Vital Energy, Inc.

Thank you, Carissa, and good morning. With me today are Randy Foutch, Chairman and Chief Executive Officer; Jerry Schuyler, President and Chief Operating Officer; Mark Womble, Senior Vice President and Chief Financial Officer; and Dan Schooley, Vice President of Marketing, 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 SEC.

In addition, we will be making reference to adjusted net income and adjusted EBITDA, which are non-GAAP financial measures. Reconciliations of GAAP net income to these non-GAAP financial measures are included in this morning's news release.

Also as a reminder, Laredo reports operating and financial results on a 2-stream production basis that includes the volumes and values of our natural gas liquids in our gas stream, not as part of our oil and condensate or included in the 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 the product.

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.

Earlier this morning, the company issued its third quarter 2012 earnings release, which resulted in adjusted net income of $12.6 million or $0.10 per diluted share. Included in this release is the company's updated guidance for the fourth quarter of 2012.

If you do not have a copy of this news release, you may access it on the company's website at www.laredopetro.com.

I'll now turn the call over to Randy Foutch to begin our discussion on the quarter.

Thanks, Rick, and good morning, everyone. I think it's appropriate before I begin our discussion to express, on behalf of the entire Laredo team, our deepest sympathies to those in the Northeast affected by the recent storms and all those still dealing with the aftermath.

Since our inception, the Laredo team has focused on using a data and science-based approach to identify, confirm and develop potential oil and gas resources. That's exactly what we've been doing on the roughly 190,000 acres we've amassed in the oil- and liquids-rich Permian Basin.

We have been concentrating our activities within our core Garden City area fairway, which represents approximately 140,000 net acres of that total. To date, alongside our vertical drilling program, we have identified 4 productive zones on this acreage, which we are targeting for horizontal development.

To date, from more than 50 horizontal wells and supporting industry activity, our data has enabled us to derisk and confirm the development feasibility of the Cline and the Upper Wolfcamp formations on 70,000 and 60,000 net acres, respectively. This is a great start, but really only covers about 1/4 of our effective acreage position, which we consider we have 4 potential zones on 140,000 acres, or the equivalent of one producing horizon over roughly 560,000 acreage.

We're aggressively working on our plan over the next 24 to 36 months to derisk the remaining acreage, not only for the Cline and the Upper Wolfcamp, but, as you'll see, also for the Middle and the Lower Wolfcamp zones.

Results from our first horizontal wells in the Middle and Lower Wolfcamp appear very encouraging. But keep in mind, they're just the first horizontal well in each zone, and this is a very large area.

We will continue to delineate the potential of these zones, as we have done with the Cline and the Upper Wolfcamp, by taking our knowledge from the well results to help us efficiently and methodically derisk and define the ultimate potential from all 4 of these zones on our Permian acreage.

This delineation program is critical to truly defining the size of the prize on our Permian acreage position. We are balancing this delineation effort with our vertical and horizontal development drilling program.

We are aggressively working on a horizontal development plan to optimize the drilling of the Cline and Upper Wolfcamp acreage that has already been derisked while providing for flexibility to add the Middle and Lower Wolfcamp, upon its confirmation, to expand our reserve, production base and cash flows. As always, our focus is on maximizing not only our returns, but also the efficient recoveries and total value from these assets for our shareholders.

Our team is off to a great start, and I'm very excited about the expanding opportunities the team is uncovering.

Now, I'll turn the call over to Jerry Schuyler, our President and CEO, to discuss a few details of the operating results.

Thanks, Randy, and good morning. Our production volumes for the quarter came in at 30,835 barrels of oil equivalent per day.

That was up about 27% year-over-year. Much of our production increase came from our focus on the oil-rich Permian Basin, and we expect to continue to focus activity on the Permian asset during the remainder of the year and on into 2013.

As anticipated, our quarter-over-quarter sequential growth was relatively flat as a result of approximately 2,000 to 2,500 barrels of oil equivalent per day of production being curtailed because of third-party gas constraints in the third quarter. Without the curtailment, our quarter-over-quarter sequential growth would have increased above second quarter 2012 instead of the flat to slightly-declining quarter-over-quarter sequential growth reported.

The curtailments, which carried on through October, have now all been resolved, primarily by Laredo. We did this through connections of our gas-gathering system to 3 additional downstream pipelines.

The stairstep-type growth rate growth remains in line with our previous annual production growth 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. Keep in mind that Laredo has achieved a compounded annual growth rate of greater than 60% over the past 3 years.

However, on a quarterly basis, this may appear lumpy from time to time.

As we have mentioned before, we are currently drilling longer laterals in the Upper Wolfcamp and Cline formations in the Permian. We believe that over the long run, these long laterals should provide for more efficient development of our acreage by minimizing our footprint on the leasehold, reducing unit operating costs and reducing the unit F&D cost.

In the Upper Wolfcamp, we have completed 16 horizontal wells to date. 10 of these wells have lateral links of 6000 feet or greater.

The average 30-day IP per stage for the Upper Wolfcamp horizontal wells that have 30 days of initial production is 30 barrels of oil equivalent per day.

As Randy mentioned, we also now have 30-day results for the first Middle Wolfcamp and Lower Wolfcamp horizontal wells. Both of these wells were drilled with lateral links of approximately 6900 feet and completed with 26 frac stages.

The 30-day IP for the Middle Wolfcamp horizontal was more than 900 barrels of oil equivalent per day with a per-stage 30-day IP of 36 barrels of oil equivalent per day, while the 30-day IP for the Lower Wolfcamp well was more than 700 barrels of oil equivalent per day, with a per-stage 30-day IP of 28 barrels of oil equivalent per day. While these are only single well results, they are certainly in line with what we expect from our database.

In the Cline, we've completed 11 horizontal wells during 2012, with the most recent lateral links approaching 7,000 feet. Similar to the Upper Wolfcamp results, the average 30-day IP per stage for these 11 Cline horizontals is 30 barrels of oil equivalent per stage.

During the quarter, we also drilled 28 vertical wells in the Garden City area, and we continue to be very pleased with those results.

To finish up our activity summary, we continue to operate 3 rigs drilling horizontal wells in the Granite Wash, and the development program 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.

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

Thank you, Jerry. For the third quarter, Laredo reported a net loss of $7.4 million or $0.06 per share.

This includes unrealized loss on derivatives of approximately $31 million. Exclude that unrealized loss, our adjusted net income for the quarter was $12.6 million or $0.10 per share.

The combined impact of the year-over-year production growth, coupled with our strong hedge position and our continued focus on unit cash cost, contributed to adjusted EBITDA of $110.8 million for the third quarter, up 11% from a year ago.

Laredo continued to see improvements in its cash operating metrics during the quarter. Lease operating expenses, production taxes and G&A expenses in aggregate totaled about $14.14 per BOE in the third quarter of '12, which is a per-unit decrease of approximately 6% from the third quarter of 2011, both of those excluding stock-based comp.

Production taxes for the quarter were slightly higher than initially guided as a result of our ad valorem taxes being up a bit higher due to increased valuations on our Texas properties and an increase in the number of wells included in those valuations as a result of our drilling activity.

number one, the transition to higher value oil reserves, which include higher costs; and number 2, decreases in the SEC natural gas price used to calculate reserves. For the fourth quarter, we are adjusting our guidance for DD&A to be in the range of $22 per BOE to $23 per BOE.

During the third quarter, Laredo invested $251 million in total CapEx, and that includes $20.5 million relating to the acquisition of oil and gas properties. Drilling expenditures totaled right at $212 million, about 90% of which was in the Permian.

We continue to add targeted acreage in and around our core areas. We had a total of approximately 425,000 net acres at quarter end.

And we are still on track for our announced total CapEx budget of around $900 million for 2012 if you exclude these small acquisitions.

At the end of the quarter, we had $50 million outstanding on our credit facility with our banks with a borrowing base set at $785 million, and we had $29 million of cash on hand. This results in total liquidity of more than $760 million.

It gives the company significant flexibility in managing the exploration and exploitation of our continued attractive mix of opportunities.

After the end of the third quarter, in November, Laredo has had its credit facility borrowing base increased from $785 million to $825 million. We also borrowed an additional $50 million and we'll borrow an additional $35 million on a revolver during the week in November 12.

As Randy mentioned, Laredo aggressively monitors commodity prices, including the impact of basis differentials. We continue to use puts, swaps and collars to protect and stabilize our cash flow and to underpin our capital programs.

At the end of the quarter, we had put in place floor protection under almost 60 million MMBtus of natural gas at a weighted average price of $4.16 per Mcf and $5.1 million barrels of crude oil at a weighted average price of $76.75, and we've, obviously, included the details in the footnotes to our third quarter 10-Q -- all the details on our hedge positions, if you'd like to look at those.

In summary, we believe we have conservatively positioned Laredo with the appropriate financial flexibility to realize the ultimate value of our extensive drilling inventory.

With that, I'll turn it back over to Randy for some closing remarks, and then we will take your questions. Thank you.

Thanks, Mark. Thanks, Jerry.

But before we open up the line for Q&A, let me just add a few summary points, take-away summary points for the quarter.

Laredo has now derisked a substantial portion of our Permian-Garden City acreage related to the Upper Wolfcamp and Cline development. We are going to continue our efforts to derisk the additional acreage in these zones as well as the Middle and Lower Wolfcamp going forward.

The second point is that we continue to be on track to meet our annual production guidance of greater than 11.2 for the year, even given the relatively flat last quarter.

The third point I'd like to make is that our operating metrics remain strong even as we continue to focus on our higher cost per barrel oil development in the Permian. And then the fourth point that I'll leave you with is that we've been aggressively evaluating and defining our acreage, resulting in the current outspend of our cash flow.

We believe this is appropriate for the meantime. However, as we've expressed in the past, we're very committed to retaining our strong financial position.

With that, I think, Operator, we'll open up the lines for any questions.

Can you guys talk about -- you gave us the frac stages and I know you've, in your presentation, gave about more details about IP rates. But have you identified an optimal frac stage and kind of where you're steering things toward?

Or is that going to vary based on -- or how much variability is that going to be based on the field? Or could you just talk more about, expand a little bit more on that?

This is Randy. I'll take the first crack and then see if Jerry wants to add anything.

But I don't think we've quite optimized the frac, not only in terms of the number of stages, but also I think we're still -- some work left to be done on how much water and how much sand. So we're getting a lot closer to the optimization than we were even 3, 4, 6 months ago.

But we do know that early on, we were not dense enough. We've dramatically increased the amount of sand we're using, but I think there's still work to be done.

Jerry, do you want to add anything?

No. I mean, we're -- our standard with about 7,000 feet is about 26 frac stages, and that appears to be certainly in the ballpark of where we need to be.

Okay. And then as we look to next year, I know you haven't given official '13 guidance yet.

But as we look to next year, can you talk about what's going to be your approximate mix of horizontal and vertical? And any other changes we should expect over the next 3 to 4 quarters as you guys develop out the Permian?

I think we have said in the past, and you can't get around it, that we're going to have a component of our vertical drilling program continue for some time. That does a number of things for us.

It helps us with our continuous drilling obligations, and it gives us data specific on where to land. And as you know, we've only booked I think less than 30% of those locations on our proved reserve category.

There's tremendous value to drilling those verticals. So I think there's probably a bias to slightly more horizontal wells out there, but there'll be a big component of verticals.

All right. Let me ask one more, and then I'll let somebody else jump on.

Infrastructure, obviously, you addressed that it says, it sounds like for the fourth quarter. Are you guys -- what's the snapshot of infrastructure the next 2 to 4 quarters, realizing that, obviously, it's a stairstep, and you're going to be adding more as the process goes along, but could you just talk how you shape up, kind of, as calendar turns into '13?

We're actually reasonably comfortable, David, on where we are with infrastructure. There were some high line pressure which we took care of inside the field by taking a lot of gas, lots of different places.

And there's a lot of buildouts that are coming up early toward the end of '12 and early in '13, and for that matter, in '14, that are going to -- in our part of the world out there, it's going to dramatically help us.

Okay. So as it stands now, you're okay for '13, is what it sounds like?

Yes.

When you look at the Upper Wolfcamp area that's been derisked, this, I guess, is about 60,000 acres. How much of that is also prospective for the Lower and Middle Wolfcamp?

Or can you give us some broader comments on areas in which you have some confidence in multi-zone potential?

Yes. We think over most of that 140, if not all, the potential exists for all 4 zones to exist.

Some of the acreage in the eastern side of that, we haven't yet drilled vertical wells on. But we have 700-plus vertical wells.

We have a lot of core information. We have a lot of 3D.

We've done the -- some vertical single-zone testing. So the database suggests that there's strong indications that the entire 140,000 plus acreage may have all 4 zones.

The overlap between the Cline 70,000 acres and the 60,000 acres for the Upper Wolfcamp is there. So we know, on part of it, we have those 2 zones.

The 2 wells we have, 1 in the Middle and 1 in the Lower, also overlap. So today, we're still thinking that all 4 zones exist on the majority of that acreage.

That's helpful. And then looking at the Cline, specifically, can you just tell us, directionally, we're you're testing or where you see the play moving?

There are certainly others that are east of you or northeast of you. Is that the direction that you are kind of moving your drilling and your leasing?

We haven't done a lot of leasing there. We've made acquisitions, kind of add-on acquisitions, in where we bought acreage that was very highly prospective within our bailiwick.

As far as our drilling, we're -- our goal is to balance the development activities that we've captured with also trying to extend the Cline and the other 3 zones to the rest of the acreage. So we'll be drilling some wells across our entire acreage base for all 4 zones over the next future months and quarters and years.

Okay. And then lastly, can you just talk or add a little more color on how far ahead you feel you are in terms of making sure that processing and infrastructure is in place, and do you anticipate any delays there?

Any other disruptions, such as what we've seen for you and others, as we go into next year?

I'll tell you what, let me -- it seems like that question is going to come up. Let me introduce Dan Schooley and let him just address that, both specifically and globally, on what we see and know and think.

So Dan, do you want to...

Yes. Thanks, Brian.

It's Dan Schooley. And to just talk briefly about the things that are coming up, the downstream pipelines and processing and compression that we see that will directly impact Laredo and our production out in the Permian.

We have 2 compressors that Atlas is going to put in at their new coal ranch compressors site. Those will both be up and running by the end of the year, the first one in November and the second one in December.

Those are 8 million a day, a piece. And then, by the end of December, Targa is going to have 30 million a day expansion done on their Sterling plant.

Again, that's directly connected to Laredo's production. So we feel pretty good about the balance of '12 based on what we've already done to offload some of the high line pressure areas we had, and then these expansions, we think we're going to be in good shape all the way through the fourth quarter and into the first quarter of next year.

Then, in pretty quick succession in '13, in March, Atlas is going to fire up their 200 million a day Driver plant. Again, that will directly impact Laredo's production and dramatically lower time pressures even further.

Targa -- I mean, DCP is on track, apparently, to get their Rawhide Plant up and running. It's 75 million a day by July.

That plant is 10 miles north of our mainline that we deliver into. So that will directly impact us.

So in the balance of '12 and the end of '13, we have over 305 million a day of processing capacity coming online that's going to directly impact our production. And then finally, in '14, probably July of '14 is what they're estimating now, Targa is going to build a plant right on the Midland Glasscock County line, which is 200 million a day.

So from now until the middle of '14, we're going to see over half a Bcf a day of processing come online in the Permian that directly affects our production. And, of course, you all are aware we have 2 NGL pipelines that are coming into the Permian.

You've got Lone Star at 200,000 barrels a day in the first quarter and then followed quickly by DCP Sandhills, which is another 200,000-barrel a day pipeline in the second quarter. So we really feel good about the remaining part of '12, and then we feel even more comfortable, if you will, for '13 and '14.

And, Brian, hopefully, that finally answers the question why I just don't have a tremendous amount of concern for -- well, I think what we're going to see going forward is more of the local infrastructure, minor things that we can take care of ourselves as far as constraints or supplies issues.

I've got 3 quick ones. With the Cline wells, is the formation that you're targeting or the bench, if you want to call it that, is it uniform petrophysically?

We've shown a lot of data running across that acreage, which runs 75, 80, maybe more miles north and south, in which, across the length of that long acreage base, there's a lot of similarity petrophysically. In the core data, in the electric log, in the LS logs done.

But we do know that there'll be some differences. It just can't be the same across that 75-plus mile long acreage base.

We've seen some GOR, a few percentage points differences. So we're not expecting anything of any substance where things just completely change, but we know there's going to be some differences.

We do show in one of -- in our presentations that on the eastern part of the acreage, there's a spacing change. We don't know if that's good or bad yet, but we'll figure it out.

When it's appropriate, we'll drill some wells and then figure it out.

Okay, that leads to my next question. In order to better differentiate the placement for horizontals, you really need to do the verticals, so you can see the spacing changes.

Is that correct?

We think the verticals add -- I'm not going to say that we can't drill the horizontals without the verticals, but we think verticals add substantively to our comfort in derisking. But keep in mind, we've drilled over 700 verticals.

Our average spacing out there in the verticals is right at 1 vertical for every 200 acres. So we still have specific goals in mind for the verticals, but we do have a lot of vertical well controls.

Great. Last one for me.

How are the horizontal wells cost running completed? And are you seeing, given what's going on in the service industries area, are you seeing cost come down?

I'll let Jerry...

Yes, we are seeing service costs come down in the second half of the year. The pumping is probably down 20% to 25%, and maybe we've actually seen pipe cost drop off maybe 5% to 10%.

So we are realizing some cost savings compared to what we had -- were experiencing in the first half of the year.

But to be fair, we tend to think, John, that over the life of a program with this much drilling, that we shouldn't be chasing price down quarter-to-quarter, and we do our budgeting and modeling pretty much on what we're actually seeing historically it cost us. If we see prices stay down for long time, we'll change our model.

But with a 10-plus-year drilling inventory, I'm not sure that a quarter-to-quarter decrease means we should chase it up and down.

Well, that's really not what I was trying to get at. I was trying to -- I was assuming that, with your early horizontal wells, you'd be running more science than normal.

So I was wondering what you thought your overall completed well cost would be when you're in more of a development mode?

Yes, we're still doing some science. And I think I answered your question, John, in saying that we're pretty much going to use the AFEs that we have.

We don't forecast that 3 years from now we'd be able to dramatically change AFE cost. We think over time, costs go up.

I just have a broad level question here. So basically, I just, again, noticed that you added a little bit more acreage in the Permian, and then there was some more acreage overall to the portfolio.

So basically, I'm just looking like what plans do you guys have to basically bring the growth forward and raise the gap between the long-ended inventory that you already have and the inventory that you anticipate?

There's a couple of points, I think, you very correctly asked. One of them is we bought some acreage, part of it was acreage involved with buying some add-on producing acquisitions inside our core Garden City area.

Some of the acreage that we bought outside the Garden City area is acreage in which we think we can lever what we've learned in Garden City and apply to that acreage. We were a very early entry into those acreage acquisitions.

We got in pretty cheap. We're going to spend some capital over the next year or so getting some data, some drilling results on that acreage.

But the takeaway is, that acreage has to be, in our minds, as good as what we have, or it won't get much capital. Our view is that it needs to be as good as what we think we have before we spend any real time or talk about it or do much with it, other than spend enough money to evaluate it.

Did that answer the question?

Yes. This is just as a follow-up.

So outside of Permian, where else did you have acreage?

It was pretty much all in the Permian.

It was all in the Permian. Okay.

And -- so I just wanted to see, so in terms of your targeted debt to EBITDA and targeted debt to cap, you have a number or something over there that you feel comfortable with?

We look at debt all kinds of ways. The primary one is probably debt to EBITDA.

We're well below 2.5x. We've said publicly that we expect the debt level as we continue to explore our acreage to be in that 2.5 to 3 to 3.5 range.

We also look at debt to our market capitalization. We look at debt to our reserves, our proved reserves and our PDP reserves.

We pay very close attention to our debt levels and we're not going to overlever this company. And we're certainly in a very conservative position right now.

Just a quick question. Do you guys have the actual well costs on that Middle and Lower Wolfcamp well?

We do, and it's in range with what we've said we were going to spend for the entire Wolfcamp drilling program.

Okay, got it. And what county were these wells in?

They're in -- all of our drilling there, principally in that Garden City area, is in Reagan and Glasscock.

Reagan and Glasscock, got it. And then, do you guys have the product makeup, what percentage was oil?

It's very similar. But Dan may have a -- it's very similar to the Upper.

In general, in the Permian, it's 50% oil, about 26% NGLs and 24% gas.

Got it. And then my last question is kind of what are you guys seeing on the acquisition side?

Anecdotally, there's been some chatter that a lot of these smaller private guys are getting scared about potential looming tax burdens down the line, especially after the election. Are you guys seeing any opportunities there, maybe some bolt-on acquisitions?

We would -- I don't know that I've seen as many deals come around as we've seen lately. Certainly, it seems to me like there's a lot of acquisitions floating around for sale.

And we look a lot and we keep getting interested in spending time on them, but we keep coming back to one of our core tenets and beliefs, is that us to make an acquisition of any kind, the economics have be as good or better than what we have. And that's a problem in this area because we were buying acreage in '08 at a relatively low price, and we have great economics on what we've already captured, and we're pretty convinced we have the potential for the 4 zones over most of the acreage.

So for us to make an acquisition, we're going to have to buy it -- it has to be a very, very good property set, and we're going to have buy it relatively cheap. So I think we're looking and would like to do it, but I think it's a pretty high barrier for us to buy one.

You guys mentioned you're going to have 4 to 5 horizontal rigs. What's the mix of well you're planning for Cline versus Wolfcamp?

And kind of the mix in the Wolfcamp of A, B and C for '13?

We don't have -- we tend to look at that mix 1 well or 2 out from moving the rig around. We have some guidelines and plans on what we think we need to do to develop the acreage we have.

And we have some guidelines and thoughts on where we need to drill to prove up the rest of the acreage. But we can't give you -- we don't have a fixed number on how many of each category are in each zone.

All right. Fair enough.

Next question is, your vertical rig and your new venture, can you talk a little bit about what's going on there and potential upside associated with that program?

No. It's too early for us.

We're spending a little capital there in one-off drilling, but it's way too early for us to spend much time, much capital, or talk about what we're doing there.

Okay. And are you guys seeing any potential for Hogshooter in your acreage?

That would be over in the Oklahoma, Anadarko, I think principally. And really not.

I'm missing some detail on the cost here, if we could just circle back. Can you provide what the current AFEs on the Upper Wolfcamp and Cline shale wells are today?

And can you remind me of the range on the Middle Wolfcamp and the Lower Wolfcamp that was publicly disclosed?

The range of cost?

Right. Sorry, total AFE cost.

Yes, we've pushed those out in a couple of different investor presentations.

I think the last one was in October, so it's really fresh data.

Yes. And directionally, the Cline is about $1 million a well more.

We're using effectively the same AFE for the Upper, Middle and Lower. And it gets a little confusing when you ask for a specific AFE.

We can tell you what it costs for a lateral link in a certain number of stages that may or may not be what we actually -- how we actually drill it and complete it .But if you were kind of splitting the difference on a 6000-foot Cline well, with kind of 22 or so middle-of-the-road stages, you're talking 9 5. If you are looking at an Upper, Middle or Lower Wolfcamp well, 6000-foot and, again, somewhere around 22 stages, you'd probably be talking about 8 5, 8 6.

We are slightly biased toward longer laterals. So those costs will probably average more over the year.

Highly dependent upon the number of stages we do.

Okay. That's great.

That's very, very helpful. And then, can you revisit the discussion on recoveries per location, what you've seen so far, what you're modeling in terms of the Upper Wolfcamp and the Cline, and maybe discuss what you're seeing in terms of first year decline rate?

The first year decline rate is very steep. And again, we've pushed that data out in a couple of different presentations as far as 30-day IPs and what EURs are, and so on and so forth.

Actually, I'm not trying -- I think we've pushed it out there.

Okay. And then you expressed your resource potential known today in terms of 3x, the proved reserve base, which I believe is about 100 million BOEs.

I want to confirm that, if that's the basis of comparison. And then, should we expect updates going forward here using the same ratio?

Should we expect such step changes in the same resource potential estimate as more wells are drilled, greater production histories obtained and more data is collected?

Yes. I think at end of '11, which was our last Ryder Scott reserve report, we had something around 155, 160 million barrels, 156 million, something like that, of proven reserves.

And so, that's the 3x resource potential. But we fully expect, as we further delineate the Lower, the Middle and also the Upper and Cline over the rest of that acreage, that resource potential grows.

Okay. And then last one for me.

Why present the daily rate on the horizontal wells on a per-stage basis? And will that be the convention going forward here?

It's somewhat uncommon, is why I asked.

We're actually trying to show data that's meaningful, so our 30-day IP average -- I think we as a company culture don't like to talk about 24 IPs, 7-day IP. We would like to talk about 6-month average production.

So the 30-day average IP is kind of a compromise on trying to describe what the wells are capable of, yet not be too aggressive and talk about single-day or 7-day averages. Culturally, we would like to talk about much longer than 30 days.

One follow-up. 2013 -- I guess, if you could come back to 2013, which I recognize you haven't given yet.

But can you give us any direction on CapEx? Are you thinking up, down, sideways?

We actually think we'll have that guidance out well before year-end, David. But it's hard not to see CapEx be at least what we've spent, if not more, given the thousands of locations, both vertical and thousands of locations horizontally, that we think we've captured out there and put into some sort of mode where we need to start implementing.

Thank you, Carissa. This is actually Rick Buterbaugh.

As Randy just mentioned, we will be releasing our 2013 capital and production and cost guidance by year-end and expect to release our fourth quarter and full-year financial and operating results by mid-March. I'd like to thank you for your time and interest in Laredo this morning.

This concludes our call.