Ranger Oil Corp (ROCC) 2010 Q4 法說會逐字稿

Good day, and welcome to the Penn Virginia Corporation fourth quarter 2010 earnings conference call. Today's conference is being recorded. At this time, I would like to turn the conference over to Jim Dearlove, CEO. Please go ahead, sir.

Thank you, John and good morning. I am joined today by Baird Whitehead who is the President of the Company, and is also the person who oversees our oil and gas operation; Steve Hartman, our CFO; Jim Dean who is our Investor Relations person.

I'm going to refer to -- we put up three releases yesterday, I'll be referring primarily to the fourth quarter and full year 2010 results release. So looking at that release, and just sort of reading off the release at the beginning of it, the fourth quarter highlights, which are compared in the release to the fourth-quarter of 2009 include the following, record proved oil and gas reserves of 942 Bcfe. That's natural gas equivalent as of the end of the year 2010, which compares favorably to (inaudible -- technical difficulty) -- these numbers, which were 911 Bcfe, and that's taking out the effects of the Gulf Coast assets that we sold early in the year, in 2010.

The quarter production was just over 13 B's, or 142.5 million cubic feet a day, which is a considerable increase over what it was last year in the fourth quarter. Again, pro forma for these Gulf Coast assets. We had an operating loss of $25 million. These things are explained in the release. Primarily, however, that was driven by a 60% decline in prices. Cost, or direct operating expenses improved considerably to $2.02 [an M] produced versus about $2.58 in the fourth quarter of last year. Our recurring EPS was about $0.24.

Moving on to the comment piece of the release, I will paraphrase it rather than read it. What is going in the fourth quarter of 2010 is a reflection of our change in strategy that we put in place over the course of the year, which is to move away from being heavily leveraged to gas and moving more and more towards the liquids rich plays. At the same time, we are preserving our optionality to national gas. In other words, we had a lot of acreage in that's HBP that is there to be produced, but we are not producing it right now.

I just recited to you our production and reserve results, and they're detailed in these various releases. And some [revoke] production in reserves, as I said, we're up relative to 2009. Importantly, about 21% of our 2010 production was liquids. We expect that percentage to increase as we go forward into 2011 and beyond, with oil hovering around $100 right now, it seems like that is a very good strategy for us to be following. Trying to put our reserve picture into some context, I'd ask you to keep in mind that our reserves include a 45 Bcfe downward revision due to the five-year rule put in place by the SEC.

In summary, that rule says that any reserves that are not expected to be produced in the next five years must be removed from the reserve basin. We're not going to be alone in having to face this issue. Those reserves really don't go away.

That's not say we will produce them, but they are there, and if gas prices were to improve and we could produce them, we certainly would. Speaking of reserves we have been able to increase our reserves as a company. We've almost tripled them in the last five years, which if you do the arithmetic, gives you a compound average growth rate of about 23%.

Oil and gas -- excuse me, oil and natural gas liquids reserves increased from 17% to 21% of the total. This change had a very positive effect on our PV-10 as it's called, increased almost 30% to $880 million.

As we look into the rest of 2011, I would just say, as is summarized in a separate release we put out yesterday, we are very encouraged by our first Eagle Ford shale well, which was drilled in Gonzales County, Texas. The strong performance of this well, taken together with nearby industry results, have caused us to really increase our emphasis on Eagle Ford play and I am sure Baird will be talking about that.

One example of that, which we also announced yesterday, is that we recently acquired an additional 4,100 net acres in Gonzales County, Texas. And we've elected to shift an operated rig from the Mid-Continent to the Eagle Ford. Additionally, we expect to add a third rig in the Eagle Ford by midyear 2010. That is not to say that we won't continue to be active in other places.

We certainly have in the Mid-Continent, despite some disappointing results in some of our Granite Wash wells -- a lot of different ideas there, multiple prospects that we want to evaluate. Some we can talk about and some that we can't. As pointed out in the release, in the Marcellus we drilled our first horizontal well and are drilling a second one from the same pad.I think production results should be on line in and around midyear of 2011.

So, in 2011, these three areas will be our areas of focus, at least as we sit here today. Keep in mind that Penn Virginia has in East Texas, especially in it's horizontal Cotton Valley program, in Mississippi and in Appalachia considerable natural gas reserves that are essentially helping our production. Again, as natural gas prices improve, we are very well-positioned to take advantage of those opportunities.

If I look at -- again, following the format of the release, the -- very briefly go over the 2010 results and the fourth quarter operational results before turning this over to Baird. Not to make excuses, I think, as we all know, 2010 was a fairly difficult year for companies leveraged in natural gas, just looking at what happened to prices; they certainly took a toll.

For Penn Virginia, 2010 we incurred an operating loss for the full year of almost $99 million that included $46 million of impairment charges and other details that, again, I'd refer you to the release. The adjusted net loss which excludes charges such as the change in derivatives, fair value, or impairments or restructuring cost was about $32.7 million loss in 2010.

Again, I would refer you to the release, rather than me sit here and read numbers to you. You can look at them on the tables and compare things.

For the year, production pro forma of the Gulf Coast was 46.9 Bcfe versus 45.2 in 2009. And, as I said, reserves were up to 942 Bs. There is a table in the release detailing the year end production by region for both the quarter and for the year. Again, I'm going to leave that to Baird to talk about those kinds of results.

One thing that is only in this release does deal with prices, fourth quarter of 2010. Our realized natural gas prices, that's pre-derivatives, was $3.50 an M, 16% below the comparable quarter, 9% and 18% below the third quarter of '10.

Conversely, oil was up. Our realized price was $82.84 a barrel, 13% above last year's fourth-quarter, and a little over 17% higher in the third quarter of this year. NGL prices tend to perform sort of like oil prices, and they did for us. Our NGL price is at $42.20 were about 19% higher than in the -- either the fourth quarter of '09 or the third quarter of '10.

And finally, although I said it earlier, we had an improvement in our operating expenses. Direct operating expenses were about $2.2 an M versus 258 an M in the fourth quarter of '09. Again, I refer you to the very detailed information that is in the release, rather than me read you numbers. I think with that I will turn it over to Baird to take us through the operations.

Thank you, Jim and good morning. I will go through the play types like I typically do in the areas and of course I want to start out with Eagle Ford. The results of the first well, which were very, very good, were in the press release we made with an initial rate of about 1100 barrels a day, and about 1 million cubic feet a day. That well has been online now for almost a month, and is still making about 700 barrels a day and about 1.1 million a day, still flowing with about 1200 [pies]. So it is a much better well than what we had utilized in our type curve, and we are pretty excited about what we have here in our initial well. We drilled it at about 4,600 foot lateral, we fraced with 16 different frack stages. It is oil at 41.5 degree gravity.

The heating value is extremely high on this gas about 1500 btu, and because of that, of course, the liquid content is high. It's about 190 barrels per million. The plan is we have signed a processing and gathering agreement with a large processor. That line should be laid to December, our leasehold probably by April 1, and the intent is to go ahead and flare gas up until that point in time to continue to bring back frack fluid.

Here in April, we should start realizing the upgrade because of the liquids. The initial well is going to cost us anywhere between $9 and $9.5 million dollars. It is on the higher side. We have spent some science dollars. Once we get into an active development program, we feel we should be able to bring those costs down, at some place in the $7 to $7.5 million range as we get the synergies of higher activity.

Jim pointed out, we did make another acquisition that is fairly close to our initial acquisition. Right now, we have a little over 10,000 acres. That anticipates that a partner that we had in our original acquisition will also go along with a one-sixth interest in the second acquisition. This additional acquisition brings us 55 locations -- excuse me, it brings us 40 locations. If you take into account the original acquisition we made that has up to 55 locations, we are getting pretty close to 100 locations in the Eagle Ford. Of course, that will support an active program here for some period of time.

Jim also mentioned, we are moving more money into the Eagle Ford effort, and plan to drill up to 29 wells in 2011, spend up to about $165 million, that almost 50% of our capital program is now going to be spent in the Eagle Ford. We have the second rig showing up approximately April 1, and we have a third rig at this point in time that will show up about May 1. We will be busy in Eagle Ford by the middle of the year.

In the Mid-Con, talking about the Granite Wash, and it's really not as bad as maybe it appears to be. We did drill 11 gross, five net Granite Wash wells, both development and exploratory. Nine were development, two were exploration.

Of the five net wells, 4.5 net wells were successful and the other half-well is still under evaluation. We completed 10 gross and 3.9 net wells in our South Clinton field, with IP rates between 5.2 million and 14.9 million a day. And, to remind everyone, up to 45% of the equivalent volumes is well head oil and we have an additional, up to 25%, of NGL's net as shrink. To remind everyone, as of year end 2010, we still have 45 gross pud locations. Those pud locations have 5.4 Bcf equivalent per well including liquids. A 5.4 Bcf well is about a 50% after-tax rate of return. So it's still very attractive even though that 5.4 is less than what we had used as the average practice at this point in time.

On top of that, we have an additional 36 gross probable and possible locations. So, between the two we are up about 80 wells remaining to drill in South Clinton. As we pointed out in the last conference call, (inaudible -- technical difficulty) communication problems. We have continued to address this problem with the older frack design. We continue to shut in offset wells -- older offset wells as the newer wells are fracked. We are maintaining an active artificial lift program on the older wells to remove fluid because of the frack communication problem.

But, the frack communication problems are a lot less than what they were in the second and third quarters of this year. As I said, we shut in production on the older wells. In fact, we actually shut in about 180 million cubic feet of gas in the fourth quarter. We shut in almost 200 million cubic feet of gas in the first quarter of this year, as we continue to have an active frack program.

On the expiration program that we drilled in both the third and fourth quarters, this includes the wells that we had previously reported on in both Powell, Cloud Chief and East Sayre. At the time in the third quarter, we reported results, they were drilling results. The drilling indicators had indicated that we thought we had discoveries along with the open hole logs. After completing, we have some disappointments. To give you more detail on those, in Powell and Cloud Chief, our partner and ourself had drilled a total of four wells, three of those were horizontal and one was a vertical.

The initial well we drilled was referred to as our bright angel well -- that well actually tests at 7.7 million a day equivalent. It had some higher volumes of formation water initially that tended to decrease over time. More importantly, the oil percentage of the first well was about 70%. It was much higher than what we typically see up in South Clinton.

The second well drilled by our partner, called a Rebecca 1-14, tested 100% water. And our working interest in these first two wells were on the smaller side. In the first two wells, we drilled pilot wells. We ran some sophisticated open hole logs, or our partner did, based on those open hole logs, and knowing we had gas within those intervals, we drilled laterally in the Granite Wash D Zone in one well and the A Zone in the other well. But, what we are seeing, after we had drilled two of our own wells is this Granite Wash in general is getting a lot thicker as you go to the South.

There are some gas saturated intervals, but there is also -- as a result of the thickening, there are some water wet intervals both above and below the gas saturated intervals. What we are seeing is not only is it difficult to try and stay within that gas interval as you are drilling the well, but more problematic is when you attempt to frack these wells we are fracking in the water. Our third well that was drilled was drilled by us.

We only fracked two stages of the toe because of this potential water problem, and the third well actually made a little bit of gas, but not enough to be commercial in a lot of water. And the fourth well, we actually decided to complete it vertically and we are under way on that completion, as we speak. Because of the geology, it has gotten much more complex. There is no good way to think that we can stay out of these water zones, especially after fracking. We have decided to put any further drilling in the Powell and Cloud Chief prospects on hold because it actually introduces another level of risk, of course, in trying to drill these kind of wells.

In addition we completed our East Sayre well. Again, based on the open hole indicators, we had a discovery. The well did make gas and oil, made about 350 mcf a day and 20 barrels a day, which, of course, is lower than our expectations. At this time we do not have a real good reason why this thing has under performed.

We had three zones within the Granite Wash, we completed in one of those three zones. Depletion could have some effect, but there did not appear to be any significant depletion problem. The other problem could have been is we also had a mechanical problem and only had about 2000 feet of lateral completed. This, alone, would not have explained the result.

In any cases, because of the risk of East Sayre we're going to get this thing in-line and see how it does. But, as of now we are going to put this on the back burner, at this point in time, until we get it figured out.

Our Mid-Continent program this year is going to be comprised of primarily drilling the development wells in South Clinton. Penn Virginia will drill two to three of those wells. But more significantly, we will continue to participate with Chesapeake in 20 outside operated wells. Just to remind everybody, again, even though the reserve per well for puds are less than what we typically have seen on the average, there is still a 50% after tax-rate return. So, there's nothing wrong with that.

Switching gears and going to the Cotton Valley, rather than just talking about our fourth quarter program by itself, I think it is more important to talk about the initial test program, drilling horizontal wells in the Cotton Valley. We drilled seven of those wells in 2010 with IP rates of anywhere of a little bit less than 1 million a day all the way up to 4.1 million a day, plus liquids which adds about another 20%.

Other than the million a day well, we have been very encouraged with what we have seen. The decline rates are, are typically a lot less than what we see early in the light, as compared to a vertical well and the wellhead oil volumes, especially on the wells we drilled in the Davis portion of the Cotton Valley, which is the upper part of the Cotton Valley -- much higher in oil content. In fact, we're seeing about 40 barrels per million in these Davis wells.

At the well head, we're seeing another 40 barrels per million of NGLs. So, even though we had no money earmarked in this year's budget to drill, Cotton Valley wells is still an option that we have to drill these wells, if liquid prices continue as high as they are, and more importantly we will continue to sit back and monitor these wells and monitor their performance to confirm what we think will be very economical wells. We think, at least based on what we know right now we can selectively drill Davis wells with about 20% to 25% after-tax rate of return.

Lastly, the Marcellus, as JIm said, we did kick off our Marcellus program. We have drilled one well, a lateral length of about 3,500 feet and are currently drilling the second well from the same pad. After the second well is drilled, we will complete both wells and expect to have them online by mid-year. We have secured our transportation on one pipeline and are in the process of securing additional transportation on a second pipeline. We should have no delays after we get these first two wells drilled and get them in line. With that, Jim, I think that is it.

Thank you, Baird. As usual, a very terse report.I will turn it over to Steve Hartman now who is our CFO to take us through things like capital resources, interest expense, derivatives and then if you could go through the guidance as well, Steve.

Okay. Thank you, Jim and good morning, everyone. Turning to our capital resources and liquidity, our cash and cash equivalents at the year and were $121 million. As a reminder, this cash is what remains to be reinvested of our approximately $450 million in net proceeds from the sales of our holdings in PVG in 2009 and 2010, and from $28 million of non-core asset sales in 2010. At year-end we had outstanding debt of $530 million, consisting of our $300 million senior notes maturing in 2016 and our $230 million subordinated convertible notes maturing in November of 2012.

We had no outstanding balance drawn on our $300 million credit facility with a $420 million borrowing base. We have an accordion feature on the credit facility that will give us access to the full $420 million subject to bank participation, which I would not expect to be difficult given the strength of the bank market today. So far, our total liquidity, I assume we have access to the full $420 million borrowing base, our liquidity as of year end is $540 million.

Our liquidity, together with cash flow that we expect to receive from operations, we feel is adequate to fund the 2011 program. Moving onto our hedging program, our cash settlements from hedging in the fourth quarter were $8.5 million including our interest rate swaps. From commodity hedges and loan, we received $8.2 million during the quarter, which gave us and $0.82 per mcf uplift in our natural gas realized price.

Oil hedges, which are a small portion of our hedge portfolio, were in a payable position through this quarter and decreased the realized price of oil by $1.43 a barrel. For the full year 2010, our cash settlements from hedges were $32.8 million, $33.5 million of which were from our commodity hedges. For 2010, commodity hedges increased our realized natural gas price by $0.87 per mcf and decreased our realized oil price by $0.61 per barrel.

We recently hedged an additional 10,000 mmBtu per day for the second quarter through fourth quarter of this year and 5,000 mmBtu per day for calendar year 2012. The table on page 10 of the release summarizes our hedge position as of today. As a percentage of our midpoint of 2011 guidance, we have approximately, half of our natural gas production hedged and 40% of our total commodity price exposure, including oil, hedged for 2011.

Moving onto the 2011 guidance update on page nine of the release, and starting with production, we are reaffirming the guidance we provided in our December 17 release at 50 to 54 bcfe. We elected to keep production guidance flat despite our encouraging initial well results in Eagle Ford, in addition to the rig there, due to the start up timing in the Eagle Ford and the lost production in the Mid-Continent for moving the rig. Looking at our production mix, we expect our percentage of oil and NGL production to increase to 26% based on the midpoint of guidance, up from 18% we realized in 2010 and 15% in 2009, which further demonstrates the commitment to becoming more oily.

For operating expenses we expect 2011 to be largely in line with 2010 on a per mcfe basis. We expect gathering and processing to be slightly higher due to the addition of Marcellus and Eagle Ford production while we are contracting to have midstream infrastructure constructed and managed by third party. We raise our depreciation, depletion and our amortization guidance by $0.50 due to the change in production mix.

Finally, we are raising the CapEx guidance from our initial range of $265 million to $290 million, to our current guidance range of $300 million to $345 million. As Baird already discussed, this increase is primarily due to the acquisition of Eagle Ford announced yesterday, including adding the third rig mid-year, and to a lesser extent working on our interests in the Marcellus. This is partially offset by lower capital spending in the Mid-Continent. We're expecting an increase in development drilling by $25 million to $35 million, an increase in land acquisition cost of $10 million to $11 million, and slight increases facilities and seismic spending. That sums up the guidance.

Thank you, very much. With that, I think we will turn it over to questions, operator.

(Operator Instructions)

We will take our first question with Welles Fitzpatrick with Johnson Rice.

Good morning.

Good morning.

Can you talk about, a little bit more, on the specifics of the Gardener 1H , was that plug and perf or sliding sleeves? What kind of profit did you guys use?

Well, it was a plug and perf -- We used intermediate strength profits throughout the job. We are probably going to try to adjust what kind of profit we use, because it's high-strength stuff and gets to be expensive, so we will try some different things as time goes on as part of our cost reduction program, again as wells drill.

As far as the EUR range, I know it's obviously pretty early, but internally, should we think about that something in the $500,000 to $1 million range that people around you have been talking, or maybe $350,000 to $500,000? Can you guide us in a little bit on that?

It is early. Internally, we are using, and I will give you a range because I hate to give you specific numbers. I will give you a range of somewhere between $280,000 and $380,000. It is a lot less than some other numbers I have seen out there floating around. But that is what we are using right now. That is the DOE equivalent.

Okay. As far as additional leasing and along, should we not be expecting a whole lot more? Is that also true of the Tonkawa into Cleveland?

No. In fact, I forgot to mention that. I had it written down here. I'm glad you asked this question. No, not at all. We are still -- yes, there is no good way to spin our results for Granite Wash exploratory program. Yes, it has disappointed us so far. But we are still on track to keep an active exploratory program to make up.

We still think there are a number of good things to do. We're still picking up acreage in these select prospects. We have six exploratory wells to drill this year and three to four prospects. But, no, we are as encouraged as ever and we're going to stay on the path and try to find new things. Doing the Mid-Con because I still think the Mid-Con is a great place to be. Some of those will be Granite Wash, some will be Tonkawa, Cleveland. Some will even be resource kind of plays, i.e. Shale, so we are going to make that a fairly active exploratory program in the Mid-Con in 2011.

Okay. And one last one, if I could, as far as the downtime associated with that Mid-Con-to-Eagle-Ford rig move, could you give us a timeframe there?

Are you talking about just the rig move itself? Move down the rig, or rig up? Is that what you are talking about?

Right.

A couple of weeks, 2 to 3 weeks. It is not very long.

Thank you so much, guys.

Thank you.

We will take our next question with Steve Berman with Pritchard Capital Partners.

Good morning, guys. A question on the horizontal Cotton Valley. Baird, how many well locations do you think you might have there? Asked another way, how much is the total acreage you think might be perspective for this?

It depends on the gas price. If you are talking about just Davis which is oilier, we actually have 10 locations keyed up and we could jump on fairly quickly. If you talk about overall Cotton Valley including the gassy zones, I can't remember the number of locations. What we did is we have converted most of our vertical locations to horizontal locations. We still have a few vertical locations left on some of the smaller drilling units in which we did not get horizontal laterals placed. Of course [EnCana] would kick in as gas prices take over. We are figuring out the average reserve on these wells, about 4.5 Bcf equivalent now, based on the average of the first seven we drilled, again. Selectively the Davis wells would be the ones to be in the queue sooner because of liquid content.

On a related question, you have done a nice job monetizing assets over the last couple of years. Is there anything else out there that could fit that description, or are we pretty much where we want to be as far as that goes?

Steve, this is Jim Dearlove. I guess anything is for sale at the right price, but right now I don't think there is an active plan to monetize any of our other assets.

How about possible JVs, especially up in the --

As you know, we have the data open to explore for a JV partner into Marcellus. There's nothing I can really report above that, other than the process seems to be going well. That is certainly, something we are actively doing.

We have a smaller package on Marcellus out here with natural gas clearing, as most of that acreage is in Somerset County, which we decided we were probably better off selling at this point in time versus trying to deal with it ourselves. Thanks for correcting- I should have said that.

That is it for me. Thank you.

Thank you Steve.

We will now move on to our next question from Neal Dingmann with SunTrust Robinson Humphrey.

This is actually Joanne. I am in for Neal. He had to step away. For the Eagle Ford, do you have certain completion techniques in mind already for that area in terms of auto-length and number of frac stages?

We will tweak it as time goes on, of course. We are going to try to maintain longer laterals where we can. Fortunately, with the two acquisitions we made, will support -- much will support up to 500,000 feet laterally. The longer, the better. We will probably sort of settle in the 250- to 300-foot frac stage length, between frac stages. We think that is important to maintain that higher level of frequency on the frac stages. The more, the better in this case. We will probably do some tweaking is the profit, amount of fluid pumped, those kind of things, to maximize value. That is something we will have to learn over time like we had done with the Haynesville Shale.

You have already mentioned how you're going to move some rigs down there, but have you already locked in your pad crews?

We have. We have a one-year contract that's in place right now with C&J. We can jump on the completions ASAP. The only thing that would interfere with the timing of completion -- in fact we are, we will be drilling some locations from the same pad, rather than getting wells completed consecutively, we may have to get two wells drilled. For instance, we drill one well in one direction, in the same pad drill at 180 degrees in the other direction, and then come in and frac them after the drilling rig is out of the way.

I see. And, lastly, with your ramp in liquid projections, will you be adding additional hedges, as well?

This is Steve. We are always looking at adding hedges. We layer them out two years in advance. We adjust the volumes that we have available to hedge every six months with our reserve report update. As we add more PUD locations and PDPs, then we would definitely be adding them to our hedge position.

Excellent. Thanks, that is it for me.

Moving on to our next question from David Amoss with Howard Weil.

Good morning, guys. Following on the questions about your Eagle Ford frac -- can you talk a little bit more detail about the cost? What percentage of the $9 million to $9.5 million that you spent on the completion?

It was material, David. It is not an exact number, but probably out of a total, we have about $5 million tied up in frac-related kind of stuff.

Okay. Thanks. In Gonzales County can you -- can you give us an idea of what the leasing situation looks like now? Are there other blocks near your acreage that are for sale at the same price level? And how much inventory are you guys looking to add right now at the right price?

To answer your question, without giving away the farm, yes, there are other things to do in and around this. It is important that we sort of stay in that immediate area. We think that's a great place to be, as indicated from our first well results. We will be as aggressive as it makes sense for us to be. In trying to pick up additional acres, we're not going to go out and pay $10,000 an acre, but if we can pick something up that in the sort of fairway that we have picked up these first two, or even slightly more, we would go after it.

Okay. Great. That's all the questions I have. Thank you.

Thank you.

(Operator Instructions)

Our next question will come from Amir Arif with Stifel.

Thanks. Good morning, guys. Just a few questions. You mentioned you got the rig, or the frac crews committed, how many of the 29 involved do you expect to actually complete in time this year?

I can't give you an exact answer and (inaudible) for those completed. It probably will not be all 29, because it never is, but I would estimate we'd get probably at least 25 completed.

Okay. Then, the Marcellus, I notice you guys are drilling off the same pad. I take it you are not too worried about any kind of HPP issues or acreage expiration?

We have the conditions of terms under our lease. Over time we have to -- the issue's to get a lay on the land to figure out what we have as far as potential goes, and then jump on a more active program next year or the year after. But we have got more than enough time under any term under these leases that we are not facing any big problems. Probably two years from now, 2.5 years from now things will start to accelerate and unwind -- the intent is we will try to get the majority of this HPP but -- inevitably we will have some renewals, we always do -- we should in fact pick up the stuff that we really want.

I think you guys have 56,000 acres? Most of it is, I take it, is five-year leases out there?

It is. We have one state acreage track we picked up that was 3800 acres or so, it is a ten-year lease.

Okay. Finally, shifting over to the Mid-Continent and the Granite Wash, can you just tell us, as you told the Granite Wash acreage, how many acres are in the Cloud Chief and the Powell prospect area?

It is not that material. Net acreage I think it was around 8,000 net acres we had in those two areas.

How much acreage do you have, total?

Total in Granite Wash is, pretty close to 30.

30,000 acres? Okay. I know you are obviously not going to give up in the area. You mentioned that you are looking at some other stuff. Essentially, even though there are different zones, it sounds like the water's going to be an issue no matter what. So even if you weren't shipped in the Eagle Ford, it sounds like, even then you would not be drilling at least in these two areas?

That is a fair statement. Cloud Chief and Powell, even though we know there is gas there, it is trying to solve the problem, which is not an easy problem, or trying to figure out how to stay out of it. One way you might be able to do it, and we will test that idea in our Simpson well which is the third well that I mentioned, and our first well drilled by us. We only completed two stages in the tow, because the Granite Wash is much more permeable as you go to the south. You might be able to go ahead and just perforate and do a very small breakdown job as we refer to it in the business, and not get any kind of significant extension height-wise on your frac, and try to stay out of that water. And there may be enough perm that it can still make sense. But we have yet to test that, but that is the first technique we're going to try to use in trying to fight this problem -- we slow it down regardless, yes.

Okay. That is all for me. Thank you, guys.

Moving on, we will take Shawn Grant with Standard General.

Hello, good morning. You guys have done a great job moving towards more oily production and, obviously, you said in response to a mere 25 potential Eagle Ford's actually being completed and tied in this year. What would you see the Company looking like if everything goes well next year, a couple years out in terms of percent of oil, do you get the 50% plus?

That is a very difficult question to answer. If you asked that question a year ago we would not have even had the Eagle Ford. Clearly, the strategy is we have articulated is to try to become more involved with liquid-rich places, but I don't want to -- maybe Baird does, and, again, if he wants to -- I don't think it would be wise to try to put percentages on things that --things you write them down, and we're held to things we just can't estimate right now. Clearly, what we are trying to do, not to be evasive, is move towards more liquids-oriented plays. The only sure gas play we are drilling right now is Marcellus because we have to learn about it. As I tried to say, and Baird did as well, we will maintain our optionality if you will, to gas whether it's in the Haynesville or the Cotton Valley, which has some oil in it. If those prices improve, go back towards it, but would it be 50% oil or 60% oil or 45% oil is very difficult to say as we are actively leasing and exploring.

Okay. Great. Thanks.

Moving on, we will take our next questions from MIke Jacobs with Pioneer Press. Mr. Jacobs, your line is open.

Alright. Thanks. I just had a couple on the Eagle Ford. Have there been any down-space pilots or results that you've seen so far evolve in the oil window?

We have not. We think, ultimately, you could probably drill this stuff on 600 feet between laterals. It is pretty ratty stuff. We will research trying to drill 600-foot stuff -- between laterals and maybe do the zipper fracs. We have the industry talking about some of these shale plays to get a more effective stimulation across the shale, if you treat both wells at the same time. There has not been enough drilling down in this area to confirm that. But it's a thickened-up reservoir, it being oily, you tend to have -- need to have closure space, and kind of wells to have better recoveries because it is liquid versus gas. Intuitively, I think the closer spacing, ultimately, will be proven the right way to go.

Okay. Just thinking in some of the other title plays, what we have seen is -- in the bedrock, you typically do different number of locations than you do in the tighter rock. It seems like you have some really good rock over there. When do you think you will test some of those zipper fracs, just thinking about -- seeing results from Down-space 12?

I'd say probably not, realistically probably until next year. The goal is right now to try to get our acreage HPP. We have leases that have some terms on them. It is not that we have a gun to our head, I'm trying to get things done sooner than later. But at the end of the day, we need to get this acreage HPP. So, I'd say we will probably not go back in and try to get some of these zipper fracs until we get the acreage issue burned, after which we will have the chance to go back in and drill a lot of down-space wells.

That is great. Thank you.

You're welcome.

At this time we have no further questions. I would like to turn the call back to our speakers for any additional or closing remarks.

Thank you, Operator, and thank you to those of you who are on the call. I guess we will do this again, or some of us will, next quarter. Thank you very much.

And ladies and gentlemen, that does conclude today's conference call. Thank you for attending.