Vital Energy, Inc.
Q4 2013 Earnings Call Transcript

Published: 27 Feb 2014

[Executives:]

Ron Hagood Randy A. Foutch - Founder, Chairman and Chief Executive Officer Jay P. Still - President, Chief Operating Officer and Director Richard C. Buterbaugh - Chief Financial Officer, Principal Accounting Officer and Executive Vice President Patrick J. Curth - Senior Vice President of Exploration & Land

[Analysts:]

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division Gilbert K. Yang - DISCERN Investment Analytics, Inc Joseph Bachmann - Howard Weil Incorporated, Research Division Jason Smith - BofA Merrill Lynch, Research Division John P. Herrlin - Societe Generale Cross Asset Research Jeffrey Connolly - Mizuho Securities USA Inc., Research Division

[Operator:]

Good day, ladies and gentlemen, and welcome to the Laredo Petroleum, Incorporated Fourth Quarter and Full Year 2013 Earnings Conference Call. My name is Michele, and I'll be your operator today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. And it's now my pleasure to introduce Mr. Ron Hagood, Director of Investor Relations. You may now proceed, sir.

[Ron Hagood:]

Thank you, Michele, and good morning. Joining me today are Randy Foutch, Chairman and Chief Executive Officer; Jay Still, President and Chief Operating Officer; Rick Buterbaugh, Executive Vice President and Chief Financial Officer; Pat Curth, Senior Vice President, Exploration and Land; Dan Schooley, Senior Vice President, Midstream and 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. In addition, we'll be making references 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 today's news release. As a reminder, Laredo reports operating and financial results, including reserves and production on a 2-stream basis, which accurately portrays our ownership of the oil and natural gas produced. Therefore, the value of the natural gas liquids is included in the natural gas stream and pricing, not as part of the oil and condensate or included in a combined liquids total. Reported on a 3-stream basis, Laredo's barrel of oil equivalent volumes for reserves and production, including initial production rates and EURs would increase by 15% to 20%, which you should keep in mind when comparing the companies that report on a 3-stream basis. Similarly, 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 a news release detailing its financial and operating results for the fourth quarter and full year of 2013. 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'd now like to turn the call over to Randy Foutch, Chairman and Chief Executive Officer.

[Randy A. Foutch:]

Thanks, Ron, and good morning, everyone. Thank you very much for joining us for Laredo's fourth quarter and full year 2013 earnings conference call. 2013 was an exciting year for Laredo with many significant accomplishments, which we believe have enhanced the value for our shareholders. We grew Permian production and reserves, we've redeployed capital and talent from Anadarko Basin properties into the higher return opportunities in the Permian, confirmed the development plan for our Garden City acreage and began to transition into full scale development. We also strengthened our financial position to enable this acceleration of development drilling, bringing forward value in our Permian-Garden City acreage. Laredo's Permian Basin production for the full year of 2013 averaged 24,960 barrel of oil equivalent per day, up 21% from comparable 2012 volumes, with oil production as a percentage of total production of approximately 59%. Our drilling success added 69.9 MMBOE of proved reserves at an F&D cost of $12 a barrel. These reserve additions replaced nearly 500% of total production and well above the reserves divested in the Anadarko Basin sale. As a result, our total reserves grew to a record 203.6 million BOE, of which approximately 55% are oil and 45% liquids-rich natural gas. Pretax present value of our reserves increased to $3.1 billion, up approximately 30% from year end 2012 and up more than 40% in the Permian. As I mentioned, divestiture of the Anadarko Basin allowed us to accelerate the value accretion in the Permian Basin. After confirming the equivalent of 360,000 net acres for horizontal development from our 4-stack zones during 2012, we focused our efforts in 2013 on several of the key initiatives to enable us to begin the full scale development of our Permian-Garden City asset. We modeled and confirmed the initial and development spacing of the lateral, both horizontally and vertically. We designed our horizontal development plan for predominantly multi-well pad drilling, and we implemented initiatives to appreciably reduce cost. And we began the build out of the infrastructure necessary to efficiently move resources around our leasehold and to market. We believe that investment in this infrastructure will pay significant dividends in our ability to ramp up activities in an efficient and cost-effective manner. Laredo has been drilling horizontal wells in the Permian Basin since 2009, and we've completed our first long lateral horizontal well in 2012. We have a significant amount of long-term production data that supports our top curve for all 4 zones. Laredo's commitment to a deliberate science-based approach has positioned us well to execute our 2014 program and transition into full scale multi-zone development of our Garden City asset. I will now turn the call over to Jay Still, President and Chief Operating Officer.

[Jay P. Still:]

Thank you, Randy. Operationally, we accomplished a great deal in the quarter, despite having to overcome significant disruptions in drilling and production operations resulting from severe winter storm. Drilling operations were curtailed for close to 2 weeks in production and a majority of our wells were shut in for up to [ph] 3 weeks. Thanks to some outstanding work by field personnel, we were able to have operations almost back to normal by the end of the year, and disruptions in the first quarter were minimized. In the fourth quarter, we completed 15 horizontal wells. Significantly, 11 of these wells were on common pads and varying configurations. On well completions chart in the press release, we've indicated the wells that were drilled on common pads by grouping them together with a notation at the end of the well name. Thus the 2 wells that have an A notation were drilled on a common pad and so on through letter E. The severe winter weather we experienced in the fourth quarter did have a negative effect on our 30-day IP rates for these wells due to the power interruptions, compressor performance and lack of trucking availability. However, we have stayed with our consistent approach on how we present our 30-day results and have not attempted to adjust these results to reflect the interruptions. We do not believe that there will be a long-term performance impact on these wells. In Middle Wolfcamp, we doubled the number of wells completed in the zone. The 6 Middle Wolfcamp development wells, on average, are currently exceeding our Middle Wolfcamp-type curves at 650,000 BOE EUR. The other development wells completed in the Upper and Lower Wolfcamp zones are, on average, performing as expected in relation to the respective-type curves. The exploratory Middle Wolfcamp well testing the northern corner of the Glasscock County with a known facies change was disappointing. However, this area is not included in our de-risk acreage nor does it impact identified drilling inventory. We're currently completing our first Spraberry well with announcement of the results when we have meaningful data. While we report 24-hour IP and 30-day average well rates, we believe the long-term production performance is much more indicative of the wells' ultimate recovery. Since Laredo began drilling lateral wells longer than 6,000 foot, we have completed 32 wells with at least 180 days of production history and 23 wells with over 1 year of production history. As you can see from the table on Page 3 of our press release, the average results from our Wolfcamp wells are exceeding the company's respective type curves. While the time wells' performance is currently below expectations, the last 2 completions in the zone are at 125% of the company's client-type curves through 180 days of production. We currently have 6 rigs working in the field, and we'll be drilling multi-well pads throughout the remainder of the year. Our 7th rig is expected to be on location at the end of this week. In anticipation of these rigs arriving, we have predrilled the surface holes with 2 spudder rigs and are completing the intermediate section of the hole with a vertical rig. This will help accelerate the completion and production of these wells. Operational efficiency initiatives this past year have resulted in reduction in our drilling and completion cost of 5% to 10% across the field. Improved well design and construction and implementation of well automation have reduced the amount of required workovers. Laredo's Reagan County Wolf Station and the first production corridor should be operational early in the second quarter. This is an 8-mile right of way that will allow us to move oil, gas and produce water off location via pipes and return water from completions, process high-pressure gas for artificial lift and process low-pressure gas for fuel to refuel our rigs. This will allow us to drill, complete and produce our contiguous acreage position for several rigs along long lines of development. The installation of this production corridor has provided the ability to convert our first of many rigs to natural gas fueling this quarter resulting in a savings of approximately $3,000 per day in diesel costs. Our water recycle facilities supporting this corridor is expected to be operational in the fourth quarter. I'd like to turn the call over to Rick Buterbaugh, EVP and CFO.

[Richard C. Buterbaugh:]

Thank you, Jay. As stated in this morning’s news release, Laredo reported fourth quarter 2013 adjusted net income of $19.1 million or $0.13 per diluted share and adjusted EBITDA of $111 million. For the full year of 2013, adjusted net income of $75.7 million or $0.56 per diluted share and adjusted EBITDA increased to a record $472 million even following the divestment of our Anadarko Basin properties in August. Therefore, keep in mind that the fourth quarter was the company's first full quarter as a pure-play Permian producer. Total oil and natural gas sales for 2013 of approximately $665 million increased nearly 14% from the prior year sales amount. The increase reflects higher oil production and oil realizations that were offset in part by lower gas volumes following the sale of the Anadarko Basin properties. Fourth quarter oil and gas sales were essentially flat with the prior-year quarter as higher realized prices for both oil and gas offset the lower gas volumes following the sale. And oil volumes were unchanged in the period due to the storm impact that caused an approximate 2-week shut-in of our production in the 2013 quarter. In the fourth quarter of 2013, cash expenses for lease operating expense, production taxes, G&A, excluding stock-based compensation, totaled $18.57 per barrel of equivalent, down approximately $0.50 per BOE sequentially from the third quarter of 2013 rate of $19.09 per BOE. Higher oil production, as a percent of our total production coupled with higher realized natural gas prices, increased our average realizations to $68.24 per barrel of equivalent in the fourth quarter, which resulted in a cash margin of $49.67 per BOE, up from $46.39 in the previous quarter. Total expenses for lease operating, production taxes and DD&A declined sequentially from third quarter 2013 primarily due to the storm impact on total production volumes. In 2013, Laredo invested approximately $740 million in total capital expenditures, including approximately $37 million in bolt-on acreage acquisitions in the Permian Garden City area. This was in line with our budget of $725 million [ph], which excluded acquisitions. For 2014, our Board of Directors has approved a budget of approximately $1 billion, excluding acquisitions. We expect to fund this program through a combination of operating cash flow and existing cash on hand, which currently stands at approximately $625 million. This cash, coupled with our undrawn credit facility, provides the company with approximately $1.4 billion of total liquidity today. We believe that this liquidity, coupled with our anticipated internally generated cash flow from operations, provides us a clear path to fund the accelerating development of our Garden City asset in the near term. We expect to continue to use derivatives to underpin our cash flow and our capital programs. As described in this morning's news release, we have recently added to our hedged gas volumes for 2014. We currently have floor protection on approximately 75% of our expected oil production and approximately 40% of our projected gas production for 2014. We also recently unwound a 4-year physical contract and corresponding basis swap that effectively provided pricing of grant less $7.75 per barrel. We unwound this transaction due to our counter-party's decision to exit the physical commodity trading business. And this resulted in the company receiving net proceeds of approximately $77 million. This transaction will be reported on our first quarter results and be classified as an early termination of derivative instruments and included in our adjusted net income. This morning, we also issued production cost guidance for the first quarter and full year of 2014. As we have discussed previously, our transition to full-scale development using multi-well pads of 2-, 3- and 4-stack wells on single pad will cause the cycle time from the spud to first production of this pad to lengthen. As we are ramping up this program, our production growth has become more lumpy and will certainly be weighted towards the second half of 2014. As a result, we expect unit costs will continue to trend down throughout 2014. At this time, Michele, would you please open the lines for any questions?

[Operator:]

[Operator Instructions] First question we have comes from the line of Ryan Oatman from SunTrust.

[Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division:]

I want to go back to 4Q and try and get a feel for how bad the storm set you back. With about 2 weeks offline out of 13 weeks, I mean the impact seems pretty significant. Have you guys looked at that in a barrel equivalent? And do you have any thoughts on kind of what that disruption meant on a production per day basis?

[Randy A. Foutch:]

Yes, we had, as I mentioned on the call, we had a majority of our wells down 2 to 3 weeks. That equated to 2,500, 2,800 barrels a day. We were off the quarter.

[Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division:]

Okay. That's very much helpful...

[Richard C. Buterbaugh:]

And Ryan, let me just add. Based upon your -- the fact that we were down about 2 weeks on a significant piece of the production, and volumes were impacted probably for 3 weeks, if you essentially annualize or take the 24,000 barrels of oil equivalent per day of production that we reported and gross that up, that would have been the equivalent to about 28,900 barrels of oil equivalent per day without that downtime. So that gives you a framework around what the production could have been.

[Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division:]

Right. So I mean it could have been anywhere from 2,500 to, let's call it, 5,000 barrels a day potential impact. Taking that into account, you're looking at 2014, the guidance does imply a heck of a ramp from about 27,000 barrels of oil equivalent per day in 1Q to an average of 33,000 just to get to the low end of guidance. Can you speak with -- to your comfort level around guidance given the recent Permian disruptions and whether we should be expecting output towards the low end, kind of how production looks throughout the year? How it looks now, how 4Q can look? Just trying to get a feel as to the production ramp throughout 2014. And I'll abide by the 2 questions limit and hop back in the queue.

[Richard C. Buterbaugh:]

As we've stated in the past, our production and even prior to the storm impact that our production was going to be very stairstep growth throughout 2014. Starting -- initiating the process of transitioning into these multi-well pads where we're going to now be drilling up to 4 wells on a single pad, you're deferring the production impact from that first well until all 4 wells are completed and ready to be produced. As a result, it could take up to 6 months before a pad begins and actually comes on production. Since we began this transition to multi-well pads really primarily in the fourth quarter of 2013, we knew all along and expected all along that our production growth is going to be very weighted towards the second half of 2014. So we are still very comfortable with our overall annual guidance for 2014. You're going to see very lumpy growth, and we will give guidance on a quarterly basis as we report each quarter's results.

[Operator:]

The next question we have comes from the line of Gil Yang.

[Gilbert K. Yang - DISCERN Investment Analytics, Inc:]

A couple of questions. Randy and Rick, you guys are very analytically focused. Can you talk about -- in the context of that delayed onset of production, can you talk about the pluses and minuses, the benefits and problems associated with the -- to the rate of return given the fact that you have a lot of capital sitting in the ground for 6 months before it actually starts producing -- offset by the cost benefits that you're getting from the pad drilling?

[Randy A. Foutch:]

We've obviously looked at that as you kind of indicated a number of different ways. And there's a couple of points that I want to, that I'll make and then I'll see if Jay or Rick wants to respond. We believe that the efficiencies of the pad drilling in terms of just simple cost reduction is meaningful. Obviously, with -- the issue is going to be, if you have one of the laterals has a problem and you have to delay completions on the other laterals then that could impact it, but we kind of feel like we've modeled in some of those kind of issues that we've talked about in the past. So on the one side just the efficiencies of pad drilling should help us substantially on the cost. We've talked about that and has a rate of return impact. The other point that I'll make is that there's also a very pragmatic practical view in that we can set up in our production corridors. We can set up water handling. We can set up frac, tanks and ponds and recycling and really be very, very efficient in how we utilize those kinds of resources and shorten greatly the time that it takes us and the cost of doing those kind of things. So our pad drilling is based both in terms on the of rate of return, but just our ability to move fluids, including water, around inside our production corridors. So we're -- we feel like we've -- are well ahead in understanding how we need to do that. And we built out those production corridors. We built out the one, and we'll be building out others. Jay, do you want to add anything to that?

[Jay P. Still:]

Yes, the other thing you have to take into account, Gil, is if you drill 1 well, say in the Upper Wolfcamp, and you bring it on production, when you come back in to drill the Middle, Lower or any other bench, you're 25-foot away from a wellhead that's actively producing. So you would essentially have to shut that well in anyway. So it's much more practical to go ahead and knock out the wells you're going to drill that are in close proximity, so you don't have long-term impact of shutting those wells in, while you have an active drilling operation in the near vicinity.

[Randy A. Foutch:]

Yes, one last one, and that is there is some argument and some data that suggest you get a better frac and stimulation when you're stimulating zones that have basically virgin pressure. And there's some suggesting that kind of back in later, if there is a minor fracture or something that sees both wellbores, it makes it difficult to frac the original pressure reservoir.

[Gilbert K. Yang - DISCERN Investment Analytics, Inc:]

Great, that's a very helpful answer. Can you talk a little bit about the facies change that you mentioned regarding that Glasscock County well? What were the problems associated with that facies change? Were you -- with the facies change, is that going to be positive or negative for that well? And what your sort of outlook is after that, following that result?

[Randy A. Foutch:]

I'll address it from 50,000 foot and let Pat comment -- let Pat Curth comment if he wants to. We said early, early on that on the very, very northeast end of that, that we saw carbonate increase a few percentage points in the, our acreage. And it's -- that well represent something like 12,000 acres. However -- and we said that we didn't understand if that was going to be negative or positive. It has some good things, but we didn't understand how much oil in place kind of changes that made and whether or not it would be delivered. But the point I want to leave there is that we're still going to drill some vertical wells on there. And we still have -- we're still evaluating other horizontal possibilities, so that's 12,000 acres on the northeast end of the county that in the Middle Wolfcamp, 1 well, which doesn't make or break a play, either good or bad, was disappointing. We're not done yet looking at that acreage by any means. Pat, did you want to add anything?

[Patrick J. Curth:]

As Randy said before, we mentioned the facies change. It's been a while back, and this was our first test. It's related to where the shelf edge is, and we will continue to look at that. We need to step back and understand the petrophysics better and understand how we complete those wells. So the results indicate that we had more work to do, but certainly don't condemn that acreage by any stretch of the imagination.

[Gilbert K. Yang - DISCERN Investment Analytics, Inc:]

Did you mean that you're not condemning the Middle Wolfcamp, or are you giving up on Middle Wolfcamp and you're just focusing on the other horizons at this point?

[Patrick J. Curth:]

No, we're not giving up on the Middle Wolfcamp at this time. We have to drill -- we're going to step back and look how we completed that well, see if we should have done something differently. We're going to go back, as I said, and reanalyze our petrophysical data. There's some changes there, no doubt about it, in the rocks, doesn't mean that it's negative. It just means that we need to understand it better before we write-off any zones. So no, I would not say at this time we're done with the Upper Wolfcamp in that area.

[Operator:]

The next question we have comes from the line of Jeb Bachmann from Howard Weil.

[Joseph Bachmann - Howard Weil Incorporated, Research Division:]

Randy, I was just wondering if you could provide what the commodity mix was on those 365-day type curves that you guys outlined in the press release, if they were still consistent with what you were expecting.

[Randy A. Foutch:]

I'll let Dan or Jay give you the details. We fully expect -- there's going to vary some a little bit up and down the field, and also quite frankly, quarter-to-quarter depending on exactly what we're doing. But we're pretty much on track. Fundamentally, things are going as we said they were going to go a couple of years ago. Jay, do you want comment on what the mix really was?

[Jay P. Still:]

We see the wells performed right on as our type curves were played out. We've had no real surprises in the performance of our recent wells.

[Joseph Bachmann - Howard Weil Incorporated, Research Division:]

Okay. And then I guess a follow-up, looking at year end '13 and the booked EURs, are you guys using the higher percentages, or are you -- or kind of using what you said in the past for those Wolfcamp wells?

[Randy A. Foutch:]

I don't think we've seen any significant data deviating that would make us want to change what we're using as far as type curves or 1% or 2% change in oil content this early. It doesn't change us up or down. So I think the message is it's coming around about like we thought it would.

[Jay P. Still:]

Keep in mind, when we bring these wells on the oil percentage is 75%, 85% and as you produce these wells, the gas content will come up in a matter of months. And it'll settle into the 60%, 58% -- through its life. So but the oil -- the GOR does change from initial production through the life of the well.

[Richard C. Buterbaugh:]

And just as a reminder, Jeb, Ryder Scott prepares our reserve report as -- which is consistent with our own internal estimates, which takes into account those changes over the life of the well.

[Operator:]

The next question we have comes from the line of Jason Smith from Bank of America Merrill Lynch.

[Jason Smith - BofA Merrill Lynch, Research Division:]

I have a question on the client wells, with the last 2 wells actually trending above your type curves. Is there anything you guys changed in terms of completions or anything like that versus what you guys are doing previously?

[Randy A. Foutch:]

Not really. I'll let Jay back it out. We've stated before that we needed to see more than 1 or 2 wells to really understand the curve. We had -- we could talk long and hard about our 4,000-foot Cline and Penn State fracs and what we learned and how we view those wells, which are clearly economic and the learning curve that we've gone through from there to where we are today. But our view was that the overall curve, if you count the last 2 wells, which we don't have a year of production on, and I've said more than 1 time that I'd really like to see 6, 9, 12 months before we talk. These 24 IPs just don't matter at the end of the day. So I'm relatively comfortable that our Cline and the other EURs are holding up as we get more data. If we need to adjust down some or up some, we will, but the Cline is pretty economic.

[Jason Smith - BofA Merrill Lynch, Research Division:]

Okay. And then on your -- I know delineation is still -- I mean it's not a huge part of the program. I think it's 10% of the CapEx and following the Glass well. What's the plan in terms of where you guys move next? I mean are you going to move further west, or are you going to stay in that area?

[Randy A. Foutch:]

We're really, in 2014, playing the year as the year that we're going to do significant development in pad drilling within the core area. So the majority of our budget is going to be in that core area. And it's going to be development and pad drilling. As mentioned, we do have a Spraberry test that we just literally started the completion on. We've talked a little bit about delineating the rest of the acreage. We've talked a little bit about -- at some point, we need to test the Atoka, Beaver area. We need to test the Canyon. The message that we'd like to convey is that in the de-risked acreage, we've still got thousands of vertical wells and thousands of very, very economic horizontal wells to drill. We recognize that we haven't de-risked either the additional acreage outside of that core area we call de-risk. We recognize that we have other zones up and down the wellbore that we need to test. But our view is that the majority of our funds should be spent in what we think is really going to make the most value for shareholders. And that's the stacked lateral pad drilling in the development area.

[Operator:]

The next question we have comes from the line of John Herrlin from Societe Generale.

[John P. Herrlin - Societe Generale Cross Asset Research:]

With respect to your drilling program, are the horizontal and vertical well camps going to be evenly distributed during the course of the year, or is there certain seasonality? That's question 1. And question 2, with the stack pad completions at the end of say, the second quarter, how much of a volume ramp are you willing to talk about since you're going to be adding a lot of high-volume wells? How much of a pop do you get at the end of the quarter by approaching things this way?

[Richard C. Buterbaugh:]

As far as the allocation of the wells, the vertical wells will be fairly consistent across the 4 quarters. We anticipate drilling approximately 125 gross vertical wells. On the horizontal wells, although the drilling will be relatively consistent, the completion and bringing them online will be fairly lumpy. And that's what's driving the lumpy production growth. Although we're very comfortable with our overall guidance for the year, we will give guidance on a quarterly basis for production as we move through each quarter of the year. And the reason for that is that bringing on these large pads, these 3-well pads, the 4-well pads, we're going to see a sizable uptick in production when those pads come offline. Just from a timing standpoint, if a pad comes online very late in the quarter, it obviously, it's not going to have that much impact in that quarter. But a 2-week delay or acceleration in a pad coming on online or being deferred for 2 weeks can have a significant change in a quarter's production. And that's why we're giving guidance quarterly as we step through the year. As I mentioned though, you really should not anticipate seeing significant production growth until the third quarter. By the time when we're discussing the second quarter, the pad should be coming on late in the second quarter probably not a whole lot of impact to that second quarter volumes, but certainly major impact to the third and fourth.

[Operator:]

[Operator Instructions] We have another question and that comes from the line of Ryan Oatman from SunTrust.

[Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division:]

Looks like that Wolfcamp B step-out was about as far north as you could get on the acreage position. You talked about what that means for that 12,000 acres kind of around that area. Obviously, there's some acreage in between that, that you've successfully tested horizontally for the Cline. How does that acreage differ between kind of let say, Northern Reagan where you've had Wolfcamp A, B, C success and kind of the acreage in, I'm going to say, the South Central part of Glasscock County as opposed to that northern acreage that you tested this Wolfcamp B on?

[Randy A. Foutch:]

Ryan, we call that well Middle Wolfcamp, and that's the terminology that we use within the field, so I'm comfortable using that. As we identified early on, that well was in an area where we recognized the facies change back literally when we were buying the acreage in 2008, 2009. We just weren't clear what it meant, and we've got vertical wells up there that are decent wells. All across our acreage, we now have 900 vertical wells, and I don't know, 300-and-something plus deeper vertical wells that go all the way through, in most cases, the Atoka; in some places, deeper. And what we've said is that we've identified that facies change numerous times and said, "Well, we're not sure what it means." I'm not sure that we now know what it means. We'll go back and re-study that, but our view is that clearly in the area that we call de-risked, and part of that acreage between our core area and this well, we've de-risked with the Cline with our drilling. We have not drilled that many Wolfcamp horizontal wells in between there. But based on what we've seen from that plethora of vertical drilling, 3D, our core work, our single-dome testing, when we get to it, we fully expect a lot of that acreage to become de-risked and only add to our drilling inventory.

[Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division:]

Okay, that's helpful. And then one kind of unrelated question for me. Some Cline wells below the curve, some recent ones below it. Even the ones that are below curve, can you kind of speak of the EURs and IRRs for those 4 wells, let's say, that you have 365 days of production. Do you feel like there's still clear 10% to 15% rate of return threshold? Just kind of curious, your thought on the economics and EURs of those wells.

[Randy A. Foutch:]

I'll let Rick or Jay if they have better numbers. But we're not at all uncomfortable with the result of those wells. Obviously, you want better wells. We've always thought and characterized this as from well to well on that 80, 90 mile, 75-mile long acreage trend, we expect to be some differences. But we were confident based upon our well work that our averages were going to be about right. And if they're not, we'll change them in the future. So I think our view is that the Cline is still a very viable part of our go-forward plans here. We're certainly not backing off from it. We did do a lot more evaluation in the 12,000 acres, that's Northeast of that facies change. But we've addressed those kind of problems many times at this company and other company. So we'll work through that. But we're not backing off from lacking the Cline in any way.

[Jay P. Still:]

Yes, some of our best wells are the Cline wells. So in some of the areas -- we're talking about a pretty good geographical expanse of acreage. And the geology does change in some wells or better in the Cline than others. But they're all very -- all have very strong economics, and that will be a meat and potatoes part of our program.

[Randy A. Foutch:]

And just as -- well, like Jay said, if you go back and you look at our Analyst Day last September, where we talked about the top 20 wells, the Cline was very well represented in there. So we're happy with that.

[Operator:]

The next question we have comes from the line of Jeffrey Connolly from Mizuho Securities USA.

[Jeffrey Connolly - Mizuho Securities USA Inc., Research Division:]

Just a quick follow-up on the Cline. The 2 recent completions that are outperforming the type curve, did you do anything differently on the completion side? Or did you just land it in what might be a sweet spot on your acreage?

[Randy A. Foutch:]

We did not do anything significantly different on the completion. It's in a different part of the field. We've had great Cline results. As we progress and understand the rocks better, which we have a tremendous amount of horsepower going into understanding the rocks and technical data, we're understanding where the better parts of the Cline are in our field and focusing our Cline development in those parts.

[Operator:]

The next question we have comes from the line of Gil Yang from DISCERN.

[Gilbert K. Yang - DISCERN Investment Analytics, Inc:]

Can you talk about what the reduced workovers, how you achieve that and how that changes capital cost and LOE going forward?

[Randy A. Foutch:]

We've greatly reduced workover costs. We inherited a number of wells that were, in our opinion, not designed correctly to isolate corrosive San Andres water. We spent a lot of money early last year going in and repairing wells, doing subsequent cement jobs to protect the casing from the corrosive zones. That was one aspect of what we have done to reduce those well payers. The other is well automation and putting in pump-off controllers and those kind of things on wells to reduce cyclic loading on your tubing. Just automation and kind of refining our production operation has significantly impacted the number of workovers that we've had to do and pulling tubing, tubing failures and casing failures.

[Gilbert K. Yang - DISCERN Investment Analytics, Inc:]

Can you cite sort of a pennies-per-barrel benefit to LOE or...

[Jay P. Still:]

I think we're comfortable that we reflected that in our guidance. We did talk some over the last year or 2 about we had some bump-up in LOEs, and we expressed our thoughts that we were going to get on top of that and control it a little better. And I think what you're seeing in our guidance reflects exactly what our plan was in terms of automation and reducing not only workovers, but making sure that we were taking care of those wells, where the casing was and then writing things like that. So I think it's reflected in our guidance, just as we understand it.

[Gilbert K. Yang - DISCERN Investment Analytics, Inc:]

Was the -- where did you get on those wells last year in capital expenditures or in LOE?

[Randy A. Foutch:]

No, they were in LOE.

[Operator:]

The next question we have comes from the line of John Herrlin from Societe Generale.

[John P. Herrlin - Societe Generale Cross Asset Research:]

One last one on the horizontal wells for this year. Could you give us a breakdown, Wolfcamp, Cline or the different members of the Wolfcamp you'll be targeting?

[Randy A. Foutch:]

You're talking about going forward, John?

[John P. Herrlin - Societe Generale Cross Asset Research:]

Yes.

[Jay P. Still:]

The majority of our wells will be drilled in the Wolfcamp. We have, I guess in the middle part of Glasscock, we'll be focusing on the Cline and Upper Wolfcamp and Lower. In Reagan County, we'll primarily be focused on the Wolfcamp with a couple of Clines thrown in there.

[Randy A. Foutch:]

We have -- just talk about the 75% to 80% of those wells will be various Wolfcamps of the anticipated 75 wells that we have for horizontal wells that we anticipate for 2014.

[Operator:]

At this time, I would like to turn the call over to Ron Hagood for closing remarks.

[Ron Hagood:]

Thank you, Michele. We will report our first quarter [indiscernible] on Thursday, May 8. And we'll host an earnings conference call [indiscernible]. And that concludes our conference call. We thank you for your interest in Laredo Petroleum.

[Randy A. Foutch:]

Thanks, everyone.

[Operator:]

Thank you for your participation in today's conference. This concludes the presentation. You may now connect -- disconnect. Thank you for joining and enjoy the rest of your day.