Vital Energy Inc (VTLE) 2013 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Laredo Petroleum Incorporated fourth-quarter and full-year 2013 earnings conference call.

(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.

Thank you Michelle 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 of Exploration and Land; and Dan Schooley, Senior Vice President of 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 two-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.

On a three-stream basis Laredo's barrel of oil equivalent volume score reserves and production including initial production rates and the EURs would increase by 15% to 20%, which you should keep in mind when comparing the companies that report on three-stream basis. Similarly, Laredo's unit cost metrics will appear higher when compared to companies that report on the three-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 would now like to turn the call over to Randy Foutch, Chairman and Chief Executive Officer.

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 redeployed capital and talent from our Anadarko basin properties into the higher return opportunities in the Permian, confirmed the development plan for our Garden City acreage and began the 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 barrels 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 approved reserves at an F&D cost of 12 bucks a barrel. These reserve additions replaced nearly 500% of total production and well above the reserves divested of 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, the 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 four-stacked 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 development spacing of lateral, both horizontally and vertically. We designed our horizontal development plan for predominately multi-well pad drilling and we implemented initiatives to appreciably reduce cost. And we began to 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 type curve for all four 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.

Thank you Randy.

Operationally we accomplished a great deal on the quarter, despite having to overcome significant disruptions in drilling and production operations resulting from severe winter storms. Drilling operations were curtailed for close to two weeks and production on the majority of our wells was shut-in for up to three 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 and 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 main. Thus, the two 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 six middle Wolfcamp development wells on average are currently exceeding our middle Wolfcamp type curves of 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 their 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 are currently completing our first Sprayberry 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 a well's ultimate recovery. Since Laredo begin drilling lateral wells longer than 6000 foot we have completed 32 wells with at least 180 days of production history and 23 wells with over one 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 companies respective type curves. While the Cline well's performance is currently below expectations the last two completions in the zone are at 125% of the Company's Cline type curves through 180 days of production.

We currently have six rigs working in the field, and we'll be drilling multi-well pads throughout the remainder of the year. Our seventh rig is expected to be on location at the end of this week. And in anticipation of these rigs arriving we have predrilled the surface holes with two 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 a reduction in our drilling and completion costs of 5% to 10% across the field. Improved well design and construction and implementation of well automation have reduced the amount of required work overs.

Laredo's Reagan County Wolfstation 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, processed high pressure gas for artificial lift and process low-pressure gas for fuel to fuel 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 $3000 per day in diesel costs. Our water recycle facility 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.

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.

An 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 years' 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 for 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 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 the third quarter of 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, 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 assets 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 unbound this transaction due to our counterparty'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 two-, three-, and four-stacked wells on a single pad will cause the cycle time in 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 Michelle, would you please open the lines for any questions?

(Operator Instructions)

Ryan Oatman, SunTrust

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

Yes, as I mentioned in the call, we had majority of our wells down 2 to 3 weeks. That equated to 2500 or 2800 barrels a day that we were off the quarter.

That's very much helpful.

Ryan, let me just add that based upon the fact that we were down about two weeks on a significant piece of the production and volumes were impacted probably for three weeks, if you essentially annualized 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 28.9 thousand barrels of oil equivalent per day, without that down time. That gives you a framework around what the production could have been.

Right. It could have been anywhere from 2500 to, let's call it 5000 barrels a day, potential impact. Taking that into account, looking at 2014, the guidance, it 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 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, how production looks throughout the year? How it looks now? How 4Q could look? I'm just trying to get a feel at the production ramp throughout 2014. I'll abide by the two question limit and hop back in the queue.

As we stated in the past, our production and even prior to the storm impacts, that our production was going to be very stair-step growth throughout 2014. Starting in initiating the process of transitioning into these multi-well pads, where we're going to now be drilling up to four wells on a single pad, your deferring the production impact from that first well until all four wells are completed and ready to be produced.

As a result, it could take up to six months before a pad begins and actually comes on production. Since we began this transition to multi-well pads, primarily in the fourth-quarter of 2013, we knew all along and expected all along that our production growth was going to be very weighted towards the second-half of 2014.

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 quarters results.

Gil Yang,

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 to the rate of return. Given the fact that you have a lot of capital sitting on the ground for six months before it actually starts producing. Offset by the cost benefits that you're getting from the pad drilling?

Good morning.

We've obviously looked at that as you indicated, a number of different ways. There's a couple of points 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, you know, 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 and that could impact it, but we kind of feel like we modeled in some of those kind of issues like we talked about in the past. On the one side, just the efficiencies of pad drilling should help us substantially on the cost. We've talked about that. It has a greater 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 kind of resources. And shorten greatly the time that it takes us and the cost of doing those kind of things.

Our pad drilling is based both on terms of rate-of-return, but just our ability to move fluids including water around inside our production corridors. We feel like we are well ahead in understanding how we need to do that and we've built out those production corridors. We build out the one and we'll be building out others.

Jay, do want to add anything to that?

The other thing you have to take into account Gil, is if you drill one well, let's 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 well head that is actively producing. So you would essentially have to shut that well in anyway. 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'd have an active drilling operation in the near vicinity.

Gil, one last point and that is there's some argument and some data that suggest you get a better frac in stimulation when you're stimulating zones that have basically virgin pressure. There's some suggestion that coming back in later, if there is a minor fracture or something that sees both well bores, it makes it difficult to frac the original pressure reservoir.

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, was that facies change expected to be positive or negative for that well and what your outlook is after that -- following that result?

I'll address it from 50,000 foot and then let Pat comment, Pat Curth comment if he wants to. We said early on that on the very Northeast end of that, we saw a carbonate increase a few percentage points in our acreage. That well represents 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 and place changes that made and whether or not it would be delivered. The point we 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 in the Northeast end of the county that in the middle Wolfcamp one 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?

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 have more work to do but certainly don't condemn that acreage by any stretch of the imagination.

Did you mean that you don't -- 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?

No. We're not giving up the middle Wolfcamp at this time. We're going to step back and look at how we completed that well, see if we could have done something differently. We're going to go back, as I said, and reanalyze our petrophysical data.

There are some changes there. No doubt about it in the rocks. It doesn't mean that it's negative, it just means we need to understand it better before we write off any zones. No, I would not say that at this time we're done with the upper Wolfcamp in that area.

Okay. Thank you very much.

Joe Bachmann, Howard Weil

Randy, I was wondering if you can 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?

I'll let Dan or Jay give you those details. We fully expect -- their 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. Dan, do you or Jay want to comment on what the mix really was?

The wells perform right on as our type curve were played out. We've had no real surprises in the performance of our recent wells.

Okay. I guess a follow-up. Looking at year-end 2013 and in the book, the URs, you guys using the higher percentages or are you kind of using what you said in the past for those Wolfcamp wells?

I don't think we've seen, you know, 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 doesn't change us up or down. I think the message is it's coming around about like we thought it would.

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

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

Jason Smith, Bank of America Merrill Lynch

I have a question on the Cline wells with the last two wells actually trending above your type curve. Is there anything you guys changed in terms of completions or anything like that versus what you were doing previously?

Not really. I'll let Jay again back it up. But we've stated before that we need to see more than one or two wells to really understand the curve and we could talk long and hard about our 4000 foot Cline and 10-stage fracs and what we learned and how we view those wells which are clearly economic in 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 two wells which we don't have year-end's production on, I've said more the one-time that I'd really like to see 6, 9, 12 months before we talk. These 24 IP's 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.

And then -- I know delineation is still not a huge part of the program but I think it's 10% of the cap ex and following the Glass well, what's the plan in terms of where you guys move next? Are going to move further west or are you going to stay in that area?

We really in 2014, claim the year as the year that we're going to do significant development in pad drilling within the core area. The majority of our budget is going to be in that core area. It's going to be development and pad drilling. As mentioned, we do have a Sprayberry 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 deeper, we need to test the Canyon. The message that we'd like to convey is that in the de-risk acreage we've still got thousands of vertical wells and thousands of very economic horizontal wells to drill.

We recognize the we haven't de-risked either the additional acreage outside of that core area we called de-risk. We recognize that we have other zones up and down the well bore that we need to test. Our view is that the majority of our funds should be spent in what we think is really going to make the most value per shareholders and that is the stacked lateral pad drilling in the development area.

I appreciate the thoughts Randy, thanks.

John Herrlin, Societe Generale

With respect to your drilling program, are the horizontal and vertical well counts going to be evenly distributed during the course of the year or is there certain seasonality? That's question one.

And question two, 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?

As far as the allocation of the wells, the vertical wells will be fairly consistent across the four quarters. We anticipate drilling in roughly 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 three well pads, the four well pads, we're going to see a sizable uptick in production windows when those pads come offline.

Just from a time standpoint, if a pad comes online very late in the quarter it obviously is not going to have that much impact in that quarter. A two-week delay or acceleration in a pad coming online or being deferred for two 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, really should not anticipate seeing significant production growth until the third quarter. By the time we are discussing the second-quarter, pads 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.

Thanks Rick. It was worth a shot.

(Operator Instructions)

Ryan Oatman, SunTrust

Thanks for taking the follow-up question here.

It 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 is some acreage in between that you've successfully tested horizontally for the Cline. How does that acreage differ between, kind of, let's say northern Reagan where have you ever you have had Wolfcamp A, B, C success and the acreage in the south-central part of Glasscock County as opposed to the northern acreage that you tested this Wolfcamp B on?

Ryan, we call that well middle Wolfcamp and that is 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 and 2009. We just weren't clear what it meant. We've got vertical wells up there that are decent wells.

All across our acreage we now have 900 vertical wells and 300 something plus deeper vertical wells that go all the way through. In most cases the Toca and in some places deeper. What we've said is that we've have 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've call de-risk, and part of that acreage between our core area and this well, we've de-risked for the Cline with our drilling. We have not drilled that many Wolfcamp horizontal wells in between there. Based on what we have seen from that plethora of vertical drilling, 3D, our core work, our single junk 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.

Okay. That's helpful. And then one unrelated question from me. Some Cline wells below the curve, some recent ones are below it.

Even the ones that are below curve, can you kind of speak to the EURs and IRs for those four wells, let's say, that you have 365 days of production? Do you feel like those still clear at 10% or 15% rate-of-return threshold? Just kind of curious your thought on the economics and EURs of those wells.

I will let Rick or Jay if they have better numbers, but we're not at all uncomfortable with the results of those wells. Obviously, you want better wells. We've always thought and characterize this as -- from well to well on that 80, 90 mile, 75 mile long acreage trend we expect to be some differences. We were confident, based upon our well work that our averages were going to be about right. And if not we'll change them in the future.

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 do need to do a lot more evaluation in that 12,000 acres that's Northeast of that facies change, but we've addressed those kinds of problems many times with this company and other companies so we'll work through that. We're not backing off from liking the Cline in any way.

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

Just to support what Jay said, if you go back and look at our analyst day last September, where we talked about the top 20 wells, the Cline was very well represented in there. We're happy with that.

Perfect. That's it for me. Thank you.

Jeffrey Connolly, Mizuho Securities, USA

Just a quick follow-up on the Cline. The two 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?

I would -- 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.

Thanks. That's it for me.

Gil Yang, Discern

Thanks for taking another question. Can you talk about what the reduced workovers -- how you achieved that and how that changes capital costs and LOE going forward?

We've greatly reduced workover cost. We inherited a number of wells that were, in our opinion, not designed correctly to isolate corrosive San Andrea 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. This automation and refining our production operation is significantly impacted the number of workovers that we've had to do and pulling tubing, tubing failures and casing failures.

Can you say, sort of a pennies per barrel benefit to LOE, or --?

I think Gil, we're comfortable that we've reflected that in our guidance. We did talk some over the last year or two about we had some bump up in LOE's 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 wasn't done right and things like that. I think it's reflected in our guidance just as we understanding of it.

Was the work that you did on those wells last year in capital expenditures or in LOE?

They were in LOE.

John Herrlin, Societe Generale

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

Are you talking about going forward, John?

Yes.

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. In Reagan County we'll primarily be focused on the Wolfcamp with a couple of Cline's thrown in there.

Thank you.

But we have to talk about 75% or 80% of those wells will be various Wolfcamps. Of the anticipated 75 wells that we have for horizontal wells that we anticipate for 2014.

Great. Thank you.

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

Thank you Michelle.

We will report our first quarter results on Thursday, May 8 and we'll host an earnings conference call (technical difficulty).

That concludes our conference call. We thank you for your interest in Laredo petroleum.

Thanks, everyone.

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