8th, is very well positioned to go forward this year and into the future. I think we've got a meaningful position in many of the, if you will, sexy shale plays that are out there right now, maybe with the exception of the Barnett. We are quite please with what's going on with our 20-acre spacing in the Cotton Valley, and what's going on in the Granite Wash in the Mid-Continent, with that, I think I'd just say, operator, we'll open it up to questions.

Thank you. Ladies and gentlemen, we will now be conducting a question-and-answer session. (OPERATOR INSTRUCTIONS). One moment, please, while we poll for questions. Thank you. Our first question comes from the line of Scott Hanold with RBC Capital Markets. Please proceed with your question.

Thanks. Good afternoon.

Hi, Scott.

In east Texas, can you talk -- obviously you have that Haynesville lower Bossier drawing to the extent you will, can you give us any kind of update on what you're seeing there? Kind of thinking beyond that, if it becomes -- if it's successful and that's an area you want to go out a little bit harder sooner or later what type of gas is that? Is that going to be like a hot gas similar to the Cotton Valley sands that would need to be processed, or could it just be put into the production stream right away.

my understanding, Scott , and I'll ask Mike to add to this my understanding it's much dryer than, say, the gas you'd find a little higher up. Mike, do you want to just elaborate a little bit?

Sure, Jim. That's correct. Our vertical test indicate 8% less on a BTU factor. It's still processible, if that makes sense, and we put it in the same gathering system. We would not need to have a redundant gathering system just for the Bossier.

So would you still go through the PVR processing plant, is what you're saying then, is that correct? Can you talk about where you're at on that well?

Well, we aren't going to make any predictions about would it might do, but, Mike, in terms of -- I guess we're drilling the lateral, and when might that be complete?

Jim, we've actually completed the lateral drilling. We're finishing the last of the reamer runs and we'll be installing the completion pipe here very soon.

Going to Appalachia, I guess do you have a water disposal system in place some time, I think you said third quarter, Frank, if I'm not mistaken. Can you kind of draw some context around how much cost savings that could actually contribute during the quarter? And in terms of the prior one, I'm to use this term, filled up. How long would that take where youd to have look at expanding that system again?

Scott, this is Frank. It's actually in East Texas where that disposal facility will be installed. That's where most of that water issue has come up. And order of magnitude, and Mike Mooney can correct me if I'm wrong but I believe in the facilities that we've had previously it was costing us somewhere in the order of $0.10 a barrel to dispose of that water, when the current facilities reached capacity we had to switch to trucking that water. I know for awhile it was running us over $2 a barrel to dispose of it from $0.10 when we had the facility. So we're still trucking it now. I think we've gotten a slight break on the rate there, but I think we're looking at a step function change down in the grade per barrel to dispose via that water when we have that facility in. I believe our current plans have it to commence service, or go into service, if you will, in the third quarter. I can't tell you what the capacity is and how long that new facility might last. I don't know, Mike, if you have any color on that.

Frank, you're on track about the expense reduction, and I would anticipate -- we would never really actually fill one up. Logistically we just find that better place to put one as drilling activity expands. What we would see is 4 to 5,000 barrel a day capacity well is what this one is designed to be. We would think about another one sometime either late fourth quarter or early first quarter '09.

Okay. Thank you.

Thank you, Scott.

thank you. Our next question comes from the line of Sven del Pozzo with CK Cooper. Please proceed with your question.

Good afternoon, gentlemen.

how are you?

Good. How are you doing? Just to clarify what you were just talking about, the fourth quarter '08, first '09 water disposal facility, that would be another one in addition to the one that Frank mentioned to be in service by the third quarter '08?

I believe that's what Mike said, yes.

Okay. So that would be two in total, each with a 4 to 5,000 per barrel capacity.

I believe that's correct. Mike, if we're wrong tell us.

That's correct.

I was just looking at your liquids realization at about $85 or so. And that looks pretty strong, and I wouldn't have expected it to be that strong given that it's not -- the vast majority of it is not oil, if I'm not mistaken. I'm wondering, are there local market dynamics there that are causing your liquids realization to be so high, and does your processing capacity in the region help you out at all, or just help me understand.

I think it's primarily oil, Sven. It's not affected that severely by the NGL barrels that will be coming in through there.

So what percentage of the whole liquid treatment is oil and what percentage is NGLs?

We're figuring it out.

Historically, it's been roughly, in terms of number of barrels basis, I'd say '07 was roughly not more than 20, 25% NGLs, 75% oil. I think that ratio will start to move in '08. I think we're expecting something closer to 50/50, but its a function of when we get to record the barrels from that plant in East Texas, primarily. I think it's probably going to start to approach 50/50 as we get later into '08.

Thanks. And then the plant in east Texas, as Jim mentioned, as of April 17th that plant is on-line?

Well, yes. As of April 17, the plant could be -- was declared to be fully functional, however, there's a residue line that needs to be hooked up to that plant, and it's not. That said, the constructor of that residue line is paying us as though the plant were running, they're paying the plant as though it were extracting fees for processing that gas and the accounting rules allow to us take credit for that gas as though -- and the upgrade, as though we were producing it and putting it through the plant.

And just, about your lease operating expenses, even though you have had some production delays, they still look relative low and it seems like you're mentioning quite a few things that might be temporary in nature, I'm wondering if the additional compression rentals, the colder temperatures in March, are those things that we can expect not to influence the future lease operating expenses? What should I focus on in terms of what's more permanent out of these factors, I'm thinking the water handling charges which you're working on, and also, your gas processing plant, when that's up and running, how much do you think you're going to be able to save on an absolute basis or per MCF or whatever, just to give me a better understanding.

Without having all the specifics of every component of that, Sven, I think the way we're modeling and forecasting this going forward, we'd expect by late this year to start to approach LOE levels that we had late in 2007, or middle of 2007, for 2007, if you discount operating expenses and what we call toad your taxes, other than income, I think we averaged about $1.59 an MCF equivalent, and as we get to the end of 2008, our models are showing us to be at similar levels, around that same level.

Okay, and then I got two questions on PVR. One is, can you give me a feeling for what the -- for much running room your lessees have? You say coal production is going to continue to increase. Are there any mine depletions that you have in mind? I'm just thinking going a little bit further out than 2008, what you think your lessees might be able to achieve in terms of volume growth.

I know it disappoints all of you who are trying to build models, but we simply don't provide guidance beyond 2008, you can see our guidance for 2008 was fairly flat with last year, up a little bit. The first part of your comment, how much running room do our lessees have, the answer is very little. Most of the coal we have is leased, and if you've got a shovel and a mule, you're mining everything you can mine right now to take advantage of these prices, so you won't see production from our existing mines change very much if at all.

The area where you might see some growth, and Keith Horton can correct me if I'm wrong, but I believe that if we see growth in volumes, we'll tend to see it probably more in the Illinois basin as we go into '09.

Finally, regarding the processing, natural gas processing in the M LP, what percentage of your volumes are under keep-whole arrangements, and what percent are under percent of proceeds, and what percent would be fee-based?

Keep-whole, the modification that it has a floor is about 57% or so, the other two are divided roughly equally, probably POP a little bigger than fee-based, but roughly equally.

That's a percentage of volume -- of inlet volumes?

Yes.

Okay. All right. Thank you very much.

Our next question comes from the line of David Tameron with Wachovia. Please proceed with your question.

Good afternoon, everyone. Talking about the Bakken, who is your partner in the play? And you're operating those wells, correct?

We're operating them. John, can you help me out there?

Our partner is Bettis Boyle and Stoval and Sonic which are two affiliated entities.

And can you give me a feel for where the -- in what counties it's in, is there any wells recently drilled in the neighborhood?

It's Dunn County, but John, I'll let you answer that, if you can.

Yes, we're in Dunn County. Marathon and Tracker Resources have drilled near our acreage with some very encouraging results. And on our well we're currently at about 15,000 feet.

15,000. And what's the -- what's the length of the lateral on that?

That's about a 4500-foot lateral.

Okay. And any feel for the well costs? I know you have a feel for it, but any numbers you want to give us?

As expected.

All right.

John, you're going to be very good at this.

Yes. When should we hear more on those wells?

Probably not until the end of the second quarter, early third.

Okay. Moving to east Texas -- let me jump to Granite Wash first. The horizontal wells you've drilled, have you guys drilled any verticals in this play?

Again, John, I will defer to you.

Earlier wells were drilled vertically. But the better wells are the horizontal wells.

Okay. And -- that's what I was going to ask. Even -- I had heard -- did your partner test on a couple of these wells?

Yes.

I had heard their numbers, 5 to 7 million for horizontal wells. Do you care to confirm or deny if.

Are you talking capital or production rates?

No, capital. I know you guys have other rates. I'm talking about the cost of the well.

I think they're probably going to be on the higher end of that range that you mentioned.

Going to the lower Bossier, what type of rates do we need to see in order for you guys to declare success and drill that second well out there?

We're going to drill a second and third well, I think, regardless.

Okay. I know it's not that simple. I'm trying to boil it down.

Mike, make an educated guess, would you, please?

Sure. There's two components. Initial production and stabilized rate. I'm interested now in the stabilized rate aspect of it, but I would hope to see something three to five million a day.

Okay. And every vertical -- you haven't had any sustained vertical test other than just to make sure there's gas, is that correct?

Go ahead.

Actually we have had some sustained tests, and we actually have comingled some of the lower Bossier stuff along with the upper Cotton Valley sequence. We still are, in fact, producing the lower Bossier from the vertical wells.

You are. All right. I'll let somebody else jump in.

Thank you. Our next question comes from the line of Joe Allman with JPMorgan. Please proceed with your question.

Hey, Joe.

Just a follow-up on the Bakken. I think you said 15,000 feet. That's not the depth from the surface, right?

Actually, it was John Brooks that answered.

Go ahead, John.

That was the measured depth. The PVD is somewhere between 9700 and 10,000 feet.

A separate question. The second quarter, are you expecting -- I know you've given guidance for the full year but are you expecting a bump-up in production on average for the second quarter from the first quarter?

Yes, we're expecting -- not a great big jump but a modest jump. I think you will see most of the jump, if you will, in the second half of the year. Our modeling sort of says that 55 to 60% of our production will be in the second half of the year.

Okay. Can you give me that percentage again.

55 to 60.

Got you. And then separate issue, in terms of -- I know you increased your CapEx budget and I saw the split. Are you reallocating capital among the different areas? For example, are you putting more money in the Granite Wash play and less money elsewhere? Could you talk about that a little bit?

I can only talk about it in general terms, and that's simply because there's not a real specific to talk about. If an opportunity avails itself in the Granite Wash or somewhere else we would -- we would, in fact, look at our portfolio and decide if we didn't want to fund something, because it was significant out of debt to redeploy assets or to redeploy our capital budget, Joe, that's a decision we make on the fly almost every quarter. There's an update to our forecast and our mix of projects. So, yes, we would move things around as opportunities presented themselves, and if necessary we would high-grade the portfolio. Just a little bit more on that because I think it's in our offshore leases and so forth. We haven't done a major reallocation of any kind. For example, within the Cotton Valley play I think we've allocated a little bit of money away from some of the vertical drilling towards the horizontal drilling, things like that.

It looked like the drilling capital is roughly the same from where you had it before.

Right. That's correct. That's true. What I will tell you, again, I know you're trying to build a model, but that can move around. It traditionally has with us.

Understand. Appreciate it.

we've increased the exploratory drilling a little bit. We've increased the leasehold spending. Just a number of smaller factors.

Got you. Last question. On the Haynesville, are you looking to bump up your acreage position pretty meaningfully from here, or do you sort of take -- wait until you see the results and then try to be aggressive there.

I think we're constantly trying to lease. Chesapeake makes that announcement, kind of messes up the neighborhood. Made things a lot more expensive to lease. But we surely have landmen deployed, and we're trying to add to our leasehold, whether it's the Haynesville or the Cotton Valley.

That's helpful. Thank you.

Thank you. Our next question comes from the line of Irene Haas with Canaccord. Please proceed with your question.

like to ask you a question I heard earlier. You mentioned you made a purchase in the midstream in western U.S., I believe in the Wyoming Powder River area. And you said that it it will give you an window into the whole gas world. My question is are you interested in the midstream or are you also looking at upstream as well?

We're interested in the mid streerjs and that certainly is the acquisition we made. But anything that we do, we ask Baird's people on the oil and gas side to see if they can find something that's a midstream application and the reverse. So if we are sitting in the management meeting, and within the rules, of course, of what you can reveal and not, if we find an opportunity that might lead to something on the up stream side we look at it, we're not currently there. We're not real wild about being in another area, to be honest with you. But if a real opportunity reared its head, we would surely look at it. I want to make sure that I'm clear that we're not actively looking to get into the Rockies.

That's what I'm trying to get at since right now you have a really nice portfolio in the Central and Eastern part of the country. Great, thanks.

Thank you. Our next question comes from the line of Richard Tullis with Capital One Southcoast. Please proceed with your question.

Hey, Jim and Frank. Good afternoon.

How are you?

Good. Going back to Bakken, how close did you say you are to recent Marathon wells?

I didn't, but John did. What did you say, John?

Well, we are currently drilling is several miles away, although we do have acreage relatively close to the recent Marathon test.

Ballpark, what are you guys looking for? Something similar to the 300, 340,000 barrels EURs that's Marathon's referencing?

I think that would be considered a successful well for us.

What kind of well costs are you looking for on those first couple of wells?

You have the floor, John.

That's probably going to range between 5.5 and 6 million on the high side.

Okay. What kind of cost trends are you seeing in your more active areas on rigs, completions, things like that?

We're in a lot of active areas. And I want to try to answer your question so let me just -- Mike what are you seeing?

Well, we're doing well to hold our own right now but there's an upward pressure across the board right now from steel to the service sector to the drilling side.

John?

I would echo that. There are definitely upward cost pressures.

And Jim, what about Mississippi and Appalachia?

Steel prices are certainly increasing. The service pressure for Northern West Virginia and Pennsylvania I think is going to increase exponentially as the Marcellus shale projects take off.

Thank you. Jim, are you able to give out your current production level?

Well, for the quarter we were 115, and maybe we're 120 right now. I don't have the number right in front of me, because we don't compute it day to day but it's right around 120, maybe a little above it.

Very good. Lastly, on Haynesville Bossier, what kind of activity are you seeing around you as far as acreage acquisition costs, things like that?

Well, the general answer it's getting more expensive. I think Chesapeake has become pretty active in and around our area, but Mike you can help me out I'm sure.

You're correct, Jim. Chesapeake and all of the usual suspects are pretty active right in our area. We've got a great position well within the heart of what we consider to be the best gas use region, and we're working to consolidate that, then also to expand it. So we've got a significant leasing effort of our own.

How thick do you think that shale is in your area?

Well, I don't know. I guess there's nothing wrong with -- what do you think, Mike? 250? 150?

There's actually two distinct lobes we're looking at. The lower one where the initial well was targeted is approximately 350 feet deep.

Okay. Excellent. That's all for me. Thanks a bunch, gentlemen.

Thank you.

Thank you. Our next question comes from the line of Steve Berman with Pritchard Capital. Please proceed with your question.

Thank you. Good afternoon. A follow-up to that last question in terms of the leasing activity. I think it's pretty widely known on the Louisiana side of the place, it's pretty crazy, but are you also seeing a lot of activity on the east Texas side with costs going up, et cetera?

It's certainly gotten a lot more active. I think Mike tried to allude to that. I don't know what exactly what the cost structure is there but it's getting more active. And, I'm not talking down about anybody. Chesapeake gets in there, and they'll spend money, and that generally tends to drive prices up, and we're surely seeing that.

Okay. And on the -- Jim, on the future wells you are going to drill, in the Haynesville, would you anticipate wanting to test some of the joint venture acreage with GMXR with these two or three more wells you're going to do in the back half of the year?

Mike, I'll ask you to help me. I don't know that we've sited those wells, per se, or have we?

The short answer is yes. The joint venture acreage is certainly has some prospectivity. We've got three or four other areas that we'll be testing this year, and they'll all be on PVOG 100% acreage.

thanks.

Thank you.

Thank you. There are no further questions at this time. I would like to turn the call back over to management for closing comments.

Thank you very much. Again, all of you, thank you for listening and participating. It's a pleasure to talk to you. It's a pleasure to try to answer your questions. And we'll see you next quarter.

Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation.