Battalion Oil Corp (BATL) 2010 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the fourth-quarter 2010 RAM Energy Resources, Incorporated, earnings conference call. At this time all participants are in a 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 will now turn the presentation over to your host for today's call, to Bob Phaneuf, Vice President of Corporate Development. You may proceed.

Thank you, and thanks to all of you for joining us on the RAM call this morning. Today with us we have Larry Lee, our CEO; Les Austin, our Senior VP and CFO; Larry Rampey, our Senior Vice President of Operations; Drake Smiley, our Senior VP of Land and Exploration; Sabrina Gicaletto, our VP of Finance; and Manny Redifer, our VP of Exploration.

Our agenda today for the call is we are going to have a brief overview of 2010 activity by Larry Lee. He is going to turn it over to Les to talk about the details of our refinancing, the benefits it provides to our business plan, financial highlights, and guidance. Then we will turn it back to Larry to have an update on our activity, especially our Osage exploration project.

Before we get under way, let me read a few comments about our Safe Harbor statement. On our call today, we are going to make statements that are other than historical facts and information in the dialogue, Q&A, and all such statements that refer to management plans or expectations including, but not limited to, estimates of timing and completion of planned development, exploration activity, general capital spending, assumed hydrocarbon pricing, and our guidance, derivative positions, interest expense, G&A, and other industry conditions are considered forward-looking statements within the meaning of the Securities and Exchange Act. 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. So further information on these risk factors are included in the press releases and in the Company's filings with the SEC. We encourage you to review the disclosure in both of these documents.

That being said I will turn it over to Larry Lee for the overview.

Thank you, Bob, and good morning to everyone. As everyone knows, in the middle of last year we instituted a strategic review; and what came out of that review was our goal to reduce our debt. We targeted to reduce that below $200 million, which we were able to accomplish.

We did that by selling our nonstrategic natural gas nonoperated assets, and then refinanced our debt. We were pleased to announce yesterday that we completed that final step in the strategic review process. Les will get into more detail on the refinancing as well as some other things, and then -- so when he gets finished up I will give everybody an update on where we think we are here in the first quarter and also what is going on in Osage and also in our enhanced oil operation in our major oil fields.

So with that, I am going to quickly turn it to Les so we can get through 2010 and some of that stuff and come back to operational update. Les?

Thanks, Larry. First of all, I would like to update a few financial highlights. For the year, our revenue was up 13% to $111 million versus the $98.2 million in 2009, driven primarily by a 33% higher commodity price deck in the current year versus last year. Our cost-containment initiatives drove our production expenses 10% lower in 2010, and our G&A expenses were 11% lower in 2010.

Reported net income for the year was $2.4 million in 2010 versus a $58.4 million loss in 2009. Our free cash flow for the year was $32.6 million, which fully funded our development and exploratory CapEx of $32.4 million for the year.

The asset sales of $51.7 million before closing adjustments that we executed in December of this year helped reduce our bank debt to $196.7 million at year-end, which also reduce the Company's leverage ratio to 3.87 times at year-end.

For the fourth quarter, revenues were $27.5 million versus $29.7 million in the year-ago quarter. Cost and production expenses and G&A expenses in aggregate were relatively flat in this year's fourth quarter versus last year's fourth quarter.

Interest expense in the current year fourth quarter decreased $300,000 or about 5% of last year's fourth quarter due primarily to the asset sales that we had in December of this year. There was one unusual item in the fourth quarter of this year, a $2.4 million realized derivative loss that we incurred as a result of our risk-adjusted modifications to the hedge portfolio now that our mix of commodities is more liquids, oil and gas liquids related.

On the new credit facility, we entered into a $250 million first lien revolving credit facility led by SunTrust Bank as administrative agent and Capital One as syndication agent. Other participating banks included Societe Generale, Regions Bank, CIT Bank, and Citibank. The initial borrowing base on the revolving credit facility was set at $150 million. The interest rate was initially set at LIBOR plus 3.25% and can range from LIBOR plus 2.5% to LIBOR plus 3.25% based on borrowings outstanding at the time. The maturity was set at five years from the closing date of 3/15/2011.

We also entered into a $75 million second lien term loan facility led by Guggenheim Corporate Funding as the administrative agent. There is no amortization on the $75 million term loan. Its term is 5.5 years from the closing date of 3/15/2011. The interest rate on the term loan was set at LIBOR plus 9% with a 2% LIBOR floor, or an effective rate of 11%, with make-whole provisions of 103 in year 1, 102 in year 2, and 101 in year 3. The Company has a $25 million clawback option in year 1 that allows the debt to be repaid with no prepayment penalty for certain asset sales or equity issuances.

RAM anticipates that its blended interest rate will be approximately 7% for the balance of the year versus the 8% blended rate that we had in 2010. This blended rate should reduce our cash interest expense by approximately $1.3 million for the balance of the year based on our current business plan.

The guidance that we had previously issued -- the Company is not making any current adjustments to that guidance and will not until the first-quarter results are finalized. Just to reiterate, our previous guidance was production of 1.7 to 1.8 million barrels of oil equivalent; EBITDA of $52 million to $55 million; capital expenditures of $35 million; and interest expense of $14 million to $15 million.

I will note that this guidance was based on NYMEX strip prices at the end of the year, which had an average oil price of approximately $87 a barrel, an average gas price of approximately $4.75 per Mcf, and an average NGL price of approximately $56 a barrel. This guidance was also based on the credit facilities as refinanced, assuming that they would be refinanced in March.

With that, I will turn the call back over to Larry.

Thank you, Les. I would speak briefly to the first quarter. As most of you know, we had very, very severe weather in Oklahoma and in Texas for a little over a two-week period in February. So we think that is going to result in us coming in at the lower end of our guidance for the first quarter; but we think our guidance numbers for the full year are still very achievable.

As Les said, our forecasts were based on a much lower particularly oil price. So with the higher oil price that we have been receiving in the first quarter and our hedge protection that we had on our natural gas at the $5 level, we think that the revenue dollars will compensate for us coming in at the lower end of our production guidance in Q1. And we think we will be able to begin to grow that as we move through the balance of the year.

I would just reiterate, we set a target capital program for 2011 of $35 million. $18 million of that was for development and exploitation; and we allocated $9 million to our exploratory program; and then we had $8 million for geophysical, geological, seismic, and additional lease acquisition for the year. We are still sticking with that capital program, and we have begun implementing it according to our plan.

Let me give you a quick update on what is going on in Osage, because I know this is a focus area with all that's going on in the Mississippi oil play and the North-central Oklahoma and Southern Kansas. In the first quarter, we drilled our first saltwater disposal well, which is necessary for us to have so that we can then begin fracking the wells that we are drilling up there so we can dispose of both the frac fluid as well as the produced water.

We did drill that; we got a very good-looking section of Arbuckle, and so we've got a very fine disposal well. It is completed, and we are in the process of hooking in the wells around it so that we can dispose into it.

We also drilled the Farmland 1-16 in the first quarter. That was planned as we had discussed.

We were delayed on our seismic program because of the weather. We originally had hoped to have the second phase of the seismic shoot, which covers 19,000 acres, well underway by now. But the weather issues caused a delay.

The survey is set to begin at the end of this month. The thumper trucks are scheduled to be on location in mid-April. So there is a small delay there, not a significant delay.

We also have our first two frac dates scheduled. They will be -- hopefully they're scheduled to show up right at the end of the second quarter and the beginning of the first quarter. So we should have -- we are really looking forward to those early fracs on some of these wells.

Also, we have two rigs under contract at this point. The first rig is scheduled to show up right around the end of March to drill two wells for us. The second rig is contracted to show up about mid to late April and drill two more wells for us.

These are the four wells that we had forecast to be drilled in Q2, so we are being able to get rigs under contract and get those drilled earlier than we had originally hoped. So we are pleased with the progress that we are making. We are looking forward to, as I said, the second seismic shoot and the continued drilling up in our Osage concession.

Briefly, I had talked about and we have about $4 million in this year's budget; it is within the $18 million of development and exploitation, where we have been working on some EOR projects within our major oil fields. I am pleased to report that we are beginning to see some real progress on those.

The W. R. Piper lease in North Texas, the lease where we were changing up the injection pattern and adding some additional injection wells and producers, and we have taken that lease from roughly about 60 barrels a day. It is now up around 90 to 100, and we are still working on that. So we are seeing response on that.

Also, on the Waggoner A-NCT number 3 lease, once again we have been working on that one as far as the water patterns there. We have gone from about 50 barrels a day that we were producing in there, in that lease, like middle of last year; and we are getting it up into that 90 barrel a day to 100 barrel a day kind of stuff.

So we will begin to talk a little bit more about that when we are at the IPAA conference in New York in early April. But we are pleased to be able to point out some success coming from the EOR investment dollars that we have budgeted for this year.

With that, Bob, I think we can take it turn it over and take Q&A. So, operator?

(Operator Instructions)

Operator, it looks like from our screen we have a couple of people in the queue, Chad Mabry, Ron Mills, and [Kyle Rhodes]. Are they not coming through?

Chad Mabry, Rodman & Renshaw.

Thanks, good morning. Hey, guys, just wondering if you could give us an update on kind of what production is running from the mature oilfields following the winter outages? I think the last update that we saw was about 2,300 barrels a day. I think that was November.

Chad, they are back up to about 2,500 barrels a day. They have come back up from that downturn that we had in there. They are about 2,500 barrels a day right now and we think that we can continue to add a little bit to that.

Okay, fantastic. Then I guess one follow-up. Could you provide a breakdown on the reserves as far as the revisions that you guys saw as far as performance price related? Any I guess PUDs that you might have lost to the five-year rule? Any color there?

Yes, Chad, this is Les. We will be releasing our 10-K later on today; and in there, there is an explanation of the reserve reconciliation. Obviously, you are aware of the 545,000 barrels of oil equivalent that we added through extensions and discoveries. We had 4.6 million barrels that we lost through sales. 2.2 million barrels that we lost through production.

And the revision -- the previous estimates was the 3.3. That 3.3 was a positive impact. We had a 1.8 million barrel increase due to pricing. We had a 1.1 million barrel downward revision due to the transfer of proved undeveloped properties to P2, P3. That would be your five-year rule, if you are asking.

And then we had 4 million barrels of downward revision due mostly to well performance in our gas properties in South Texas.

Okay, that is very helpful. I will get back in queue. Thank you.

Ron Mills, Johnson Rice.

Good morning, guys. On Osage, Larry, can you walk through again the expected cost and recoverabilities? Based on data that you have seen from the Mississippian Chat in other areas, what kind of spacing could you envision?

Then the follow-on to that is how much of your acreage -- I know you are shooting a second set of seismic and presumably will shoot a third at a later date. When you look at prospectivity -- out of the first shoot about a third was prospective. Is that kind of the right ratio that we should expect going forward?

Ron, we think of the current 15,000 acres, the first shoot, we think somewhere between a third and 40% of that is prospective for what we are looking for. We are basically looking for a porosity signature on our seismic; that is how I get to that number.

We expect the second shoot to be every bit as good as that. In fact, geologists think we might be even moving into a little bit better hunting ground with the second 19,000 square shoot.

Let me go back and recast how we got into that and what the information is. We went and looked at 700-plus wells immediately around -- and some of them were actually in -- our concession, that were Mississippian completions. They are listed Mississippi Chat, but there could be a few solids in there.

But what those 700 wells did, when you normalized the curve, it came out with an initial start rate of 7 barrels a day and they recover 36,000 barrels of total EUR. That is on about a 10-acre spacing, is what we think it is. So that is the numbers that we used to run our economics when we decided to get the concession, invest in the shoot, invest in the drilling, etc. etc.

The key to it is, one, a producing well will hold a 160-acre quarter section under our agreement. So, obviously, if -- what our plan is, as you can look at the map that we had in our IPAA presentation in February and it is on the website, you can see where we are planning on drilling in the current 15,000 square mile shoot this year.

What we are trying to do is confirm our seismic interpretation. So far the wells we have drilled have done that, and they have continued to confirm our seismic interpretation.

Then we will come back at a later date and begin to do the development drilling around that; or in the alternative, consider horizontal drilling. But right now our plan is to drill as much of this as we can on a vertical basis, at a very modest cost, and get this acreage HBP-ed while we still have plenty of time under our concession to do so.

The vertical cost to drill these wells have been costing us about $350,000. I think on one of them we may have spent as much as $400,000, but that is when we did some coring; and we also have frac jobs scheduled in that number. We think once we get into, quote, development mode in this play, that these wells can be drilled for about $250,000.

In fact, we are already have been evaluating the cost to construct our own rig versus buying an existing rig and replicating what we have done in North Texas in the past. If the play continues to evolve the way we hope it does, that would probably be our plan, is to get our own rig and not have the rig availability issues going forward. Is that responsive?

Absolutely. Just to clarify, when you talked about frac dates I think you mentioned -- earlier you said late second quarter, but then also late first quarter. Do you have the frac dates for the next two wells lined up for late March, early April, or is --?

Yes, the first two are lined up for late March and early April. I am always -- you know how with frac guys, I am always afraid to give exact date. But the date that is currently on the schedule with these guys for the first frac is right at the end of the month; and then the second frac is within the first two weeks of April.

So we think we will have those. And what I am hoping is that we will have that information available to share with the market by the time we are up at the IPAA in April.

Okay, let me get out of queue and jump right back in.

(Operator Instructions) Ron Mills, Johnson Rice.

Guess I'll keep going. Just in terms of your --

Ron, one thing I didn't say, and let me just put it -- the first well up there really was what we call our significant discovery well, the Surber. I said that the average of all those wells came in at 7 barrels and recover 36,000 barrels. Surber came in naturally with just an acid job at -- I think it was 84 or 85 barrels. And that well is still producing without a frac job in the mid-20 barrels.

So we are hoping we're going to find more of those, obviously, with how we are going about this project.

That kind of leads into what I was about to ask. You can see on your map where the saltwater disposal well was drilled, and presumably you can tie in a number of your vertical wells.

How do you plan on staying ahead from a saltwater disposal well standpoint as you move in a Northwesterly division and begin testing some of the new acreage in terms of the new -- I mean, I'm sorry. As you move both directions really; how are you going to plan your saltwater disposal versus your drilling programs?

Here is what our plan is, and we have kind of learned this. We get our permitting from the Osage Nation and then we also get it approved by the BIA, the Bureau of Indian Affairs. That process moves really pretty briskly.

Now there is a lot of activity in Osage. So it is just sort of the normal dealing with bureaucrats as far as getting the approvals. But those things go pretty smoothly.

The disposal wells have to go through those two regulatory hurdles, but then they also have to go to the EPA office in Dallas. That hasn't been a problem; it just takes a little longer.

So what our plan is moving forward -- is when we permit these wells, as you look at the map in our presentation, which is on page 13 of our website, in the stuff we did in February, we are going to file for permits for saltwater disposal wells essentially at the same time as we file for permits to drill the wells. So that if we continue to see the success, then we will come right in behind that and we drill the saltwater wells.

As you well know from conversations -- I am sure you have heard from Eagle and from SandRidge and maybe to a lesser extent from Chesapeake -- but drilling saltwater wells is an integral component of how we will develop this Mississippi oil play up here. So we are planning for that, and that is another reason for us to move towards maybe having our own rig up here, so that as soon as those saltwater wells get approved we can get those drilled very quickly. Then that allows us to then come back in, begin to do some development work in and around those initial drill sites.

Looking ahead just six to nine months, you will end up drilling another four to seven wells over that time frame alone. What are some of the decision points and information you will need along the way to determine how much to potentially accelerate the play and/or even begin testing some horizontal activity? Though the more shallow depth I guess would somewhat limit the lateral length. But what are some of the buttons to watch for over the next six to nine months?

I think the thing to watch for is if we -- as you can tell, we are accelerating the pace at which we are doing this. In other words, we are going to get these four wells that we had scheduled for -- excuse me. We had three wells scheduled for Q2, but we are going to actually get four wells drilled.

We have got four wells contracted, and we are going to get those drilled early in the second quarter. We are continuing to be in discussions with our rig contractors about when they can come back, because all 11 of these wells we have decided we are going to drill this year. So to the extent we can get them drilled earlier than we had previously planned, we are going to do that.

That will help us identify this program. So I would say that is the thing I would watch for.

And then the seismic program on the second phase, we probably won't have that processed and available to us until summertime, Manny? Yes, late summer, early fall Manny is telling me, the VP of Exploration.

So our activity this year is going to be focused on this Phase 1 shoot. We will keep the market posted as we begin to get these wells drilled and know what we have got.

One thing, too, Ron, and I hope -- I am not differentiating between our play and what is going on further West in Oklahoma. The Mississippi play out in Western Oklahoma is about 50% condensate and natural gas liquids, and about 50% gas. In our play, we may get some casing head gas, but it's essentially an oil play. We're going to get almost all of our volumes I think out of the oil.

Great. Just one last for Les. With the new credit facility, what is the current outstanding portion on the credit facility portion? I am assuming what ended up happening is your credit facility now stands at between $121 million, $122 million drawn, with $75 million out on the term loan. Is that fair? I'm just trying to get the split between the two pieces.

No, we haven't released that information because it is moving around based on where we are in the month. But we will put it out when we get to the end of March. We are 15 days away from telling you what our end of the first quarter balances are.

Okay. All right, guys. Thank you very much.

Kyle Rhodes, RBC.

I wonder if you guys can provide a quick update on South Texas. You guys don't have a backlog down there? Or what is the size of that?

We still have a backlog down there. Essentially all of it is held by production. And, Kyle, given gas prices for one thing and the continued tightness in frac crews in South Texas -- because of what is going on in the Eagle Ford -- we really haven't forecast spending much money in South Texas this year.

Now, depending upon what is happening in world events and if we began to see some improvement in natural gas prices, we would certainly revisit that. But we basically have said South Texas is HBP-ed, and let's just wait until we see a higher gas price before we start aggressively drilling down there again.

Okay, great guys. That's it for me. Thanks.

At this time there are no other questions in the queue. I would like to turn the call over to Mr. Larry Lee, Chairman and Chief Executive Officer.

Well, I want to thank everyone for joining us. I hope you can sense some of the enthusiasm that we have here at the Company.

We feel like that we set about accomplishing some things, getting our debt down to a very manageable level, getting it refinanced, getting our portfolio much oilier.

I love the fact everyone wants to talk about how oily their portfolio is getting. Well over 55% of our daily production is oil, and then you've got another 10% or 12% of natural gas liquids there. So we are where most people would like to be.

We are very excited about some of our EOR projects. While those aren't big, at $100 oil they make an impact.

And we continue to be excited moving forward on our Osage concession. So with that, I thank everyone for taking time to join us and we will look forward to visiting with you again. Thank you.

Ladies and gentlemen, thank you all for your participation in today's conference call. This concludes the presentation and you may now disconnect.