Vital Energy Inc (VTLE) 2012 Q2 法說會逐字稿

Good day, ladies and gentlemen and welcome to the second quarter 2012 Laredo Petroleum Holdings, Inc. earnings conference call. My name is Tahitia, and I will be your operator today. (Operator Instructions). It is now my pleasure to introduce Mr. Rick Buterbaugh,Senior Vice President of Investor Relations. Please proceed.

Thank you, Tahitia and good morning. It is a pleasure to be you with again as part of the Laredo team where I believe the Company has put together a very attractive acreage position in one of the most prolific regions in the country. This acreage offers an extensive inventory of identified proven projects with solid economics that we believe can support double-digit growth for multiple years to come. With me today are Randy Foutch, Chairman and Chief Executive Officer, Jerry Schuyler, President and Chief Operating Officer and Mark Womble, Senior Vice President and Chief Financial Officer as well as additional members of our management team.

Before we begin this morning, let me remind you that during today's call we will be making Forward-looking statements. These statements including those describing our beliefs, goals, expectations, forecast an assumptions are intended to be covered by the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. The Company's actual results may differ from these Forward-looking statements for a variety of reasons, many of which are beyond our control.

Additional information concerning certain risks and uncertainties relating to our business, prospects, and results are available in the Company's filings with the Securities and Exchange Commission. Also as a reminder, Laredo reports operating and financial results on a two-stream basis. That includes the volumes and values of natural gas liquids in our gas stream not as part of oil and condensate nor is it included in a combined liquids total.

Although two-stream reporting does understate our production volumes by approximately 20% relative to companies that report on a three-stream basis, we believe this accurately portrays our ownership of these products. As a result, Laredo's unit cost metrics will appear higher when compared to companies that report on a three-stream basis. However, the true economic value is the same. I will now turn the call over to Randy Foutch, Chairman and Chief Executive Officer of Laredo.

Thanks, Rick and good morning everyone. I am going to begin by providing some color on some of the highlights for the second quarterwhich begins with Laredo achieving record production volumes totaling 31,385 barrels of oil equivalent per day. This is up 36% year-over-year, up 12% sequentially from the first quarter of the year.

The second quarter production growth was fueled by a 44% year-over-year increase in our crude oil and condensate production which was driven by focusing the majority of our development drilling on the oil rich formations in the Permian Basin. By concentrating on these activities, we have increased the mix of crude oil as a percentage of our total production to 41% during the second quarter, and we expect this percentage to increase as we continue development of the Permian assets.

Laredo has provided annual production growth guidance with the understanding that interim quarterly production growth will likely come in a stair-step fashion. Our second quarter was indeed very strong, and we believe we remain on track to achieve our total targeted production for the year of more than 11.2 million barrels of oil equivalent.

As an independent producer, we believe it is our job to proactively manage fluctuations in prices, and Laredo takes an aggressive approach to do just that by maintaining an active hedging program. As you are all very aware, the industry continues to experience fluctuating commodity market prices. Most recently pricing of natural gases has declined more than 40% during the past year, and the value of natural gas liquids has declined more than 22% from their first quarter amount.

As a result of our actively managed hedging program, much of the value of our increased production was protected, despite dramatically lower average prices for natural gas and natural gas liquids. Moving on to operations, we believe that as a Company we have just scratched the surface regarding our opportunities set in the Permian Basin. During the second quarter, we continued to progress our knowledge base of the initial four identified stack plays consisting of the upper, middle and lower Wolfcamp and the Cline formation.

Our corporate goals are to reach the inflection points for each of these formations to be able to fully quantify their ultimate resource potential, determine the most efficient cost effective plan for full scale development of the entire acreage position, and truly maximize the value for our shareholders. During this process, we also expect to test other known formations such as the Strawn, Atoka, and Fusselman as well.

To date, Laredo has been successfully drilling vertical Wolfberry and horizontal upper Wolfcamp and Cline wells. We have begun testing longer laterals and increasing the frac density to further enhance our economics in these formations and maximize their value. After extensive core evaluations and vertical production tests, we have recently begun our first horizon drilling activity in the middle and lower Wolfcamp formations.

Our entire Permian program is still in the evaluation phase, and we still additional work to do, but our team is working diligently to fully grasp the potential that exist in all four of the stack zones that we have identified in the Permian. I will turn the call over today now to Jerry Schuyler, President and COO to discuss a few details on the operating results.

Thanks, Randy, and good morning everyone. As anticipated, our production volumes continued to grow during the second quarter. We were up nearly 3400 barrels of oil equivalent per day or about 12% as Randy mentioned from the first quarter of 2012.

Also, as Randy noted, much of our production increase came from our focus on the oil rich Permian Basin, and we expect to continue to focus activities in our Permian asset area during the second half of the year. As you all know, we do not give quarterly guidance, but with our second quarter being as strong as it was and with us encountering some minor pipeline infrastructure constraints in July and early August that we are correcting in the Garden City area, we expect a much lower growth rate in Q3.

Also as Randy mentioned, this stair-step type growth remains inline with our previous annual production guidance of approximately 30% annual production growth for 2012 resulting in total volumes for the year greater than 11.2 million barrels of oil equivalent. As we have mentioned before, we have begun drilling longer laterals in the upper Wolfcamp and Cline formations in the Permian. We believe that over the long run these longer laterals should provide us more efficient development of our acreage by minimizing the footprint of the leasehold, reducing the operating costs, and reducing the unit F&D cost.

In the upper Wolfcamp we have completed 12 horizontal wells to date. Five of these wells have lateral lengths of 6,000 feet or greater, and the results to date are inline with our expectations. As disclosed in our press release this morning, we have recently drilled our first middle Wolfcamp horizontal, and we are in the process of completing it as we speak. We have also begun drilling our first lower Wolfcamp horizontal well. And we are in the lateral as we speak.

Since we began activities in the Cline formation in 2009, we have drilled and completed a total of 31 horizontal Cline wells. Most recent one is actually approximately 7,000 feet laterally. This is our longest lateral horizontal Cline test to date.

We continue to gain confidence in the quality of this formation and the confirmation of our models. To round out our activity summary, we continue to operate three rigs drilling horizontal wells in the Granite Wash and the development program there continues to meet our expectations. For our overall drilling program for the rest of 2012, we anticipate utilizing 13 to 14 rigs, three horizontal rigs in the Granite Wash, and 10 to 11 rigs operating in the Permian with four or five of those rigs drilling horizontal wells. Science also continues to be a critical part of our ongoing exploration and exploitation efforts.

In addition to our already extensive technical database of cores petrophysical analyses and all the vertical wells zone testing, et cetera, that we have, we have recently also completed shooting an additional 283 square miles of 3-D in the southern portion of our Permian acreage in Glasscock and Reagan counties. With the completion of this high-quality seismic program, our total 3-D coverage is around 750 square miles in the Permian Basin. With that, I will turn the call over to Mark Womble, our CFO.

Thanks, Jerry. The combined impact of the production growth that we have detailed along with our strong hedge position and our continued focus on reducing unit cash costs contributed to adjusted EBITDA of $113.9 million for the second quarter which is up 13% from the year-ago quarter. We had some encouraging improvements in cash operating metrics during the quarter.

If you look at the total of lease operating expenses, production taxes and G&A expenses in aggregate, they total $12.18 per barrel of oil equivalent during the second quarter which is a per unit decrease of about 9% from the second quarter of 2011 and about a 20% per unit decrease from the first quarter of 2012. Our noncash charges for DD&A increased due to higher production volumes and were up slightly on a BOE basis primarily due to just higher depletion rates.

During the second quarter , Laredo invested $233 million in total CapEx with right at $200 million of that in drilling and 80% -- 87% of that total was in the Permian Basin. So we continue to concentrate there. We continue to add targeted acreage in and around our core area. We had a total of 404,000 net acres at quarter-end.

We are still on track for our announced total CapEx budget of approximately $900 million for 2012 activity not including acquisitions. At the end of the quarter, we had nothing borrowed under our bank revolving credit facility, and we had about $146 million of cash on hand. This results in total liquidity of about $930 million if you add our cash plus our current borowing base of $785 million. That gives us continued significant flexibility in managing the exploitation and evaluation of our inventory of drilling locations.

As Randy mentioned, we continue to aggressively monitor commodity prices including the impact of any basis differentials. We frequently examine our production level and forecast against our hedge positions, and we use puts, swaps, and collars to protect and stabilize our cash flow and to underpin our capital programs. As you will see noted in our SEC filing that was made this morning, we increased our hedge positions both during the second quarter and after the end of the quarter as noted under subsequent events.

We now have put in place floor protection under $63.6 million MMBTUs of natural gas at a weighted average price of $4.24 per MCF and 5.7 million barrels of crude oil at a weighted average price of $77.11 per barrel.

We now have extended our gas edges out through 2015, and you can see in the footnotes to our second quarter 10-Q all the details of those hedge positions. So in summary, we have conservatively positioned Laredo with the appropriate financial flexibility to continue to realize the ultimate value of our extensive drilling inventory. Randy, any closing comments or are we ready for Q&A?

I think we are ready for Q&A, Mark. Tahitia, you want to set the queue up?

Sure. No problem. (Operator Instructions). Your first question comes from the line of Brian Singer from Goldman Sachs. Please proceed.

Thank you, good morning.

Good morning, Brian. How are you.

I am pretty well, thank you. You highlighted your increasing lateral lengths and the cost efficiencies that that brings, though at the same time you are rising your lease operating expense guidance. Can you add some more color regarding more specifically the lateral length that you are planing whether that should encompass all future horizontal wells in the Permian and juxtapose that with what we should expect in terms of drilling and completion costs in corporate LOE.

What we are seeing -- we talked about it, Brian last time also is that we like the early results --preliminary results we are seeing from the longer laterals. I am not sure that we are convinced that there -- we yet understand the optimum length. Not -- we also have a few places where we are going to have to put together deals with offset operators to drill things more than 4,000 feet, but I would suspect that our lateral length is predominantly going to be in the 6000 to 7500-foot length as we go forward. LOEs are up some because we have started focusing on how to best allocate production engineering expertise to these properties, and we are really putting some effort into what we think will long-term be a benefit to us on our production engineering side.

Okay. Thanks. And then can you just talk a little bit about aerial extents from recent drilling in the Wolfcamp and the Cline whether your views at all have changed or any more specifics as to whether your recent drilling has been pushing the Wolfcamp north and your view on how east and northeast -- far east and northeast the Cline goes?

We have indicated -- well, first off, you know, I am actually pretty excited about where we are. But secondly, we view this as a mini quarter kind of a project and we are wanting to see some fairly significant production time between wells before we draw conclusions. So have we extended it? Yes, some. Are we ready to talk about conclusions or meaningful results? No. Are we seeing enough encouragement that we are going to continue? Yes.

Great thank you. Thank you.

Thank you.

Your next question comes from the line of David Tameron from Wells Fargo. Please proceed.

Hi. Morning.

Good morning, David. How are you?

Good. A couple questions. You talked -- can you talk about what you are seeing in the lower Wolfcamp? I know you have drilled -- I know you have not drilled as many wells there as you have in the upper, but can you it you just talk about what you are seeing there.

We are so premature it is probably not early, but if you go back, we have gotten some pretty good hole cores - -

Yes.

And we have vertical single zone testing in the lower Wolfcamp, and we are just now getting any - - our first well drilled. It is not completed, and so as far as a long horizontal. So I do not have anything there to really add other than the core data, it has some validity, but it is not in production. A single zone vertical test has some validity, but we would really like to see four, five months production in the long reach horizontal well, and we are just not there yet.

Okay. Fair enough. Can you give us an update on well costs where you are currently running maybe just the horizontal Wolfcamp and the horizontal Cline?

We have not changed our model any. We are seeing some decrease in some of the cost and some of the other costs are stable and a few of them have actually gone up. So we have not seen enough evidence to change our forecasted cost.

Okay. A couple more questions. Dalhart. Can you give us on update there? I know a large Houston company was talking about, Apache was talking about it at their analyst day. Can you give us an update of anything new there to share?

We are going to put some more money into that this year. But it is not meaningful money, and as yet we have not seen any reason not to do that. We have not seen enough data to really pound the table and jump up and down about it . So I think it is in that category of we are going to be pretty methodical in spending exploration dollars there, and we need to go ahead and put some relatively minor amount of CapEx into that.

Okay. Then finally on leasing. You made some lease purchases in the first quarter, and I have not had a chance to dig this number out of the Q yet. But can you -- were there any leasehold dollars spent in second quarter, anything significant?

We have spent some dollars and it is all detailed in the Q, but we are not -- you know, for us -- for us to buy acreage we kind of have to think that it has a potential to be as good as what we have and that is a -- we think what we have is pretty good. So we have bought some acreage. I do not think you should view it as significant or over powering, and we are aways away from putting much capital to work there.

Alright. I have got a couple more but I will let somebody else jump on. Thanks.

Thank you.

Next question comes from the line of from the line of John Herrlin from Societe Generale. Please proceed.

Yes. Hi. Just two quick ones really. You said for a lot of the horizontal drilling you are still kind of in a science mode. You are now increasing your lateral lengths. Do you think the increase of lateral lengths will kind of offset the science costs, meaning as you go forward, the well costs will be relatively what they are now?

We do think -- we have not seen a reason to change our well cost yet and we do, John, take a little different view of that than most. We like to use long-term model costs relatively realistic on what we are actually spending and hope that over time we drive those costs down. We try not to forecast lower AFEs than we are actually seeing. Sometimes we are able to drive costs down, but sometimes we are not and over time over a life of a project this long it is going to be better for us to use actual cost as our go-forward model.

Okay.

The question on the science cost. We actually spent some time talking about that fairly frequently, and one of our goals is to get to the inflection point where we kind of know what we have in terms of the four horizontal targets there and maybe some of the other targets and then as efficiently as possible workout a development plan and somewhere between getting to the inflection points of the development plan we will dramatically -- we will have captured most of the science we need.

Okay. In terms of benchmarking your performance you tend not to give volume rates, obviously. In the general area you see what your peers are doing or perhaps what partners are doing. How are your wells stacking up in the neighborhood? In the Permian.

We are not at all ashamed of how our wells are stacking up compared to our peers.

Okay. That is it for me. Thank you.

Thank you.

(Operator Instructions). Your next question comes from the line of Abhishek Sinha from Bank of America. Please proceed.

Yes. Hey. I just wanted to ask you on the Granite Wash. How much of that acreage is HBP? And how many rigs do you need to run to hold acreage?

We are - - I will let Jerry or somebody get the HBP number, but we are self-limiting the number of rigs that we run there. While that is a very attractive economic property set our view is that we need to drill a well, have some significant production history, and really understand the reservoir better before we offset. But we have been relatively constrained by our knowledge and database as opposed to lease expirations. And running three more or less rigs there very, very comfortably gets all that acreage held by production over the next couple of years.

Okay. So just on the Dalhart Basin I know there was a question asked before. I just wanted to ask on that. (inaudible) When would you be in a position to announce any results from the Dalhart Basin?

I do not know if it will be this year. It depends on -- we will spend some capital there this year, but it depends on what data we get and our issue there is that one or two really good wells or one or two not good wells does not dramatically determine the fate of that acreage. So we are going to be pretty methodical and drill and learn and kind of feed our way through that, which is kind of historically how we have always done that. We are pleased with that acreage block, but I do not think we are going to have any tremendous moves there in the next quarter or two.

Sure. Sure. Again and the last. One I keep hearing about this two-stream three-stream business. So I was wondering if what is stopping you guys from reporting a three-stream business, and is that something in the plan any time soon?

That is an excellent question and we sell our product -- our natural gas wet at the wellhead and receive the value from that wet natural gas at the tailgate of a process plant. And so our view is we do not properly own those liquids once they leave the wellhead. We do receive full value for them, and in our presentations, we have shown what the numbers would look like three-stream. But I think for the foreseeable future, we are going to be reporting two-stream, getting the value, but not able to book the barrels.

Sure. That is all I have. Thank you very much.

Thank you.

(Operator Instructions). Your next question comes from the line of Mario Barraza from Tuohy Brothers. Please proceed.

Hi. Good morning guys.

Hello, Mario how are you.

Good, thanks of the yourself.

Good.

That is good. Hey just wanted to -- I know you guys do not really give quarterly commentary, but you did mention that you have some production curtailments going on in July and they went through this much. Is that primarily ethane rejection, or is this similar to what your peers were talking about with just delayed in turnarounds from third-party and it should be resolved in hopefully the next couple months?

It had nothing to do with NGL in any way. It had more to do with infrastructure pipeline and compression in a couple of areas and it is not related to one area specifically. There was actually a couple of areas which we are internal infrastructure marketing infrastructure, and we are going to work on that over the next month or two. That started earlier. So, Jerry, do you want to add something?

Yes. I mean one key thing is a tie-in to the Deadwood plant, which we have got everything is there and should be done in the next few days. So that is what has caused this to be a little bit constrained in July and early August.

Okay. And then just shifting gears, you guys mentioned in response to an earlier question that you might need to put together some small deals in order to get some longer laterals. What percentage of your acreage in the Permian would you need to try to work with a neighbor or say just an offset to be able to go out 7500 feet?

It is not a percentage that at this point matters. We have several years of drilling of long reach laterals. Our acreage is pretty blocked up.

I think my answer was not intended to point out that we had a significant issue with leasehold. It is just the opposite. And it is going be to everybody's benefit to drill those longer laterals if in fact that is where the industry heads. But it is not -- we have got a lot of 6,000, 7,000, 7500-foot laterals to drill. The conversations about should we join up on combining acreage with some of the operators? That actually started sometime ago, and we have not made any deals, but that will happen when it is appropriately time.

Okay. Great. That is all I had. Thanks for your time.

Thank you.

Your next question comes from the line of - - you have a follow-up question from the line of David Tameron from Wells Fargo. Please proceed.

Just a couple more, Randy. Can you just talk about in general the pace of acquisitions? You said you are not actively looking. But can you talk about just the Permian as a whole? What you are seeing come across your desk, et cetera?

The pace is still -- we are seeing a lot of stuff. Again and time will tell if we are right. But our view is it has got to be better -- as good or better than what we have, and since we were such an early entry out there we have got some embedded economics that are with low lease prices and so on and so forth. So it is kind of hard for some of the things we see to be as good or better than what we have. We are always in the market looking. We pick up little odds an end here, but it is a- - there is a lot of deals currently, but we are not -- with our embedded inventory and the quality of it I think is difficult for us to make acquisitions.

Okay. Is it fair to say just on the whole you think there are more sellers than buyers right now?

I do not know. I do not know, Dave.

Okay. A couple more. And you guys talked about getting a survey back or getting some data back on the southern part of the basin. How should we think about - - when does that data get processed? And when will that show up in any type of drilling plan?

We -- have been -- it is -- the processing and the interpretation of that is almost ongoing from way back when we started the data acquisition. We actually preliminary processed some of it sometime ago and where that data has been very helpful to us is in looking for places -- the exact place to land the laterals and to look for any kind of small structural changes in things. We have also started doing some pretty detailed geophysical work on internal structure and fabric and things. So we have been using that data for some time. We just got the entire data set finished. We are off and running.

Okay. So no change -- and what I hear is no change in necessary capital allocation or drilling plans just kind of a refinement of current drilling and where you are placing lateral, et cetera?

I think that is accurate. I think the seismic is very, very helpful. It is part of our overall database. But I do not think we are changing CapEx just based upon that. We will change drilling plans and CapEx based upon production results and several months of that.

Okay. And final one. And Rick you mentioned the three-stream versus two-stream and your possibly not apples to apples comparison there as far as LOE and your cost would be lower then three-stream. Do you have any -- have you run the numbers? Do you have any feel for what that would ballpark what that would lower your LOE by just so we can get apples to apples verses everybody else in the industry.

This is Womble. Let me just touch on that. As Rick mentioned by stating our volume in two-stream rather than three-stream, if you moved it to three-stream it would add about 20% to our BOE production. So if you just took our BOE produced during the quarter, increased it by 20% and use that as your new diviser to divide into our total cost, you would have our new metrics.

Okay. Okay. So just approximate 20%, 25% of NGL cut?

No. 20%.

20%. Okay. all right. Thanks. That is helpful.

Your next question comes from the line of Richard Tullis from Capital One Southcoast.

Thank you. Good morning.

Good morning.

Randy, I guess over the last several quarters oil production as a percentage of total production has been drilling about 1% or so sequentially. Do you see that trend continuing going forward into -- well into next year, do you see some acceleration there?

I do not think it is going to accelerate by any means. I do not think it is going to continue at that rate. We are fortunate that as we grow overall production we very, very slightly may move that percentage of oil, but it's not a -- it is not going to dramatically increase. Mark, do you - -

No. That is right. In all our companies, we have always tried to have a balance, and that is what we have got here.

Okay. And with the recent acreage acquisitions could you give a general breakdown by county of what your net acreage holdings are?

We show in the -- that in the -- we have shown before in presentations that in the Garden City area, which is principally Glasscock and Reagan County we have got around 135, 138,000 net acres. We have shown that to you in the past. And that is about as far as we have broken that down.

Okay.

The rest of that acreage we are buying. we have not highlighted that yet.

Okay. That is all I have. Thanks very much.

Thank you.

Your next question comes from the line of Dan McSpirit from BMO Capital Markets. Please proceed.

Thank you. Gentlemen, good morning.

Morning, Dan.

How much is too much to pay for acreage in the Permian basin? Is that, at what price does it not make economic sense or maybe put differently what is Laredo's limit?

We are not going to address our limit, but what I will say is that if all four zones work you can pay a lot for acreage. The issue we have is we have a lot of acreage that we have not paid alot for. And I am not completely comfortable reaching out and buying high cost acreage when we have a plethora of locations on our current acreage.

Got it. And then based on your own internal models and assuming current well costs as well as strip pricing. What do you place the economic limit or the economic breakeven of the upper Wolfcamp today? At what price, WTI?

It is -- we are -- the answer to that is we are pretty thoroughly hedged at what Mark? Call it $75 a barrel?

A little over $77.

A little over $77 and almost our hedging has been disclosed and disclosed again. The way I answer that not trying to avoid the exact numbers. The way I answer that is that at our hedge position we generate enough cash flow to continue to implement our plan. We continue to be excited about that. So our breakeven is something less than that, but at $77 we like where we are. We like $97 better than $77, but at $77, we are still very comfortable that we can implement our plan.

Got it. And then turning to the Cline shale. Can you, and a apologize if I missed this, but can you speak to the game plan to drill and complete wells for the balance of this year third and fourth quarter this year to the Cline?

We are going to continue the Cline. We are liking what we are seeing there, and what we are trying to do is balance. We are comfortable with the Cline.

We are getting comfortable with some of the upper Wolfcamp where we have drilled in the middle of our acreage, and we are balancing that development program in the Cline. The development program in the long reach upper Wolfcamp with our need to go ahead and test the extent of our acreage the four corners and also test the middle and lower. So we are going to continue drilling Cline, continue drilling upper Wolfcamp, and get data on north and south outside of the core area in both the Cline and the upper Wolfcamp, and get some data on the middle and lower Wolfcamp.

Okay. Last one for me just turning to the balance sheet. Based on your own internal models when do you think you dip into the revolver assuming that you have not no amounts outstanding after the quarter-end?

We will use the revolver some between now and year-end, but it will not be very significant. The existing liquidity we have gets us well past year-end 2013.

Very good. Thank you.

Thank you.

(Operator Instructions). And your next question comes from the line of Jeff Bachmann from Howard Weil. Please proceed.

Morning guys.

Good morning.

Morning.

Just I had a quick question on reserves and just wonder if you had any idea of what mid-year number looked like from the first half of this year.

We have not asked John -- we don't have a third-party reserve engineering report for the mid part of the year, and we will just leave the answer at that.

Okay. Great. Thanks.

Thank you.

That concludes our Q&A processing. I would now like to turn the conference back over to Mr. Randy Foutch for any closing remarks.

We really appreciate you giving us the time to talk about our quarter. We are excited about it. We are pleased, and we will look forward to our next time we visit with you, and certainly at the next earnings call. So thank you very much.