Ranger Oil Corp (ROCC) 2004 Q1 法說會逐字稿

Good afternoon, ladies and gentlemen. Welcome to the Penn Virginia Corporation first quarter earnings conference call. At this time all participants are in a listen-only mode. A brief question and answer session will follow the formal presentation.

If at any time you require operator assistance, please press star 0 on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Jim Dearlove, Chief Executive Officer of Penn Virginia Corporation.

Thank you, Megan and good afternoon to those of you who are on the call. Again, it is my - my format here is to not necessarily read to you the press release. On the other hand it does contain all the information so we will try to track along at least in the order of it.

You'll notice that we start with a table this year for this quarter which is a little different. We normally haven't done that but I think it summarizes some of the key financial numbers right up front and you can see and I hate to read to you but I'll just say it, revenues are up about 16%.

The first quarter '03 to first quarter '04 net income is down about 4% and that is what the number is. I would remind you, though, that in the first quarter of 2003 we had a sort of a catchup because we adopted the accounting standards number 143 which added about $1.4 million to -- of gain to that quarter.

So if you were to adjust to that catchup you would actually find that we had a little bit better quarter, about 11% better in terms of net income this year versus last. The cash numbers are strong comparing the two years as you can see, up 30% on net cash provided by operations and up about 21% on operating cash flow.

Lets look behind the numbers a little bit starting with oil and gas. Our oil and gas revenues of $37.5 million are about two thirds of total revenue. Those oil and gas revenues were up about 9% over the first quarter of '03 and that came about primarily because of an increase in production of about 11%.

Actually, since we're at 89% gas, the fact that gas prices were down actually quarter over quarter hurt us a little bit but we were able to over come that with slightly higher oil prices and increase in production.

Expenses, again, as you can see, were up about $3 million or 16%. Two main drivers as Frank has outlined here in the release, $1.4 million came from exploration which is something we can do at our discretion, of course.

And about $1.2 million was a noncash increase in DD&A driven primarily by the increase in production. Cap Ex, again, up about $20 million, -- $20.3 million - not up, was about $20.3 million which is roughly 18% of the mid-point of the guidance that we put out this quarter which is a budget of 110 to $115 million, we'll tell you a little bit about why it increased.

We spent that $20 million drilling 33 wells. Two were unsuccessful, they were miocene - shallow miocene well in eastern Louisiana. We will step back clearly on that program and take a look and see what we are doing there that was not critical to our guidance.

Beyond that 22 of the 33 gross wells are on production. One is being evaluated the others are either being completed or are waiting connection to a pipeline. I think not to hit on all of them but there is a couple of high points that I think are worthy of mention.

One, our GMX project, in eastern Texas, on the cotton valley, we're very pleased with how that's begun. That's new to us this year. We drilled a well and completed it and it is in line, expected to make a million and a half to two million a day.

Right now we are producing out of the cotton valley but we have reserves in the Travis Peak and we will ultimately co-mingle those. The second well is TD and is being completed based on what we can see so far. We're quite pleased with it, we've excellerated the process, brought a second rig in, it'll be in ten days or so.

Right now what we're hopeful is that we'll drill at least 12 wells there instead of the 8 that we had expected to drill earlier in the year. Just to put it in some perspective, we have an 80% working interest in the first five wells that are drilled and then if GMX wants to go forward we're 70 -30 after that.

We continue to be successful in the Selma Chalk in Mississippi, we're 12 for 12 this year. With the horizontal CBM program there's two wells that are complete, and we hope this year to be able to drill the equivalent really of 30, 400-acre patterns. Some will be more complex and a little bigger, but on an equivalent basis that's what it would look like.

In Kansas which is, again, a project that we undertook late in 2003, we drilled ten wells there. They are conventional CBM wells, they're dewatering, we've got some gas shows.

I would say we are cautiously optimistic but making no predictions. It'll probably early in the third quarter before we're really sure of what we've got there.

Baird, is there any exploration update that you want to give?

As far as what we got accomplished the first quarter, we did not get a lot accomplished the first quarter. We got two wells drilled in Mississippi like Jim said.

We TDd our Esperanza well in Oasis-Kennedy, Texas, the Vixberg test - that well is still under evaluation as we speak. Most of our activity is going to be in the second, third and fourth quarters. Our Creole discovery we had in (ph) Camera Parrish, Louisiana late last year a lot of (ph) planulina sands, O sands and J sands specifically we will have a development rig moving in sometime in June to drill an offset to the first discovery we had.

We expect a second rig sometime about a month thereafter to start our exploration program there. We have three wildcats planned in that project and two development wells planned this year.

Stella, we have a rig coming in here soon and by late May we should spud another [inaudible] test. That was an area that we drilled four out of four successful wildcats last year in [inaudible] Parrish, Louisiana which [inaudible] the operator.

Our Fannett project which we talked about in previous meetings, you know, we have a seismic and interpretation, we're finding a lot of good things to do and we should get the first of three wildcats spudded sometime in June.

We have two half berry tests to drill and one [inaudible] and we also have an updip, at least one updip exploitation well that we will get drilled probably toward the end of the year.

Lastly, in Kingsville, we have decided to step our program up somewhat from the original budget. We're in the progress of doing a sidetrack with 100% working interest. There was a well that collapsed last year after being placed on production. We are undertaking that by ourself.

We have one development well planned also probably in the third quarter that we did not expect to drill at budget time and we still have our one exploratory well, probably to be drilled in the fourth quarter. Lastly, in the east we have our two key projects up there.

We have an extension of our CVM project in the northern part of West Virginia, we should expect to get spudded by late June after we get some regulatory work completed with Dominion as our partner.

(ph) Devonian shale we talked about it in prior meetings this is in Mason County, West Virginia, test. We're going to be drilling some dual laterals. We are drilling at 100% but it is -- it is a formation that sort of acts like coal that we think that some type of horizontal technology can apply and exploit it also.

Thanks, Baird. I think it is fairly clear that we're trying to stay busy on all fronts. Sticking with oil and gas then for just one more minute and then, of course, we will take questions you will notice in our guidance that second quarter guidance numbers are lower than the first quarter guidance numbers with regards to production.

You may also notice that for the full year the guidance is unchanged. There is a note to the guidance table that explains what is going on here and let me elaborate a little bit on what we faced, and Baird if I say something wrong jump in and correct it.

The KA20 line of Columbia is undergoing repair work on compressors and I guess the line itself which is resulting in a curtailment.

That has spilled over on to Dominion. Dominion has taken on some of the customers who would have been on the KA20 just across the board as has curtailed the people who were already on the line on a pro rata basis.

Regardless of whether we think this that is a good idea or not, there's not a heck of a lot we can do about it. The result is that we're curtailed as we sit here today as of May 1st about 6 million a day which is significant and that is what caused this reduction in guidance in the second quarter.

Worst case, I guess, is that these curtailments are expected to last or we're being told by the pipelines that they will last until November 1st. We can't do anything about it. That would cost us about .9Bs are current or to be developed production. But we still think we can make our guidance.

In order to do that, we're going to need a good fourth quarter, which we expect and we expect the drivers in that quarter to be the horizontal CVM and the GMX.

We have managed to get 5 million a day of firm, and we're looking, scrambling as hard as we can to get another ten. This is a very tight market. We thought we had the ten. Columbia had put 200 million a day of firm up for auction. We had every reason to think we were in it, at the last minute, literally 6 seconds to go in the process somebody came in and bought 158 million of those 200 million. That knocked us out of that game.

So we're fighting back trying to get firm some other way and we're working the prong as hard as we know how. That has prompted part of the increase in the situation in our Cap Ex.

We're accelerating the building of a pipeline 17-miles of 12-inch line which we hope will alleviate problems in the future, give us a little better control of our own fate. So that isn't the most pleasant thing to have to report to you but I can assure you we are doing at all we can.

That is another reason we ramped up our drilling and ramped up our Cap Ex budget to try make up for this and if we get the 10 million a day we'll be in good shape. So we're working the problem.

On the coal side, of the house, and that is to say PVR, the MLP, the MLP had a terrific quarter. It set a record for production, revenue, net income, cash flows. And what drove that as much as anything else was the fact that production was 8 million-tons for the quarter, which was 25% higher than the same quarter last year. And, quite frankly, not something we expect in the future.

It was driven by -- well, at least in the immediate future. It was driven by the fact that on our property we had a long wall that contributed almost a little over a million tons of that 8 million-tons. They were 100% on our property for the quarter.

Just given the way that geology and lease lines work, that long wall will move, which will mean it won't be producing and then it will be producing on and off of our property for the rest of the year. So we don't really think, in fact we're not at all predicting that we bill producing 8 million-tons a quarter.

We're predicting that on the average we'll be producing 7 million-tons a quarter. That is giving us the guidance which is unchanged of 27-29 and take the mid point is 28.

Coal prices are very strong. We think that our coal -- well, we don't think, we know, we reported our coal royalties were up 47% over the first quarter of 2003. About half of that is the result of that increase in production. About half of it is the result of the increase in the realization we are getting on those leases which are sensitive to prices which is about 70 -- 67% of our leases. About two thirds of our leases.

The coal numbers are fairly self-explanatory. Just giving you the biggest drivers. There is a line item called royalty expenses which is up to a million six over $300,000 a year ago, all that is is the fact we on a couple of our leases actually have a -- are a sub lessee so we actually pay royalties and collect them. Collect from the operator but have to pay some to a different land owner.

A lot of that coal got mined this particular quarter so drilled that expense up. DD&A is up a little bit because production is up. Basically I think the coal numbers speak for themselves.

A lot of folks perhaps on this call arent as coal oriented. One quick second on the market. Market prices are strengthening.

The spot market for coal, which is not a very meaningful thing because not a lot of coal is sold on the spot market but is in the $50 range. There is trains that we are ware of at 75 bucks. You can get all euphoric over that, but I'd caution you not to because really not that much coal gets sold that way.

Much more meaningful is the market prices that are being negotiated between the operators and the utilities. We're finding that those are up in the high 30s, low 40s.

We're finding in addition that some utilities are willing to sign five year contracts as opposed to one, two or three year contracts. In our particular case, averaging across the whole of what we have, we are getting on the average $34 a ton.

Our operators are, which is up about five bucks over what it was a year ago. We think that at least in the near term prices are going to strengthen because supply is down and it is down significantly.

For example in central Appalachia, production is down about 4.5% year-over-year. And 52 week period that translates into 10 or 11 million-tons.

Another 20 million-tons is going to most likely go to the met market. Normally that would be steam coal.

The export market is much, much stronger and demand is up because electricity generation is up and that's generally where coal is used. It is a pretty robust, I don't like that word, but a pretty healthy picture I guess on the coal side.

So, maybe that's enough of me and let's hear from you. Operator, we're ready to try to answer questions.

Thank you, sir. Ladies and gentlemen, at this time we will be conducting a question and answer session.

To allow everyone the opportunity to ask a question, please limit your time to one question and one follow-up. If you would like to ask a question, please press star one on your telephone key pad. To remove your question from the queue please press star two.

A confirmation tone will indicate your line is in the question queue. For participants using speaker equipment, it may be necessary to pick up your hand set before pressing the star keys.

Our first question will be coming from Ray Deacon of First Albany Capital.

Yes, hey Jim, I was wondering if you could repeat again the amount of volumes that you'll lose as a result of the columbia issue?

We think that both current and developed volumes, in other words, we're going to go on drilling wells, we just won't get all of them in-line. We think that that would be 1.9Bs over the course of this 6 month period.

Okay. Got it. And what will be the cost to build this, I guess it's an alternate gathering system?

Baird, I'm going to let you handle that, alright?

Yeah, Ray, we have done this in two phases. We started Phase one last year which was some large suction lines and two new compressor stations. That is still in progress. That was 6-miles of 10-inch and some miscellaneous 6-inch and 4-inch and one large compressor station about 5,000 horsepower and another smaller compressor.

Phase two which will begin in a month or two, month and a half which we expect to have done by November 1st would include 17-miles of 12-inch pipeline. That will allow us to essentially tie Columbia and Dominion together with one discharge line to move gas both ways.

In total we will spend about it will be around $12 million between last year and this year with this new pipeline projects to facilitate a horizontal CVM project for the next foreseeable future.

In fact, it's going to take our capacity of our pipeline system in [inaudible] Loup Creek and the garage area from about 20 million a day to 60 million a day so we're adding a lot of throughput capacity with these new pipeline investments.

Right, okay. That is great. How much -- okay. Your capacity goes up by 20 million or to 20 million.

It will go from 20 to 60.

Oh.

When this is all said and done.

Thank you, gentlemen. Our next question will be coming from Joe Allman of RBC Capital Markets.

Hi, everybody.

Hi, Joe.

Question for Baird. Baird, you talked about Kingsville and I missed what you said. Could you just repeat - I heard you say you're stepping up kingsville. Could you say the rest?

We're currently side tracking a well. It's a well that went off production about a month after it was turned in line late last year so, we are doing that side track at about a million and a half dollars. 100% Penn Virginia. We have a development well, that we will drill probably late second quarter, early third quarter time frame. And we still have our exploratory well planned in an adjacent fault block to the main field.

Did you ever figure out what happened with that one dry hole that you folks drilled there?

All said and done, Joe, after we got drilled the dip was just a lot steeper in that part of the field and some of those development locations we had or originally thought we had went by the wayside. But we still feel there is a number of good things to do on the development basis in kingsville and, you know, there are a number of exploratory things to do in adjacent fault blocks as you go to the east.

Thank you, sir. Our next question will be coming from David Khani of Friedman Billings Ramsey.

A question for you, Baird. Could you lay out by area how many wells you expect to drill for the year? Make it simple for us.

Let me start with the east first which includes Mississippi. At this time, we'll drill 35 to 40 wells, 35-45 wells in Selma Chalk. That is between Baxterville and Gwinville.

Our conventional stuff in West Virginia will be some where between 10-15 wells. As Jim said on the horizontal stuff, for planning purposes, we have 30 4-hundred acre type patterns. Now that may be less wells with more acres per pattern. Some mix of that.

We have about $30 million of drilling associated with wells gross on the horizontal CVM. We have 28 gross wells planned in our properties in Virginia. We refer to as Roaring Fork, Wise County, Virginia. Those are only fourteen percent working interest type wells. But they're good locations.

On exploratory front, we had the two wells Jim talked about. We plan on drilling maybe one more toward the end of the year based on the postmortem what we learned on the first two we drilled but we still think it is a viable play.

We had the Devonian shale well I talked about the horizontal Devonian shale well and we also have an exploratory horizontal CVM well in the northern part of West Virginia that we will spud sometime late June.

And lastly we're going test the coals in Gwinville. There is a Wilcox coal that is 20-25 feet thick. It has got gas in it. It is a (ph) sub-bituminous-type coal and we will give it a shot. Based on gas cost debt and pressures we will give that a shot and see if it works.

In the gulf coast, we will drill four wells, four to five wells in north, Louisiana, in the Cotton Valley. That is with a partner. We have about a third interest in those wells. As Jim mentioned, we will drill at least 12 wells in our Cotton Valley play and in east Texas and which we're very pleased with the results so far.

On our [inaudible] Parrish Stella project we have drilled one small interest wildcat first quarter which was successful. We have two more wells planned throughout the year the first of which out to get spudded here in a few weeks.

Creole, our Camera Parrish project, we have two development wells planned off the successful wildcat we drilled last year. And we have three wild cats planned. All these wildcats, by the way, are identified.

Esperanza, we drilled the first well as I earlier spoke. We have two (ph) freia wells planned. These are on the larger side, 5 to 600 acre. Fairly large prospects that are bright spots and look pretty good and we should get the first of those spudded probably early June.

We have one more Vicksburg test to drill that tests the shallower section of the Vicksburg than what the first one did and we will probably get it spudded sometime late summer early fall.

We have at least one well on the Bayou Sally project this is the one when we were talking about south Louisiana, it's over in Saint Mary Parrish. This is the joint project we have with Plains based on a new 3D we shot last year. We are finding a number of good things to do. We're very pleased so far with it.

And we should spud the first of those wells probably mid-summer time. Fannett we have three wildcats planned and at least one development well and maybe more than that. We should get spudded on the first wildcat sometime in -- sometime in mid to late June.

And lastly, Kingsville we have the one side track, we have the one development well to be late second early third and we have the wildcat, excuse me, late in the year.

The problem with Baird is he is never specific, you know.

I spill my guts. Everything I know.

Thank you, sir. Our next question will be coming from Dan Morrison of Aperian Group.

I apologize, I got on a little late. I was depending on my computer clock. Looks like your gas realizations relative to Nymex improved substantially in the first quarter. Is there something behind that other than a shift towards more Appalachian production kicking in? Or is that a good explanation for that?

I think you captured the -- what is going on.

And did you give a production breakout by region early on?

No, I don't believe I did.

Do you have one handy or I can call back and get it if --

It is probably in that book and I didn't bring. We're looking. We'll answer your question,I just can't do it off the top of my head.

Dan, I could tell you, for the first - this is Frank Pici.

Hi, Frank.

We produced about 2.4Bs in what we consider the west region which is Texas, Louisiana, and about 4.1Bs in the what we call the east which is Appalachia and Mississippi.

Is that a shift to the east relative to the prior couple of quarters?

I don't think so.

No.

I wouldn't.

Not on a relative basis. I mean it is -- it is about the same. Maybe a little bit more after shift because of the HCBM, the horizontal CBM production.

Baxterville we turned in a bunch of wells late last year, Dan, in the first quarter and Baxterville was ramping up considerably in the first quarter so that cost a big part of it. First quarter.

First quarter, that's right.

The other thing we had going on in price realization just, by the way, we had more hedging settlements in the first quarter.

Higher hedging losses, if you will, just due timing of when we placed our hedges so that brought our realizations down a little bit first quarter '03 compared to first quarter '04.

I was looking at sequentially from the -- you know, even just third and fourth quarters of last year looks like you had a good improvement in the aggregate realization.

Yeah, okay.

One quick follow-up question. The -- you had some pretty long length horizontals that were drilling or completing, you know, recently. Did y'all share any of those rates off of those things yet? The ones that had like the 120,000 feet?

Dan, we're still drilling those. We have -- we have one of those -- we have two of those co-mingled patterns done in one well. We are drilling the other ones and should have those wrapped up probably in the next month or so.

The first well, we drilled we don't have a rate ton but based on preliminary information from the field it looks like it is going to be a very strong well.

So until we get this Columbia issue resolved, probably not going to get a fair, fair uncurtailed test on these wells of course, but we will be doing some testing to the atmosphere and in line tests. But so far we're very pleased with the one well, we have done up in Loup Creek and (ph) La Grass area.

Thank you, sir. Our next question will be coming from David Snow of Energy Equities.

Just trying to get an idea as to how many rigs you will be using for this horizontal drilling? You have got I guess 28 wells to go. Plus I think the Devonian shale and a couple maybe I'm double counting them with Dominion and Exploratory. How many rigs have you been using and what are you going to be using to accomplish all this over the balance of the year?

In the AMI that we have with this company called CDX that we referred to from time to time and who has the patents on the technology that we are using with them in central Appalachia, we have three rigs running right now.

I guess we -- we're hopeful there may be a fourth rig running this year but right now there are three rigs running. If the shale test and the other CBM test that Baird alluded to, those would be other rigs.

Would that be CDX rigs?

No.

Who would you be partnering with there?

Well, in the -- in the CBM test we would be partnering with Dominion. In the Devonian shale test.

That is 100% work interest. Doing it ourselves.

That is doing it ourselves.

Thank you, gentlemen. Our next will be coming from John (ph) Arfrig of Third Point Management.

Hi, guys. I notice that the distribution at PVR right now is $2.08 a year and I'm curious how soon will PVA's GP interest income start to stream in from PVR? And are there plans to do accretive acquisitions to increase that payout and then consequently enhance the GP interest at PVA?

I'm not sure what your first question really was, John. Did you ask whether we are moving through the splits? I'm not sure what you really asked us. I'll answer both halves of the question but I didn't understand the first one.

Sure, well basically, I'm looking at the split schedules and I realize that some of the GP interest has kicked in at 2 bucks and the threshold is at 220. We're getting closer to higher payout thresholds and I'm curious what your plans to enhance that dividend payout or if you guys are, you know, actively looking for acquisitions to make.

Okay. Excuse me. Yeah, the second half of that for sure, yes, we're looking or acquisitions that would be accretive.

We made a couple of bids this year, as a matter of fact, that we didn't work out but we're quite hopeful on some other things that we are working on.

Just so for the sake of completeness for the people who are on the call because we addressed this a couple of hours ago on the PVR call, we are looking at coal acquisitions. We are looking at coal acquisitions, they are hard to make in this environment.

Sellers demand what sellers demand and they look at prices today and want to price everything off of today's prices and not what prices may be in the future. Perfectly understandable but makes it a little more difficult.

We're looked at some ideas that we have with coal infrastructure, i.e. facilities that handle coal and aren't necessarily tied to a given mine or a given set of reserves. We are looking at some oil and gas mid-stream ideas.

Again, the thought there is to walk before we run but we have got expertise in-house to evaluate and manage those sorts of assets. So we're looking at those as well.

So PVR is very, very actively looking for acquisitions with the intent, John, that they would be accretive and with the intent that it would move us closer to those splits and through the splits.

We surely want to get into the splits but the worse thing you can do in our opinion in an MLP is to raise your distributions to a point you can't sustain them.

Along those lines if you look at pricing increases, can you just go through what type of pricing pickup we should see over the next couple of quarters and how that will enhance any types of distributions?

In coal you mean? You mean coal prices?

Sir, he has exited the queue.

I think if you meant for coal prices and that's what I'm going to assume. As I said, two-thirds of the coal that is sold off of our property is sold in to what are price sensitive contracts.

50% of the coal that is sold off of our property is sold into term contracts that are operator -- the operators on our property have with the utilities. Those might be anywhere from 1-3 years long. Typically a third of them rolls off in any given year. Those prices have increased year-over-year on such that our average realization has gone up 5 or 6 bucks a ton, then we get a percentage of that 6, 7%, whatever it may be.

There are spot market is wild right now and about 20% of our coal is sold on to the spot market. So prices have increased. They are continuing to increase. We think they will continue to escalate, although it is like any commodity, it going to be mean reverting. There will be an end to the game.

But the economy is strong. Supply is low. So all of that said, we would expect a gradual increase in the organic element of PVR but the real way to grow PVR is not to grow coal prices. It is to grow volumes.

We can't grow volumes off the existing lessee set rapidly because it takes twos to get a permit for a new mine and basically we're fairly leased up. The name of the game has to be acquisitions and that is ow we are trying to play the game.

Your next question is from Ray Deacon of First Albany Capital.

Yes, hey Jim, just following up on that last question. So without acquisitions, what would you see that 8 million or 7 to 8 million-tons per quarter number stay basically flat going into next year or a little bit of a decline or?

I think what we are expecting over the next few years is for that number to not increase dramatically. I think there is some, Keith, help me here. We expect some organic growth in production but even without acquisitions; is that fair?

That is correct. We will see little ramp up over the next 2 -3 years.

Okay. Got it. Okay. And Baird, I was wondering whether you could just talk a little bit about the seismic you got earlier this year in the gulf coast and what you're going try to get out of that for drilling this year or is it really an '05 event that we will see drilling based off that?

I think you're referring to, Ray, the western GICO database we break up 5,000 square miles. We are actively working some part of that data. We have not taken delivery of all of it because of how the scheduled delivery is set up over the next three years. But we have some outside people working it, we are working it internally but it will be prospects developed this year. Acreage acquired on the prospects this year and next year and they will be 2005 and beyond time to finish to drill that, that is correct.

Thank you, sir. I would like to remind the participants at this time, if they do have a question they may press star one on their telephone keypads. Our next question is from David Snow of Energy Equities.

Are you planning on using an attempt at the (ph) Fannett formation or something similar for the Devonian horizontal drawing?

No, it will be something very simple, David.

Just a simple horizontal lateral, I guess.

That is correct.

What is the potential for ongoing drilling at Selma?

Well, we have acquired a fairly large acreage position especially in Baxterville and we have a lot of locations. I would estimate at this time anywhere from 150 to 200 to drill over the next 3-4 years. We are still acquiring acreage. One thing we have found is we have been able to push the dime dip limit of the field further down than we originally thought so we have got a fairly large drilling inventory of things to do down there.

Thank you, sir. Our next question is coming from John Arfrig of Third Point Management.

Hi, guys. Just a follow-up question. I noticed you paid down $9 million of debt at PVA in the first quarter. Can we expect continued de-leveraging on a going forward basis for the next couple of quarters?

John, this is Frank Pici. I would say probably not. What we had there was some working capital pickups we had that allowed to us generate a little excess cash. The drawing program was active but not as active as it will be the rest of the year. I wouldn't expect a big decrease in the debt level. They are already low, low leverage.

I think we have got at this point around $55 million drawn on $150 million commitment and plan to be active the rest of the year, I wouldn't expect a big decrease in debt at this point.

Thank you.

Gentlemen, this are no further questions at this time.

As always, we appreciate the questions we, we appreciate the interest and time you all take, the fact that you follow the stock, hopefully you own the stock. And so with that we'll sign off and see you next quarter.

Thank you, everyone. This does conclude today's teleconference. You may disconnect your lines at this time and have a wonderful day.