Vital Energy, Inc.

Thank you, Tahitia, and good morning. It is a pleasure to be with you again part of the Laredo team, where I all believe the company has put together a very attractive acreage position in one of the most prolific regions of 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, forecasts and 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 2-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 2-stream reporting does understate our production volumes by approximately 20% relative to companies that report on a 3-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 3-stream basis. However, the true economic value is the same.

I'll now turn the call over to Randy Foutch, Chairman and Chief Executive Officer of Laredo.

Thanks, Rick, and good morning, everyone. I'm going to begin by providing some color on some of the highlights for the second quarter, which 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's 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 gas 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 4 identified stacked 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 a 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 horizontal drilling activity in the Middle and Lower Wolfcamp formations.

Our entire Permian program is still in the evaluation phase and we still have additional work to do, but our team is working diligently to fully grasp the potential that exists in all 4 of the stacked zones that we have identified in the Permian. I'll now turn the call over today now to Jerry Schuyler, President and COO, to discuss the key details on the operating results.

Thanks, Randy, and good morning, everyone. As anticipated, our production volumes continued to growth during the second quarter.

We were up nearly 3,400 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 don't 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 in line with our previous annual production guidance of approximately 30% annual production growth for 2012, resulting in total volumes for the year of greater than 11.2 million barrels of oil equivalent.

As we've 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 costs.

In the Upper Wolfcamp, we have completed 12 horizontal wells to date. 5 of these wells have lateral lengths of 6,000 feet or greater, and the results to date are in line 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've also begun drilling our first Lower Wolfcamp horizontal well, and we're 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. Our most recent one is actually approximately 7,000 feet, lateral length.

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 3 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, 3 horizontal rigs in the Granite Wash and 10 to 11 rigs operating in the Permian, with 4 or 5 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 core petrophysical analysis and all the vertical well zone testing, et cetera, that we have, we have recently also completed shooting an additional 283 square miles of 3D in the southern portion of our Permian acreage in Glasscock and Reagan Counties.

With the completion of this high-quality seismic program, our total 3D coverage is around 750 square miles in the Permian Basin.

With that, I'll turn the call over to Mark Womble, our CFO.

Thanks, Jerry. The combined impact of the production growth that we've 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 totaled $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 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 areas.

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 borrowing 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 levels 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'll see noted in our SEC filing that was made this morning, we've 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 hedges 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've 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're ready for Q&A, Mark. Tahitia, are you -- want to set the queue up?

You highlighted you're increasing lateral lengths and the cost efficiencies that, that brings, though at the same time, you're raising your lease operating expense guidance. Can you add some more color regarding, more specifically, the lateral length that you're planning, whether that should encompass all future horizontal wells in the Permian and then juxtapose that with what we should expect in terms of drilling and completion costs and corporate LOE?

I think what we're seeing, we talked about it, Brian, last time, also is that we like the early results, preliminary results we're seeing from the longer laterals. I'm not sure that we're convinced that we yet understand the optimum length.

Not -- we also have a few places where we're going to have to put together deals with outside operators to drill things more than 4,000 feet. But I would suspect that our lateral length is predominantly going to be in the 6,000 to 7,500 lateral foot length as we go forward.

LOEs are up some because we've started focusing on how to best allocate production engineering expertise to these properties. And I think we're really putting some effort into what we think will long term, be of benefit to us on our production engineering side.

Okay. 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, how far east to northeast the Cline goes?

I think we've indicated -- well, first off, I'm actually pretty excited about where we are. But secondly, I think we view this as a many quarter kind of a project and we're 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're going to continue? Yes.

A couple of questions. You talked about -- can you talk about what you're seeing in the Lower Wolfcamp?

I know you've drilled -- I know you haven't drilled as many wells there as you have in the upper, but can you just talk about what you're seeing there?

We're so premature, it's probably not early. But if you go back, we've got some pretty good whole cores and we have vertical single zone testing in the Lower Wolfcamp.

And we're just now getting any -- our first well drilled. It's not completed, and so as far as the long horizontal, so I don't have anything there to really add other than the core data, it has some validity but it's not production.

Our single zone vertical test has some validity, but we'd really like to see 4, 5 months production in the long reach horizontal well and we're just not there yet.

Okay, fair enough. Could you give us an update on well cost, where you're currently running?

Maybe just the horizontal Wolfcamp and then on horizontal Cline?

We've not changed our model any. We're seeing some decrease in some of the costs and some of the other costs are stable and a few of them have actually gone up.

So we've not seen enough evidence to change our forecasted cost.

Okay. Couple of more questions.

Dalhart, can you give us an update there? I know the large Houston company, Apache was talking about it at their Analyst Day, can you give us an update of -- anything new there to share?

We're going to put some more money into that, I think, this year, but it's not meaningful money. And as yet, we haven't seen any reason not to do that.

We haven't seen enough data to really pound the table and jump up and down about it. So I think it's in that category of we're 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 guys, I know, you're making lease purchases in the first quarter, and I haven't had a chance to dig this number out of the Q yet, but can you -- were there any leasehold dollars spent in the second quarter, anything significant?

We've spent some dollars, and I think it's all detailed in the Q, but we're not -- for us, we -- for us to buy acreage, we kind of have to think that it has the potential to be as good as what we have, and that's a -- we think what we have is pretty good. So we bought some acreage.

I don't think you should view it as significant or overpowering. And we're a ways away from putting much capital to work there.

Just 2 quick ones, really. You said for a lot of the horizontal drilling, you're still kind of in a science mode.

You're now increasing your lateral lengths. Do you think that 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've not seen a recent change on our well costs here and we do, John, take a little different view of that than most. We'd like to use long-term model costs relatively realistic on what we're actually spending and hope that, over time, we drive those costs down.

We try not to forecast lower AFEs than we're actually seeing. Sometimes we're able to drive costs down, but sometimes we're not, and over time, over a life of a project this long, I think it's going to be better for us to use actual cost as our go-forward model.

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 4 horizontal targets there and maybe some of the other targets, and then as efficiently as possible, work out a development plan. And somewhere between getting to the inflection point and the development plan, we'll dramatically -- we will have captured most of the science we need.

Okay. In terms of benchmarking a 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're not at all ashamed of how our wells are stacking up compared to our peers.

I just wanted to ask you roughly on the Granite Wash. How much of that increases HBP, and how many rigs do you need to run to hold the acreage?

We're -- I'll let Jerry or somebody get the HBP number. But we are self-limiting the number of rigs that we run there.

While that's 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. So we've been relatively constrained by our knowledge and database as opposed to lease explorations.

And running 3, more or less, rigs there very, very comfortably, gets all of that acreage held by production over the next couple of years.

Okay. Just on the Dalhart Basin, I know there was a question asked before, I just want to ask and that is -- when would you be in the position announcing any results from that Dalhart Basin?

I don't know if it'll be this year. It depends on -- we'll spend some capital there this year, but it depends on what data we get.

And our issue there is that 1 or 2 really good wells, or 1 or 2 not good wells doesn't dramatically determine the fate of that acreage. So we're going to be pretty methodical and drill and learn and kind of feel our way through that, which is kind of historically how we've always done that.

We're pleased with that acreage block, but I don't think we're going to have any tremendous moves there in the next quarter or 2.

Sure, sure. Okay, and the last one, I keep hearing about this 2-stream, 3-stream business.

So I was wondering if -- what's stopping you guys from reporting a 3-stream business and is that something [indiscernible] any time soon?

That's an excellent question. We sell our product, our natural gas, wet at the wellhead and receive the value from that wet natural gas at the tailgate of the processed blend.

And so our view is we don't properly own those liquids once they leave the wellhead. We do receive full value for them, and in our presentations, we've shown what the numbers would look like 3-stream.

But I think, for the foreseeable future, we're going to be reporting 2-stream, getting the value but not able to book the barrels.

Just want to -- I know you guys don't really give a 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 some similar to what you got your peers were talking about with just delayed in turnarounds from third party and it should be resolved in hopefully the next couple of 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's not related to one area specifically. There was actually a couple of areas in which we are -- internal infrastructure, marketing infrastructure and we're going to work on that over the next month or 2.

That started earlier. So Jerry?

I mean one key thing is a tie-in to the deadwood plant, which we've got everything, it should be done in the next few days. So that's what's caused us to be a little bit constrained in July and early August.

Okay. And then I 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, say just an offset to be able to go out to 7,500 feet?

It's 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's just the opposite. And I think it's going to be to everybody's benefit to drill those longer laterals, if in fact, that's where the industry heads.

But it's not -- we've got a lot of 6,000, 7,000, 7,500-foot laterals to drill. The conversations about should we join up on combining acreage with some of the operators, that actually started some time ago and we haven't made any deals, but that'll happen when it's appropriately timed.

Just a couple more, Randy. Can you just talk about, in general, the pace of acquisitions?

I know you said you're not actively looking, but can you talk about just the Permian as a whole, what you've seen come across your desk, et cetera?

I think the pace is still -- we're seeing a lot of stuff. Again, and time will tell if we're right, but our view is it's got to be better -- as good or better than what we have, and since we were such an early entry out there, we've got some embedded economics that are -- with low lease prices, and so on and so forth.

So it's kind of hard for some of the things we see to be as good or better than what we have. We're always in the market, looking.

We picked up little odds and ends here, but it's a -- there's a lot of deals currently, but we're not -- with our embedded inventory and the quality of it, I think it's difficult for us to make acquisitions.

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

I don't know. I don't know, Dave.

Okay. A couple more.

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

We've been -- it's the processing and interpretation of that is almost ongoing from way back when we started the data acquisition. We actually preliminary processed some of it some time ago.

And where that data's been, it's 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 and things. We've also started doing some pretty detailed geophysical work on internal structure and fabric and things.

So we've been using that data for some time. We just got the entire data set finished, and we're off and running.

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

I think that's accurate. I think the seismic is very, very helpful.

It's part of our overall database, but I don't think we're changing CapEx just based upon that. We'll change the drilling pace in CapEx based upon production results and several months of that.

Okay. And final one, and Rick, you mentioned the 3-stream versus 2-stream, and your possibly non-apples-to-apples comparison there as far as LOE and you're constantly lower under 3-stream?

Have you run the numbers? Do you have a feel for what that would ballpark, what that would lower your LOE by so we that can get the apples-to-apples versus everybody else in the...

This is Womble, let me just touch on that. As Rick mentioned, by stating our volumes in 2-stream rather than 3-stream, if you moved it to 3-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 divisor to divide in to our total cost, you'd have our new metrics.

Okay, okay. So just approximately -- okay, 20%, 25% depending on the NGL cut.

No. 20%.

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

Do you see some acceleration there?

I don't think it's going to accelerate by any means. I don't think it's going to continue at that rate.

I think we're fortunate that as we grow overall production, we very, very slightly may move that percentage of oil, but it's not going to dramatically increase. Mark, do you?

No. In all our companies, we've always tried to have a balance.

And that's what we've got here.

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

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

The rest of that acreage we're buying, we haven't highlighted that yet.

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

We're not going to address our limit, but what I will say is that if all 4 zones work, you can pay a lot for acreage. The issue we have is we have a lot of acreage that we haven't paid a lot for.

And I'm 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, where do you place the economic limit or the economic breakeven of the Upper Wolfcamp today?

At what price, WTI?

It's -- the answer to that is, we're pretty thoroughly hedged at, what Mark call it, $75 a barrel?

A little over $77.

A little over $77 and almost -- our hedging's been disclosed again. And I think the way I answer that -- not trying to avoid the exact numbers, the way I answer that is, 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're still very comfortable that we can implement our plan.

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

We're going to continue the Cline. We're liking what we're seeing there.

What we're trying to do is balance. We're comfortable with the Cline.

We're getting comfortable with some of the Upper Wolfcamp, where we've drilled in middle of our acreage and we're 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 4 corners and also test the Middle and Lower. So we're going to continue drilling Cline, continue drilling up the 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'd get into the revolver, assuming that you have no amounts outstanding after the quarter end?

We'll 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.

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

We've not asked. John, correct me if I am wrong.

We don't have a third-party reserve engineering report for the mid-part of the year. And I think we'll just leave the answer at that.

We really appreciate you giving us the time to talk about our quarter. We're excited about it, we're pleased.

And we'll look forward to our next time we visit with you and certainly at the next earnings call. So thank you very much.