Vital Energy Inc (VTLE) 2017 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Laredo Petroleum Fourth Quarter 2017 and Full Year Earnings Conference Call. My name is Amanda, and I will be your operator for today. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes.

It is now my pleasure to introduce Mr. Ron Hagood, Vice President, Investor Relations. You may proceed, sir.

Thank you, and good morning. Joining me today are Randy Foutch, Chairman and Chief Executive Officer; Rick Buterbaugh, Executive Vice President, Chief Financial Officer; and Dan Schooley, Senior Vice President, Operations; as well as additional members of our management team.

Before we begin this morning, let me remind you that during today's call, we'll 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 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 yesterday's news release.

Yesterday afternoon, the company issued a news release and presentation detailing its financial and operating results for fourth quarter and full year 2017. If you do not have a copy of this news release or presentation, you may access it on the company's website at www.laredopetro.com.

I will now turn the call over to Randy Foutch, Chairman and Chief Executive Officer.

Thanks, Ron, and good morning, everyone. Thank you for joining Laredo's Fourth Quarter and Full Year 2017 Earnings Conference Call.

In 2017, we completed a total of 62 horizontal development wells, growing production 17% versus original guidance of greater than 15%. And we generated well over return on invested capital of greater than 30% on our drilling program. We also made significant progress in our efforts to increase the well density of our development plan for our premium Upper and Middle Wolfcamp formations, which we believe enhances the value for our shareholders.

Operating cost continued to benefit from previous investments in field infrastructure, decreasing to a company record $3.22 per barrels of oil equivalent in the fourth quarter of 2017.

Total cash expenses decreased more than 5% from third quarter 2017 on a BOE basis, driving an increase in cash margin per BOE by 20% from third quarter 2017 versus a 13% increase in our average realized price. We significantly strengthened our balance sheet through the sale of our interest in the Medallion-Midland Basin pipeline system, receiving net proceeds of $830 million and using $690 million of these proceeds to pay down debt. This reduced our net debt to EBITDA to around 1.3x based on annualized fourth quarter 2017 adjusted EBITDA. The use of our proprietary data and technology workflows is driving our subsurface understanding. Combined with our work to concentrate fracture density around the wellbore, this is enabling the codevelopment of multiple identified landing points in the Upper and Middle Wolfcamp, which in turn enables more dense development of the formation.

We currently believe that the potential development of up to 32 Upper and Middle Wolfcamp locations per section in previously undrilled acreage. Understanding the appropriate development plan is key to maximizing the value of our leasehold. Our data confirms that the presence of drilling well is solely for the best return per well, and without regard to the well-to-well interactions, parent-child effects and package, likely has a very significant detrimental impact to future recoveries from locations to move the currently targeted formation and [inflation] formations, resulting in higher short-term capital efficiency at the cost of long-term value. We believe that devoting our leasehold with the higher-density development plan and larger well packages minimizes these well-to-well interactions, which then preserves our premium inventory and substantially increases the value per 2 sections spacing unit. This value uplift can be even more pronounced of higher commodity prices as oil recovery per spacing unit increases in conjunction with higher well density. In the short term, we acknowledge this approach may reduce our capital efficiency.

At the beginning of 2017, we increased our type curves for the Upper and Middle Wolfcamp formations to 1.3-million-barrel oil equivalent per 10,000-foot well. Although our wells utilizing optimized completions were performing and continued to perform above the 1.3 million BOE type curve, we did not assign higher EURs based on these results. We understood that as we evaluated the codevelopment of multiple landing points, invest tighter vertical and horizontal spacing, well productivity will likely reflect the 1.3 million BOE type curve. While we still see significant outperformance of wells that are not being developed in higher well spacing densities, we expect our future development wells, on average, to be closer to the 1.3 million BOE type curve as we move to tighter horizontal and vertical spacing.

To fully take advantage of increased premium Upper and Middle Wolfcamp locations and bring identified value forward, we will need to accelerate our current rig cadence. Should we be able to develop 32 locations per spacing unit, we would have 25 or more years of inventory in just the Upper and Middle Wolfcamp formations at our current activity levels, taking into account already drilled locations in parent-child locations. Currently, we plan to add a fourth rig around midyear 2018 and expect to add additional rigs at a measured pace beyond 2018, although with the goal to operate within or close to cash flow. At current commodity prices, we believe that will be the case for 2018.

As announced in a separate press release last night, Laredo's Board of Directors has authorized a $200 million common stock repurchase program. We view such a repurchase program as an additional efficient way to recognize value for shareholders. Based on our view of the current value of our reserves and expected future value creation from increased premium locations, we believe such a program, especially our current share price, has potential to be very accretive for current shareholders.

We remain focused on balance sheet flexibility and believe that this repurchase program fits well within our current financial structure. If the program were fully executed today, we would still have approximately $850 million of liquidity and a debt to EBITDA below 2x. Additionally, our cash flow is supported by robust hedge position, including approximately 90% of our anticipated 2018 low volumes. And we expect capital expenditures and cash flow from operations to be in line with the fourth quarter of 2018.

I would now like to turn the call over to Dan for operational update.

Thank you, Randy. In the fourth quarter of 2017, 15 of the company's 18 completions were concentrated into 2 large packages: the 6-well Kloesel package and the 9-well Lane Trust Package. The Kloesel package was the first drilled by the company in western Glasscock acreage. The package tested multiple concepts and furthered our understanding of spacing in the area, new landing points, very narrow drilling windows, 15-foot cluster spacing and other completion optimization designs. Results from the Kloesel package continued to improve and affirm our pre-drill expectations. Additionally, oil cut is higher than modeled, but we will need more data to draw any conclusions for future drilling in the area. Production from the well packages was delayed due to issues we encountered in the drilling and completion of 2 of the wells, none of which we feel will be an ongoing issue.

In the second package, the 9-well Lane Trust package, 7 wells were tested the codevelopment of 2 zones, one of which was a new landing point in the Middle Wolfcamp. Early data on this package, especially the Middle Wolfcamp wells, is extremely promising on 2 fronts: first, confirming a new landing point in the Middle Wolfcamp gives us more confidence in our ability to develop 32 Upper and Middle Wolfcamp locations per 2 sections spacing unit; secondly, the 4 Middle Wolfcamp wells in this package are substantially outperforming their oil type curves and predrill oil production estimates. Five wells completed in the fourth quarter of 2017 were Lower Wolfcamp and 4 Cline wells. While we are seeing improved productivity in these formations from utilization of optimized completions, currently their economics are not as competitive as our premium Upper and Middle Wolfcamp locations. As a result in 2018, we expect to have little or no activity in the Lower Wolfcamp and Cline.

The company's 2018 budget released in late January includes $470 million for drilling and completion activities. The budget includes average well cost savings of $600,000 per well. Thus far in the first quarter of 2018, we believe we are on track to deliver the savings budgeted. We are delivering these savings even though our implementation of in-basin sand has been delayed until midway through the second quarter of 2018.

We recently completed an RFQ process for procuring a second full-time completions crew. Based on the pricing we saw in this process, we are very comfortable that current service cost pressures can be overcome, and average well cost can be reduced by an average of $600,000. We expect this crew and our existing frac crew to both deliver increased completion efficiencies during the remainder of the quarter. These savings are expected to build throughout the year with relatively minimal savings in the first quarter of 2018. Additionally, we feel we can overcome a moderate level of inflation and still deliver these savings.

Moving to the LMS side of the business. We continued to see substantial financial and operational benefits from our ownership of field infrastructure. A prime example of the operational benefits is our ability to move natural gas to multiple processing plants on our LMS-owned natural gas gathering system. Approximately 50% of the company's gross operated natural gas production is gathered on LMS-owned assets. This increases our confidence that temporary residue natural gas delivery issues to the WAHA hub by gas processors will not result in a substantial flaring or production curtailments. We believe that a combination of our processors' firm capacity and the ability to offload LMS-gathered natural gas to alternative processors through the LMS-owned gathering systems provides the flexibility needed to avoid substantial production curtailments. As additional protection against price dislocations, our natural gas hedges are priced at WAHA, and we have entered into Henry Hub WAHA basis swaps. Currently, approximately 85% of our anticipated natural gas production for 2018 is protected against the WAHA basis widening.

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

Thank you, Dan, and good morning. As announced in last night's earnings press release, Laredo posted fourth quarter 2017 net income of $1.70 per diluted share, which includes a gain of approximately $406 million that was recognized in the quarter, related to the sale of our interest in the Medallion-Midland Basin pipeline system.

Laredo received net proceeds from the sale of our interest in Medallion of approximately $830 million, more than 300% of our total investment. Keep in mind that, in addition to the $406 million gain reported in the fourth quarter of 2017, a gain of approximately $141 million has been deferred due to future firm transportation commitments with Medallion that we retain. This firm transportation provides Laredo access to crude markets outside of the Midland Basin. With our adoption on January 1 of this year of new revenue recognition guidelines issued by the FASB on Topic 606, that $141 million deferred gain will be recognized in the beginning balance of our retained earnings and never go through future earnings. This accounting treatment is detailed in Note 3 of our Form 10-K that is expected to be filed later this afternoon.

Other than what I just described, the sale of our Medallion interest does not impact our financial statements or our oil marketing arrangements. Our oil transportation agreement with Medallion has always been independent of our ownership interest, and all tariffs paid to Medallion were already accounted for in a realized pricing for oil. And our ownership in Medallion never had an impact on our leased operating expense. So therefore, other than the elimination of the line item for income from equity method investee, there will be no change to future income statements related to the sale of our Medallion interest.

We utilized proceeds from the Medallion sale to make subsequent improvements on our capital structure and financial position. We repaid $690 million of debt with a portion of the proceeds from the sale, which retired 100% of our $500 million, 7 3/8% senior unsecured notes due in 2022 and fully repaid the outstanding balance on our senior secured credit facility of $190 million at the time. Repayment of this debt has reduced our annual interest expense by approximately $40 million and reduced our multiple of net debt to adjusted EBITDA, a non-GAAP financial measure that is defined in our press release, from approximately 3x to just 1.3x today based on our annualized fourth quarter 2017 adjusted EBITDA.

Currently, our liquidity is just over $1 billion, primarily consisting of our undrawn credit facility. This credit facility has a borrowing base of $1 billion that was set in May of last year and supported by our year-end 2016 reserves. Keep in mind that, as we reported in January, our year-end 2017 reserves, of which were nearly 90% are proved developed reserves, has a value based upon the standardized measure of discounted future net cash flows of about $1.8 billion, which is an increase of more than 80% from year-end 2016.

As Randy explained earlier, our Board of Directors has authorized $200 million share repurchase program. We currently have 400 -- $46 million in cash on hand. Any share repurchases that are executed will be funded with this cash and our senior secured credit facility. We believe repurchasing our shares, given recent price levels, offers exceptional value for our current stockholders. Our balance sheet strength enables the repurchase of up to approximately 10% of our shares outstanding at current prices, without inhibiting future opportunities to accelerate our drilling program.

In late January, we issued our 2018 capital budget and an annual production growth estimate of greater than 10% based upon our goal to bring capital expenditures closer in line with our operating cash flow. We are reiterating our 2018 production growth estimate, and in last night's earnings press release, issued production and cost guidance for the first quarter of 2018.

First quarter 2018 production guidance is being impacted by a couple of items. As Dan noted, we had 2 wells that were completed in the fourth quarter of 2017 that experienced drilling and completion difficulties. As a result, previously anticipated flush production from the equivalent of almost 2 10,000-foot wells will not contribute to first quarter 2018 production volumes. Additionally, adverse weather in the Midland Basin in late December and early January of this year resulted in approximately 52,000 barrels of oil equivalent of reduced production for the first quarter of 2018. These impacts have been accounted for in both our first quarter 2018 and full year 2018 production estimates.

With these estimates, our continued focus on cost control in the current commodity price environment, we may be cash flow neutral for full year 2018. As a reminder, to protect our cash flows in a volatile commodity price environment, we have hedged a substantial amount of our projected 2018 oil volumes. To retain upside to increases in oil prices, a substantial portion of our hedging program is executed with put contracts. Premiums associated with these contracts can be paid upon entering into the contracts or can be deferred and paid as the contracts are settled monthly. Note 10A in our Form 10-K, expected to be filed this afternoon, provides additional details on our deferred premiums.

In the fourth quarter of 2017, the company's diluted share count decreased by approximately 4.6 million shares from third quarter. This reduction is primarily related to the structure of the company's long-term executive compensation plan. Half of Laredo's long-term executive compensation is awarded as performance shares that change in value based upon Laredo's relative performance to a peer group. This was put in place by Laredo's Board of Directors to further align the interests of management with stockholders. The diluted share count can vary based upon the company's relative performance to this peer group. If Laredo's stock value underperforms the peer group, the value of these performance shares can go to 0. And therefore, the underlying shares are excluded from the diluted share count. This is what occurred in the fourth quarter of 2017 as pro forma shares that were awarded in early 2015 vested with 0 value, and therefore no shares were issued.

We certainly understand investors' focus on capital efficiency trends, and that in the second half 2017, we saw a decline in capital efficiency after a substantial improvement in 2016. A driver of this trend was the capital we invested in 2017 to understand the optimal path for adding premium locations in our Upper and Middle Wolfcamp formations. We believe that this is the most value-accretive strategy for the company to follow over the long term. We believe high well-density development with large well packages leverages our contiguous acreage and previous infrastructure investments and positions the company to accelerate activities to unlock present value. Management and our Board of Directors is willing to back this belief with the recently announced share repurchase program.

Operator, at this time, would you please open the call for any questions?

(Operator Instructions) And our first question comes from the line of Kashy Harrison of Simmons Piper Jaffray.

So I was just wondering, could you guys walk us through the rates of returns associated with the stock repo program at current trading levels versus the rate of return associated with reinvestment in the business and pushing the drill bit? Just trying to get a sense of opportunity cost between the 2.

We're not -- excuse me, this is Rick. We're not going to give you specific rate of returns on the program. Obviously, it's going to be -- it can change from time to time as the share value changes, but we certainly look at the value that we see from our activities that have been completed, the program that we have laid out and how we believe we can recognize additional value relative to the share price that we're seeing in the market today. We don't believe that the 2 activities, either a share repurchase or acceleration of drilling activities, are independent, that they can't be done together. At this time, though, we've already stated that we plan to accelerate our drilling program midyear as we continue to get results from some of the prior activities that we have received. But that we also believe that a share repurchase is appropriate today given the current stock value and the values that we see for the company.

Got you. And as we think through the transition to drilling the higher-density wells with the multiple landing points in the Upper and the Middle Wolfcamp, I was just curious, are there any well-cost savings associated with that? Maybe less proppant or something that may not be currently baked into the forward guidance?

We think that a lot of our activity -- this is Randy Foutch. I think we think that our activities in '17, in terms of a lot of the data that we collected, was an attempt to really focus on how we can best optimize completions. And we will be talking about that in the future. But I think there's the potential for -- we've talked about what we think we can do on cost savings this year with some things. That's kind of on track. I think there's potential for focusing our completion efforts in trying to really have a precise, defined zone of completion around the wellbore, which may mean that we're not going to use massive amounts of sand. I think it's too early to really comment on that yet. Dan, do you want to add anything?

Well, yes. This is Dan Schooley. I think one of the things that you need to factor in, too, is that part of the impetus behind the larger packages is to gain the efficiency, if you will, that you gain from not having created more parent-childs and not having -- the offset wells being frac hit. So that makes us, from production standpoint, obviously more productive. So doing these in the larger packages is going to help alleviate that as we go forward.

Got it, got it. And then maybe continuing with the forward trajectory. When you think about the optimal pace of development for your acreage position, either on a per rig basis or on a per well basis per year, I was just wondering what that number might be. So what do you -- how many rigs do you think you can run on your acreage? Or how many wells do you think you can run on your acreage that would maximize the value of your asset?

We're suggesting that we have several decades of inventory in just the Upper and Middle, which are really pretty exciting zones. And of course, we have other zones that are productive with good economics, but not as exciting. And I think anytime you are looking at 20-plus years of inventory, you need to be thinking about how you can get that value created in half that or some number like that. The way we have our corridors and the way we have our infrastructure and the marketing, we can run quite a few rigs. I think, historically, we've run as many as 10 or so. So I think what the balance is, is making sure that you're being careful and trying to get balanced with cash flow. We don't want to add a bunch of rigs all at one time. We want to be a little measured as we step into this for a variety of reasons, operationally and financial and others. So I think the goal is to put that 25-plus year inventory back down to something where there's actually a present value created on those activities. And I don't know where we are exactly, but I think that means that we -- as we stated, pick up a rig probably second half of this year. And then with the measured pace pick-up rigs and you're looking at something along the lines of, I don't know, 6, 7, 8 rigs, something like that. I don't think we need to go to 15, but I do think, over the next couple of years, we need to pick up that rig cadence.

Got you. Got it. That's very helpful. And last one from me. You all, both in the press release and the prepared remarks, provided some interesting commentary surrounding your ability to avoid substantial production curtailments. I was just wondering if you could share some color, more so from the industry level, on what you're seeing in the basin with respect to gas processing infrastructure and gas takeaway? And I'll leave it there.

Thanks, Kashy. This is Dan Schooley again. From the start at the top, the processing capacity that we see in the Midland Basin and particularly connected to our production, we don't see that coming -- being constrained in the future. I think that what most people are concerned about right now is the residue gas capacity out of the greater Permian Basin and that we have, we think, a couple of things in our favor. One is we have Targa and EnLink as our 2 major purchasers on our acreage that have firm capacity for their residue gas production out of the basin. We've been in contact with both of them to make sure that we understand that and feel pretty confident that they have managed their business in a way that's going to allow them to move all of the residue gas going through their plants. So as a secondary protection, we talked about a little bit earlier the natural gas infrastructure that we have under LMS. We have the ability, particularly on our corridors, to offload substantial amount of natural gas from one purchaser to another, if there is -- if one of the 2 has a significant issue. EnLink in particular has access to not only WAHA, but they have access to the Katie(inaudible) hub. So we do feel like we have a couple of layers of protection around the residue gas issue, and we don't anticipate having any significant curtailments or requirements that we flare gas that can't be taken by our processors.

And just as a reminder. As Dan mentioned in his comments, as we discussed previously, when we put our gas derivatives in place, those are priced at WAHA. And we have about 85% of our 2018 anticipated gas production that is protected against the -- any significant -- any change in WAHA basis widening.

Our next question comes from the line of Sameer Panjwani of Tudor, Pickering, Holt.

You've done a great job here of accelerating shareholder value between Medallion and the buyback program. I'm just wondering, what other opportunities are there within the portfolio and the pull forward additional value, particularly as you're moving to this tighter spacing profile, which significantly increases the drilling opportunity around the production corridors?

We think that there's -- we're just now coming into our own in terms of being able to really articulate what the production corridors do for you in terms of LOEs and the infrastructure spend that we spent. So we kind of have a view that, as we drill what we're currently -- the number of rigs we're currently running plus some acceleration over the next few years, that that's a benefit that we keep, and we anticipate enjoying a differentially lower LOEs and funding cost. We still have a little bit of acreage here and there that we're not going to get to anytime soon. It's not in the area that we're currently acting, so there's some deal there. But I think we're very much of the mind that we're talking with data behind us about acreage. And I think there's an inventory that is exciting and economic, and we can handle it. So we're pretty excited about that.

I guess, are you able to quantify the amount of acreage that you have that isn't accessible by the production corridors as they're configured today?

It's not very much. And keep in mind that we've been able to add corridors by daisy chaining them north to south. So the cost of adding a corridor is really not that much in the overall scheme of things. But also keep in mind that we've got something like 95,000 acres or so, something like that, connected by corridors.

Okay. That's helpful. And then you guys also talked -- you provided some details around the down-spacing test and how they confirmed your predrill model and the oil cut was outperforming. Can you just provide some more context around what you are exactly expecting going in? And if it'll be possible to quantify what the initial oil cut looks like?

Yes. We're a little -- as I've said a number of times, that it's always good to have positive early data, but we do really believe that we need to see months or quarters before we start trying to really quantify and articulate those kind of numbers. I'm happy to see them, but I think you'll be hearing more about that as we get data that we're comfortable with.

Our next question is from the line of Asit Sen of Bank of America.

On production, in light of the first quarter guidance, could you talk about the cadence of production this year more back-half-loaded? Or how should we think about it?

We have talked about -- that we expect we'll be able to achieve greater than 10% growth over the year. I would expect to see it relatively even over the remaining 3 quarters. Obviously, first quarter is going to be relatively flat with fourth quarter but bumping up in the second quarter. As we bring on a fourth rig, you really will not see the benefit of that fourth rig's activity until very late in the year.

Okay. And then just following up on the high-density program. Any early thoughts on hydrocarbon recovery rate? And Randy, you mentioned a return on invested capital of greater than 30% of wells drilled last year. How does that translate into corporate returns?

Well, when we talk about the 30% -- greater than 30% at the field level, I mean, that's really kind of a half-cycle kind of a number. And it needs to obviously translate into the corporate return. And I think the steps that we've taken with cleaning up the balance sheet, reducing our interest cost, some other things we've done in that we've built out the infrastructure, we've collected most of the data, we think all those things are pushing corporate return into the right direction.

Okay. And then last, Rick. I guess, you mentioned the buyback strategy is going to be more opportunistic and not a rated program. Is that a fair way to think about it?

Well, we certainly look at what's the return, what's the impact to our existing shareholders of the repurchase program as well as -- and similarly, do the same thing when we're looking at dollars that are invested in our drilling program. At the current time, current market valuations, we think we have significant optionality to do either or both the market, given what we believe we have been able to accomplish over the last year, which is stuck to our program of enhancing the overall long-term value of the company, how we've gone about really analyzing and understanding our acreage position so that we can maximize that value. That value can only be maximized, though, if you accelerate or as you accelerate drilling activities. We are certainly prepared to do that but want to make sure that those are really value-enhancing investments and we're accelerating at the right time with the right margins and have confidence around what we're seeing both on the commodity price side as well as the cost side. So I don't think the 2 are really an either -- or rather we do the share buyback or the -- or accelerate activities. We've talked about that we are planning to accelerate activities and may do that further, but that a share repurchases, given the current environment and what we see the near-term potential value creation for the company, we think, is incredibly value enhancing for the existing shareholders.

Our next question is from the line of Joe Allman of Baird.

My first question is around the 1.3 million BOE type curves. I just -- it would be great if you could just make maybe 3 points on this one. So because you've outperformed on 114 wells, is this 1.3 million BOE type curve, is it assuming that you do have some communication between adjacent wells or nearby wells going forward? That's number one. Number two, should we apply this 1.3 million BOE type curve to all future Upper and Middle Wolfcamp locations? Is that kind of how to think about it? Or is it really just kind of looking back on what you've done so far? But of course, as I mentioned in the first point, you've outperformed. And number three, is really your focus here on maximizing NPV per section rather than NPV per well? So if you could hit on those 3, that would be great.

Well, I'll take first crack at it, and then I'll get Rick and Dan to fix on. We've had, I think, 100-plus wells that outperformed the 1.3 million. And as you know, we were slow to move up to the 1.3 million. We wanted to have substantive data when we push that number out. And we said a couple of different times that we were very comfortable with the 1.3 million. We have a lot of data across this acreage. And that's the number that we're comfortable with. You can't ignore the fact that we've got a number of wells that have performed beyond that. So I think, in terms of the spacing, I don't think we're necessarily saying that there's going to be interference that's going to take the outperformance down to 1.3 million at all. I think we're saying that that's a good number that you should use modeling going forward. We don't see necessarily interference. But what you're trying to do -- what you really want to do is get as close to interference as you can and still have it be accretive on a -- on both a well and a section basis. And if you look at Page 17 in the presentation that we pushed out concurrent, you can see, hopefully, visually, what I'm trying to say, and it is economic for higher-density development. The plan, from us, all along, which we've articulated, perhaps not well, is to really not be a best rate of return 1-off or 2-well off drilling program, but to really try and understand what this 20-plus-year acreage base inventory could really be in terms of NAV. So we've looked at what size packages. We've looked at -- we've talked a lot about -- our goal has been to prevent to the extent we could, mitigate the parent-child issues. And so I'm pretty comfortable that we're going to be drilling larger packages, which we've talked about has quarter-to-quarter impact on production. The larger packages do give us capital efficiency, but not as if we were drilling single off wells. So I think what we're headed toward is some sort of long-term sustainable growth for shareholders. Dan, Rick, do you want to add any?

We're good.

Okay. So my second -- that's very helpful, Randy. My second question is, how many wells have you drilled so far using the horizontal and vertical spacing that's implied in the 32-well per spacing unit program? Because it sure seems you're pretty confident that you're going to be maybe drilling a pretty good concentration of those kinds of wells in the second half of the year.

We've done -- one of the -- one of our issues is the amount of testing of different spacing and both horizontally and vertically that we've done. We do know a fair bit, and we've been careful to make sure that we don't pronounce success or failure too soon. But I think we've drilled something like 10 or 11 or so spacing tests in 2017 with a number of varying configurations both horizontal and vertically. And we were slow to comment on those because we wanted to see more than just 20 days or 24-hour IPs. We wanted to see several quarters of data. So we tested a number of configurations starting back in '16, but certainly well through '17.

And just as a follow-up, from your modeling standpoint, I think you should do as we've done and use the 1.3-million-barrel type curve in your modeling process.

Our next question is from the line of Eli Kantor of DIR Advisors.

Can you talk about the thought process behind pursuing a share buyback program versus repurchasing debt or issuing a dividend?

I can address that one more time. We think we have the optionality to do both, either a share buyback as well as accelerating the drilling program. They're not mutually exclusive. We look at the value created, the dollars spent rather those dollars are being spent in a share repurchase. What is the net adjusted -- the debt adjusted net impact to our existing shareholders on multiple metrics and the value that we believe we create through that? Similarly, we do the same thing when we're looking at adding additional rigs. One of the things that we have been very cautious on, especially in industry cycles as we're experiencing today, where there's still significant volatility in commodity prices, there's volatility in service cost, and making sure that the margins that result from that truly make acceleration value-enhancing as well as making sure that we have as best understanding as possible about our acreage on how we want to go about that development. We think that taking a very measured approach to that acceleration is prudent, especially in this environment.

Yes, I guess we're a little bit agnostic about how we go about trying to add shareholder value. We've never had any -- in our minds, we've always been open to share buyback. And to your point about the dividend, we've modeled that. We've modeled acceleration. And I think we've -- Rick's point about we have the flexibility to do a number of those things is accurate. We think the time, based on what we see of the world, this was a good time to make a share buyback, and it's a meaningful buyback. And I think we've talked about how we don't see that precluding us from possible increasing our rig cadence later in the year or '19 or going forward. So we think this is just another way for us to really look at adding to shareholder value.

Okay. That's helpful. If my notes are correct from last quarter, you guys have talked about the long-term oil production mix continuing to trend between 43% to 46%. How should we think about that guidance in relation to the year-end reserve mix? And do you have a breakout on what percentage of your reserves are related to horizontal wells versus legacy vertical producers?

I don't know that I know that number off the top of my head.

I don't have that number, but Ron will follow up with you afterwards on that.

Okay. Last one from me. Just a quick housekeeping question. Within the 35 million barrels of positive revisions, do you have a breakdown of how that's split between price and performance?

Hang on a second.

Just a second. One thing to keep in mind, I don't have the specific pricing plus revisions. The bulk of those revisions, if I recall correctly, over 50% are really related to what we call our historic PUDs, proved undeveloped locations that we took off the books to get -- which we did several years ago to give us maximum flexibility in the wells that we're going to drill. And as those wells, that were previously booked as PUDs, are drilled, which is the case for many of the revisions that you see, are actually drilled that come back in as revisions rather than as new reserves.

So if I'm hearing you correctly, more than half of the revisions are really a product of timing of development?

Yes, that were really -- wells that were drilled, but they have -- the way we interpret the guidelines is that they come back in as positive revisions. It's not necessarily well performance, pricing. It's just the wells were actually drilled, although they were classified as PUDs several years ago. And at this point, we'd actually drilled them.

Our next question is from the line of Derrick Whitfield of Stifel.

Perhaps for you, Randy. More broadly, when you take a step back and you evaluate the ramp and industry activity across the Permian, what gives you the greatest concern as it relates to your operations?

That's an interesting question. We think we've been pretty aggressive in hedging and pretty aggressive in hedging out both natural gas and crude oil basis. We've preserved the right to take crude oil out of the basin. So one of the things that has concerned us is just marketing out of the basin. And as you know, Derrick, coming out of the Midland Basin is easier than coming out of the Permian -- I mean, out of the Delaware. That's something we spend time thinking about. There is a lot of conversations about service cost, and we've actually bid out a number of our service providers' services in the last couple of months. And I've said, over time, service costs always go up. But we're not seeing the kind of jumps that other people are talking about. In fact, we put people to work at relatively modest service cost increases. And we took a lot of the service cost increases and told you about them at the end of '17. So we always worry about service cost, but we're not seeing anything that terrifies us. And I think the regulatory environment, the overall feeling from the administration has gotten better. So we spent time making sure that we keep on top of the regulations and very much in compliance. And we're very aggressive on making sure that we reuse our water, recycle that and careful with what we do in the environment also. So those are things that we worry about a lot. And I think we've gone a long way to mitigate those. Our balance sheet is in pretty good shape now with the Medallion transaction. We have a lot of liquidity, so there's less pressure this year on that than there was before. So I think those are the 3 big things that we worry about.

That's good. And then my follow-up is based on your diagram on Page 17. In comparing the 16- and 32-well per section cases, is the outperformance of the 16-well per section case driven by year 1 factors or out year factors in your predictive modeling?

I think it's kind of a combination. As you drill longer -- more -- as you drill more wells in a series, there's delay, and I think we've seen that you can -- as you use more water, it takes longer to get the water back. We've been careful to make sure that we've mitigated to the extent we can any kind of parent-child issues. That's helped us a lot. So I think there's going to be comfort on the actual production profile going forward. But again, our goal is to minimize parent-child, minimize frac impact and get the most value -- NAV value out of this acreage with much, much more long-term sustainability in our premium zones, which are -- it's several landing points in the Upper Wolfcamp and the Middle Wolfcamp. So I hope that answered your question, Derrick?

It did.

We have time for one last question, the line of John Herrlin of Societe.

Regarding the wells that you had the problems with, could you give a little bit more detail? And also, what are the lengths of the wells you're planning to drill this year? Are they mainly 2-mile? Or are you still doing 3-mile? And how do the 3-mile wells work?

I'll let Dan talk about the case and use in just a second. But we've -- we're kind of headed toward, I think, because of the way we're drilling and where we're drilling, probably more of the 2-mile wells this year. We're still trying -- the land grab is a little bit over. So we're still trying to block up our acreage with some trades and some purchases and some things to get us in position to have more 15,000-foot inventory. But I think our average for 2018 and our -- it looks like it's going to be something like 10,400-feet lateral. Dan, do you want to talk about...

And John, the 2 issues on the Kloesel, the drilling issue was the Wolfcamp shale that we were -- landing zone that we were in was highly fractured and a little bit higher pressure than we anticipated first time we drilled it. And we had our shoes set a little bit too shallow to handle that pressure, so we were unable to continue to build mud weight as we drilled that well. So we stopped drilling at about 4,300 feet and completed the well there. That well is performing very well for it’s -- for the length of well it is. So we're encouraged about actually that landing zone and what that looks like for us. And we think we can solve that -- the drilling issue very easily. The other well, we had drilled the well, completed the well. We're in the process of drilling out when we had a casing failure. So it only has 3 of the 82 stages open at this point in time. So that -- again, that's something that we feel like is very rare, and we don't anticipate that happening to us again.

Okay. And then what about the 3-mile cleanups?

3-mile cleanups are progressing. I mean -- none of us, I don't feel or concerned -- too concerned about it. We're at about 85% of type curve now after 180 days. The wells are still cleaning up, and its -- but there's nothing in the execution of the drilling or completion of those wells that gave us any concern. We're able to get those wells drilled very efficiently and effectively. We were able to complete those wells. We have some data that would indicate that we were effectively stimulating that lateral clear at the end -- at the very end of that lateral. So the -- we don't -- we are not, at this point in time, concerned about the 15,000-foot laterals, particularly when you look at the cost savings that we get and the efficiency that we get by drilling those wells at that length.

John, this is one of these deals where we've stepped out there and we've done, I think, more than most. And we're the leader there. And I think we're, as you know, slow to claim victory. And we're now seeing some other operators start reaching out on lateral length. And so I'll be anxious for the industry to help us give confirmation data on what we're seeing with the 3-mile laterals.

How much more time is it, Randy, in terms of the incremental cleanup versus the 2-mile lateral? Are we talking 4 months?

Yes, I think it depends a little bit on the flowback. That's kind of the number that I'm kind of holding in my head. Jason, you kind of...

Yes, that's kind of the right length of time, John.

One of those wells was a near offset partially to an older well we did. I mean, when you think about it, it's a half longer, 10,000, 15,000. So there's just a lot more water that you have to pull back out of the same vertical part and the same gas lift and everything else. So it's been taking a little bit longer to clean up. And these wells are also a little denser spacing. So all of that made us be: one, pleased with the results; and two, not surprised to see the cleanup actually take longer.

Thank you. And that does conclude our Q&A session for today. Let's turn our conference back over to Mr. Ron Hagood for the closing remarks.

We appreciate your interest in Laredo. Thanks for joining us for our year-end '17 conference call.

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program. You may now disconnect. Everyone, have a great day.