Ronald Hagood - Vice President of Investor Relations Randy Foutch - Chairman and Chief Executive Officer Richard Buterbaugh - Executive Vice President and Chief Financial Officer Daniel Schooley - Senior Vice President of Operations Jason Greenwald - Vice President of Reservoir Engineering.

Kashy Harrison - Simmons Piper Jaffray Sameer Panjwani - Tudor Pickering Holt Asit Sen - Bank of America Joseph Allman - Baird Eli Kantor - DIR Advisors Derrick Whitfield - Stifel John Herrlin - Societe.

Good day, ladies and gentlemen and welcome to the Laredo Petroleum’s Fourth Quarter 2017 and Full-year Earnings Conference call. My name is Amanda and I will be your operator for today. At this time, al participants are in a listen only mode. We will be conducting a question-and-answer session after the financial and operation report.

As a reminder, this conference is being recorded for replay purposes. It is now my pleasure to introduce Mr. Ron Hagood, Vice President of 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 and 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 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 will be making reference to adjusted net income and adjusted EBITDA which are non-GAAP financial measures.

Reconciliations of GAAP net income to these non-GAAP financial measures are included in 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.laredoletro.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 a well over return on invested capital 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 a 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 the third quarter of 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 strengthen our balance sheet through the sale of our interest in the Medallion-Midland basin pipeline system receiving net proceeds of $830 million in using $690 million of these proceeds to pay down debt. This reduced our net debt-to-EBITDA to around 1.3 times 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 of fraction density around the wellbore, this is enabling the co-development 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 to develop the 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 confirmed that the presence of drilling wells solely for the best return per well and with that regard to the well-to-well interactions and parent-child effect brackets likely has a very significant detrimental impact to future recoveries from locations in both the currently targeted formation and basin formations resulting the higher short-term capital efficiency at the cost of long-term value.

We believe that the growth in our leasehold with higher density development plan and larger well packages minimizes these well-to-well interactions, which in preserves our premium inventory and substantially increases the value for two section spacing unit.

This value uplift can be even more pronounced with higher commodity prices as oil recover of course 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 tight curves for the Upper and Middle Wolfcamp formations to 1.3 million barrel oil equivalent per 10,000 foot well. Although our well is utilizing optimized completions were performed and continue to perform above the 1.3 million BOE type curve. We did on assign higher EURs based on these results.

We understood that as we evaluated the co-development of multiple landing points and best 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 at 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 identify value forward, we will need to accelerate our current rate case.

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 formation at are current activity levels taking into account already drilled locations and 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 separate press release last night, Loredo's Board of Directors has authorized the $200 million common stock repurchase program. We view such repurchase program as an additional efficient way to recognize value for shareholders.

Based on our view of current value of our reserves and the expected future value creation from increased premium locations, we believe such a program especially our current share price is potentially 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 will still have approximately $850 million of liquidity and a debt-to-EBITDA of below two times.

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 two large pad packages. The 6-well close hole package and the 9-well lay-in-trust package. The close-hole package were the first drill by the Company in its Western Glasscock acreage.

The package tested multiple concepts and furthered our understanding of spacing in the area and landing points, very narrow drilling windows 15 foot cluster spacing and other completion optimization designs. Results from the Kloesel package continue 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 two other wells, none of which we feel will be an ongoing issue.

In the second package, the 9-well Lane Trust package, seven wells were tested the core development of two 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 two firms.

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 two section spacing units. Secondly, the full Middle Wolfcamp wells in this package are substantially outperforming their oil type curves and pre-drill oil production estimates.

Five wells completed in the fourth quarter of 2017 were Lower Wolfcamp and our Cline wells. While we are seeing improve productivity in these formations from utilization of optimized completions, currently the 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 costs savings of $600,000 per well.

Thus far in the first quarter of 2018, we believe we were on track to deliver the savings budgeted. We are delivering these savings even though our implementation of in-basin sand has been delayed until mid-way through the second quarter of 2018. We recently completed in our key process for procuring the second full-time completions group.

Based on the pricing we saw in this process, we are very comfortable that current service cost pressures can be overcome and average well costs 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 continue 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 plans on our LMS-owned natural gas gathering the system.

Approximately, 50% of the Company’s gross operated natural gas production is gathered on LMS-owned assets. This increase is 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 provide 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 entering hub WAHA phases swats currently approximately 85% of our anticipated natural gas production for 2018 is protected against the WAHA phases widening. With that, I will 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 a $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 at the rate of access to crude markets outside of the Midland basin.

With our adoption on January 1st of this year of new revenue recognition guidelines issued by the FASP on topic 606. That $141 million deferred gain will be recognized in the beginning balance of our retained to earnings and never go through future earnings.

This accounting treatment is detailed in note three 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 in all tariffs paid to Medallion where already accounted for n a realized pricing for oil and our ownership in Medallion never had an impact on our lease 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 a 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 seven and three eight percent 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 through adjusted EBITDA, a non-GAAP financial measure that is defined in our press release from approximately three time to just 1.3 times 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, or year end 2017 reserves of which nearly 90% are proved developed reserves as 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 $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 us to repurchase of up to approximately 10% of our shares outstanding in 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 of 2018 production guidance is being impacted by a couple of items.

As Dan noted, we have two 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 two 10,000 foot wells will not contribute to first quarter of 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 the investments, our continued focus on cost control and 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 the 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 interest of management with stockholders. The diluted share count can vary based upon the company's rolling performance to this peer group.

If Laredo stock value underperforms the peer group, the value of these performance shares can go to zero and therefore the underlying shares are excluded from the diluted share count. This is what occurred in the fourth quarter of 2017 as performance shares that were awarded in early 2015 vested with zero value and therefore no shares were issued.

We certainly understand investors focus on capital efficiency trends. And then in the second half 2017 we saw decline in capital efficiency after 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, low density development with large well packages leverages our continues acreage in previous structure investments and positions the company to accelerate activities to unlock present value.

Management and our Board of Directors is went to back this lead with the recently announce share repurchase program.

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

[Operator Instructions]. And our question comes from the line of Kashy Harrison of Simmons Piper Jaffray. Your line is open. .

Good morning everyone and thanks for taking my questions. So I’m just wondering, could you guys walk us through the rates of returns associate with the stock repo program at current trading levels versus the rate of return associated with reinvestment in the business and pushing to drill bit.

Just trying to get a sense of opportunity cost between the two?.

This is Rick. We are not going to be the 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 are seeing in the market today.

We don’t believe that the two activities either a share repurchase or acceleration of drilling activities are independent that they can be done together.

At this time though, we have already stated that we plan to accelerate our drilling program mid-year as we continue to get results from some of the prior activities that we have receive, but we also believe that a share repurchases appropriate today given the current stock value the values that we see for the Company. .

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

This is Randy about that.

We think that our activities in 2017 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 is the potential for we have 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 is 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 are not going to use massive amounts of the same. 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 into is that part of the impetus behind the larger packages is to gain the efficiencies of the well that you gain from not having created more parent-childs and not having the offset wells being fracked.

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.

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 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 assets?.

We are 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 of that or some number like that.

The way we have our corridors and the way we have our infrastructure in the marketing, we can run quite a few rigs. And I think historically, we have run as many as 10 or so. So, I think what the balance is, making sure that you are being careful in 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 financially and others. So, I think the goal is to put that 25 plus year inventory back down to something to where there is actually a present value created on those activities.

I don’t know where we are exactly, but I think that means that we as we stated pick-up rig and probably second half of this year and then with the measured paced pick-up rigs and you are looking at something along the lines of, I don’t know six, seven, eight rigs something like that.

I don’t think we need to go to 2015, but I do think over the next couple of years, we need to pick up that rate case..

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 an industry level on what you are seeing in the basin with respect to gas processing infrastructure and gas takeaway. And I'll leave it there, thank you..

Thanks, Kashy. This is Dan Schooley again. From the processing capacity that we see in the midland basin and particularly connected to our production. We don't see that coming being constraint 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 two major purchasers on our acreage that have firm capacity for their residue gas production out of the basin.

We have been in contact with both of them that 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 the 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 the other if one of the two has a significant issue.

Enlink in particular has access to not only WAHA, but they have access to the [KD Hub] (Ph). 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 and as we've 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 any change in WAHA Basins widely..

Thank you. Our next question comes from the line of Sameer Panjwani of Tudor Pickering Holt. Your line is open..

Hey guys, good morning..

Good morning..

Good morning..

So you have done a great job here of accelerating shareholders value between Medallion and the buyback program.

I’m just wondering what other opportunities are there within the portfolio to 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 we are just now coming into our own in terms of being able to really articulate what the production corridors do fully in terms of LOEs and the infrastructure spin that we spent.

So we kind of have a view that as we drill what we're currently - the number of rigs we are currently running plus some acceleration over the next few years, that’s a benefit that we keen and we anticipate enjoying different lower LOEs and binding costs.

We still have a little bit of acreage here and there that we are not going to get to anytime soon, it’s not in the area that we are currently acting, so they are there, but I think we are very much of the mind and that we are talking with that of behind us about acreage and I think there is an inventory that is exciting an economic and we can handle it.

So we are pretty excited about that. .

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

It’s not very much. And keep in mind that we have been able to add corridors by the easy training [NIM] (Ph) 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 have got something like 95,000 acres or so - something like and connected by corridors. .

Okay that’s helpful and then you guys also talked - you have provided some details around the down spacing tests and how they confirmed your pre-drill 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 will be possible to quantify what the initial oil cut looks like?.

Yes. As I have 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 time to really quantify and articulate those kind of numbers. I’m happy to see them, but I think you will be hearing more about that as we get data that we are comfortable with. .

Okay. Thanks Randy..

Thank you..

Thank you. Our next question is from the line of Asit Sen of Bank of America. Your line is open..

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 to be able to achieve 10% growth over the year. I would expect to see it relatively even over the remaining three 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 rigs, you really will not see the benefit of that fourth rig’s activity until very late in the year..

Okay, and then just willing 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 both the last year.

How does that translate into corporate returns?.

Well when they 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 means to obviously translate into the corporate return and I think the steps that we have taken with cleaning up the balance sheet, reducing our interest cost, some other things we have done in that we have built out the infrastructure, we have collected most of the data.

We think all of those things are pushing corporate returns into the right direction..

Okay, and then the 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 is the return and what is the impact to our existing shareholders of the repurchase program. As well as and similarly do the same thing when we are 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 markets given what we believe we have been able to accomplish over the last year which is set to our program of enhancing the overall long-term value of the Company.

How we have 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 are accelerating at the right time with the right margins and have confidence around what we are seeing both on the commodity price side as well as the cost side.

So I don’t think to our really either or rather we do the share buyback or accelerate activities, we have talked about that we are planning to accelerate activities and may do that further, but that a share repurchase 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.

.

Thank you very much. .

Thank you. Our next question is from the line of Joe Allman of Baird, your line is open. .

Thank you good morning everybody. My first question is around 1.3 million Boe type curves. If you guys you can just make maybe three points on this one so because you outperformed on a 114 wells, is this 1.3 million Boe type curves is it assuming that you do have some communication between adjacent wells going forward? That’s number one.

Number two, should we apply this 1.3 million Boe type curve to our future Upper and Middle locations? Is that kind of how to think about it or is it really just kind of looking back what you have done so far, but as I mentioned the first point you have outperformed.

And number three, is really your focus here on maximizing NPV per section rather than NPV per well, so if you can hit on -..

Well I will take first crack at it and then I'll get Rick and Dan to take some. So we have had, I think 100 plus wells that outperformed to 1.3 and as you know, we were slow to move up to the 1.3. We wanted to have substantive data when we pushed that out. And we said a couple of different times that we are very comfortable with the 1.3.

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 have got a number of wells that have performed beyond that.

So, I think in terms of the spacing, I don't think we are necessarily saying that there is going to be interference that’s going to take the outperformance down to 1.3 at all. I think we are saying that that’s a good number that you should use modeling going forward. We don’t see necessarily interference.

But what you are trying to do, what you really want to do is get us close to interference as you can and still have it being accretive on both well and a section basis.

And if you look at Page 17 in the presentation that we pushed out concurrent as 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 have articulated perhaps not well is to really not the best rate of return one off, two well off drilling program that are really trying to understand what this 20 plus year, acreage-based inventory could really be in terms of NAV. So we have looked at what size packages we have looked at.

We have talked a lot about our goal has been to prevent to the extent we could mitigate depending on child issues. And so I’m pretty comfortable that we are going to be drilling larger packages, which we have talked about has quarter-to-quarter impact on production.

The larger pack is, do give us capital efficiency, but not as if we were drilling single off wells. So, I think what we are heading towards is some sort of long-term sustainable growth for shareholders.

Dan, Rick, do you want any?.

Okay. So I think that's very helpful, Randy. Thank you.

And 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 seems we are pretty confident because you may be on a pretty good concentration of those kinds of wells in the second half of the year..

We've done one of our issues is the amount of testing of different spacing and both horizontally and vertically that we have done. We do know a fair bid and we have been careful to make sure that we don’t pronounce success or failure too soon.

But I think we have drilled something like 10 or 11 or so spacing tests in 2017 with a number of varying configurations, both horizontally and vertically. And we were slow to comment on those, because we wanted to see more than just 20 days or 24-hour IPs, and we wanted to see several quarters of data.

So, we tested a number of configurations starting back in 2016, but certainly well through 2017..

Alright. Great. Very helpful, guys. Thank you..

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

That’s very helpful guys. Thank you..

Thank you. Our next question is from the line of Eli Kantor of DIR Advisors. Your line is open..

Good morning, guys..

Good morning..

Can you talk about the thought process perhaps behind pursuing a share buyback program versus our purchasing debt or issuing a dividend?.

I can address that one more time. We think we have the optionality to do both either the share buyback as well as accelerating the drilling program. They are not mutually exclusive. We look at the value created, the dollar spent, whether those dollars are being spent in a share repurchase.

What is the debt adjusted net impact to our existing shareholders on multiple metrics and the value that we believe will create through that. Similarly, we do the same thing when we are looking at adding additional rigs.

One of the things that we have been very cautious on especially in industry cycles as we are experiencing today, where there is a still significant volatility of commodity prices.

There is volatility and 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. We are a little bit agnostic about how we go about trying to add shareholder value. We have never had any in our mind, we have always been open the share buyback and to your point about the dividend, we modeled that. We have modeled acceleration and I think Rick’s point about we have the flexibility to do a number of those things as 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 talked about how we don’t see that precluding us from possible increase in our rate cadence later in the year 2019 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 of the year end and 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 of 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 pricing performance?.

Just a second, one thing to keep in mind I don’t have the specific price and 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 which we did several years ago to give us maximum flexibility in the well that we are going to drill 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 to come back in as revisions rather than as new reserves.

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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 the way we interpret the guidelines is that they comeback in as positive revisions. It’s not necessarily well performance, the pricing, it’s just the wells were actually drilled although they were classified as puds several years ago and at this point we have actually drilled them. .

Got it, thanks very much. .

Thank you. The next question is from the line of Derrick Whitfield from Stifel. Your line is open. .

Thank you and good morning Randy, good morning Tim. 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 have 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 they're coming out of the midland basin is easier than coming out of the Delaware. That something we spent time thinking about. There is a lot of conversations about service cost and we've actually bid out a number of service providers services in the last couple of months. And I've said overtime, service cost always go.

But we're not seeing that 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 you told you about them at the end of 2017. 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 is gotten better. So we spend 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 with Medallion transaction. We have a lot of liquidity, so there is less pressure this year on that than it was before. So I think those are the three big thing that we worry about. .

That's good. And then my follow-up is based on your diagram have 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 one factors or how you're factors in your predictive modeling?.

I think it's kind of a combination. As you drilled more wells in a series, there is delay and I think we've seen that 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 a parent-child issues. That's helped us a lot.

So I think there is 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 NAV value out of this acreage with the much, much more long-term sustainability in our premium zone which are several lending points in the Upper Wolfcamp and the Middle Wolfcamp.

So I hope that answers your question Derrick..

Yes, it did. Thank you, Randy..

Thank you..

Thank you. We have time for one last question, the line of John Herrlin of Societe. Your line is open..

Yes, thanks. Regarding the wells that you have the problems with, could you give a little bit more detail and also what is the lands or the wells you are planning to drill this year.

They mainly two-mile or you are still doing three-mile and how did the three-mile wells work?.

I will let Dan talk about the case using just a second. But that we are kind of headed toward, I think because of the way we are drilling and where we are drilling, probably more than two-mile wells this year. We are still trying the land grabs a little bit over.

So, we are 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 it looks like it’s going to be something like 10,400 feet laterally. Dan, you will talk about….

Yes. And John, the two issues on the Kloesel, but the drilling issue was the Middle Wolfcamp Shale that we took landing zone that we were in those highly fractured and a little bit higher pressure than we anticipate first time we drill that 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 drill that well. So, we stop drilling at about 4,300 feet and completed well there, that well is performing very well or it’s for the length of well with this.

So we are encouraged about actually that landing zone and what that looks like for and we think we can solve that the drilling issue very easily. The other well, we had drilled well, completed the well, we are in the process of drilling out when we had a casing failure, so with only has three of the 82 stages open at this point in time.

So, again that something that we feel like is very rare and we don’t anticipate that happening to us again..

And what about the three-mile clean-ups?.

Three-mile clean-ups are progressing. I mean none of us, I don’t feel or too concerned about it, worried about 85% of type curve now after 180 days the wells are still cleaning up, but there is nothing in the execution of the drilling or completion of those wells that gave us any concern.

We are 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 simulating that lateral clear at the end, into that lateral.

So 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 link..

John, this is one of these where we have cut out there and we have done, I think more than most, and we are the leader there. And I think we are, as you know, slow to claim victory.

And we have now seen some other operators start reaching out on lateral length, and so I will be anxious for the industry to help us give confirmation data on what we are seeing with the three-mile laterals..

How much more time is it Randy in terms of the incremental clean-up versus a two-mile lateral that we are talking four months?.

Yes. I think it depends a little bit on flow back, 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, I mean when you think about it, it’s a half longer 10,000, 15,000.

So, there is just a lot more water that you have to pull back out of the same vertical part in the same gas lit area and it’s been taken a little longer to clean up and these wells are also a little denser spacing. So, all of that’s made us to be one, pleased with the results and two, not surprised to see the clean-up actually take longer..

Okay, great. Thanks..

Thank you..

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

We appreciate your interest in the Laredo. Thanks for joining us for our year-end 2017 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..