Battalion Oil Corp (BATL) 2006 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Ram Energy Resources second-quarter 2006 conference call. My name is Lisa and I will be your coordinator for today.

At this time, all participants are in listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. (OPERATOR INSTRUCTIONS). As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the presentation over to your host for today's call, Mr. Bob Phaneuf, Vice President Corporate Development of Ram Energy. Please proceed, sir.

Thanks, Lisa, and thanks to everyone who is joining us on this conference call.

I'd like to introduce the RAM management participants today. With us we have Larry Lee, our Chairman and CEO; Larry Rampey, our Senior Vice President of Operations; Drake Smiley, our Senior VP of Land; John Longmire, our Senior VP and CFO; and John Cox, our Vice President and Treasurer. I'm Bob Phaneuf, as Lisa mentioned, and I'd like to briefly outline our agenda for today. Larry and I will review second-quarter operations and update, and then we will stop there and open it up for Q&A.

Before we proceed though, just duty calls with regards to the Safe Harbor statement. I just want to remind everybody that, in our call today, we may make statements that are other than historical facts and information in the presentation that you see on the webcast 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 risk 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, as well as at the conclusion of the webcast slides that you see today, and the management of RAM encourages you to review these disclosures in both documents.

So having said that, let me jump right into a quick review of the -- some of the highlights of the second quarter here. For those of you on the webcast, if you'll turn to Page 2, we had a number of exciting events happen to us in the second quarter. First, on May 8, Ram Energy, Inc. completes its merger with Tremisis to become a publicly traded company that you now see as Ram Energy Resources, Inc. Secondly, we were also privileged to be included in the Russell 2000 index in July. Third -- and we will talk about this in just a second in more detail -- our second-quarter '06 production increased 3% over that of the first quarter in '06. We also have emerging production from the Barnett Shale. That's growing in importance, bringing the Barnett Shale up to our fourth largest producing area currently. RAM has an interest in nine wells in the Barnett Shale, and Larry Lee will be discussing this in more detail, as well as the next bullet point here, our initiation of an exploration play targeting the Wolfcamp Shale in Southwest Texas.

Lastly, in terms of highlights in the first -- in the second quarter here, our first-half capital spending totaled $10.5 million. It's right on track with our planned full-year non-acquisition spending target of $24.3 million. During the first half, we spent approximately 8.7 million of that 10.5 million on lower-risk exploitation activities and the remaining 1.8 million was used for exploration activities.

Now, let's move on to discuss production. For those of you on the webcast, if you'll turn to Page 3, there are really two important takeaways I think with respect to production that we would like to share with you today. The first is our 3% gain in Q2 '06 versus Q1 '06 production on a BOE basis. This is a product of strong 7% increase in liquids production. Number two, the second-quarter '06 versus the second-quarter '05 production is shown on Page 4. Here this is a little bit more difficult to see so I will walk you through it.

Recall first that, in late '05, we had a reversionary interest in one of our principle properties, and when that took effect, that effectively reduced our production from that area going forward. So if you read on this slide left to right, the first three sets of bars indicate our production as reported in the quarter versus the second quarter '05 with the second-quarter '06 production reflecting the impact of the reversionary interest and the '05 quarter absent that reversionary interest effect. So a more representative comparison, we think, is going to be shown by that last bar on the right, which shows that, exclusive of the reversionary interest, second-quarter '06 production would have been up 2% to 346,000 BOEs versus 340,000 BOEs in the second quarter '05, which again was unaffected by the reversionary interest. So therefore, we think we're making significant progress in the area of production, although it's a bit difficult to appreciate, given the impact of the reversionary interest.

Moving on to Page 5, we show here our realized prices for the quarter. As most of you I think expect, average oil price for us was up a substantial 32% while the average gas price was somewhat weaker compared to the second quarter of '05. However, given our hydrocarbons mi of about 60% oil, the average price per BOE that you see on the right hand-side of the slide was actually up 21% to $54.70. So prices were a good, strong benefit to us for the most part in the quarter.

On Page 6, we've summarized some of our financial results. In the press release, we noted that our second quarter '06 was impacted by certain non-cash items pertaining to both the merger that was completed, as I mentioned, on May 8, and unrealized losses related to our derivative transactions. Our net income, excluding these non-cash items, would've been $283,000 or $0.01 a share, represented by the bar on the left.

Also, I want to point out, on the far right-hand side of that slide, our non-GAAP cash flow from operations in the second quarter. We define non-GAAP cash flow from operations as cash flow that excludes working capital and unrealized gains or losses from the derivatives. Our cash flow from operations for the second quarter was up 11% to $4 million compared to the second quarter '05.

So with that, I will stop and turn the operational update over to Larry Lee.

Thank you, Bob.

On Page 7 of the slide show, the drilling success -- we continue to enjoy 90-plus% drilling success. We've had 46 wells that we drilled in the first half of the year. 96 of those were successfully completed. We did have a couple of dry holes in the first half. I think the successful drilling rate that we are having is what is continuing to drive our organic sequential production growth.

On Slide 8, this is just a recap of our areas of operations. The principle field, Electra, is still our largest, Boonsville second, Eagan third. And something of importance I think is the Barnett Shale, which is principle field number four, has risen to become our fourth most significant producing area, followed by Vinegarone. So we're pleased to see some of the earlier work that we've been doing and the money we've been investing in the Barnett Shale begin to be realized in the production profile and we look forward to that growing in the future.

Slide 9 covers our Electra/Burkburnett area in Wichita and [Wildberger] County. This is our largest field. We drilled 41 wells in this field in the first half of the year. All of them were complete as producers. One thing I would point out that, of those 41 wells, 33 of those were proved undeveloped locations in our reserve report at the end of last year, and eight of those drill sites were not in our reserve report at the end of the year. So we continue to identify additional opportunities to drill within this field, as well as the 167 remaining identified PUDs that existed at June 30. As I often say, we do have 100% working interest and ownership and operational control of this field, and it continues to be significant for us in producing about 53% of our actual production.

On Slide 11, at the Eagan field in Louisiana, we didn't really do much in the way of activities here. This continued to just produce oil and gas for us during the second quarter.

Page 12 is the Barnett Shale in Jack and Wise County. This is an area that is evolving and has moved into our fourth largest field. At June 30, we had eight wells producing in this field. We had one well that is currently in the process of being completed and should begin to produce in the third quarter. This acreage is all helped by production. Two of these wells are operated by RAM, six of them now operated by Devon as a result of their closing of the acquisition of Chief Oil and Gas, and one well operated by EOG.

Utilizing 80-acre spacing or less gives us the potential for some 300-plus horizontal drilling locations within our owned acreage, and the 35.28 square miles of 3-D seismic that we own or are currently in the process of acquiring and interpreting covers over 50% of our existing acreage in this play. We continue to acquire and shoot additional acreage and will continue that process through the second half of this year and probably into early '07 as well.

In the Vinegarone field, which is on Slide 13 in Val Verde County, Texas, we have three PUDs that have been scheduled to be drilled in the third quarter. A quick update -- the Coe 27-2 drilled to 10,600 feet and is currently being completed. The [Alteizer 16-B] is currently drilling at 9923 feet with a targeted total depth of about 11,000 feet. When the rig finishes up with the drilling of the [Alteizer 16-B], it will move immediately to the Coe 26-5. So we're on schedule to get those three PUDs drilled in the third quarter, and that will leave us with four remaining PUDs that we have currently identified in this field for future activity.

That's kind of a quick recap of the production. I think the fact that we are up about 3% sequentially will let you know how we are proceeding on the existing field.

In the exploration projects, the Barnett and Woodford Shale in Reeves County -- Alpine recently entered into an agreement with another company, which acquired a majority of the Alpine block, and that company will soon begin an aggressive seismic and drilling program to test the Barnett and Woodford Shale. RAM did join Alpine in this agreement for a portion of our acreage that RAM previously had farmed out to Alpine. Once again, we still believe that that will be a 2007 event for us.

This Wolfcamp Shale in Southwest Texas is an active lease acquisition play that we've been working on for some several months now. We have 15,000-plus acres that we have control of. At this point, it's a 100% owned block. We still are attempting to acquire additional acreage in this play and that's why, at this point, we are not being more specific about its location. RAM will drill two test wells early in the fourth quarter to test this play. Dry hole cost on these wells is about $0.5 million and a completed well cost is about 1.2, 1.25 million. The depth of this goes down to approximately 7,500 feet in total depth, and the Wolfcamp section has an overall thickness of about 3,000 feet in this area and it's in embedded sands and shale throughout the full 3,000-foot thickness. So we will keep everyone posted about how that play evolves as we move forward in the year.

Kind of a summary on our financial and operating data -- you know, we are -- there's almost 650,000 barrels of oil equivalent in the first half of the year, $35 million in revenue, and we had $17.1 million in EBITDA. This was 17.1 million in EBITDA after deducting $3.6 million in realized derivative losses that we incurred in the first half of the year.

During the first half of the year, we still had some relatively lower-priced ceilings on some oil collars that we had in place for some time, almost I guess 18 to 24 months. Those rolled off at the end of June. So, we will be benefiting from higher realized prices, net of our derivatives, as we move forward into the second half of the year.

One thing that I would like to point out is, on Page 16, which is -- we talk about our liquidity. At June 30, we had $13 million in cash and another $37 million of availability under our revolving credit facility, so that gave us $50 million worth of liquidity. This is in addition to the fact that we have been able to fund our CapEx program by the cash flow that we are generating from our operating activities.

Our senior debt -- we still have the 28 million of 11.5% Notes outstanding, and we had $103 million borrowed against our senior secured credit facility at June 30. So this is reflective of the new credit facility that we entered into with Guggenheim Funding Partners in the second quarter in April of this year. So we feel like we are well-positioned to either accelerate our CapEx expenditures, if we have reason to, and to also look at some potential acquisitions in and around our existing operating areas.

Flip over to Page 17. This is our valuation slide that we continue to update. The share prices that are reflected in this valuation matrix are as of July 31. Our peer group continues to be the same. The PV10 and the reserve numbers in here still are year end '05, and while our peer group has traded down, unfortunately we've traded down with them and so the valuation gap between us and our peer group continues to exist. I think that part of that is we still are a relatively unknown name and need to continue to aggressively market and advise the markets of the RAM story. We will continue to be doing that over the next several weeks and months.

Once again, if you look at the total enterprise to reserves on a BOE basis, we trade at a substantial discount to our peer group. Total enterprise to PV10 (indiscernible) very substantial discount to the peer group. Reserve life index is very similar to that peer group and our developed reserves is a higher percentage than our group. So if you look at the net asset value being $7.02, that continues to exclude any of our gathering systems, our Barnett Shale acreage, our Reeves County acreage or the future potential that might end up being related to the Wolfcamp play.

I think, with that, I will turn it back over to Bob real quickly and then we will go into Q&A.

Thanks, Larry. Lisa, I think we're ready for the Q&A part now.

(OPERATOR INSTRUCTIONS). [Barry Segal], [Gilford].

Larry, can you share with us the oil costs and unit economics of the Barnett Shale as you see it today?

Barry, we're very anxious to see the cost structure that we will be participating in with Devon as we go forward. The cost structure that we were experiencing under our relationship with Chief was very attractive. We were drilling those wells on a 100% basis for well less than $2 million. The EOG well was in excess of $2 million, and so we're quite anxious to see the first well that Devon is fully in control of. The [Ettaburros], which is a well that is currently being completed, was transferred after it was drilled but before it was completed to Devon so we really can't give you a good answer on that, Barry.

The reserve volumes -- we continue to increase our reserve estimate the more time that we've had on the wells that are currently producing. We've been fairly conservative initially and continuing to increase those. Certainly, the industry talk of a couple of Bcf per well and $2 million to drill the well seems to be not too out of line I think. It's our feeling also that the rig rates seem to have topped. They are certainly not declining yet but they don't seem to be escalating anywhere close to the rates that they were recently. So what we're hoping is we're going to see these costs stabilize somewhere in this $2 million range and that we will be looking at reserve recoveries of 1.6 to 2.5 Bcf. I mean, there will be some variations within the field.

Okay. Now, you've very successfully grown this company utilizing a combination of the drill bit as well as acquisitions. In regard to the latter, i.e. acquisitions, can you share with us what you've seen happening at the macrolevel, and how a strategy of utilizing the futures curve to lock-in wide margins of might be something that you would consider going forward?

Barry, you well now we've always been relatively active in the hedging market, and I do think that the price of acquiring oil and gas assets, both producing and leases, are certainly going up, but the increase in the commodity prices and the ability to hedge out on a much longer-dated basis than we could even two or three years ago allows one to take a lot of the risk out of producing acquisitions at this point in time. Certainly, we would, in all likelihood, utilize the commodity markets on any acquisition that we would enter into.

I certainly thank you.

(OPERATOR INSTRUCTIONS). Robert [Stankham], [Telios].

Thanks for taking my question. Larry, you mentioned the RAM story not being that well-known yet. Any upcoming plans for September and onward in terms of marketing, in terms of analysts?

Robert, we have a marketing trip to New York and to Boston in early September. We are on the agenda to address the OGIS West, which is the oil and gas investor series that they have in San Francisco early October, and we are working on some additional marketing trips to Chicago and maybe another trip to the Mid-Atlantic. We did make a trip to the Mid-Atlantic area in late July and had some good meetings. We still are a little frustrated that we've not yet had the benefit of getting analytical coverage, but we do have an oil and gas analyst that will be in here later this week to sit down and visit with us and hopefully that will lead somewhere. Bob may be able to speak a little bit more directly to that, Robert, than --.

Yes, Robert, I think, right now, you know, we've had requests from probably half a dozen analysts for historical information to help them build models. You know, based on that evidence, I guess I would say that while, as Larry mentioned, we don't have anybody with a full-blown written report yet, it seems like there are a number of folks that are interested enough to start doing some real homework. We are, of course, glad to supply them with that information.

I think a little bit of it, too, was wanting to wait until we sort of had a full-blown quarter out under our belts. While this almost qualifies since we went public in May, I think it's got pretty representative information out there that people can now look at for the first half and begin to think about what the rest of the year would look like. So, I'm cautiously optimistic that we will continue to see the interest go forward.

Great, thank you.

Barry Segal with Gilford.

Larry, you mentioned that the gathering assets don't have any imputed value as you expect in the share price. What kind of hard value on the balance sheet are the gathering assets carried at? What do you think the reasonable market valuation might be?

Barry, they probably have 0 value on the balance sheet because -- well, I take that back. They may have some. They were part of the acquisition of the Boonsville field, but subsequent to the acquisition, we did add some additional compressors to that field, so we might have a relatively small amount of value on the balance sheet, but it would be in the maybe a couple of hundred thousand dollars, Barry. It would not be any significant number at all.

We have been having some very preliminary discussions with -- we're looking at really three things with those assets, either try to grow them ourselves on our own; either joint venture them with someone who's in that business, and we've had some very preliminary discussions with potential parties in that regard; or sell them and use that capital to more directly invest in drill bit activity.

So Barry, I think those are the three courses of action that we've identified. We're working on those but we do not yet have a course of action that we've adopted. I will probably be able to give you a better sense of the value of that after these discussions proceed a little bit further. I just don't really have a number I would be comfortable with throwing out there right now. But, you know what [cross-tax] paid for the midstream assets that were acquired in the Chief acquisition. So, we've got a basis upon which I think with a little more work to could come up with a model that we can share with people and it will have some serious data to use to value that asset.

Likewise, can you give us any guidance or point us in the direction of how we should be taking a look at the acreage valuations of the Reeves County and your (indiscernible) Barnett holdings?

You can look at what Chesapeake paid for 18,000 net acres recently that was highly publicized, and they paid $10,000 an acre for a 75% term lease. So what does that do to our 6800 net acres that are HBP-ed without term? I don't know, but I would think it would be a higher value than that. That's the most recent valuation that has been announced on a pure acreage basis.

Now, I would hasten to say that having 18,000 acres contiguously and having 100% ownership of it certainly makes them very valuable, and that's why Chesapeake stepped up so large for those assets. But the market value of acreage in the Barnett is doing nothing but going up.

I really can't comment much about the Reeves County thing, Barry. Just -- under this agreement that we've participated in with Alpine, we really kind of got our hands and mouth tied on that point.

Who are the other competitors in that area who you come across in the public environment?

In which area -- Reeves or Barnett?

In Reeves.

Well, EOG is actively out there; Enacan is out there; Chesapeake is out there; Burlington is -- Conoco, now they are still apparently trying to block up additional acreage even though they've now been acquired by Conoco. Who else am I missing? [Petrol Hunt] is in the area pretty actively; of course they are private. Riada is in the play. So it's a fairly active play and I think that's -- you know, Alpine announced -- they put an announcement about what they did in July, or we couldn't have even talked about that. But you know, there's activity clearly going on in that play and quite frankly, for our position, we are pleased to see some of these bigger majors come in with the skills and the technology to hopefully turn that into a real development play as opposed to opposed to an exploratory play.

Larry, one last question without hogging too much time here -- obviously, liquidity of the equity is an important consideration for investors when they take a look at a small, newly public E&P Company. In that light, you've got 13-odd million shares in a trust, in (indiscernible) trust. Can you shed some light as to what the longer-term thinking might be with regard to that holding?

Secondly, as part of this liquidity question, would you consider utilizing equity to fund your growth in the event of an acquisition?

Barry, I think that it's too soon for me to give much of a direction on Dr. [Tally's] estate. His daughter is still extremely emotionally supportive of the Company. I mean, this is something that her father and I created, so there's still a great deal of emotional attachment and support for what we're doing. But I do think any reasonable person would expect that, at some point in the future, it would be wise for her, since she's not involved with the business and certainly has no intention of getting involved with the business, to consider diversifying. I think that could be an event that will allow some additional liquidity into the marketplace.

Before the market turned so sour on us this summer, we had visions of it at some point that we would get our stock level to the point where the warrants would be exercised and that would bring additional equity into the marketplace. So those are the two events that -- and probably that we would think might add some market liquidity to the stock.

I think that the answer is we would consider using equity but only in the context of -- if we felt like the valuation that we were getting for the equity in exchange for the assets that we were buying through acquisition was beneficial to the existing shareholder base. So, hopefully that is responsive, Barry.

Kyle Kreuger, Apollo Capital.

Have you had a chance to meet with Devon since the Chief takeover? Any revision to their drilling plans that may have resulted from that meeting since your June production update?

Kyle, we have had -- before the sale and before it was announced and even before it closed, we had ongoing discussions with Devon about some seismic sharing arrangements which we have been able to work on. So there has been -- I have not spoken with anyone at Devon and Drake, I don't believe you have, but at staff level, there's been quite a bit of discussion between our staff geologists, our team there, Kyle, and their team. So that's ongoing and it's going in a normal kind of oil company to oil company way, so there's nothing there.

(inaudible).

Yes, the timetable for drilling under that acreage that they acquired from Chief that we are involved with will not change. Because remember, they do have the drilling commitment to continue to earn the farm-out interest that they got from us.

I have heard in town and in the state that Devon has stated that their intention is to accelerate drilling on the acreage that they bought from Chief, so that's not any -- those are public pronouncements that kind of have been made and are floating around. So if anything, we are thinking that we may see an acceleration of activity on our joint leases, particularly on this raw Burress lease because all of the midstream infrastructure is in place. We have what, two [raw] wells and -- or three Burress wells on this one lease. So that infrastructure is there, so it would certainly makes a lot of sense for them to, if they wanted to accelerate, accelerate there where we can drill them and get that gas to market very quickly, Kyle. So that's what we're hoping is going to happen.

One of the reasons that we're moving so aggressively on the seismic acquisition and interpretation on all of the remaining of our acreage -- we already have seismic and interpretation on the joint acreage that we have with Chief -- so that we will be in a position to be able to propose wells to EOG under our joint acreage if that's what we need to do.

Got you. That's what I was thinking, Larry, that, if anything, there was a possibility that Devon, being better capitalized and not for sale like Chief was, may even look to accelerate the activity. That would be fantastic.

That's certainly the word that we're hearing from just about every place that we turn to. Of course, we have felt like all along that that acreage would be developed at a very nice pace and that our biggest challenge was getting ourselves technically qualified to propose wells to EOG and to move forward on the EOG acreage. That has really been largely, Kyle, our focus internal to the geological and land team here for the last several months.

Got you. On the existing interest in the Barnett wells, I guess your production is a little bit under 300 a day per. Are they following your expected production profile? I mean, have they made that big turn to the right in terms of leveling off? Where are those wells at?

Kyle, all of the Chief wells are performing better than we had initially forecast. We have been disappointed with the results we've seen so far out of the EOG well. But it's only one well, and so I'm not damning EOG by any means. It's just that well hasn't been as good as we had hoped it would be. The Chief wells have all been better than we had hoped they would be. We are working on and probably sometime after Labor Day, we're going to put out a little operational update on our Barnett and we will be able to share a little more of that kind of information with the market at that time, Kyle.

Yes, okay. Following up on Barry's question on the gathering and the discussion surrounding the possibility of monetizing an asset which you clearly aren't getting any credit for, do you have any third-party gas currently going into that system, Larry? What's the capacity of the system in relation to current throughput?

Kyle, the only third-party gas that's going through the system is primarily [Ted Collins] the other working interest owners in the wells that we operate. We are not really transporting for third parties. We could transport for third parties. We just never have and that's one of the things that we're working our way through in that kind of three-pronged approach that I was discussing. The capacity of that system -- Larry, we've probably got (inaudible).

(inaudible).

We're running about 4 million day through it right now -- (multiple speakers) -- (inaudible) -- 10 million I think is what we think we probably could do through the existing lines and things, Kyle. So we've got quite a bit of capacity.

Of course, one of the things that we've also been trying to be thoughtful about how we approach this, Kyle, the reason why -- that gathering system sits on top a lot of our Barnett -- over 10,000 acres of our Barnett Shale acreage. So one of the things that we wanted to make sure of is that, if we needed that for take-away capacity as we drill wells under that acreage, that we had that ability. In other words, if we sell it to somebody, we will want to make sure we reserve some capacity; if we joint-venture it, we want to make sure we reserve some capacity; and of course, if we keep it, then that's not an issue at all. So, it's not quite as simple as just trying to put a value on it and then either monetize it or figure it out because we don't want to do something that's today smart but a year from now looks real stupid because we've got a bunch of shut-in gas in our Barnett deeper play and you can't get it to market.

This ends the Q&A portion of the presentation. I would now like to turn the conference back over to Mr. Bob Phaneuf for final remarks.

Thanks, Lisa. Well, we thank you all very much for joining us today and if you have any follow-up questions over the next couple of days, please give me or my associates Donna Murray a call at 918-632-0680. Thanks very much again. Good-bye.

Thank you for your participation in today's conference. This includes the presentation. You may now disconnect. Today.