Battalion Oil Corp (BATL) 2007 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Third Quarter 2007 RAM Energy Earnings Conference Call. My name is Latasha and I will be your coordinator for today. At this time, all participants are in a listen-only mode. We will be facilitating a question-and-answer sessions towards the end of this conference.

(OPERATOR INSTRUCTIONS)

I would now like to turn the call over to Mr. Bob Phaneuf, Vice President, Corporate Development. Please proceed, sir.

Thank you very much, Latasha, and thanks to all of you for joining us on the RAM Energy conference call to discuss third quarter 2007 operating and financial results. With us today from RAM are Larry Lee, our CEO; John Longmire, our Senior Vice President and CFO; Larry Rampey, our Senior VP of Operations; Drake Smiley, Senior VP of Land and Exploration; and John Cox, Senior VP, Treasurer, and Secretary.

Our agenda today for the call is to have a review of operating and financial results. I think Larry will them give us a brief update on the status of the progress towards closing the Ascent transaction, and that will be followed by a Q&A period.

Before we begin, I'd like to just remind everyone that in our call today, we may make statements that are other than historical facts, particularly as we talk about the timing and the things to come on the Ascent transaction. Information in the presentation and all such statements that refer to management plans or expectations, including capital spending, derivative positions, and industry conditions, are forward-looking statements within the meaning of the Securities and Exchange Act of 1934.

The Company cautions that such forward-looking statements are necessarily based on certain assumptions, which are subject to risks and uncertainties, which could cause actual results to differ materially from those indicated today. Further information on these risk factors is included in the Company's filings with the SEC. The management at RAM encourages you to review these disclosures. So, having just finished with all the preambles, I'll turn it over to Larry Lee for a review of operations and financials in the third quarter.

Thank you, Bob, and thank you, everyone, for joining us today. We'll start with kind of the highlights for the quarter. We did report net income of $4.8 million, or $0.12 a share. Our cash flow from operations was $6 million in the third quarter and $16 million for the nine months ended September 30th. Our third quarter production was 336,000 barrels equivalent and this is slightly down from our 337,000 barrels in the second quarter, and I'll go into a little bit more detail about the production there. We're a little disappointed with the production results in the third quarter, but I think we've got those back on track. We'll talk about it a little bit more.

We did spend $5.6 million of non-acquisition capital in the third quarter. That raises non-acquisition capital to $15.4 million. And with our acquisition in the second quarter, we've now invested $34.1 million through the nine months.

Some good news for us in our Barnett play, we have completed, I think I mentioned this in our last call, we were in the process of unitizing the raw Burress lease with Devon. We've now completed that. Devon has proposed two wells that will be drilled, back to back, in that lease. And, in fact, the first well has spudded and it is in the process of drilling, and the rig will immediately drill the second well as soon as we get this one drilled and we'll complete those two wells at the same time. So, we're anxious to see that take place. Our interest is 36% in both of those wells and we'll invest about a million bucks each in those two wells.

In addition to this, Devon has permitted two additional wells and so we'll be anxiously awaiting to see when Devon proposes that we drill the next two wells after the Etta Burress 2H and the Etta Burress 4H. Another note about our Barnett play, EOG began drilling the well called the Dethloff in the third quarter. I had a rig break down. The rig had to be taken off the well and repair work done to it. That repair work has been completed and EOG is now drilling again to try to complete the drilling and completion of the Dethloff well. So, we're pleased to see that EOG is back working in our play and that activity is moving ahead.

Our liquidity remains in excellent shape. At the end of the third quarter, we had $48.5 million worth of availability. We had $27 million in cash and $31 million of availability under our line of credit, and we're reserving $9.5 million of that line of credit for retirement of our 11.5% senior notes, which will be retired on February 15, 2008. We do plan on closing the Ascent acquisition by the end of November and I'll go into a little more detail on that in just a few minutes.

For the nine months, actually that should be the quarter, we drilled four producers, we had eight dry holes, and we had six -- that number's not right. Yes, I'm sorry, I've got 48 wells for the nine months, producers, we had six dry holes, and three wells that we're drilling for completion. I'm sorry, I got some bad data on this. And so, we were right at 90% for our success rate through the first nine months of the year and that's still in line with our 92% rate, long-term.

In the third quarter, we produced 181,000 barrels of oil, 48,000 barrels of natural gas liquid, and 641,000 cubic feet of gas for 336,000 total BOE versus 342,000 for the quarter of last year. During the quarter, we suffered some production shut-ins. We had about 14 days in the quarter of where we had significant power outages and compression problems as results of those power outages in our north Texas play. This primarily affected our Electra/Burkburnett field and our Bridgeport field, which those are our largest and second largest producing fields, and that contributed to both a decline in oil production, as well as a decline in gas production.

Those have, fortunately, that weather has sort of passed and we're getting back into a more normal weather pattern for north Texas. I'm sure, for those of you who are not familiar with this part of the world, we've had unusually wet and stormy weather this year that would normally be providing rainfall in the southeast United States. It seems to be stuck over Texas and Oklahoma and that's impacted us both in Q2 and in Q3. I will let everyone know that the production has popped back up. We're back up over 3,700 barrels a day equivalent now in through the first half of the fourth quarter and continuing to add and restore production in those two key fields for us.

Realized prices were, of course, quite a bit better than a year ago. Oil in the third quarter, we realized prices of $72.78 versus $62.79 for a year ago and NGLs were about flat with a year ago at $47.07. And gas prices were up slightly at $6.34 versus $6.13 for the third quarter of '06. So, on a BOE basis, we're up to $58.03 versus $53.43. And as a result of that, our oil and gas sales increased at $19.5 million versus $18.3 million, even with the decline in production that we experienced in the third quarter.

Our net income, of course, was $4.8 million versus $4.2 million a year ago and net income per share is down slightly because we had a larger share base outstanding in the third quarter of '07 versus what we had in the third quarter of '06. And, as I said earlier, our non-GAAP cash flow was $6 million for the quarter.

We're a little behind on our CapEx investments this year. We're about on target in Electra/Burk. We still got some work to do in Boonesville, Egan, Arkoma, and our other areas, we're pretty much on track with that just because of the investments we've been spending with Chesapeake in the Arkoma play. That was very active in the last half of the first quarter and through the second quarter. We only drilled one well in that play in the third quarter, the Weyerhaeuser 9, which was a decent well but not as good as a couple of the other wells we've had. Chesapeake has some more wells permitted from that area, but they've not proposed any additional wells, so we're kind of waiting to see what they're going to propose in that area.

In our West Texas Woodford/Barnett play, we are drilling some shallower wells with our partner, J. Cleo Thompson, out there and those are small interests, but it looks like we will invest that money during the year. And, of course, our play there continues to be to try to make production in the shallower [Valcanyon] wells and hold that acreage for future, deeper plays when gas prices, hopefully, will justify drilling those deeper Woodford and/or Barnett wells. Now, our Wolfcamp formation, we've got held off on that, given gas prices and everything else that we were doing, quite frankly, with the Ascent acquisition taking so much time. That probably will push that over into Q1 of '08.

This kind of relates to a sense we did increase and restructured our loan agreement with our lenders and we did that at the end part, at the end, of the second quarter and actually executed that in the third quarter. And as a result of that, we had $800,000 of one-time interest expense where we paid down the $40 million on our B loan and had a 2% prepayment penalty associated with that. So, our interest cost was $800,000 higher than normal in Q3. And, of course, since that time, we have completed the signing of the Ascent acquisition.

We now have agreed with our lenders on increasing our credit facility from $300 million to $500 million and we'll increase our availability from $150 million to $375 million. We had $58 million worth of total liquidity available to us at 9/30. And pro forma, for the closing of Ascent, we will have about $89 million worth of liquidity available to us. And, of course, we're looking at $28 million of that as being reserved to redeem the balance of our 11.5% notes when they mature in February of next year. So, we feel like we've got adequate liquidity, going in, into the Ascent transaction to be able to execute on our '08 business plan.

This is our well Burress area. This is the area that Devon has proposed to drill both the Etta Burress 2H and the Etta Burress 4H. We're going to drill those, essentially off of the same pad and we're going to actually attempt to simulfrac on those two wells once they get drilled. Most of you remember the [TL Dickinson] well, which Devon drilled at the end of the second quarter. It was the best well we drilled out here and that has encouraged us to drill these two wells, back to back, and attempt to simulfrac on them. We're anxious to see the results of this. And, as I said, ELG, or excuse me, Devon has permitted two additional wells within this lease block, which we were able to unitize, which allows us flexibility and location of our drill site on this set of assets.

I think that we still believe we've got a pretty stable cash flow base and our valuations continue to look attractive versus the peer group. Our exposure in terms of our commodity mix is still quite attractive. And with the Ascent acquisition, we'll continue to be over 50% oil and another 9% natural gas liquid, so 60% of our reserves and actually a little larger percentage of that, more like 62% or 63% of our daily production, will actually be liquids so it should continue to be beneficial to us, going forward. We will, obviously, increase our inventory of growth opportunities with, both PUDs, probable, possible, and our shale opportunities. We do have a fairly high degree of operating control. We will be in operating control of well over 90% of our total assets on a combined basis. Of course, management continues to be very much aligned for shareholder value and creating that.

I might come back just quickly to the production issue because I do want to try to cover that. We probably ended up, as I said, we lost 14, we had 14 days where production was curtailed and that probably cost us somewhere between 100 to 150 barrels a day of production throughout the quarter. As I've said, our daily production rates are back up over 3,700 barrels a day and climbing. And Ascent's production continues to hover around 3,100 barrels a day as we move into that acquisition.

We did have, on the cost side, we had about $400,000 in work-overs that we had not planned on, or had not budgeted on, and then, of course, we had the $800,000 in interest costs. And I think those were the two things, combined with a little lower production, that resulted in our BOE/LOE jumping up on us in the quarter. So, I think we've seen that we're back in line where we feel it should be, going into Q4.

I'd like to take just a couple seconds and update everybody on where we are as it pertains to the Ascent transaction. We did mail the 14C information statement to all of our shareholders on the 9th of November and therefore, the record date for closing the merger has been set at November the 29th. And we are moving forward with that and don't anticipate any issues at this point of seeing an impediment to closing on November 29th. So, that's where the Ascent transaction stands. And, I guess, Bob, with that, why don't we open it up for Q&A.

Great. Operator?

(OPERATOR INSTRUCTIONS). And your first question comes from the line of Neal Dingmann with Dahlman Rose. Please proceed.

Good morning, Larry.

Good morning, Neal.

Say, on the Electra/Burkburnett, what are your plans, near term, for that 3,700? Are you going to be deployed around there or are you going to step that up a little bit?

On which one, Neal?

On the Electra/Burkburnett and the Bridgeport.

Yes, those have both kind of started coming back up and that's what's been able to drive the numbers back to north of 3,700 and we're continuing to see a little improvement with that, Neal. We're going to try to look at those numbers and we may give the market some indication of what we think we will actually see out of that for the fourth quarter.

Okay, okay.

I don't have that right now, but I'm going to see if we can't give the market a little insight into what we think is coming there.

I gotcha, I gotcha. And then, on the, can you give a little update on the Wolfcamp? If you've, as far as the zones, have they all been fraced or evaluated? Or where you sort of sit there?

Neal, they have all been fraced, they've all been tested, they're all capable of flowing gas. The thing that we've got to do is decide where we're going to try to drill the horizontal test within that, within those. We got two well boards there. We've picked one of them out we think is the best candidate for that, but honestly, Neal, with everything we've had going on with Ascent, we just kind of had to put that a little bit on the back burner until we could get back to it. And I think we can, as I said, we're probably going to do that in the first quarter.

Okay. If I could just sneak one last one in. Is it too early to tell, such as on the setup in the Appalachian, do you know how long you sort of test and evaluate before you'd start to see any real production up there?

Neal, they've had production volumes out of all of the wells that they've drilled. I mean, they've drilled five verticals, and I think they've tested, it's three or four of them that they've actually tested and attempted a completion on. They have drilled one slant well. I think they got a little bit of a test out of it. And they've drilled two relatively short-legged horizontal. I mean, they're, I think one of them is about 1,200 feet and one of them is about 800 feet, approximately. What we need to be doing up there and looking around at the others is we would hope we could get those laterals out to 2,500 feet is what we would be projecting.

So, we've looked at the zones. They look like they're capable of producing. From what we've seen from other players immediately around us, and I'm talking, I guess, primarily Cabot, they're the closest to us, most people are talking about 0.8 to 1.2 bcf for a horizontal well and about 0.4 of bcf for a vertical well. A vertical well costs about $500,000 to drill. A horizontal well costs about $1 million to $1.2 million to drill. And, of course, one of the things we'll have to do is get our midstream assets in place to do that because we are nitrogen fracing these wells and one of the challenges, and we're looking into this now, is you've got to get the nitrogen level down to pipeline quality.

And one of the things we're evaluating is how quickly can we get a nitrogen rejection unit in place and begin to start selling gas. The wells have been drilled. It would appear that they could sell gas in commercial quantities if we can get the nitrogen level, or once we get the nitrogen level, down to pipeline quality.

So, the big challenge for us as we move into 2008 is to design our drilling program for the Appalachian and to design our midstream marketing program. In fact, that's one of the things we're working on right now and will be part of what we provide to the market early in December. Our plan, of course, is to unveil our 2008 capital program some time early in December so that you and the other analysts that follow us can begin to put that into your model. And we'll do that not only for Ascent, but we'll also, it'll be the total capital program for all of RAM's activities for next year.

Good. I look forward to all the activity there.

Thank you.

The next question comes from the line of Leo Mariani with RBC Capital. Please proceed.

Yes. Good morning, guys.

Good morning, Leo.

Hey, I was wondering if you could elaborate on what your recent activity has been in, say, the last six to nine to months and maybe what your plans are for the next six months in some of your other major fields, like Boonesville, Egan, and Vinegarone, that make up a chunk of your production.

Leo, in Vinegarone, we really let Exco lead there. They're the operator. They own the majority of it. Our interests run from about 25% to, I think, the largest interest we have is like 40%, 45% in one or two of the wells. On average, it's a little over 25%. They're an operator and we're not an operator, so we're letting them drive Vinegarone. So, we don't really have any plans there.

And as far as Egan, we really don't have any major plans for that field at this point. We're just producing that field out. It still has some behind pipe zones but until we complete the lower zones, it doesn't make sense to try and move up the well bore there. I mean, at some point we will.

In Boonesville, we are actually still doing some additional acreage acquisitions and do plan on drilling some wells in that. We've been reprocessing our seismic. We do have seismic over in that field, or a big part of it anyway. And we're reprocessing there to see if that'll help us further identify what we want to spend money on, but we still have some more, mostly PUD drilling in that field, more so than it is exploratory.

As far as Electra/Burk, which is our biggest field, we continue to drill in that field. We did spend quite a bit of money in the third quarter, redoing our, not redoing, but really adding some additional compression capacity and also some water handling capacity. We've been permitting some additional injection wells and we've been putting in some, quite frankly, a little more modern pumping system to be able to handle the fluid level there. And we're continuing to drill, try to drill, weather and such allowing us to still drill about six wells a month in that field.

Okay, so in terms of actual activity in Vinegarone, Egan, and Boonesville, there hasn't really much in terms of new drilling work-overs in the past nine months. Is that fair?

Yes, there really hasn't been in those three fields. I think we drilled one new well in Boonesville this year and haven't drilled anything in Vinegarone or in Egan.

Okay. Can you give us a little better update on sort of what your last discussions were with EOG in terms of how you kind of position yourselves there in attempt to accelerate drilling on those properties?

Yes. Leo, we had proposed a well, called Brown. I don't remember the exact number of it but it was one of the wells in our joint acreage. EOG had elected to drill and operate that well. The proposal on it lapsed because EOG did not drill it under the timeframe that's required in the operating agreement. We re-proposed that well to EOG with a little stronger language, basically, that if they didn't commence drilling that well in accordance with the operating agreement, we were going to consider them having elected to go non-consent. They came back and said that they would drill and operate that well, so we're sitting tight, watching that.

I think that we're trying to establish our good faith effort to drill and develop the minerals that we own in that play. And I think that I would and I would expect that EOG would also perform in good faith to drill and develop those minerals. Those are mineral rights that are owned by royalty owners and we feel like that we want to drill and produce those minerals and we're just trying to establish the course of dealing with EOG in this matter. So, we're hopeful that it will end up in a very positive thing for both of us. But, at this point, EOG really has, from our perspective, not really dedicated the resources to this joint acreage that we feel like, contractually, they should be. So, we're --

Okay.

We're going to be a little more aggressive on that. Candidly, though, I think with what we were doing, getting the due diligence and the negotiations of the Ascent transaction nailed down in the third quarter, the re-proposal of the Brown was really all we pushed at EOG. Now that we've got that kind of, I mean, one of the things, we handled, and this might be a little bit background, we handled the Ascent deal a little different than a lot of acquisitions. We essentially did most of our due diligence before we signed the contract. So, that was really taking quite a bit of our time and attention in the third quarter. And, as a result, we really weren't as aggressive, pushing EOG.

We were in contact with Devon and we knew we were in the process of unitizing the leases in the raw Burress area, and once we got those unitized, we would accelerate the drilling program. That's exactly what's happened. It took us a little longer to get those leases unitized than we probably would've hoped, but hey, we got them unitized and now we're charging ahead. So, we feel pretty confident now that we really don't have to focus a lot of our time and attention on Devon in that area and now we can really kind of turn that time and attention to the EOG situation.

Okay. What's the current production on that Dickinson well and what's the production on that first EOG well? How's that hanging in?

The Dickinson well has been hanging in extremely well. It's over two million a day still. I think the last number I saw was about 2.3 million a day on the Dickinson. Now, being a non-operator, we're kind of running a month behind, but that thing has actually been producing much, much better than we had anticipated. And the EOG well is between 500 million and 600 million a day right now.

Okay. Do you have any initial rates on some of those Appalachian Shale wells? You mentioned it seems like you had some tests over there. Any initial kind of production rates in any of those?

Leo, we haven't released any of that. We probably will when we have, when we unveil our '08 program. I think, given the fact that those were vertical wells and that they were short laterals, I don't know that they're indicative of what we, or our neighbors, are expecting or seeing. The best go by that I think is that Cabot has announced that they have drilled six horizontal wells, immediately south of us. If you look at the map that we've published, they're just almost immediately south of us.

Cabot's our largest lease-hold neighbor and five of those wells, EOG has reported initial production rates over one million a day. The best one, I think, they said was 1.6 million a day. They had one of those wells that was less than one million a day and they have given a range between, I think, 1 bcf to about 1.6 bcf is what they have said at EURs. That's about all they had said, or at least that's all I can find in any of the public, published information. And so, that's partially where we're getting some of our projected sort of declined curve that we're looking at as a tight curve, as well as the EURs may be on that.

(OPERATOR INSTRUCTIONS). Your next question comes from the line of Richard Rossi. Please proceed.

Good morning, everybody. Just a couple things. Would you remind us where we are on EOG in terms of how many wells have you proposed? How many wells have they drilled?

We've proposed six. They've drilled and completed one. They spudded the second well. That's the one that they had mechanical problems in, had to stop, pull the rig off, repair the rig. They're now back drilling that well. So, we proposed six and they completed one and are currently drilling the second well.

Okay, and that's including the one that they lapsed on?

Yes, that's, yes.

Okay, and your strategy will be to continue to essentially propose one a month? Or are you going to focus more on pushing them to get what you've already proposed on?

Both, Rich.

Okay.

I mean, I think that that's partially why we re-proposed the Brown with the language that we did, trying to get their attention. And we will be proposing additional wells to them, in addition to the six that we already have, but we're going to push them real hard to get the ones we have proposed, that they've already agreed to drill and participate, and get a rig on them.

Alright. And just one other thing, on the cost side, you talked about the unplanned work-overs, but did, how much of an impact did weather have on productions costs? Obviously, it hurt production, but how many, does it have an impact on just slowing things down, et cetera.?

Yes. I mean, what you do is you're just dragging your equipment and your people through the mud down there. I mean, and you're just shut in when you have those electrical storms. Both of those fields, I mean, Electra, we've got a significant number of pumps that are moving the fluid, the oil and the water in that, and running. If we lose power, it basically shuts us down until we can get the power restored. And the same thing in Bridgeport. All of those wells are being set into our gathering system and, Rich, that's a good question. I really haven't focused on does it affect our cost? I know it affects our production level, but I can't really give you any color on whether it also increases our cost. I'll go look at that, specifically.

But, qualitatively, one would assume that you just get, everything becomes less efficient, everybody takes a little --

Absolutely it does. It just does. I mean, when you're, it just costs you more per barrel, obviously, because you've got less barrels (inaudible) that same cost structure over.

Okay, well, that's it. I'll get back in queue. Thanks.

Thank you, Rich.

And your next question comes from the line of Barry Sahgal with Gilford Securities. Please proceed.

Good morning, Barry.

Good morning, Larry. I wanted to ask a high-level question, no particular detail required for the answer here. Obviously, there's been a pretty vibrant rally in the underlying commodities since you announced the Ascent acquisition. Can you give us a sense of how good you're feeling about it right now relative to what the A&D marketplace is looking like in the areas in which Ascent operates?

Well, we put this transaction together sort of based on about a $60 price tag in terms of our evaluation of it and about a $6.50 gas tag. I mean, it looks like to us, as we look at the commodities' futures, gas is going to be a little higher than that and I think the liquid side of the business is [quite] a bit higher than that. If you look at our derivative situation, we've been able to layer in 1,000 barrels a day, Barry, with a $70 floor, no ceiling on it, for the first three quarters of next year. And we continue to look at those opportunities to kind of put those $60 oil floors under us and the $7.00 to $8.00 kind of gas floors under us.

So, it just looks like to me that the commodity cycle is going to be pretty strong for the near-term. I don't, I'm not an expert at this, but I just don't see where, short of a worldwide recession, that we're going to get the oil to power India and China and the rest of the developing world. So, I'm pretty bullish on liquids and I'm okay on gas. I think gas is going to be $6.00 to $7.00 in the summer and $8.00 to $10 in the winter and those ought to be prices that make places that we're planning on drilling economic.

Again, I always make the observation to myself to remind myself that very few small cap companies, like RAM, that have the kind of oily exposure that you guys do. And just carry on the good work, guys.

Thank you, Barry.

Your next question comes from the line of Mark Lear with Sidoti & Co. Please proceed.

Good morning, guys.

Good morning, Mark.

In terms of the Ascent acquisition and, I guess, potentially some other RAM properties, I just kind of want to get a feel where you thought you guys would be looking to make some divestitures and what you think you guys can get in the current market for some of these properties? Can you talk about that?

Well, I think the acquisition market is, I think you can get very good prices if you've got some decent stuff to sell. One of the things that we will do, Mark, is kind of take a look and re-prioritize both the RAM and Ascent fields and look at whether or not some of these fields that are primarily cash flow generators, if it makes some sense to consider disposing of those, taking that capital, and reemploying them in the areas where we see growth. We clearly will be looking at that as we move into '08.

We don't have any specific fields or assets identified as sale candidates, but I would expect that we would be looking at those and identifying some and we probably will have some areas that we will want to get out of, because the thing we want to make sure we do is focus the management, time, and talent on those areas where we have significant growth opportunities.

Clearly, those, we believe, as we look going forward, is South Texas on the Ascent stuff. There's a lot of opportunities there, both in the PUDs, as well as probable and possible reserve within that area. The West Virginia Shale play, we are pretty excited about the opportunity that that presents. And we're very anxious to see if the Tier II Barnett acreage that we're getting is viable. We'll be evaluating that very aggressively. We probably will not stay in the Woodford, Caney, and Arkoma Basin. That's a smaller, non-operated position and we'll probably exit that. Principally, it's undeveloped leases, so it may or may not be huge dollars but it's not an area that I think we want to devote the management and attention to.

And then, some of our more settled or longer producing, longer-life fields, may be attractive to buyers in this market. We may look at that as a, we look at that as a de-leveraging opportunity. I mean, we really think we have two or three de-leveraging opportunities facing us that we can consider. We obviously will have the warrants that either will expire and go away on May 11th or they will bring in $94 million in cash into the Company for de-leveraging. We obviously will be evaluating for some of these assets might be better suited to be in the hands of an MLP and then some property sales. We're looking at two or three potential opportunities to de-leverage over the next 12 to, say, six to 12 months.

Thanks for the color, Larry.

Your next question comes from the line of Ron Mills with Johnson Rice. Please proceed.

Good morning.

Good morning, Ron.

Just from, a follow up from the Ascent conference call, I'm curious if you could give us any more color on it sounds like they had not really spent much money in the past couple years on the properties and you haven't come out with your '08 budget, but do you still think that you'll end up spending probably more on the Ascent properties than on the RAM legacy properties next year?

Yes. I think so. I think, as we look at the Ascent properties, there was a significant amount of preferred drilling in South Texas, in East Texas, in their Barnett play, and in the Fort Worth Basin. And while they did some work in West Virginia, most of that was sort of the kind of testing work that you would do in sort of a science project. So, those have been done in West Virginia, so we expect a fair amount of capital to go there.

Actually, Ron, we're already drilling a well in South Texas that's on our account. In other words, we've actually, the way we structured our transaction with Ascent, there's a work plan that they were going to carry over and things above that, we approved and they're essentially being done for the benefit of the merged company. And we've actually begun some work in that effort so that, hopefully, we won't be sitting here for a couple of months, or two or three months, waiting to get the Ascent '08 program really kicked off.

Okay. And then, from their base production, the Ascent properties bring over that 3,100 barrels a day. Are there any opportunities to ramp that production? Or is growth on their properties really going to come from new drilling opportunities?

We think there's opportunities within the existing production, particularly as it relates to the Oklahoma assets. Those are assets that they have not really spent a great deal of money on. They're more infill drilling, there is the institution of the [Hunt and Viola] water flood in the Northeast [Fits] field. So, that field is in water flood in the [McAllister], which is at a shallow zone -- 1,300 to 1,500 feet, the Hunt and Viola is about 4,000 and they've been drilling that to get it on primary, but it's a flood candidate.

And so, we really have a lot of plumbing issues and that's one of the things we're, as we look to the Ascent assets, we were excited about the ability to turn the petroleum engineers loose on the existing production, as well as turning the geologists and the engineers loose on the exploratory and PUD drilling. So, we really think there's quite a bit of work to be done on both categories of the Ascent assets, Ron.

And could you just clarify one thing that I may have gotten wrong? I think that early in the conference call, you said you had $48 million of availability in terms of --

That's of September 30th, under the existing facility.

Okay.

That was the deal that is currently in place, not the new credit facility that will be in place.

Okay.

We'll have about $60 million is our best estimate right now, starting off on December 1 when we close the Ascent merger.

And that includes cash and availability or is that just availability under the new revolver?

That's cash and availability.

But it assumes that the bonds are paid off.

Right. That's a good point Bob makes. Actually, the credit facility will have $89 million of, or $88 million, or $86 million of availability pro forma, but we're reserving $28 million of that to take care of the bonds when they mature on February 15th. It's more cost effective for us to let those bonds go to maturity than it is to call them and pay a call premium between now and February 15th.

I understand. Okay, great. Thank you, guys.

Thanks, Ron.

Your next question comes from the line of Monica Verma with Gilford Securities. Please proceed.

Hi, guys.

Good morning, Monica.

Just two quick questions. One has to do with any changes to your hedges? And the second one, if you could give a little more color on the Arkoma Chesapeake interplay there, why they haven't proposed any new wells?

Well, I mean, in Page 15 of our presentation, which you can go to on the website, it gives you the additional hedges that we have been putting in place. What we've been doing at this point is layering in some additional puts in '08 and then secondary floors in '09 to add to that. I think, also, from the last time we reported, we've added some additional volumes in the first and second quarters of '09 and the first quarter of 2010.

Once again, Ascent being about 50% oil and liquids, we've really been trying to take advantage of the crude market where it is as far as getting hedges in place and we'll probably be adding more gas hedges as we get closer to closing or in the month of December, Monica.

Okay.

We're going to continue to try to target, having about 60% of our production with the sort of relatively either floors or wide collars. I mean, that's worked fairly well for us as far as continuing to raise the floor level that we've been able to do. So, we'll continue to try to do that in the market.

Oh, the Arkoma, I think, and this is our take on it, I think Chesapeake, like us, we drilled -- what was it, Rick? We drilled six wells or seven wells and we've had very good luck with those. I think, now, what we're doing is just probably sitting back and watching the production volumes on that because as we begin to step further and further out, they're going to become a little riskier.

So, I think that with probably a combination of gas prices and other things, Chesapeake cut back some of their activities from other places, and all of this acreage now is helped by production, so it's probably not as pressing for Chesapeake, at this juncture, as it was.

So, we expect them to come back to it. As I said, they proposed two more wells. I don't remember. It seems like they proposed maybe a couple of more wells. Unless they've proposed, they've gone to the Commission to get them approved, density wells, but they haven't come back and proposed them to the working [industry] at this point.

Okay. Great, thanks.

Thank you, Monica.

(OPERATOR INSTRUCTIONS). And your next question is a follow up with Leo Mariani with RBC Capital. Please proceed.

Hi. Just one, one last question here for you folks. Are you guys going to plan to file your 14C document with the SEC at some point in the near future? And, if so, when?

Leo, we've already filed it and the SEC gave it a no review. It's been filed, it's been cleared by the SEC, and it's been mailed to the shareholders.

And it's out on the website. It's the, shows you the def -- definitive 14C under the Investor.

Okay. I guess, yes. I'm looking at it right now and for some reason, I don't see it here.

Yes, it actually, the merger will take place 20 days after we mailed it and we mailed it on the ninth. The 29th is the closing date for the Ascent transaction.

Okay. I guess you folks may just want to check in with the SEC because I don't see it available under your list of filings here at all.

If you go to our website, Leo, under Investor Relations. And then, there's a dropdown menu, there's an SEC Filings tab. Go to that and it should show up in there.

Again, I'm on the SEC website right now. I don't see it. So there might be some kind of issue there with the posting.

Okay. We'll look, because I'm holding in my hands, the printed copy that was mailed out by Continental to all the shareholders. I received mine in the mail, yesterday.

Okay.

So, we've actually, we are clear with the SEC, so we're finished with that part of the process.

We'll go check under SEC's website though.

Yes, we'll double check that.

Okay. Thanks, guys.

Thank you, Leo.

I show no further questions in the queue. I'd like to turn the call over to Larry Lee for closing remarks.

Well, I'd just like to thank everybody for dialing in this morning and I think that we're not happy with our production in the third quarter as we would like to be, obviously, but I think we're rectifying that and we are charging ahead to close the Ascent transaction. And we'll keep everybody posted on that. And, as I said, we will be hosting a presentation some time early in December. As soon as we get the date pinned down, we'll send it out so that interested parties can dial in and we'll be talking about our 2008 capital plan and our drilling program associated with that.

So, we look forward to rolling that out to everybody. I know that the analysts, as well as our shareholders, will be anxious to see that 2008 business plan and we'll get it out very quickly. And with that, I thank all of you for joining us today. Goodbye.

This concludes the presentation. You may all now disconnect. Good day.