Battalion Oil Corp (BATL) 2007 Q1 法說會逐字稿

Good day, ladies and gentlemen. And welcome to the RAM Energy Resources First Quarter 2007 Earnings Conference Call. My name is Latasha and I will be your coordinator for today.

(OPERATOR INSTRUCTIONS)

In our call today, we may make statements that are other than historical fact.

Information in the presentation and all such statements that refer to the 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 the risk factors is included in the Company's filings with the Securities and Exchange Commission, and is enumerated at the beginning of the webcast presentation slides.

The management of RAM encourages you to review this disclosure in both documents.

I will now like to turn the presentation over to your host for today's conference, Mr. Robert Phaneuf, Vice President, Corporate Development of RAM Energy Resources, Inc. Please proceed, sir.

Thank you. And thanks for joining us on the RAM Energy conference call to discuss first quarter 2007 operating financial results.

So, with us today from RAM are Larry Lee, our CEO, John Longmire, our Senior VP and CFO, Larry Rampey, our Senior VP of Operations, John Cox, our VP and Treasurer, and me.

Our agenda for the call today is pretty straightforward. We have a few prepared remarks that review the operating financial results and we'll follow that by a Q&A.

The only housekeeping item today is to let you know that we did issue two press releases yesterday, one dealing exclusively with our most recent acquisition and the other with our first quarter earnings release.

So, assuming that everybody has seen or has access to both of those, I'll turn it over to Larry. And we'll begin the prepared remarks.

Thanks, Bob. And I want to thank everyone for joining us on our first quarter conference call today.

Our highlights in the first quarter was a well proposal and drilling activity aimed at developing our Barnett Shale acreage continues to grow. We've had two wells drilled in the first quarter. Both of those wells are currently in the completion process.

We have three additional wells approved by the interest owners and our inventory of seismically identified locations at the end of the quarter stood at 33 and we continue to work the seismic and add to that inventory.

RAM participated in the drilling of 18 gross, 14.7 net wells in the first quarter -- 11 of those were completed as producing wells and five were in various stages of completion at March 31st

Just as an aside, we only drilled 14 wells in Electra/Burk, which is our most active drilling area during the first quarter.

And we had some weather delays, but we have begun to make up for those. And we have now -- through the 15th of May, or for the first half of the second quarter -- we have spudded in 10 wells.

And so we're working our way back on track for our six wells to be drilled each month in Electra/Burk.

Our first quarter production totaled 313,000 barrels of oil equivalent. Daily average was 3,478.

That's up about 1% from the 3,446 BOEs daily average that we had in the fourth quarter of 2006.

And we lost about approximately 3,000 barrels of production as a result of winter weather issues in January and in February of the first quarter.

We did complete a 7.5 million share follow-on offering during the first quarter and netted approximately $27.4 million to the company.

And I would also point out that I personally was able to acquire 50,000 shares in open market transactions during the first quarter, during the limited window that was open and available to me.

Additional first quarter highlights is our lending group. We affirmed our borrowing base at $140 million. And at the end of March, our liquidity remained a substantial $66 million at the end of the quarter.

Other highlights, I think, is, as a result of the year-to-date pace of the proposals and apparent development activity in April and in the Barnett Shale, the board decided that we needed to increase our capital budget commitment to the Barnett Shale.

And we increased that by $6 million, or 150% over the original budgeted dollars for the Barnett Shale, so that we now have $10 million committed to that program for 2007. And that raises our total CapEx budget to $36.3 million for drilling and development activities.

We did close today on the acquisition that we announced yesterday. We purchased 120 wells located principally in Southeast New Mexico and West Texas for a price of $18.5 million, subject to normal adjustments on a transaction such as that.

I would point out that, with this transaction, that now increases our capital expenditure budget for 2007 to $54.8 million.

And I'll take just a second here to give a little more color on the acquisition because we're quite excited about it. Almost 90% of the value is in Southeast New Mexico. There is three fields -- two in Southeast New Mexico, one in West Texas.

The seller's report represented about 1.3 million barrels of proved reserves. It is currently producing about 280 barrels of oil a day equivalent. This package has a 14-year reserve life. These are very long life predictable reserves.

We did acquire 100% working interest in all three fields. And all three of these fields are located within a 25-mile radius of each other. So, from an operating standpoint, it will be a very simple task to integrate that into our operations.

100% of the reserves that the seller represented in their report were PDP reserves. 85% of that is oil, 15% of that is natural gas. And the oil in this package is all New Mexico [sweets] and West Texas intermediate, so it's high quality crude.

We do think that there's the possibility that we'll be able to increase the prices that we're getting and that we would expect this oil to carry this same differentials that we're currently getting on the rest of our portfolio.

I think the key component that we look at in this acquisition is that we were able to acquired almost 7,400 gross and net acres, basically in oil and gas country in Southeast New Mexico. This is an area that has been extremely profitable to RAM in the past.

We have had a lot of success out there. We've operated in that area from 1989 all the way through 2004, when we sold our operating assets in that Southeast New Mexico area and redeployed those assets into additional acquisitions of field in Texas.

The acquisition is accretive on both the daily production basis and on a reserve basis. There's no additional G&A that the company will incur as a result of this acquisition. So we expect all of the net operating income to just drop right to our net operating income line.

We do have deeper potential in the [Atoka and Morrow] areas, primarily in Lee County. And we have shallower [San Andrews] potential, primarily in Roosevelt County. Those are both in New Mexico.

And then, the one field that we picked up in West Texas is a water flood. It has the largest number of wells, but it's the least valuable of the fields we acquired. But we do think there's maybe some operating efficiency potential in this field.

And we will be looking at that and evaluating whether that's a field that we will keep in the portfolio long-term, or whether we might turn around and off load that one field.

But I think I would just quickly say this is an area and this is the kind of asset that over the years, RAM has been very successful at buying and creating shareholder value with. So we're kind of excited to be back in this area.

The sellers were a private company. It was a gentleman in his mid-70s who wanted to retire. And we think this opens up a new area for us to look for acquisitions in this Southeast New Mexico, West Texas area.

Going on after that, EOG Resources has notified us that they will participate and operate in the Brown #2H well. That's the fourth well that we proposed to EOG this year. And they just recently sent in the election. And so we're pleased that they're continuing to do that.

And I think with that, that kind of covers the highlights. I'll ask Bob to quickly go through the first quarter results on the next page.

Sure, Larry. On page five, for those of you who are following along on the slide presentation, oil and natural gas sales for the first quarter of this year were $15.1 million, about 10% less than the $16.8 million for last year.

As Larry previously pointed out, on a volume basis, most of the volume that was down, albeit marginally, was due to weather.

So, it looks like most of this differential is really due to the decline in oil prices that we experienced of about 7.5%, and in gas prices, at about 11%, down to $56.37 per barrel and [$6.71] per Mcf of gas, respectively, as an average price for the quarter.

Net income for the quarter was a loss of $580,000 versus a gain of $2.8 million last year. Again, these numbers were particularly skewed as a result of the impact of pre-tax, unrealized derivative gains and losses.

Specifically in the first quarter, net income was negatively impacted by $1.05 million of pre-taxed, unrealized derivative losses.

While in the first quarter '06, income was benefited substantially by pre-taxed, unrealized gain of $3 million. So that explains, I think, most of the difference there.

Following on to that, we had 37.8 million basic weighted average shares outstanding for the quarter, which made the net loss of the quarter $0.02.

And non-GAAP cash flow from operations this year of about $4.1 million versus $5.3 million last year.

So, importantly, I know Larry's going to point this out in more detail, but the non-GAAP cash flow from operations basically is very close to or just about equal to our CapEx for the first quarter.

Thanks, Bob. And next page is slide six, for those following along. And this is our revised CapEx budget, with our $10 million commitment to our north Texas Barnett Shale program.

Our commitment for the other projects remains the same at this point. But with the $18.5 million acquisition, that does increase the entire CapEx budget for this year, up to almost $55 million. And so, we're expecting to get that budget put to work and begin to see the results from it.

On slide seven, just to do the recap quickly for the financial liquidity, at March 31st we did have $66 million worth of liquidity.

And just to show you what our pro forma liquidity is at 5/15, post of this acquisition, in West Texas and Southeast New Mexico, we still are sitting with $50 million worth of financial liquidity.

And as Bob indicated, our cash flow from operations for the first quarter was $4.1 million and we invested about $4.5 million in CapEx in Q1.

And of course, our CapEx investment will be ramping up from that level pretty substantially over the next several quarters.

So we still feel like we've got plenty of dry powder to do everything we've got scheduled for this year, along with the cash flow coming off of the assets.

In Electra/Burk first quarter, we produced 173,200 barrels of oil from this field. We drilled 14 wells. We drilled 79 in '06. And as I indicated, we now have spudded in 10 wells since April 1st.

So we're getting back on track to make up for those roughly four wells that we did not get drilled in the first quarter because of weather related issues, primarily.

We did start the year with 200 identified PUD drilling locations. And as I've said many times, this is a field that we own 100% of and have the operational control and the various assets, drilling rigs and supply company and work over rigs and the earth-moving equipment and the other things to really help keep our drilling and completion cost at a very attractive $6.29 per BOE, as projected.

Our Boonsville field in Jack and Wise County, our first quarter production was 35,500 barrels of oil. We have 20 identified PUD locations in this field. We still have our gathering system.

And this is a field that we project about $1.6 million will be spent in CapEx for the year. And once again, this is our producing wells that hold our Barnett Shale deeper [rights].

Our Barnett Shale program in Jack and Wise County, where we own almost 28,000 gross, 6,800 net acres, which is all held by production and 90% of this is in the core area in Wise County. So we now have nine producing wells that are existing.

We have two wells that are currently completing. The T.L. Dickenson, the multi-stage fracing has started and that should go for the next week or so and then we would expect to begin seeing results come back in the next several weeks.

The Ashe C 1H, which is operated by EOG, has been drilled and cased and perforated and turned over to the fracing department. And we are awaiting a frac schedule.

We have 5 PUD locations here and 19 probable seismic locations, nine possible seismic locations, for a total of 35. And this count is as of the end of the quarter. We'll update this information to the market at the end of each quarter going forward.

As we look at our EOG acreage, which is 23,500 or 5600 net of our acreage. We have the one producing well, the Ashe 1H. We have the Ashe C 1H that is currently completing. And we've not yet booked any PUD locations on any of this acreage.

This is an area that we do have 37 square miles of our 3D seismic program. And the great bulk of our 2007 seismic plan is scheduled for this acreage.

We have proposed four wells now to EOG. We've been able to, sort of, have a well proposal a month to them. And they continue to elect to participate.

And so, there's times I wish they wouldn't participate. We could have a much larger interest and charge ahead with this. But they are continuing to do it.

The second well in the EOG acreage is on the drilling schedule, but I don't have a date that it should start in. but we do know it's on their drilling schedule. And as soon as we get a date, we'll probably advise the market once that starts.

Our Barnett Shale acreage that's with Devon is 3,500 gross acres. Here we have a 36% working interest. We have seven wells to date.

One well has been drilled and, as I said, is now in the completion process with the first stage frac done this week. And they'll just continue to work through this. I believe we have a six-stage frac job schedule for this well.

We do have five PUD locations here. And we do have our continuous drilling clause. So, we're expecting that we will continue to see about three wells a year out of Devon on this acreage.

And I would say our working relationship with Devon in this area is been nothing but excellent.

Kind of a quick recap, the six wells that have been drilled and completed in this area -- this was as of the end of the year. But the average initial production was 1.921 million Mcfe's per day. Average EUR is about 1.8 and average well cost about $1.8 million.

So we're pleased with the EURs that are projected here.

And we're hopeful now that we may see a peaking of and hopefully even a decline of the cost to drill and complete these wells. Drilling costs are coming down. And we're anticipating that the completion cost, if not coming down, will at least quit going up for the time being.

Our Wolfcamp play in Southwest Texas -- this is where we've got 15,000 acres -- we have drilled the two test wells. We continue to stimulate and recover frac fluid as testing is underway on these wells.

We do hope to have more information to share with the market later in this quarter. But the status is pretty much as it was just a couple weeks back when we were at the IPAA conference in New York.

As kind of a summary, we think our investment considerations -- we've got a very long stable life cash flow base.

I continue to be amazed at the valuation compared to our peers and how we seem to trade at a continued trade of discount.

We've got significant management and technical expertise. We've got a real balanced mixture of the commodity price right now, particularly with oil being so price advantaged.

And a larger inventory of our growth opportunities -- we've got 228 PUD, I think it is, Bob, and all of our potential drill sites in our Barnett Shale North Texas.

A high degree of operating control. And I'll point out, just like the acquisition that we just made where we'll operate 100% of that field -- or all three of those fields.

And we do know how to create value through both acquisitions and our drill bit. And I say, management is substantial owners in this company.

And I was very pleased to be able to pick up another 50,000 shares in open market purchases during the limited window that was available to me in the first quarter of this year.

With that, I'll turn it back over to Bob to --?

Thanks, Larry. That concludes our prepared remarks. And so, Latasha, we'll turn it back over to you to open it up for the question and answer period.

Thank you. (OPERATOR INSTRUCTIONS)

And your first question comes from the line of Leo Mariani with RBC. Please proceed.

Yes. Good afternoon, gentlemen.

Good afternoon, Leo.

Just a couple of quick ones here for you guys. I guess I'm a little surprised to see your well cost of these Devon wells kind of as low as it was at $1.8 million and sort of coming down.

Could you give us a little bit of, sort of, information in terms of depth of the Barnett in around the Devon acreage and length of lateral these guys have been drilling?

I kind of thought maybe your well cost would be a little higher. And I'm sure that there's probably some explanation behind that.

That is the average well cost of all those wells that were drilled. Some of them were in '04, '05 and '06. So that's not indicative of what we currently are [AFEing] these wells for.

We're drilling these wells about 9,800 feet total depth with about a 2,800 to 3,000 foot lateral on the end of them. So we're going down about 6,800 feet -- or 66, 67, 6,800 feet -- and then kicking out and doing about a 3,000-foot lateral.

The recent wells that we've AFE-ed, we've AFE-ed them at $3 million. Now, it looks like they may come in at less than that, and so we're anxious to see.

The drilling part of the cost is coming down, based on what it took them to get the wells down, cased, logged and perforated.

So, we're encouraged by that, but we don't have enough data yet on what it's going to cost us to frac these wells. That's where we've had a lot of increase in cost in this area, as everyone has had in the play.

Okay. Quick question on your Wolfcamp play here. I know that you guys have stimulated the several zones on these two vertical walls that you had drilled prior.

Can you give us the sense of basically when the timing you went ahead and fraced those zones, and, sort of, how long you've been flowing fluids and gas back from those wells at this point in time?

Leo, -- I'm sitting here scratching my head -- we've probably been test -- well, we've fraced the first zone and the first well.

And I guess we tested it, -- Larry, for what, about 30 days? -- and set a bridge plug, moved up and went in and tested the second zone in the first well. And at the same time, we fraced the first zone in the second well. And we've now been flowing those back and testing those for -- 40 days?

Yes, but --?

About a month, 30-some-odd days. and we're now deciding whether we're going to take the bridge plug out and co-mingle the first two zones in the first well or go on up and test the third well -- the third zone in the first well and second zone in the second well.

So what we're seeing is that it's taking us about 30 days or so to get the fluid off of it and begin to see some results.

We did have some sand coming back into both zones that we had to go in and clean the hole out, put our screens in and do some things like that.

We have put -- all these wells flowed pretty nicely in the beginning and then we've put mechanical pumps on to try to get the frac fluid off of it.

So we're probably getting ready to look at scheduling the next frac in the two most upper zones that we still have left to test, Leo.

Okay. Well, thanks a lot for the information, guys.

Thank you.

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

Hi, guys.

Hello, Monica.

So quick question is on the production guidance that you have. Are you guys looking at revising that, given the first quarter, or should we expect to see a pick up in the latter part of the year?

We haven't given specific guidance, Monica. But, clearly, we're going to -- our second quarter is going to be higher and we'll get -- we're getting some natural benefit from the drilling and things that we're doing.

And the weather related issues are not hurting us at the moment. Those are behind us, thank goodness. We got the winter out of the way.

And we'll some benefit out of this acquisition in the second quarter, but we've not given specific guidance. We're wrestling with that and might try to come back and give you at least a second quarter guidance here in a fairly short period of time.

Great. Thanks.

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

Good afternoon. Just one quick question on the acquisition. You have 7,400 acres. All the reserves you acquired were [proved developed].

What -- if at this point, you have any drilling plans, or how's the field developed and how do you think it will eventually be developed?

Ronald, we don't, at the moment, have any plans. What we will do is -- there is -- the production is in the Pennsylvanian Sand section at about 9,500 feet. This area has shallower San Andrews zones up the hole in the Southeast New Mexico part.

And there has been some success chasing the deeper Atoka and Morrow sands in this part of the state. And those have to be seismically identified.

And what we don't have at this point is we've not gone out and either acquired or shot seismic to look at the deeper zones, which we will do.

And then we will do our usual scrub the wellbores down to see if we see anything else behind [fi-bo] in the San Andrews that we think may be up the hole. And then we'll decide what we're going to do.

So, as soon as we have some CapEx commitments or guidance as it relates to that field, we'll let the market know. But at the moment, we do not.

And I will point out that we'll probably book 100% of the cost of this thing to PDP reserves. At the moment, we don't really -- I mean we don't see any benefit to us to necessarily try to drive the acquisition BOE cost down.

It's already quite a bit lower than the averages that we're seeing the marketplace. And we do think there's some potential out in this area. So -- but we don't have it specifically identified.

Now the field that's in Cocoran County, Texas is a water flood in the San Andrews. And there, what we're going to be looking at is principally and probably purely operational efficiencies.

And if we can apply some operational efficiencies as we have in Electra/Burkburnett, we might decide to keep that field.

If we see or feel like there's really not the operational efficiencies to be gained, we'll probably look at maybe disposing that. The asset -- as I said, 90% of the value is in Southeast New Mexico and only about 11% of it -- or 10.5% of it -- is in West Texas.

Our focus is really just those two fields in West Texas.

Okay. And then in the Barnett, just to clarify your answer to Leo and to answer my question. The $3 million AFE -- that related to the EOG wells, correct?

$3 million, yes. And the Devon wells that's in AFE at $3 million.

So the 1.8 includes earlier vintage wells that were cheaper.

Exactly. That's the average of all those wells that we have that's actual, factual numbers.

Okay. So on the $3 million AFE, is the expectation from a -- on the EOG acreage -- from a reserves and the initial production rate mimic that of what you've seen to date on the Devon acreage?

Yes, that's what we -- we think that's kind of indicative of this area within Wise County that we've looked at -- yes, 1.8 to 2.0 BCF kind of wells. And currently, they're costing about $3 million to drill and complete. Okay. Thank you guys.

(OPERATOR INSTRUCTIONS)

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

Yes, I had just a quick follow-up question for you guys, here. Curious to know if you guys have made any sort of additional well proposals above the four that have been accepted at this point by EOG.

And, kind of, whether or not you've gotten the chance to maybe sit down with these guys in a little more detail and maybe map out a plan for the rest of the year, in terms of growing on those properties?

Leo, we haven't proposed a fifth well, yet.

The land department has obviously been busy the last couple of week working on this acquisition, getting it buttoned up. But, we are working on doing the land work necessary to make the proposal. Our goal is to propose one a month this year.

We've shared that with EOG. We've not had a real "sit-down." We've had a lot of, what I'll call, staff-to-staff talk -- land department-to-land department, the geological group at EOG with our geological group.

And I think they know that what we propose to do and how we would propose to continue to make the well proposals for them. But we haven't "sit-down" and sort of hatched a plan.

We've just kind of said, "Guys, this is what we want to do this year. And we're going to do it." So it's working okay. And there doesn't seem to be any real headaches or hiccups with it.

It's just a -- I think they're not going to lead the parade. They're going to expect us to make the proposals to them. And we'll continue to do that.

Okay. Great. Thanks.

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

Just a follow-up on that. As long as you propose one well per month, then it remains a viable option to maintain a continuous one-rig program on that acreage.

That's what we're hoping to do, Ron. I think what our plan is, is we'd like to see one well proposal a month to kind of get this program going on a steady basis.

And as we get our '07 seismic program pulled together, then we'll be in a position to have the ability to escalate the well proposals, probably, beginning in late-'07 or early-'08.

So, that's why I think it's important to have 33 locations that we've currently identified that we could pick from, from a seismic standpoint and a geological standpoint.

And now we have to work the land situation to be able to actually propose those. I mean, it's a three-step process. So --?

With the land situation, is that permitting, is it rights-of-way, or is it just title work or all of them?

Ron, it's primarily title work and then also looking at the topography and identifying a surface location that you can propose the well on. That's one of the issues throughout the Barnett Shale area is surface locations to drill.

So in order -- we can't just say to EOG, "Hey guys, we want to drill a well out in section such-and-such, such-and-such."

I mean you have to specifically identify where you want to drill that well, what depth you want to take it to, and how far your lateral needs to be.

And there's a whole series of things that you have to have in that proposal. And you have to have your title work lined up, as well.

So that's kind of what we're working on now. See, we've got the scientific backlog. And now we're working on the land backlog so that we'll continue to be able to do this one-a-month this year with an eye towards increasing that proposal level next year.

Okay. And then on the production side, to clarify Monica's question. With the acquisition, you'll definitely show sequential growth?

Excluding the impact of the acquisition, were you still on track to be able to show at least some sequential growth?

Yes, we think so.

Okay. Great. Thank you.

I show no further questions in the queue. I would now like to turn the call over to Larry for closing remarks.

Well, I'd like to thank every one for taking time to join us today. And we feel like that the first quarter has set us up, and so far in the early part of the second quarter, has set us up to have a good second half of this year.

And we look forward to an increased CapEx budget and the results that come from that.

We're pleased with this acquisition. We think this is just one in a series of the way that RAM, over the 20-odd years, has been able to create value for its shareholders.

And so, we look forward to additional acquisitions of, sort of, this kind of style and magnitude. And we look forward to getting our CapEx drilling budget really cranked up.

And with that, I look forward to seeing all of you at the next conference or at the next conference call. Thank you very much.

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