Vital Energy Inc (VTLE) 2011 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the fourth-quarter and full-year Laredo Petroleum Holdings, Inc. earnings conference call. My name is Chanel, and I will be your operator for today. At this time all participants are in listen-only mode. We will be conducting a question and answer session after the financial and operations report. As a reminder, this conference is being recorded for replay purposes.

It is now my pleasure to introduce your host for today's event, Mr. Randy Foutch, Chairman and Chief Executive Officer. You may proceed, sir.

Good morning, everybody. Before we start I will let Joan say a few words.

Good morning. This conference call may contain forward-looking statements intended to be covered by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. For a detailed description of our disclaimer, see our press release issued yesterday and posted to our website as well as other public filings. Randy?

Thanks to everybody for joining. This is Laredo's first earnings call as a public company and we've got a lot to talk about. We are excited about telling our story over the next few days. We put out a lengthy earnings release last night which highlighted our results from last year, and this call, along with the review of our 2011 financial data. We are going to suggest where we go from here in terms of our focus, and particularly our view of the Laredo opportunity set in the Permian and Anadarko basins.

In addition to the earnings release and this call, we will be putting out a significant amount of data on Monday in conjunction with our scheduled presentation at the Howard Weil conference. This data will help complete the picture for those looking to model the Company, in terms of publically releasing more data, which will include maps, well economics and return data. So what that means, on this call, you may get referred to that to-be-released next Monday information in the Q&A today, if we don't cover it this morning.

One of the things that we will also talk about is that Laredo reports on two-stream basis rather than three-stream. And the value of our natural gas liquids are reported in the price we receive for our natural gas. I would like to back up for a minute and talk about how our Company finds itself at the forefront and leading on some of these opportunities in the Permian Basin, and describe how focused we have been on science as a private company.

Laredo ventured into the Permian in 2008, leasing approximately 4000 acres initially, and looking to analyze deep targets to drill horizontally. We began building a proprietary core database that led us to recognize the potential in the Cline shale, which kicked off our additional leasing efforts in late 2009 and early 2010. After our initial horizontal drilling program in the Cline, and more analysis of similar rock to the South, we've made the acquisition of Broad Oak Energy in mid-2011.

Today, our acreage position stands at around 135,000 net acres, with around 5800 identified potential drilling locations in the Permian Basin. Our petrophysical database now includes more than 2200 feet of whole core, covering multiple formations under our acreage; more than 400 sidewall core samples, covering multiple formations; over 8000 open whole logs and approximately 50 proprietary petrophysical logs. In 2011, we acquired an additional 150 square miles of license and proprietary 3-D data, and will soon add 290 square miles of additional 3-D in the Permian. This current program will bring our total seismic 3-D database to 760 square miles in the Permian.

Bottom line -- science in the collection and analysis of proprietary data is integral to how we approach this business at Laredo. Our work serves to identify early-entry opportunities. Then we work to continue to define and exploit these opportunities. At some point, when these plays transition from exploration to development drilling, the drilling program itself brings together the science, the needed data to optimize and make the most efficiency and economic results possible.

All of the plays we described in the press release, and that I will review in just a minute, follow the same pattern and are in various stages of exploration and development. We ourselves, as Laredo, generate a tremendous amount of proprietary data for a company our size. And we use that to get in to these productive areas, and our data then guides our decisions in terms of leasing, drilling and completing.

One very important way we have collected data is through our vertical Wolfberry drilling. The vertical Wolfberry is a bread-and-butter drilling program that has performed for us since our initial leasehold. We expect it will continue to be an important component of our drilling, and we are currently running eight vertical rigs drilling Wolfberry wells. We are constantly analyzing our mix of vertical versus horizontal wells, as referenced in yesterday's press release. These vertical wells are economic, and they supply our Company with a tremendous amount of data on emerging opportunities in other zones such as the Cline and Wolfcamp shales.

Our horizontal Cline shale program has, at least on part of our acreage, become a nicely contained, repeatable resource play. This is in the Glasscock County, principally. Keep in mind, the Cline is deeper than the Wolfcamp and will hold the shallower zones by production. We are expanding to different parts of our acreage where we have found similar core data, guided by our vertical Wolfberry drilling. We completed 26 horizontal wells to date in the Cline, more than any other operator. And we feel our proprietary petrophysical and seismic data across our acre position really puts us at an advantage for establishing an economic and repeatable drilling program in the Cline.

We are working on the optimization of lateral links from a land perspective and we are in the process of completing 3-D seismic over all of our acreage to assist us in expanding this drilling effort. We believe we will get the most economic well results with the longer lateral lengths. At just under 4000 feet in lateral length, and with 15-stage fracs -- which was our initial, early entry drilling and completion approach -- our average 30-day IP is just over 500 barrels of oil equivalent per day. And we have had at least one at almost 800 barrels of oil equivalent per day. We think our Cline horizontal drilling program will be a solid component of our plans going forward.

In the horizontal Wolfcamp program, it's really early, but our proprietary core single-zone testing in vertical wells and horizontal drilling data suggest that we do have an exciting program here in the upper Wolfcamp. We have not yet drilled horizontally in the middle or lower zones. We have completed six wells in the upper Wolfcamp, and five of those have 30 days of production or more. These wells are located in the central part of our acreage. The wells have been completed differently, again as part of our optimization. The first two were gel fracked, while on the last three we used slick water. Two had laterals less than 4000 feet, and three had laterals over 5000 feet, which, along with a higher frac density, allowed much more rock to be stimulated.

Our best well -- which we feel, so far, demonstrates the optimization approaches -- had a 30-day, two-stream IP of 949 barrels of oil per day. Keep in mind that we are talking 30-day and two-stream production. It's a slick water well, with the laterals almost 6000 feet, in 22 frac stages. This optimization program will continue. We are still doing a lot of science, and we will move forward in testing other parts of our acreage position. Clearly, we are optimistic that there's a lot of economic drilling to do in these zones.

Finally, our liquids-rich Anadarko Granite Wash success is a result, also, of early entry approaches similar to what we have done at Laredo. It was aided by the proprietary whole core data and vertical well control we were assembling over this acreage. To be sure, this is surgical drilling, but we love the rates return and feel most of the heavy lifting has been done with regards to defining the drilling targets themselves. We still consider this a Laredo core area, and will continue to exploit it alongside the more oily activities in the Permian Basin.

With that, I think I'll turn the call over to Mark Womble, CFO, for his comments.

Thanks, Randy. Thanks for joining us on the call today. In the press release that we issued yesterday after the market closed, we detailed various quarter-to-quarter data along with our full-year 2011 results. We believe that this gives our investors the most transparent picture of our operations and financial results. Please remember that all of our published numbers are reported on a combined Company basis to reflect our acquisition of Broad Oak Energy that was closed in July 2011. These data, along with the guidance information that we released in January for CapEx, production, and several operating expense items, combined with our upcoming presentation at Howard Weil next week that Randy mentioned, result in a lot of new information in the public realm for the first time on Laredo, its operations, and its financial strength.

As reported, we produced a total of 8.7 million barrels of oil equivalents during 2011, an average of 23,709 barrels of oil equivalent per day. The 2011 production was 39% crude oil and 61% liquids-rich natural gas. As Randy mentioned, we report everything on a two-stream basis, and include the value of our natural gas liquids in the natural gas stream. We generated a little over $500 million in revenues during 2011, which was more than double our combined revenues during 2010. Our net income was a little over $105 million, up 22% from $86 million in 2010.

Of course, our revenues were driven by the production growth that we had, but also by our healthy realized prices. Including our realized hedges, we averaged $88.62 a barrel and $6.67 per Mcf during 2011. We've continued to layer on additional hedges, particularly for oil. And you can see the most recently posted hedge update in the corporate presentation that is posted on our website.

Moving to reserves, it's important to discuss our reserve growth in the context of our liquidity and capitalization. We grew total proved reserves by 15% year over year. And proved developed reserves grew by a little more than 40% during 2011. Interestingly, if you look at just our proved developed oil reserves, they grew by over 90% during 2011.

All of our results are currently being evaluated by our commercial bank group. We have our semiannual bank meeting scheduled next week in order to re-determine our borrowing base under our $1 billion bank revolving credit facility. The borrowing base was last re-determined in October of 2011, and was set, at that time, at $712.5 million. We had a total of about $85 million drawn at year end, a little less than 12% of the available borrowing base.

With that, I will turn it back to Randy. And I will also be available to answer questions during the Q&A. Thank you.

Okay. Mark, thank you. Thanks very much. I think, at this time, we will open up the phone line for questions and answers.

(Operator instructions) Joe Allman, JPMorgan.

In terms of the Cline 30-day average IP rate that you gave, I think you said over 500 BOE per day. So that seems better than what you previously talked about it. Is my interpretation there correct?

What we are seeing there -- and that's based on principally 4000-foot laterals with 15-stage fracs, Joe -- and what we are seeing is, that as we work on this optimization, we are seeing early results that are better than we initially thought. Of course, the question is going to be, what's the results a year or two from now? So the 30-days IPs are, I think, a little better than we thought.

Okay, that's helpful. And then, in terms of cost, could you just talk about recent cost to drill and complete, for both the Cline and Wolfcamp horizontals?

We will show a lot of that detail specifically next week in that presentation. But costs in general, I think it's safe to say, is up about maybe 10%. We are still doing a lot of science, and we are doing some extensive testing. And we do have quite a database of high-dollar petrophysical logs. That adds to our cost some. But we anticipate, over the next year or so, getting all that science done and collected.

Got you. Okay, that's helpful. And then, right now you've got two rigs running for the Wolfcamp horizontal and the Cline horizontal. So do you have the same number of rigs for both plays? Is that an indication of feeling better about the Wolfcamp horizontal than you previously did, in terms of economics?

I think we view the economics that we've seen on both Cline and the Wolfcamp to date as pretty positive. Early data -- and we like what we are seeing. We've just got to, one, figure out how to really optimize the most economic way of drilling those wells and completing them. And then, two, we at some point have to figure out the extension of those plays on our acreage base, both laterally, over that 80-mile-long acreage play, but also test additional zones in the Wolfcamp and test the Cline on the rest of the acreage. So we're pretty optimistic where we are today. There's still a lot left to be done.

Gotcha. Okay. And then, lastly, with the vertical, the Wolfberry, you were at seven rigs at year end. I think your original plan was to go to 12 in 2012. Is that still the plan, to go to 12 rigs? Or is that just a work in process, trying to figure that out?

I think it's a work in process. As we get -- I think we are going to add rigs to the program through '12, within the same kind of capital budget we've talked about so far. But I think the ratio of vertical to horizontal rigs, Joe, we are still -- we look at that pretty frequently as we get data. And I think, we kind of think we will drill about like what we said. But we may drill more horizontals than we initionally thought.

David Tameron, Wells Fargo.

A question for you -- I guess, Randy, you guys mentioned the Cline wells. How many wells was in the dataset you mentioned, with the average IP of 500? And then, can you talk at all about the variability, as far as around that 500? Obviously, there's some that are always bad and some that are always good. Can you just talk about how much physical kind of variability around the number?

Yes. That number reflects somewhere around the 25-26 kind of number to date in the horizontal Cline. And when we release, Sunday night or Monday morning, whenever, at the presentation, we do talk and show a lot more data, David, about the variability. Part of the variability is the way we are trying to figure out how to optimize them. Because, keep in mind, we were in there early and spent a lot of time doing what would be considered a relatively short lateral today, 4000 feet.

We've seen one or two places where the Cline performance may not be as good as the average. In those places, on that acreage, we still have pretty exciting Wolfcamp and Wolfberry potentials. We will show all that, but we are not seeing the type of variability that would, I think, scare us or worry us a lot.

Okay. That's helpful And then Wolfcamp, just to verify -- you said that the two-stream IPs, you said the average 30-day production was 949; is that right?

That's on one well. And we really hesitate to talk about one well. But that's a two-stream number. It has -- it's a 30-day test. And the other wells that we are drilling, we have some that we are completing and have some production data on, that are not 30 days. And as you know, David, the flush productions sometimes is misleading. Sometimes a 30-day is misleading.

It's still a big number.

And I think that's the takeaway, is that the numbers in the Cline and in the Wolfcamp are meaningful, significant numbers.

Can you give us an approximate breakdown -- gas, oil for that?

Hang on just one second. As a matter of fact, David, I may come back to you on that.

Okay. Let me throw another question at you, because I'm a stubborn guy and I always ask the same questions. Infrastructure -- I know you said it always takes care of itself, over the long run. But can you give us just a snapshot of where you're at today -- what bottlenecks, if any? And are you flaring gas? Are you able to get your gas out? Can you just talk about what kind of bottlenecks you have out in the field, if any?

One of the things that we've done to address those bottlenecks is, as you know -- and we have said this a lot -- we spent, I think, $60 million, $58 million or so on infrastructure at the Company. And we do that purposely to try and have multiple take points. We've really -- we haven't had any issues with takeaway at all, other than our crude oil ready to be sold in the tanks at the leases. And we have really reduced that over the last 90 days or so. In the last week, it's up to about three days average production. So, so far, we are working on no real issues there. And we are trying to address what we do if the Wolfcamp and Cline are as good as we think they might be. We want to make sure that we stay in front of that infrastructure. On a 6-to-1 basis, David, back to your question, we are about 55% to 60% oil in those Cline -- in the Wolfcamp.

Okay. I'll let somebody -- I've got a few more, but I'll let somebody else jump on. Thanks. And congrats, again, on getting out and getting the IPO out there.

Richard Tullis, Capital One Southcoast.

Randy, are you able to provide your year-end exit rate production?

You know, we generally have talked in terms of averages for the quarter. And you can see our quarterly average production rates in the press release that we issued. For the fourth quarter, we were a little over 26,000 BOE per day compared to the 23,709 for the full year. So it continues to build at a pretty good clip.

So, you've given guidance for the full year at this point. What do you expect, production-growth-wise, in the first-quarter?

We are talking about production for the full year being up on a 25% annual growth rate. And we are very comfortable with that guidance.

So it represents, I guess, about 8% or 9% growth over Q4 2011. How do you feel about upside to your guidance at this point?

We don't provide any color on that. We like to give it on an annual basis. You've got to realize, on the kind of wells that we are drilling, they have a lot of flush production. And any one day they could be up or down. But we're just saying we are comfortable, on a year-to-year, of that 25% growth target.

Looking at the expenses for Q4 versus the guidance, I imagine you probably had some one-time expenses, still, related to maybe the takeover of Broad Oak properties. Are you still looking for the guidance on an expense basis -- LOE, G&A and such -- that you put out in January?

Absolutely. We will reaffirm those guidance numbers. We did have some kick ups one one-time events in the fourth quarter. But we are comfortable with our year-to-year.

I think that's all I had right now. If I have anything else, I'll jump back in the queue.

Pavan Hoskote, Goldman Sachs.

I had a question on the Cline shale and Wolfcamp shale. You have lastly been focused on Cline shale drilling on the northern portion of your acreage. Recognizing that it still very early, what is the level of confidence that you have that the play extends further to the south? Similarly, at the Wolfcamp shale, how confident are you that the play extends to the north?

We are going to talk, about in the release and presentation, some of our core data and some of the vertical well single-zone testing we've done. And we have a lot of enthusiasm that we need to get on with determining whether or not the Cline extends to the southern parts. Similarly, we have a lot of enthusiasm with the Wolfberry all across the acreage. The issue, in our view, on the Cline, is we need to finish the 3-D that we are currently shooting -- proprietary 3-D -- because I think that will help us. And we know that that helps us with our Cline horizontal drilling.

On the Wolfcamp drilling to the north, that's not University lands. And we are going to have to do some work on some lease issues to get the long lateral lengths that we think we need to drill there. And we are rapidly getting that behind us. So the answer to your question is, I think it's going to take us some time to really push the Cline knowledge across that entire 80-mile by 20-mile acreage base, and take us some time to understand fully the Wolfcamp. But the data we have to date is pretty enthusiastic.

David Tameron, Wells Fargo.

You guys had some -- I guess you deemed exploratory acreage -- but Dalhart, Anadarko Basin; and I believe you had some other Panhandle, if I remember correctly. Can you guys -- any update there? There's been a lot of different things in the industry going on in all kinds of different places. But any update you can give us on any of those plays?

Not that's meaningful. Part of that acreage is dry gas, and we are not putting any capital on it. The Dalhart, we did spend some capital, and we've got some early results, and we're waiting on lots of interpretation. But I don't think there's anything meaningful going on there.

Jeb Bachmann, Howard Weil.

Just had quick question, and I might have missed this, on the Granite Wash. Just wondering if you had any update on the recent horizontal activity there, if that has been better than your IP rates that you talked about previously. And then also, follow up on -- if costs, if you have seen any kind of increase in cost there as well.

We are still running three horizontal rigs in the Granite Wash, and occasionally a vertical rig in and out. We are actually excited what we are seeing there. The drilling is sometimes a little tricky if we take a lot of gas kicks in the horizontal portion of the wells. But we think what we've talked about is pretty much on track. We will have a little more data on that coming out, that we're pretty comfortable there. Cost in the Granite Wash have been almost flat. As you know, there is cost pressure everywhere, but we have not seen a lot of increasing cost pressure there.

Appreciate the call, looking forward to next week, everyone.

Joe Allman, JPMorgan.

Mark, in terms of those one-time adjustments you had to make for LOE and DD&A in the fourth quarter, could you just give us some more details on that?

Yes. You will notice that the LOE kicked up in the fourth quarter, and that was due to some work over cost that we had. It's nonrecurring in nature. We are still very comfortable with the $5 metric, $4.75 to $5.25, that we gave guidance on, on the LOE. On the DD&A, we did a lot of drilling of PUDs last year. And you know what that does to your finding cost and, consequently, your DD&A. We came in -- in the fourth quarter, we came in less than 5% off on our anticipated reserves and within 10% of the AFE. So we are pretty satisfied with the way that we ended up the year there. And we think this year will be right in the middle of the guidance that we gave.

So, in 2012, you expect to be drilling, as a percentage, fewer PUDs than you drilled in 2011?

No, I didn't say that. I just said we drilled more PUDs in '11 than we have ever drilled before.

And Joe, I think our view -- just to expand on that just a little bit -- is we have done a tremendous amount of proprietary science. It's not cheap to get 2200 feet of whole cores and do all the work we do with them. Those single-zone testing in the vertical wells add up, and drilling the PUDs. But as we expand in attempting to drill, broaden that Cline horizontal and Wolfcamp horizontal, those are obviously not PUD locations. So when we look at this, we're pretty comfortable with our guidance going forward.

Okay. That's very helpful. And just in terms of service costs, so I understand you're doing a lot of science in your horizontal drilling. But in terms of rig day rates and completion costs and whatnot, are you seeing those costs flattening or declining? Or are you seeing them going up? I heard your comments on the Granite Wash and you're generally flat there, but specifically in the Permian.

I think we view the Permian as slight increase, kind of across the board, although there is some variation. The service companies do a pretty good job of fixing supply shortages, from their perspective. And we are not quite in balance, but I think we are basically getting lots and lots of service companies to focus on that area. Over time, I just think costs will go up. The question is, do we get more efficient to offset that? And that will be the look that we need to make going forward.

Dan Morrison, Global Hunter.

A couple of quickies -- the use of 3-D in the Cline -- what are you actually imaging there? Is it natural fracturing trends you are trying to honor or exploit? Or trying to image porosity or structure significant element? Can you kind of shed a little color on that?

We've drill a lot of Cline wells, I think. And what we do with our 3-D is we do look for a lot of the attributes you just mentioned, in terms of fracture analysis and that type of stuff. We really do shoot very, very high-quality, high-resolution 3-D. So we are able to use that for some internal reservoir attribute work. Our Cline -- we have learned that we really need to kind of pay attention to where we land the horizontal. And we need to stay in zone very carefully there. And that structural component of the 3-D has been very, very helpful to us. And we have seen that, without the 3-D, we can make mistakes. So we use it both structurally, for faulting or other things to land the Cline; but we also use it for lots of attributes on reservoir geometry and modeling.

Are you steering the wells, or just more conventional directional tools?

We are steering the Cline pretty tight.

And then -- I know you said you would reveal a lot more with your upcoming presentation, but are you still pretty limited so far to activity in Glasscock and Reagan Counties? Or have you leaked outside of those counties much?

We've stayed within that -- pretty much that trend there. The vertical drilling runs, basically, from the north part of the 80-mile-long trend to the South. The Cline and the Wolfcamp horizontal has been kind of concentrated in the central part. We are starting to drill Cline north and also further south, and we are expanding the Wolfcamp as we can. So we have not jumped out very far from that core acreage position, where we have significant vertical control and significant whole core proprietary data.

Nathan Churchill, Societe Generale.

Just on the Cline, I'm wondering if you could help us understand these 4000-foot laterals and 15-stage fracs that you're averaging. How closely do you think that has got you dialed into what you might consider optimal? Are we kind of well on that path? Is there quite a bit more room to run, based on what you're seeing?

We started in the Cline well over two years ago with that as the model, 4000-foot. We actually had some that we did 10-stage fracs, and we have migrated to the 15-stages over the last year. I don't think that's the optimal length or number for fracs stages at all, based on what we've seen on some recent data that we will, at some point, get enough confidence in that we can talk about it. So I don't think we've optimized yet the lateral length or the frac stages. What we are seeing is more lateral translates into higher IPs; more fracs stages translates into higher IPs, which is kind of obvious. But the question is, are those really better economics? We think so, Nathan. But we are not ready to pound the table. I would expect us to lead us toward longer laterals and more stages.

Okay, and that one well that you had -- greater than 800 BOEs a day -- was that also a similar kind of 4000-foot-ish and 15-stage? Or did you tweak that one up little bit more?

I think we are tweaking all of the ones that we are drilling over the last year or so. Either in more stages -- we have not yet gotten very many with longer laterals.

I see. And was that a more recent well?

Yes.

There are no further questions. I would now like to turn the call back over to your CEO, Mr. Randy Foutch.

We very much appreciate the time you have given us today. We are excited about this story. Thanks very, very much for participating the call. Thank you.

Ladies and gentlemen, that concludes the presentation. Thank you for your participation. You may now disconnect. Have a great day.