Vital Energy Inc (VTLE) 2012 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the third-quarter 2012 Laredo Petroleum Holdings, Inc. earnings conference call. My name is Carissa, and I will be your operator for today. At this time all participants are in a listen-only mode. We will be conducting a question-and-answer session after the financial and operations report. As a reminder, this conference is being recorded for replay purposes.

It is now my pleasure to introduce Mr. Rick Buterbaugh, Senior Vice President of Investor Relations. You may proceed, sir.

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 risk 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 two-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 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 the 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.

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 will now turn the call over to Randy Foutch to begin our discussion of 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 is exactly what we have been doing on the roughly 190,000 acres we have amassed in the oil and liquids rich Permian Basin.

We have been concentrating our activities within our core Garden City area of Fairway, which represents approximately 140,000 net acres of that total. To date, alongside our vertical drilling program, we have identified four 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 de-risk 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 a quarter of our effective acreage position which we consider we have four potential zones on 140,000 acres, or the equivalent of one producing horizon over roughly 560,000 acres.

We are aggressively working on our plan over the next 24 to 36 months to de-risk the remaining acreage, not only for the Cline and the Upper Wolfcamp, but as you will 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 are 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 de-risk and define the ultimate potential from all four 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 the horizontal development plan to optimize the drilling of the Cline and Upper Wolfcamp acreage that has already been de-risked, 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 am very excited about the expanding opportunities the team is uncovering.

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

Thanks, Randy. Good morning. Our production volumes for the quarter came in at 30,835 barrels of oil equivalent per day. That was up 27% year-over-year. Much of our production increase came from our focus on the oil in the Permian Basin, and we expect to continue to focus activity on our 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 2000 to 2500 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 three additional downstream pipelines. This stairstep type 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 three 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 the long -- over the long run, these longer 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 costs.

In the Upper Wolfcamp we have completed 16 horizontal wells to date; 10 of these wells have lateral lengths 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 lengths 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 lengths approaching 7000 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 three 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 will 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. If you 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 costs contributed to adjusted EBITDA of $110.8 million for the third quarter, up 11% from a year ago. Laredo continued to see improvements in it 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 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.

DD&A expense for the third quarter totaled $63.9 million, or $22.53 per BOE. This DD&A rate has increased due to a handful of factors, most notably, number one, the transition to higher value oil reserves which include higher costs, and number two, 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 $22.00 per BOE to $23.00 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, and 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 will borrow an additional $35 million on our revolver during the week of November 12th.

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 have obviously included the details in the footnotes to our third-quarter 10-Q all the details on our hedge positions if you would 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 will turn it back over to Randy for some closing remarks, and then we will take your questions. Thank you.

Thanks, Mark; thanks, Jerry. Before we open up the line for Q&A, let me just add a few summary points, takeaway summary points for the quarter. Laredo has now de-risked 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 de-risk 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.

Third point I would 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 will leave you with is that we have been aggressively evaluating and defining our acreage, resulting in a current outspend of our cash flow. We believe this is appropriate for the meantime. However, as we expressed in the past, we are very committed to retaining our strong financial position.

With that, I think, operator, we will open up the lines for any questions.

(Operator Instructions) David Tameron, Wells Fargo.

Hi, morning. Can you guys talk about -- you gave us the frac stages and I know in your presentation you give more detail 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 feel? Or can you just talk more about -- expand a little bit more on that?

Hi, this is Randy. Thanks for the question, David. I will take the first crack and then see if Jerry wants to add anything. But I don't think we have quite optimized the frac, not only in terms of the number of stages but also I think we are still some work left to be done on how much water and how much sand.

So we are getting a lot closer to the optimization then we were even three or four, six months ago. But we do know that early on, we were not dense enough. We have dramatically increased the amount of sand we are using, but I think there is still work to be done.

Jerry, you want to add anything?

No, I mean our standard with about 7000 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 is going to be your approximate mix of horizontal and vertical? Any other changes we should expect over the next three to four 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 specifically on where to land.

As you know, we have only booked I think less than 30% of those locations on our proved reserve category. There is tremendous value to drilling those verticals, so I think there is probably a bias to slightly more horizontal wells out there. But there will be a big component of verticals.

All right, let me ask one more and then I will let somebody else jump on. Infrastructure, obviously you addressed it, it sounds like for the fourth quarter. Are you guys -- what is the snapshot of infrastructure over the next two to four quarters, realizing that obviously it is a stairstep and you're going to be adding more as the process goes along? But can you just talk about how you shape up kind of as the calendar turns into '13?

We are actually reasonably comfortable, David, on where we are with infrastructure. You know, there were some highline pressures which we took care of inside the field by taking a lot of gas lots of different places. And there is 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 is going to dramatically help us.

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

Yes.

Okay, all right. I will let somebody else jump in. Thanks for the color and answer.

Brian Singer, Goldman Sachs.

Hey, good morning. When you look at the Upper Wolfcamp area that has been de-risked -- I guess it's about 60,000 acres -- how much of that is also prospective for the Lower and Middle Wolfcamp? Or can you give some broader comments on areas in which you have some confidence in multi-zone potential?

Yes, we think over most of that 140,000, if not all, the potential exists for all four 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 have done some vertical single-zone testing. So the database suggests that there is strong indications that the entire 140,000 plus acres may have all four 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 two zones.

The two wells we have, one in the middle, one in the lower, also overlap. So today we are still thinking that all four zones exist on the majority of that acreage.

That's helpful. And then looking at the Cline specifically, can you just talk directionally where you are 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 some acquisitions, kind of add-on acquisitions. And where we bought acreage, that was very highly prospective within our baileywick. As far as our drilling, our goal is to balance the development activities that we have captured with also trying to extend the Cline and the other three zones to the rest of the acreage.

So we will be drilling some wells across our entire acreage base for all four zones over the next future months and quarters and years.

Okay, thanks. 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 the processing and infrastructure is in place? And do you anticipate any delays there or any other disruptions such as what we have seen for you and others as we go into next year?

I 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. This is Dan Schooley. 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 two compressors that Atlas is going to put in at their new coal ranch compressor 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 apiece.

And then by the end of December, Targa is going to have a 30 million a day expansion done on their Sterling Plant. Again, that is directly connected to Laredo's production. So we feel pretty good about the balance of '12 based on what we have already done to offload some of the highline pressure areas we had. And then these expansions, we think we are 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 line pressures even further.

Targa -- I mean DCP is on track apparently to get their Rawhide Plant up and running at 75 million a day by July. That plant is 10 miles north of our main line 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 on line that is going to directly impact our production.

And then finally, in '14, probably July of '14 is what they are 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 are 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 two 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 Sand Hills, 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 kind of answers the question why I just don't have a tremendous amount of concern for it. I think what we are 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 supply issues.

Got you. That's really helpful. Thank you.

John Herrlin, Societe Generale.

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

We have 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 is a lot of similarity petrophysically, in the core data, in the electric log, in the ELS logs we've done; but we do know that there will be some differences. It just can't be the same across that 75 plus mile long acreage base.

We have seen some GOR, a few percentage points differences. So we are not expecting anything of any substance where things just completely change, but we know there is going to be some differences. We do show in our presentations that on the Eastern part of the acreage there is a facies change. We don't know if that is good or bad yet, but we will figure it out. When it is appropriate, we will drill some wells there and 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 vertical so you can see the facies 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 the verticals add substantively to our comfort and de-risking. But keep in mind we have 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 well costs running completed? Are you seeing, given what is going on in the services industry, are you seeing costs come down?

I will 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 we have actually seen pipe costs drop off maybe 5% to 10%. So we are realizing some cost savings compared to what we 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 are actually seeing historically it cost us. If we see prices stay down for a long time, we will change our model. But with a 10-plus-year drilling inventory, I am 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 would be running more science than normal. So I was wondering what you thought your overall completed well costs would be when you're in more of a development mode.

Yes, we are still doing some science. And I think I answered your question, John, in saying that we are pretty much going to use the AFEs we have. We don't forecast that three years from now, we will be able to dramatically change AFE cost. We think over time, costs go up.

Thanks.

Thank you.

Abhishek Sinha, Bank of America.

Yes, hi. I just have a broad level question here. So basically, I just again noted that you added a little bit more acreage in the Permian, and then there was some more acreage throughout the portfolio. So basically, I'm just looking like what plans do you guys have to basically bring the growth forward and bridge the gap between the long-dated inventory that you already have and the NAV that we anticipate?

There is 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 have learned in Garden City and apply it to that acreage.

We were very early entry into those acreage acquisitions. We got in pretty cheap. We are 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, yes. So this is just a follow-up. So outside the Permian, where else did you have acreage?

It was pretty much all in the Permian.

It was all in the Permian? Okay. So just wanted to see in terms of your targeted debt to EBITDA and targeted debt-to-cap, do you have a number or something over there that you feel comfortable with?

You know, we look at debt all kinds of ways. The primary one is probably debt to EBITDA. We are well below 2.5 times. We have said publicly that we expect the debt level, as we continue to explore our acreage, to be in the 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 are certainly in a very conservative position right now.

Sure, sure. Thanks for that. That's all I have for now. Thank you very much.

Thank you for the questions.

Timm Schneider, Citigroup.

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

We do, and it is 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?

Yes, 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, thank you. And then my last question is kind of what are you guys seeing on the acquisition side? Anecdotally, there has been some chatter that a lot of these smaller private guys are getting kind of 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 have seen as many deals come around as we have seen lately. Certainly it seems to me like there is a lot of acquisitions floating around for sale. And we look a lot and we keep getting interested and spending time on them, but we keep coming back to one of our core tenants and beliefs is that for us to make an acquisition of any kind, the economics have to be as good or better than what we have.

And that is 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 have already captured and we're pretty convinced we have the potential for the four zones over most of the acreage. So for us to make an acquisition, we are going to have to buy it -- it has to be a very, very good property set, and we're going to have to buy it relatively cheap.

So I think we are looking and we would like to do it, but I think it is a pretty high barrier for us to buy one.

Okay, that makes sense. Hey, that's it for me. Thank you.

Daren Oddenino, C.K. Cooper.

Good morning

Good morning, you guys mentioned you're going to have four to five horizontal rigs. What is the mix of wells you are 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 a well or two 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. 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 it, a fixed number on how many of each category are in each zone.

All right, fair enough. Next question, your vertical rig in your new venture, can you talk a little bit about what is going on there and potential upside associated with that program?

No, it's too early for us. We are spending a little capital there and one-off drilling, but it is way too early for us to spend much time, much capital, or talk about what we are 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.

Okay. All right, that's all I've got.

Dan McSpirit, BMO Capital Markets.

Thank you, folks. Good morning, and thank you for taking my questions. I'm missing some detail on the costs here, if we could just circle back. Can you provide what the current AFEs on the Upper Wolfcamp and Cline shale wells are today? Can you remind me of the range on the Middle Wolfcamp and the Lower Wolfcamp that was publicly disclosed?

The range of costs?

Right, sorry, drill and complete costs.

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

I think the last one was in October, so it is real fresh data.

Yes, and directionally the Cline is about $1 million a well more. We are 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 length 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 were looking at an Upper, Middle or Lower Wolfcamp well, 6000 foot, and again somewhere around 22 stages, you would probably be talking 8.5, 8.6. We are slightly biased toward longer laterals, and 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 have seen so far, what you are modeling in terms of the Upper Wolfcamp and the Cline; and maybe discuss what you are seeing in terms of first-year decline rate?

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

Okay.

Not trying to -- I don't -- 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 BOE. I want to confirm that, if that is the basis of comparison.

And then should we expect updates going forward here using the same ratio? Should we expect step changes in the same resource potential estimate as more wells are drilled, greater production history is 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 million, 160 million barrels, 156 million, something like that of proven reserves. And so that is the 3 times 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 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 is somewhat uncommon, is why I ask.

We are actually trying to show data that is 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 six-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-day.

Okay, many thanks.

David Tameron, Wells Fargo.

Hey, Randy, one follow-up. 2013, I guess coming back to 2013, which I recognize you have given yet, but can you give us any direction on CapEx? Are you thinking up, down, sideways?

We actually think we will have that guidance out well before year-end, David. But it is 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 have captured out there and put into some sort of mode where we need to start implementing.

Okay. No, that's helpful. I appreciate that. Thank you.

There are no further questions at this time. I would like to turn the call over to Randy Foutch for closing remarks.

Thank you, Carissa. This is actually Rick Buterbaugh. But 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 would like to thank you for your time and interest in Laredo this morning. This concludes our call.

Thank you very much. This concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.