Ranger Oil Corp (ROCC) 2010 Q3 法說會逐字稿

Good day, and welcome to the Penn Virginia Corporation third quarter 2010 earnings conference call. Today's conference is being recorded. At this time, I would like to turn the call over to your host, Mr. Jim Dearlove, President and Chief Executive Officer. Please go ahead.

Thank you. Good morning to those of you are on the call. As the Operator just said, the purpose today is to discuss the third quarter results. We'll talk about operations, as well as the other release that came out. Speaking today, in addition to myself, will be Baird Whitehead, who is our Chief Operating Officer and runs the only Gas Company; Steve Hartman, who is our Treasurer; and Jim Dean may be called on to speak at some point. He's our Corporate Development and Investor Relations person.

So, we'll just get going here. I'll just read you a little bit out of the release and then try to make some comments, and then turn it over to these other folks. As you can see, just in the headline, we had a 27% sequential quarterly production increase, 19% year-over-year, and pro forma to take out the effects of the Gulf Coast assets that we sold in January this year.

Also, we'll give you a little bit of guidance for 2011 as we go along. Let me just read the highlights, and normally I don't read the release, but in this case I'll pretty much paraphrase it or read the highlights part of it. Quarterly, oil and gas production of 13.3 Bcf equivalent, or 144 million cubic feet a day, was a roughly 19% increase over the third quarter of 2009, as I just said, and a 27% sequential increase, that is comparing it to the second quarter 2010.

Operating loss we suffered for the quarter was $53 million, which is better than it was a quarter ago, and both of those things were heavily influenced by impairments that we took. We had a net loss from continuing operations of $30 million or $0.66 a share, compared to a much larger loss last year, again influenced by some of these events. Adjusted net loss attributable to PVA, a non-GAAP measure that takes a lot of these impairments and other non-cash events, we were, missed my point here, $0.31-- I can't find --

$0.31.

$0.31. Sorry Jim, I've written notes on my piece of paper here and I can't read it -- compared to $0.24 last year.

Before I turn this thing over to Baird to talk about it, let me just talk about the comment that I made in the release. As I said, production in the third quarter is up over 2009, in the third quarter of 2009, as well as the second quarter 2010. And you may recall , the due to suspended pricing we suspended drilling for part of 2009, which affected our results in 2009 and certainly into early 2010.

Drilling resumed late in the fourth quarter 2009, and has continued throughout 2010. Also, a number of Haynesville Wells that were waiting on completion early this year were completed in the third quarter. Now these factors combined to drive the production increase we're reporting right now.

Due to the current state of the natural gas market, we are at least temporarily shifting our focus away from dry gas, and instead increasing our exposure to oil and liquids-rich plays. Fortunately, we have a pretty solid inventory of prospects in the Granite Wash, and we've recently taken a position in Eagle Ford Shale. We expect to begin drilling the Eagle Ford this quarter, and we'll move a rig from East Texas.

The Haynesville and the Horizontal Cotton Valley pro's in East Texas, both of which have really yielded some excellent results, particularly as we have increased the number of frac stages and the amount of seed we're putting away, but both of those efforts will be suspended until the prospects for natural gas prices improve. We are currently moving a rig from Mississippi where was drilling in the Selma Chalk to the Marcellus Shale. Although the Marcellus, which is our Marcellus that we're concerned with here, is in Tioga and Potter Counties, is also dry gas, we believe that it's prudent to begin to delineate that acreage. Virtually all of our acreage in East Texas and Mississippi, where we've suspended drilling, is HBP.

Of course these moves will affect production from East Texas and Mississippi until drilling resumes, and we expect the declines that we'll suffer there will be offset in 2011 by production growth from the Mid-Continent, the Eagle Ford, and the Marcellus. In fact, as we say in our release, our preliminary look at 2011 and guidance indicates a growth in production of roughly 10% over midpoint 2010. Now we believe this growth can be achieved next year with a CapEx budget that is 35% to 45% lower than the CapEx guidance midpoint for 2010, and as we also point out in the release we believe we will exit 2011 in a very solid financial position.

Just looking again at the part of the release called "Third Quarter Financial and Operational Results", I won't repeat the production. There's a paragraph in there that describes for you the prices that we realized, prices that we had for gas, natural gas liquids, and for oil. What you see is it's pretty much unchanged from the second quarter of this year, and somewhat higher than it was in this third quarter of 2009.

Some of the specifics of the line items on an income statement, you'll see that our LOE, or lease operating expenses, decreased by about 14% or $1.5 million dollars, and this was lower charges for equipment and compressor rentals, water disposal, et cetera, somewhat offset by higher repair and maintenance costs. Gathering and transportation expenses were up $1.2 million, or 50%, and this is mostly production increase, as well as the geography of where were actually drilling and producing. Production and lower taxes -- (audio lost) -- D&A expenses decreased, this was do to the lower depletion rates as well as some of the impairments activity that we had, I said last week, but I should also say, speaking of that impairment there is some discussion in the release about those impairments. The next thing that I want to do is to turn over to Baird the discussion of our operations.

Good morning, and thanks Jim. As I always do, I'm going to go over each one of our play sites and give you some more detail as far as what we're doing. Starting out with the Granite Wash, as reported in the press release, we drilled or participated in 11 gross, about five net Granite Wash wells in the third quarter, eight of which were development wells; the other three were exploratory. Also during this quarter, we completed 11 gross by 5.6 net wells, with IP rates of anywhere between 2.2 million and 15.4 million a day equivalent. This does exclude any process liquids, which adds 20% to 25% equivalent production volumes.

Just to bring you up to speed as far as trying to explain some of these lower rates, especially the 2.2., we did drill a few wells at the edge of what we call the fan portion of our geological model. We knew the Granite Wash was going to be thinner, but what has also affected some of these wells, at least recently, is we have communicated with the existing older wells during the frac jobs themselves. So it has affected the initial rate, not only the new well that you have stimulated, but it has also affected the production on the existing well.

And to explain this a little bit further, we have eight wells, both operated and non-operated, that exhibited this communication problem during the frac jobs. As I explained, this lowered the IP rates on both wells. In fact, on the older well in some cases, it completely loaded that well up with frac fluid, and the well went off production. So we had to -- we went out there and installed some artificial equipment, both gas lift valves and compression, and over time we are getting those wells cleaned backup and the rates are increasing. So this has worked.

The other thing we have done is we have changed the defrack design on our new wells. Whereas we usually pump about 400,000 pounds of sand and 450,000 gallons of water per stage along the lateral, our recent wells are about 150,000 pounds of sand and about 140,000 gallons of water. We've also gone from a slick water gel to a cross-linked gel, so at the end of the day, what this is doing is creating a shorter, wider frac that is propped from top to bottom to minimize the chances of communicating with the existing well.

What we're also doing is shutting in the older well for up to a week, while that well is being prepared to be fracked, so while were shutting in older wells we also have a loss of production during that time period. In fact, during the third quarter, it is estimated we had about 300 million shut-ins because of these because of this new frac design and what we're doing to remedy the situation. So, we have put these different kind, this newer frac design on our five most recent wells; we've not seen any evidence of communication between wells with this new design, and the IP results of these new wells are what we would expect taking into consideration geology. So, we had a problem, we dealt with the problem, and we think we have fixed the problem moving ahead.

We currently have two rigs in South Clinton, and our partner is running one rig. The non-op drilling has scaled down somewhat during the second half of the third quarter, but we expect that development activity will ramp back up as the year goes on toward the end of the year.

Also during the third quarter and at the beginning of the fourth quarter, we drilled four exploratory wells; two of those were in our collective Cloud Chief and Powell prospects, one was in East Sayer, and the fourth was in Mountain View. At least based on the open-hole logs, running the pilot holes, and in some cases the open hole logs running the laterals themselves, we feel very good about Powell and Cloud Chief and East Sayer, and the logs look very promising, and we expect those wells to be productive. Two out of those three wells are waiting on completion, and we just started completion on one of the wells in Powell and Cloud Chief.

The fourth well, which we have already disclosed in a conference presentation, was Mountain View, and it was unsuccessful. We did frac it, we had a little gas after frac, but not near enough to be (inaudible - microphone inaccessible). We feel happened after the fact is, even though there were indications of crossing on the pilot hole, it appears, based on [phetchaphysical] analysis there was some clay and quartz overgrowth within the core spaces that reduced the effect of porosity.

We do think, based on the geological model that we have, that we need to drill an additional well to test the fan portion of that model. The original well was drilled in a channel, where we expected thicker granite wash, and it was thicker, but it was tighter. So we could argue based on the geological model that we should have improved porosity within that fan, but we don't plan on drilling another well on that prospect until sometime next year.

Yes, Mountain View was a disappointment, but if you take into consideration the success of Cloud Chief and Powell and East Sayer, and the 9,300 net acres associated with those three prospects, we've added anywhere from 100 to 240 gross locations. The upper end will take some additional drilling as this year goes on into next year, and we'll add anywhere from 25 to 65 net locations. So again today, what we think these three successful prospects have added has essentially replicated South Clinton. It's added another South Clinton at the end of the day.

We do have a development well being drilled in Powell as we speak, with a Penn Virginia operated rig, and we're going to keep that rig busy going into next year; starting to drill development wells and expand, improve up the geological model, both Cloud Chief and Powell. The other thing I want to mention, and I'll get off the Granite Wash, is it appears in Cloud Chief and Powell and East Sayer, there are multiple pays. In fact in Cloud Chief, there appear to be two pay intervals, and in Powell, there are three, and in East Sayer there are also three. So the additional locations I gave you were only based on the single zone we were drilling laterally in. We have yet to digest how many additional laterals we may have with the other zones, but this offset has not been included in any of the locations that I just mentioned.

And lastly, we are actively leasing in new prospect areas. We haven't disclosed where they are. We have three new oily prospects; we have about 8,000 net acres in one of those, is a carbonate. We just started leasing in another area which has both Tonkawa and Cleveland potential, and we have about 1,300 net acres to date those two prospects.

So we are moving along in coming up with our new prospects and getting them drilled . These last three I just mentioned will probably be drilled some time in the latter half of 2011.

In the Eagle Ford, Jim talked about that, we do have 7,000 net acres that we disclosed in August up to 40 locations. We feel, we have been already been adding acreage organically around what we picked up in August. In fact, we have an additional 400 acres to date; there about another 1,300 acres that we feel that we can add in around there. So at the end of the day, we should be up north of 8,000 net acres in that Cortez acquisition in Gonzales County. The plan is to get an H&P rig down there once we finish up in East Texas on our last Cotton Valley well, which is spudded toward the end of this month, and we should probably get it fracked probably early in 2011.

The other positive to mention, I realize service costs are going up and trying to get service sector pumping equipment can be problematic in some areas, including Eagle Ford. What we were able to do is add the Eagle Ford frac for services agreement that we announced earlier, so it allows us to quickly get our wells completed,or just having to wait around for months to understand what we have drilled.

In the Marcellus, we have about 55,000 net acres to date in this play. There's about 35,000 net acres in the Potter/Tioga County, which is the initial area in which we're going to drill our first well. To remind everyone, we did drill a vertical well earlier this year, collected a bunch of detailed reservoir and geological information. All of that data was positive.

Taking into account that data, along with offsetting peer activity in Potter and Tioga County, we think were in the right hunting ground. The plan is to get the rig up from Mississippi; it's on its way as we speak. We should spud our first well toward the end of this month because of the long mobilization move, but the plan is to start drilling at the end of this month and keep that rig busy drilling horizontal wells into 2011.

The Haynesville Shale, to bring you up-to-date, we did complete four grows 3.8 net wells. We had IP rates of anywhere from 7.6 million to 10.2 million a day, 30-day rates of 5.3 to 8.7. It's clear that with the increased frac stages and higher volumes of sand, first stage pump, that the performance of these most recent wells have improved significantly, and yet, we're still holding quite a bit of back pressure on these wells. We've made a conscious decision not to publish a bunch of high IP rates, mores trying to be prudent in the production of these wells.

And as a comparison, if you take into account all of the wells Penn Virginia has drilled, the well that has the highest cube to date is the first well we drilled, which was 2.4 years ago, that made 1.1 Bcf. If you take into account the five most recent wells we have drilled, late last year to this year, one of those already made 1.1 Bcf in only four and a half months, and there's another few of these wells that are on pace to be of equal quality in the same period of time. So we've made a lot of progress in driving up the results of these Haynesville Wells, but we do think temporarily, the right thing to do considering low gas prices, is to suspend drilling and come back to this play once gas prices cooperate.

The Cotton Valley, we are finishing up on the last well there; we completed three wells in the third quarter. We completed one more early in the fourth quarter . We had IP rates that were anywhere from 2.5 million to 4.1 million a day. We just turned a fourth well in line . With these Cotton Valley wells, once you get about 30% of your frac fluid back is when these rates start to increase, and increase almost hourly after you turn these things in line.

So anyway, what we are impressed about with Cotton Valley is the initial decline rates of these wells appear to be much less than we would typically see with the vertical well, and probably because of the amount of frac fluid you put away, and they clean up over a long period time. We think with the $5 million to $5.5 million dollar drilling completion costs, which we think we can get our costs down to, these wells will be economical with not too much of an increase in gas prices. And with the Haynesville, we will suspend drilling there after this last well; that rig going to the Eagle Ford.

And lastly, I just want to mention the Selma Chalk, even though we've probably been in this play the longest on drilling horizontally out of all horizontal plays, we continue to tweak the completion side; the results continue to improve. We recently have increased our frac stage sizes from roughly 75,000 pounds of sand to 200,000 pounds of sand per stage, up to eight or nine stages. At least based on the initial results, those IP rates gone up on these higher stages, but as typically, we need to digest the producing result of these wells to see if it makes economical sense. So I think I've gone through every play fairly thoroughly.

I think you were fairly thorough, yes. Thank you, Baird. And I'll be a little bit repetitious before I turn this over to Steve Hartman. He'll take you through things like that capital resources, liquidity, interest derivatives, and also look at the guidance table.

But I just want to make a re-make point that I think I made earlier, and Baird just made too. As we shift our focus from these oily -- excuse me, to these oily and more liquid-rich plays and away from dry gas in East Texas and Mississippi, there's going to be period of transition. When you go from two rigs in East Texas to none. Then move from Mississippi to Marcellus, as I said, would require six to eight weeks. The Eagle Ford program will start in 2010, but we won't see any results from it until early 2011.

These moves were not anticipated when our guidance was originally put together. In fact, some of them were not anticipated even as we updated, as we go through the year. We're trying to be responsive to changing conditions. We believe the decision to make these shifts is prudent, and we think it creates greater long-term value for our shareholders.

The inevitable effect of these shifts is for production from the affected areas to decline, and for us, this will primarily be a fourth quarter issue. And as you can see from our guidance for the fourth quarter of this year, it's little bit lower than the original guidance for the reasons I just mentioned. And of course, it also affects our CapEx, which is lower than we forecast. All of that said, we still look forward to increasing production in 2011 by roughly 10% over our midpoint. So Steve if you wouldn't mind taking us through some of the rest of this stuff.

Okay thanks, Jim, and good morning everyone. Returning back to the earnings release and starting with capital resources and liquidity, our cash and cash equivalents at end of the quarter was $205 million, this cash coming of course from the earlier sale of our non-core assets. Also at the end of the quarter, we had outstanding debt of $530 million, consisting of our $300 million senior notes due in 2016, and our $230 million subordinated convertible notes due in December 2012.

We had no outstanding balance on the $300 million credit facility, which has a $420 million borrowing base. We do have an accordion feature on the credit facility that would give us access to the full $420 million, subject to bank approval, and I don't anticipate that we would have any issues accessing that capital if we needed it. As of right now, that $300 million commitment level that we maintain is adequate for our needs.

Moving on to hedging, our cash settlements from the quarter were $6.8 million, including our interest rate swaps. From commodity hedges alone, we received $7.4 million during the quarter, which gave us a $0.69 per Mcf uplift in our natural gas realized price. Our hedge position is detailed on page 10 of the release.

You can see that through this winter we have 50,000 MMBtu per day hedged, at a weighted average floor price of $5.60, so well above the current strip. This equates to being approximately 45% hedged , as a percentage of the midpoint of our implied fourth quarter natural gas production guidance. Our hedge volumes trailed downward through the years as you would expect, with next summer being hedged at 30,000 MMBtu per day, and next winter being hedged at 20,000 MMBtu per day.

Moving on to walk you through the guidance on page nine of the release, we tightened our full-year 2010 production guidance to 46.5 Bcfs and 47.5 Bcfs on an equivalent basis. This is down slightly, as Jim explained, from our previous guidance, primarily due to the decision to move the operated rigs to Eagle Ford and Marcellus, plus having non-operated rigs temporarily move off our joint acreage in Granite Wash, as Baird explained.

For natural gas standalone, we expect our production to come in close to the top end of the previous guidance range from July, with current guidance at 38.3 Bcf to 39 Bcf. We're keeping our natural gas guidance higher because of the outperformance of the East Texas wells, as Baird explained, and also because of some assumed ethane rejection in the fourth quarter. For NGLs and crude oil, we've lowered our guidance, as you can see, primarily due to the timing related to moving out of the Cotton Valley and lower non-op activity in the Mid-Continent, and also because of the ethane rejection assumption that I just mentioned.

Moving on to expenses, our LOE came in at a very attractive $0.70 per Mcf for the third quarter, primarily due to higher volumes, and we expect the full-year number to come in below our year-to-date average in a range of $0.75 to $0.80 per Mcf. There's no change in guidance for gathering, processing, transportation expenses, or production ad valorem taxes for the year .

For our general and administrative guidance, we're providing a little bit more detail than we have in the past, because of the one-time expense related to the PVG PVR sales, and also because of relocation expenses when we relocated from our Kingsport, Tennessee office to our Pittsburgh and Houston offices. To make a little clearer for you, we've split our G&A expense into what we believe is an ongoing G&A category, non-cash equity-based compensation and restructuring charges. We expect our ongoing G&A expense will be around $10 million to $12 million per quarter.

Exploration expense guidance is up primarily in anticipation of some seismic shoots planned for Eagle Ford and Marcellus, and also because of un-proved property amortization related to our lease acquisition program. And finally for expenses, we lowered our guidance for DD&A , primarily because of the mid-year reserve additions and impairments, as Jim mentioned earlier.

Moving on our capital expenditures guidance, we've lowered the midpoint of our total CapEx program for the year to a range of $465 million to $485 million. This comparison is pro forma to the $31 million land acquisition we made earlier in the Eagle Ford, just in case you're looking at the July guidance, you'll know to make that adjustment.

Development drilling is lower, due to the movement of rigs out of the development areas in Mississippi and East Texas, as we have already discussed. And conversely, the exploration drilling expanding is expected to be higher, due to the start-up drilling in the Eagle Ford and Marcellus. Pipeline, gathering, facilities CapEx and seismic expenditures are both expected to increase in the fourth quarter at a higher rate than you've seen so far this year. And this is due to activity related to the program start-ups in our new areas.

And finally, lease acquisition, we've been very active in this category this year, as you've already heard, and we've re-deployed capital from our non-core asset sales . We increased our full-year guidance in this area to $143 million to $150 million.

Finally, one more note on guidance, I'll add just a little bit more color to the 2011 guidance that Jim discussed earlier. We don't have much to provide detail-wise beyond what has already been discussed by Jim and Baird, but we do expect the program for 2011 to be in the $250 million to $300 million range, which is significantly below, 35% to 45% below, the midpoint of our 2010 guidance. But even with the lower CapEx, we do expect production growth in 2011, with the ramped-up program in Eagle Ford and Marcellus and continued drilling in Granite Wash, we expect to produce between 50 Bcfe and 54 Bcfe in 2011, so a healthy 6% to 15% production growth year-over-year. And I think Baird give you quite a bit of color on why we would expect that to be the case. And we expect our current liquidity is sufficient to execute the program. And that's sums up guidance Jim.

Thank you. Very thorough as well. And with that, Operator, I'd happily turn it over to questions.

Thank you. (Operator Instructions) Our first question will come from Stephen Berman from Pritchard Capital Partners.

Good morning, guys. A couple of play-specific questions first. If I recall you had talked about possibly wanting to shoot seismic before drilling in the Eagle Ford. What your thoughts on seismic now as we go forward?

Steve, we were able to buy some off the shelf 2-D that gives us a high degree of comfort on the first couple of wells. After which, we still think we're going to have to shoot some 3-D or some closely spaced 2-D. We'll probably do that some time next year, but we can get the initial wells drilled without any seismic.

Right, and then the horizontal Cotton Valley, what kind of liquids per million cubic feet of gas are you thinking there, just to get a sense for how wet that gas might be?

On a well head side we're seeing anywhere from 15 to 25 barrels per million. You make about another 15% to 20% of NGLs on top of that.

Okay. And then just a more of a big picture question, in terms of the 2011 guidance, given that a lot of this 50 billion to 54 billion, some significant part of it I assume is coming from new areas. I'm just wondering your confidence level in that number, how much you've risked it, etc. I just want to get more of a feeling for - - I mean, seeing that nice big CapEx cut and still being able to grow production is very impressive, but I just kind of want to get a feeling for how your confidence level is in those numbers, the production side?

It's a hard question to answer. What we typically do is we raise our exploratory volumes, and let me categorize our exploratory volumes, probably in two buckets. One buck of which would be, step-out wells to say like Powell and Cloud Chief and East Sayer, which would have a lesser risk, because it's not a new [wild cat] per say, but it's a two or three well [step] in some cases to which you've already drilled. So there is some inherent risk on drilling these kind of wells, but less risk.

The other bucket is the initial well in a new prospect, like Mountain View, or some of these other prospects I mentioned. As I said, even with Mountain View, way back when, we have a lot of vertical well control that gives you a high degree of comfort that you're going to find [to zone]. The problem you run into is, it's not if you're going to make hydrocarbons, it's a the matter of how much.

Mountain View, at the end of the day, was a miss because we misinterpreted the porosity that we had seen on those vertical wells on the older logs. But these other plays, the carbonates and the sandstones like the Tonkawa and Cleveland, we don't feel there's going to be a lot of risk, but we have risked them because they are exploratory, and we've tended to push them out, just because of timing of unknown when you're going to get them drilled exactly and when you're going to get it turned in line. So don't place a lot of volumes, I guess what I'm trying to say, on the exploratory category for those reasons I just mentioned.

Steve, I might say that if you look back at the history of the Company, we've certainly made mistakes and missed guidance and done other things in the past, because it's a tough business as we all know. But I think we tend to be pretty conservative, and we're certainly aware that if we put out a guidance number, with all the caveats that it's preliminary and that things change, and the world continues to turn, we know that it gets stuck in a model somewhere and people measure us against it. So we wouldn't put out a number of we weren't pretty confident that we could get it.

Alright, great. Thanks, Jim. Thanks, Baird.

You're welcome.

The next question comes from Welles Fitzpatrick from Johnson Rice. Go ahead please.

Good morning.

Hi Welles.

I was wondering, you kind of updated, saying that they'd probably be in line, but can you talk about the net effect on completed well costs, (inaudible), location/spacing, kind of all of the good stuff for the new technique that you all have in the wash?

We're still doing as well as on 160-acre spacing. We see no reason to make it a larger spacing because of this communication issue. Because the gas in plays, volumetrically, we feel like we still need four wells a section to drain it. The problem is on these unconventional kind of reservoirs; you tend to create a single planing frac, whereas on these resource plays, because of the stress issues it sort of shatters the shale, and you tend to have less likelihood of communications because of the multidirectional effect of the frac induced [cell].

So we still think 160-acre spacing is the right way. We're just creating a shorter, wider, and [cropping] the entire interval within the Granite Wash, versus a longer frac that is typically created with a slick water gel and by pumping additional sand in water. So that is the engineering logic of how we did what we did.

Okay. And on the cost side is it about similar?

No, that's actually less. Because [the size of the jobs have come down] considerably, I think if I'm not mistaken, it's is $200,000 to $300,000 less per well on the completion side because of this frac design change.

Okay. And I know it's preliminary but you're thinking that these are going to be around the same EURs as the older technique?

Yes we do. I mean admittedly, the EURs will tend to come down over time because you're drilling up the field and there are going to be some geological issues; i.e., thickness of the reservoir, that's going to cause an adjustment down. But you know that going into it before you drill them.

But, the [fifth Bcf well] we typically use, that was pretty close to 100% after tax rate of return. If you drill a four Bcf equivalent and it's 40% after-tax rate of return, it certainly, you're still going to go ahead and drill it. Your IP rates are going to be less, you're [alternates] are going to be less, but it's still a very attractive investment. It still one of the better if not the best opportunities we have the plate now, competing with [what hopefully] is the Eagle Ford. But going forward they're going to come down, but it's not frac driven, it's more so geologically driven.

Okay. And in the Eagle Ford, how should we expect acreage additions? I mean, are those going to be opportunistically getting acreage surrounding your current area, or should we expect you guys to dip a little bit more into the war chest and so something bigger?

I would say both. That's not to guarantee anything. But clearly in the Gonzales County acquisition, we're trying to add a little to it as Baird said, and the Eagle Ford right now is sort of the flavor of the month, and so prices are going up, and we don't want to be a lemming and follow the herd. On the other hand, there's an awful lot of activity and were monitoring it, and looking at things, and we may or may not make a bid on something, but we wouldn't shy away from it made sense.

Okay. And lastly, if I can get one more it, you mentioned that you're assuming ethane rejection, at least on a portion of your production going forward. Can you elaborate on that, on where you think that's going to occur?

Well that was more of the planning, this is Steve. It was more of a planning assumption just to be on the conservative side. So we weren't making a statement to say that we've looked at the forward curve, and we think that we are going to be in ethane rejection through the fourth quarter. It's just our way to add a little bit more conservatism into our numbers.

Okay, so you haven't been seeing that yet?

This is Baird, Welles, we are rejecting ethane in East Texas, but we are processing ethane in the Mid-Con and the Granite Wash, so as Steve said, we will apply some additional risks to ethane recovery at the end of this year going into next year. The unknown is associated with the ethane market. You've read some of the publications just like I have, and because of the flood of ethane in the market, there could be a good chance you may want to keep BTUs in the gas stream versus taking it out as far as ethane.

Okay, perfect. Thanks so much guys.

(Operator Instructions) Our next question comes from Brian Corales with Howard Weil. Good morning guys.

Couple of questions. (Audio lost)

Okay, no, that's fine. And then, with a shift in focus moving out of East Texas, how you see that production makeup changing, kind of as a percent around gas, say from this current quarter to year-end 2011? I mean, probably see some gas decline as a result of moving the rig out of East Texas?

Brian, it's Baird. I cannot remember exactly the numbers, but I thought that we could expect to be somewhere around 20% liquids, 25% liquids by the end of next year, with the transition.

Okay, and - - ?

Your out building models and we're trying to give you some guidance, but it's very preliminary.

I totally understand; I know it's early and we've seen a massive decline on the gas price. One other question, just kind of the thought process on the Marcellus, to kind of test the acreage here. Is this a leasehold that you have to start drilling on? Is this really just to get an evaluation of what you have and how it looks going forward? What's the thought on taking a rig from East Texas or Mississippi up to Marcellus?

Well, it's sort of both. The clock is ticking on the terms of this acreage of course, and we also need to start drilling to understand what we have so we can start beating our chest that we've got Marcellus, good Marcellus results. But at the end of the day these are really , in our opinion, [almost development rows] because of the nearby activity.

It's just a matter of the transition of getting out there, getting a drill, getting lines laid, the lead time required that you have to go through to get a new project kicked off. So, we're looking at less as an exploratory effort, but more so, I guess you'd call it, the [bellacat] kind of thing, whereas it is of the lower risk category, that you just have to execute an operation to get things done and get the pipelines laid.

Okay. My final question was just more on the takeaway in both the Eagle Ford and the Marcellus, is this something that, once it's drilled and completed can be put online in a relatively quick manner, or is there a little bit more infrastructure maybe needing to be put in place?

We feel like there are good transmission takeaways in both areas, in Marcellus, specifically, because there's a lot of larger lines, national [field dominions] specifically, Leidy Storage Field is not that far away, so we're pretty close to a hub in the Marcellus, it's a matter of just getting a gathering system later, which will take some time of course.

In the Eagle Ford, we already have some preliminary discussions with some folks, and there will be some start-up kind of delays on getting lines laid. We may decide, depending on how much gas versus oil we're making to go ahead and [flur] the gas temporarily, to get the oil tested, and truck it out of there, but we think we will also have good opportunities to get rid of liquids and gas once we get into development mode in Eagle Ford.

Alright guys, thank you.

Thank you.

Our next question comes from w Our next question comes from Wei Romualdo from Stone Harbor. Go ahead please.

I just want to know what's the plan for the CFO side, do you look for a replacement there? And also, the convert that is due 2012, when do you intend to tackle that?

Well, the CFO question, we are in the middle of searching, and will have a new CFO in place as soon as it makes sense, meaning as soon as we find somebody suitable. I didn't quite understand your question about 2012.

Oh, the convertible that's due, 2012.

Oh, I'm sorry. Steve?

Oh, I'm sorry I missed that also. The convertible note due 2012, we are starting to evaluate, refinancing debt, so it's in process and I would expect us to do something about it in 2011.

Okay, last time, I have in my notes, is it still true that you can't issue - - you cannot buyback those converts with asset sales? Can you refinance them with senior notes?

Well, they are non-call notes. So if we were going to buy back any of the notes, it would have to be through some kind of a tender offer or negotiated sale or buy back with the note holders, as is customary with all of those notes, that's not unique to those notes.

Buying them back with a senior issue, that just gets into a little bit of a trickier situation, because you have to deal with restricted payments and such, and it's a more difficult question to answer. But, so, I hope that helped a little bit. We can use asset sale proceeds, that's unrestricted cash, so we do have different options available to us for refinancing.

Okay. Thank you.

Thank you.

At this time I'm showing there are no additional questions in the queue.

Well, with that then, again all of you on the on the call, we appreciate it. Baird, Steve, thank you for your help, and we'll talk to you next quarter.

That concludes today's conference call. Thank you for participation.