Ronald Hagood - Director-Investor Relations Randy A. Foutch - Chairman & Chief Executive Officer Daniel C. Schooley - Senior Vice President-Midstream & Marketing Richard C. Buterbaugh - Chief Financial Officer & Executive Vice President.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc. David R. Tameron - Wells Fargo Securities LLC Ryan Oatman - Cowen and Company Brian Singer - Goldman Sachs & Co. Jason Smith - Bank of America Merrill Lynch John P. Herrlin - SG Americas Securities LLC Daniel Eugene McSpirit - BMO Capital Markets (United States) David Meats - Morningstar, Inc.

(Research) Phyllis Camara - Pax World Funds.

Good day, ladies and gentlemen. Welcome to Laredo Petroleum, Inc.'s Fourth Quarter and Full-Year 2015 Earnings Conference Call. My name is Nicole, and I'll be your operator for today. At this time, all participants are in a listen-only mode. We will be conducting a question-and-answer session after the financial and operations report.

As a reminder, this conference is being recorded for replay purposes. It is now my pleasure to introduce Mr. Ron Hagood, Director 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, Chief Financial Officer; and Dan Schooley, Senior Vice President, Midstream and Marketing; as well as additional members of our management team.

Before we begin this morning, let me remind you that during today's call, we'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 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 today's news release. Beginning January 1, 2015, Laredo began reporting production in proved reserves on a three-stream basis. In the news release issued yesterday, financial and operating results and well results have been reported on a three-stream basis.

Additionally, a conversion of production and unit cost data for 2014 from two-stream to three-stream has been provided in the appendix of the corporate presentation released yesterday.

In the news release and in comments on this call, when volume-based comparisons between 2014 and 2015 are made, 2014 results have been converted to comparable three-stream figures. Yesterday afternoon, the company issued a news release and presentation detailing its financial and operating results for fourth quarter and full year 2015.

If you do not have a copy of the news release or presentation, you may access them 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 2015 earnings conference call. 2015 was a tough year for our industry. It was a very tough year. However, despite the challenges presented by the declining commodity price environment, we think we have made some pretty good progress at Laredo.

As we will address on this call, the catalysts we have been talking about all through 2015 are positively impacting the company. We have continued to efficiently improve our operations and make significant strides to enhance our well economics.

We have substantially increased our drilling and completion efficiencies during the year, which are translating into lower well costs in 2016. And we are seeing extremely promising results from both our Earth Model and our enhanced completions. In a few minutes, we will update you on the Medallion system growth.

All these catalysts enable the company to efficiently weather the current price downturn. The steps we took early in 2015 to restructure our balance sheet and slash costs have paid off as we operated approximately within cash flow during the second half of 2015.

We entered 2016 with over $800 million in liquidity and hedges covering 85% to 90% of anticipated 2016 oil production, and 70% to 75% of anticipated 2016 natural gas production. We have no long-term debt due until 2022.

As Rick will discuss in a few minutes, in 2016, we have again reduced our capital program to better align expenditures with cash flow. Additionally, as we'll explain in greater detail, we have adjusted our approach to booking PUDs.

We believe this adjustment will greatly increase our flexibility to drill locations in the future that have the opportunity to achieve the highest rate of return. As we have highlighted in the past, we have invested capital in building out infrastructure on our contiguous acreage.

Well, we are now seeing the benefits of this early investment, especially in this period of depressed commodity prices. Our infrastructure investments in production corridors had a benefit of approximately $13 million to the company in 2015, and that benefit is expected to grow by more than 50% in 2016.

The Medallion pipeline system, in which we own a 49% interest, commenced operations and grew from no transported volumes in January 2015 to an average of 69,000 barrels of oil per day transported in the fourth quarter. During the fourth quarter of 2015, we essentially completed an 11-well project along a one-mile stretch of our Reagan North corridor.

This project effectively demonstrated the significant advantage of our contiguous acreage position, supporting our ability to drill long laterals, and serves as further justification for our in-place investments in our highly efficient production corridors.

Along this stretch of corridor, we drilled and completed 11 wells back-to-back, benefiting from multi-well pad drilling, and a water handling and recycling infrastructure, and on average, completing the project at approximately 90% of expected cost. As I've said earlier, we think we have made some pretty good progress this year.

We grew production 18%, while reducing our exploration and development costs incurred by 48%. By the second half of the year, we had successfully transitioned the majority of our drilling program in the more capital-efficient 10,000-foot laterals and almost eliminated the need-to-drill vertical wells to meet drilling obligations.

We have continued to reduce well costs with the best practices program that has increased our drilling efficiency measured in feet drilled per day by 75% versus 2013 levels. Completion efficiency as measured in average stages per day has improved by 20% over the same time-frame.

These are sustainable improvements regardless of service cost or commodity prices. During 2015, the Earth Model and our continuing improvement in completions were also a big catalyst for Laredo. We partially or fully utilized the Earth Model on 33 horizontal wells. Additionally, we used more sand per lateral footing completions on 10 wells.

The average uplift over the oil-type curve for those 10 wells that utilized both the Earth Model and more sand is on average approximately 30%. In 2016, we expected to continue to optimize our completions accompanying Earth Model data and higher proppant density.

The majority of our 2016 capital budget is focused on maximizing rate of return by concentrating on drilling 10,000-foot laterals along the production corridors and target the Upper and Middle Wolfcamp zones.

The capital efficiency derived from the lower well cost and longer laterals that I have mentioned a minute ago means that at our current pace, we believe that we have nearly 30 years of drilling inventory that is capable of generating a 12% or higher rate of return in the prevailing price environment.

In 2015, as we reduced completion activity and brought on fewer high rate horizontal wells, our oil production as a percentage of total production dipped from approximately 50% to 45% in the third quarter and fourth quarters. In 2016, we expect our oil cut to increase with increased completion count.

In the first quarter, we expect our oil cut to be approximately 48% and to be approximately 47% for full-year 2016. I would now like to turn the call over to Dan for an update on Laredo Midstream Services..

Thanks, Randy, and good morning, everyone. Taking advantage of Laredo's contiguous acreage position, LMS' infrastructure investments including oil and gas gathering, centralized compression and water services provided substantial benefits to the company both economically and operationally in 2015.

With a focus on increased corridor drilling, LMS enabled Laredo to grow the percentage of the company's crude oil gathered by LMS for approximately 35% in the fourth quarter of 2014 to 46% in the fourth quarter of 2015. Every barrel gathered by LMS results in $0.95 uplift in netback pricing and an additional $0.75 in gathering revenue to LMS.

The combined pricing uplift and gathering revenue totaled $8 million for 2015.

With the drilling anticipated in our existing corridors, we expect the volume of Laredo's crude oil on our gathering systems to increase to approximately 60% in 2016, generating the same price uplift and gathering revenue benefits to Laredo with little additional capital expense.

Laredo's increased drilling in existing production corridors will also drive additional water-related savings to both capital and LOE. Our water treatment plant became operational in the second half of 2015.

With the increased level of drilling in our corridors in 2016, we are projecting that our water treatment plant will be capable of providing over 60% of the total water required for our completion operations.

Depending on the amount of recycled water utilized and the proppant intensity, utilizing recycled water in our water system in Laredo's completion operations should provide total savings of between $100,000 and $200,000 per well in 2016, again, with little additional capital expenditure by LMS.

Laredo's water system also provides savings for transportation of flowback and produced water in our corridors. On average, we estimate that we will transport over 15,000 barrels per day of produced water, generating a water transportation savings to Laredo's CapEx or LOE of approximately $5 million in 2016.

Additionally, our water system allows Laredo to save on disposal cost for flowback and produced water. Our 2016 drilling program is expected to allow us to increase the amount of produced water that we can recycle at the water treatment plant from 25% in the fourth quarter of 2015 to 45% by the fourth quarter of 2016.

The increased volume of flowback and produced water delivered to our water treatment plant instead of disposal is expected to reduce Laredo CapEx and LOE by $1.6 million to $2.4 million in 2016.

Combined price uplift, capital, and LOE savings to Laredo generated by our production corridors exceeded $13 million in 2015 and should exceed $21 million in 2016, at minimal capital expenditure to Laredo. Another important tool in giving Laredo access to various markets is our 49% ownership in the Medallion crude oil pipeline system.

As the Medallion pipeline system continues to build out in 2016, we expect our cash flow per barrel to vary from quarter to quarter.

Based upon current estimate from producers, including us, we expect throughput on the system to increase from 85,000 barrels of oil per day in the first quarter of 2016 to approximately 150,000 barrels per day by the end of the fourth quarter of 2016.

This volume increase is expected to be somewhat lumpy as construction projects are completed and as more of the production comes from larger, consolidated tank batteries in which multiple wells are brought online at the same time.

As reported today, our net income from the Medallion pipeline for 2015 was $6.8 million, which generated cash flow to Laredo of approximately $10.7 million. This net income and cash flow for 2015 included our one-time settlement of a minimum volume commitment on a natural gas project in Mitchell County, Texas.

Excluding this settlement, the Medallion crude oil pipeline generated cash flow for 2015 net to Laredo of $8.9 million, or $0.58 per barrel. The relative mix of production on the pipeline is expected to result in a decrease in the gross revenue per barrel to approximately $1.35 per barrel for all of 2016.

Simultaneously during 2016, we expect OpEx and G&A to decrease at a faster rate, to approximately $0.38 per barrel, generating cash net margins to Laredo in the range of $0.48 to $0.52 per barrel for all of 2016. With that, I'll turn it over to Rick Buterbaugh..

Thank you, Dan, and good morning. As reported last night in our fourth quarter and full year 2015 earnings release, adjusted results were essentially in line with our guidance. Production for the fourth quarter was in the upper half of the range, despite some challenging weather in the Midland area late in the year.

Our constant focus on cost controls resulted in total cash costs for the quarter declining 9% sequentially from the third quarter of 2015 and down 22% from the fourth quarter 2014 levels. However, fourth quarter DD&A was higher than projected, due to our decision to modify our approach to booking proved undeveloped reserves.

This change caused some increase in our fourth quarter 2015 DD&A rate, which is now projected to decline substantially in the first quarter of 2016. As you know, DD&A expense is essentially driven by the depletion component.

Simplistically, depletion is determined by production volumes for the period divided by the year-end reserve volumes, plus production volumes for that period, with the resulting factor multiplied by the net book value of the full-cost pool.

We have adjusted our PUD booking approach to provide the maximum flexibility in developing our significant resource potential. Our efforts to drill the most profitable wells necessitates having been able to choose any drilling location and not be tied to a specific location created in prior plans in a very different environment.

We currently have identified approximately 1,100 locations that, even at current pricing, we believe are the best of our extensive total inventory. But what is the best? These will likely change over time due to continually changing prices, costs, technology, and our acreage position.

In addition, with the further integration of the Earth Model and improved completion design into our development plan to enhance the economics of each identified location, it is not prudent to commit to drilling a specific location for three years, four years, or five years out in the future.

Additionally, as commodity prices have drastically declined, we have taken the necessary steps to significantly reduce our capital budget.

This lower capital reduces the rig cadence for future development, and therefore, reduces the number and timing of specific PUD locations that we are committing to develop, and provides optionality in the future on where we drill.

For year-end 2015, reserves have included a total of 38 specific PUD locations, and we expect that all locations will be developed by year-end 2017. In fact, 15 of the total booked PUD locations have already been drilled or are currently in the process of being drilled.

As a result, year-end 2015 reserves totaled 126 million barrels of oil equivalent, of which 100 million barrels of oil equivalent or approximately 80% are proved developed. We removed 131 million BOE related to our adjustment in PUD bookings. However, these resource volumes still exist and we expect them to be developed over time.

We also reduced 38 million BOE from our proved developed reserves, reflecting the removal of vertical wells due to a shorter economic life based upon the SEC required pricing for calculating reserves. The PV-10 of our proved reserves is approximately $830 million, 95% of which is associated with proved developed reserves.

Using the required SEC protocol for prices and costs, the reduced number we booked as PUD reserve have diminished the total value. Keep in mind that these values do not include any value for our hedge position nor does it reflect the 13% reduction in D&C cost that we've realized already this year.

Also, we still anticipate drilling at a higher well cadence than what is reflected in our PUD bookings. The conversion of these resources directly to PDP is not reflected in the PV-10 value. For 2016, we have set a capital budget of $345 million, excluding any future new projects associated with the Medallion pipeline system or potential acquisitions.

Our 2016 program is focused on taking advantage of our blocked-up acreage position and existing infrastructure to maximize the rate of return of the overall program.

As outlined in the press release, we will almost exclusively target the Upper and Middle Wolfcamp zones and the majority of the wells will be 10,000-foot laterals drilled along existing production corridors.

In total, we expect to drill 36 gross horizontal wells to 38 gross horizontal wells or approximately 40% more than what is reflected in our PUD bookings. We do not anticipate drilling any vertical wells in 2016.

Our long-term planning to meet lease obligations within our core acreage position has enabled Laredo to fulfill nearly all of these commitments exclusively with horizontal wells. We anticipate operating three horizontal rigs in the first half of the year and dropping to two operated rigs in the second half.

By midyear, we expect all of our rigs to be contracted on a well-by-well basis. Therefore, maximizing the company's flexibility to manage the pace of drilling and negotiate the best possible rates. As mentioned previously, we continue to increase the efficiency of both drilling and completion operations and negotiate lower service cost.

We expect to drill approximately 80% of our wells on highly efficient multi-well pads reducing well cost by about $200,000 per well for 7,500-foot well and about $300,000 for 10,000-foot well.

Efficiency gains and service cost reductions have reduced budgeted cost for Upper and Middle Wolfcamp wells drilled on multi-well pads to approximately $5.2 million for 7,500-foot lateral and about $5.9 million for 10,000-foot lateral. It is anticipated that cash flow from operations will fund 75% to 80% of our budgeted capital expenditures.

The balance is expected to be funded through our revolving credit facility, divestitures, or capital infusions. As of February 16, we have drawn $170 million against our elected commitment of $1 billion on our revolving credit facility.

This facility currently has a borrowing base of $1.15 billion, not including the Medallion pipeline system, which has not been pledged as collateral. In summary, we believe we have progressed the efficient development of our vast contiguous acreage position in the Midland Basin.

We have reduced our capital program to be more in line with expected cash flow. We have a strong hedge position valued at more than $280 million today, protecting cash flow for multiple years. Our credit facility is underpinned with conservative reserve values, 95% of which is PDP.

We believe the value of our Medallion interest continues to grow as the throughput at Medallion and expected EBITDA increases.

We have a substantial inventory of high-quality projects from which we will continue to high-grade and we believe we have the financial capability to continue the measured growth for the company even in a challenging commodity price environment. At this time, operator, would you please open the lines for any questions..

Thank you. Our first question comes from the line of Neal Dingmann of SunTrust. Your line is now open..

Good morning, guys. I know you have laid out the plan for next year. I'm just trying to get an idea for the drilling plan for this year. Will you do anything as far north up towards Howard or I know you mentioned in the press release where you have kind of stayed across that 11-mile area where you've got the infrastructure and such already there.

I'm just wondering about any drilling further north?.

Neal, we kind of think that the economics for us drilling within the corridor or drilling where we have water handling and recycling capability and can put our product in pipe is where we're going to focus, which means probably in that other area, but what we will say is that we notice and pay attention to what other operators are doing in and around our acreage.

And I think we're kind of excited about what we're seeing in the data that other operators are providing for us. So, I think the message would be that I would think that we're probably going to stick to where we see the best economics. But as we've said before, at some point, we're going to have to test some of that additional acreage.

But as long as we're getting data from other operators, I don't know that we need to be the first ones out there..

Sure. That's certainly what I was getting at, that other area we are certainly seeing some interesting things up there. And then just my follow-up, just wondering on, I think on the CapEx, you mentioned about the cut, about 39% spend at around (24:27) $345 million.

Just your thoughts on how much more you think you'd have to spend this year on Medallion and the other infrastructure?.

We've said that we think Medallion is mostly built out although we've told the Medallion – again, we have 49%, and we're not the management but we like what they do. I'm sure there's going to be some additional lines built to bring in trucking stations or whatever.

But I don't anticipate Medallion to be anywhere near the spend it's been or major spend this year. But we like the way the Medallion management has built out that system..

Thank you. Our next question comes from the line of David Tameron of Wells Fargo. Your line is now open..

Good morning..

Hi, Dave..

You guys put up a new slide deck and I think you addressed some of this in the Q&A, but it looks like your well costs, I guess, got a slight spin of the new deck. Looks like the 7,500-foot lateral, and we talked about this, but $5.9 million to $5.2 million and then the longer laterals coming down almost $1 million as well.

Like what exactly is driving that decrease? Can you just give us some more color on that?.

Yes. And I think that's one of the things that we've been talking about for some time as one of the catalysts. We had a pretty good effort going on really looking at any non-performance time on our drilling and completions operations.

And if you look at our operations group and there's the long list of people that were on that team and leading that effort, they did a really good job of trying to maximize the efficiencies. If you look at page nine, for example, in our presentation that we posted, from 2013 to 2015, the average drilling foot per day was about a 75% improvement.

That doesn't happen without paying a lot of attention to the details on how we drill the wells. And if you look at the same page on that, the average stages per foot, 20% improvement average stages per day. And that was one of the things that we started seeing earlier in 2015, and we said it was going to happen.

It was one of the catalysts, and we keep those efficiencies, that's what's exciting to us about it, regardless of the service cost and we are seeing still some pressure on the service cost providers..

Okay. Just following up there. Randy, how much do you think you have left as far as absent service costs? And I know it's not a static environment because as capital goes up and prices go up, et cetera, it'll chase a little bit.

But how much more efficiencies, let's say we stay here at current price levels for another 12 months, how much more do you think you could squeeze out?.

Yes. That's a wild guess, I think, to some degree. But what we're seeing is – and we've said this before and seen it before that when the service companies start cutting the compensation of the people they want to keep, it's getting kind of close to the bottom. There's not a lot left that they can do.

And we view it a little bit different, in that we think the job of our service providers are to bring us a safe crew that does the job with the knowledgeable people on there. We want them to maintain the existing equipment very well. But Dave, we also want them to continue to bring us new equipment.

The example that I use is, if you had drilling rigs under contract or own them, you'd be stuck with something probably less than 5,000 PSI hydraulics. We're now using all 7,500 PSI hydraulics. Same thing on the amount of sand move.

So there's not a lot left on the service cost, maybe some incremental savings, but we want those guys to continue to bring us the best technology and the best equipment. Now it's good for – we think that we have a little bit of a preferential benefit for them also, in that we're drilling within a corridor.

Our corridors are such that, when we do an 11-well program, they know exactly where they're going to be, the service providers on the pumping side. They're not having to drive from location to location, 20 miles, 30 miles apart. So we think the corridor drilling also gives us a pretty big advantage on the service cost side..

Thank you. And our next question comes from the line of Ryan Oatman of Cowen. Your line is now open..

Hi. Good morning, and thanks for taking my questions..

Thank you, Ryan..

I was wondering if you could elaborate a little on slide 11, you show the benefit of the enhanced completions in the Earth Model here with the 10 wells. You've got results about 30% above the original type curve, about 15% above the Earth Model estimate.

I guess first question, can you just quantify the denominator here? So what sort of incremental costs we're looking at for these enhanced completions and the Earth Model versus the original type curve?.

When we look at the enhanced completions, sand does cost more, and it's getting cheaper and cheaper to use more sand. But the good thing about the Earth Model which excites us is, we've got a team of people working it, but we've captured that data for the most part over the last couple of years. And a lot of that data you can't get overnight.

It takes years to collect the right kind of data. So the enhanced completions cost a little more, but the Earth Model itself is – that benefit comes at not a lot of cost..

Got you. That makes sense.

And then, as we look forward here, can you speak to the estimates that are embedded in your 2016 guidance?.

The estimates on? I'm sorry..

Are you talking about the production guidance? I think we've lost him..

And our next question comes from the line of Brian Singer of Goldman Sachs. Your line is now open..

Happy if you wanted to answer the previous one before I ask mine – if you wanted to, or I can go ahead with mine?.

Go ahead, Brian. The guidance....

Okay..

Excuse me, let me just add, I mean the guidance put out is based upon, as we showed, the $345 million capital program that we anticipate for 2016 from that, wells that we will drill and the resulting production that comes from that. Go ahead, Brian..

Yes, thanks. I had just two questions. The first is on slide 13; you talk about the changing production mix that is related to your rig cadence.

Can you just add any more color if there's anything geographical that's going on there, or is it just a one-quarter lag to the number of completions purely? And then if so, how that reconciles with the third quarter? And then my separate second question is if you could add some more color on the proved-to-developed downward revisions? And when in the lifecycle those wells become uneconomic? If that's something that is kind of one to two years out or five to 10 years out?.

Brian, the first question was, most of our drilling in 2015 and 2016 is in kind of one area. So the oil percentage is not related geographically. And it's literally, as we've said before, just flush production off a new drilling, means that the new wells coming on have a higher oil content.

Rick?.

And the only thing to note on that, on slide 13, Brian, is that in the second quarter of 2015, those bars represent the gross wells that were drilled.

In the second quarter of 2015, you may recall that we completed a large project there, where we only had a 50% working interest in those wells, and although there were significant number of wells coming in, the net production that we received was not as much. And your second....

Great. And on the proved to developed bookings. Thank you..

The second question, we have a number of vertical wells, some of which are either 10 years old or so, I don't know, getting into their pretty flat part of the decline.

We watch those wells carefully, and the reserves that we lost on the PDP side were principally reserves from the tail out 20 years, 30 years, in that the economic limit with lower prices got there quicker.

We have a program where we look at wells in terms of do we need to replace the pumps? Do we need to do things to them to keep them economic? And that's just part of good operations..

Thank you..

Thank you..

Thank you. And our next question comes from the line of Jason Smith of Bank of America Merrill Lynch. Your line is now open..

Good morning, guys..

Good morning, Jason..

Rick, I think you mentioned in you remarks that divestitures are an option for you guys.

Can you maybe just give an update as to what the market looks like and where the incoming interest has been? More in the upstream or midstream side?.

Well, this is Randy. We think there's still in Midland Basin a fairly active A&D acreage market out there. There's been a pretty big spread I think developed over the last year or so on buyers and sellers. We think our acreage still has value. We don't have anything specific working there. But we think that it is an option for us.

We haven't felt a lot of pressure to do things and especially as the industry – for a while we were kind of out there by ourselves doing it, but what we're seeing is that we're getting a lot of industry information in terms of the drilling in and around this as I said before. So I think that's still an option.

Your question on the midstream, we think Medallion is literally the premier crude oil transporter in the premium basin in North America. We've said before that we think we're developing great optionalities there.

We think we're developing EBITDA, which maybe we should just keep, or we think at the end of the day there's some optionality at some point monetizing our investment in Medallion. I don't know that either one of those two things in terms of selling acreage or selling Medallion, there's no pressure for us to do that now..

Great. Thanks..

But what we presented, Jason, was a slight outspend anticipated in 2016. We think we have sufficient liquidity on our credit facility today to handle that and really to do that for multiple years.

But we continually look at utilization of that versus other options and what you have seen the company do in the past as far as divestitures from time-to-time as well as accessing the capital markets.

We'll look at each of those options as the need may occur, but our overall goal is that we're going to self-fund significant portion of our capital program going forward..

Appreciate that answer and then just my follow up is, it looks like oil and gas realization guidance is down pretty significantly sequentially, even though on the oil side Midland's trading essentially at parity with WTI.

Any reason for that?.

Yes. Jason, this is Dan Schooley. There's several things going on. I think that our cost of transportation to the U.S. Gulf Coast is a greater percentage of a lower commodity price. We saw a realization from October to December drop from 92% to 82%, so we're guiding in the first quarter of 2016 to about 80% for the same reason.

The transportation differentials are not supported right now by the differential between the Gulf Coast and the Midland price..

Thanks, Dan..

Thank you and our next comes from the line of John Herrlin of Société Générale. Your line is now open..

Yes, hi. Most things have been asked and answered.

With your well completions to put down more sand, are you doing just more intervals and more clusters around it?.

John, that's an interesting question. We still view that there's incremental improvement going to happen on stimulations. We don't think we're done.

We've actually done sand from 1,100 pounds a foot up to over 1,800 pounds, I think, a foot, and we've kind of done clusters three to five and I think there's still some incremental improvement going on there. Our view is that you need more than 30 days production data to really home in on which one of those is ultimately where we go.

So, yes, John, there's still some I think some incremental improvements going on..

Okay.

With the sand, are you changing feed size? Are you going smaller or any difference in the size of the proppant?.

No. Early on a couple years ago we did a little bit of that, but no, we haven't changed proppant size or anything. And just to expand a little bit, John, we're doing some things.

We've been looking at whether you, maybe in part of the fracs, want to do a little bit with gel or a little higher viscosity fluid and tail off with that and trying to make sure that we frac the entire link to that horizontal lateral successfully. So, I think we've got a pretty robust completions effort going on trying to really optimize.

And I suspect we'll be talking about incremental optimization for some time to come..

Okay. That's fair. Next one for me, I guess, is more philosophic. This isn't your first rodeo in terms of price cycles. When was the last time you kind of changed your PUD counts in a more discretionary manner? Because, obviously, price was a lot of it, but you seem to be taking a more conservative stance by dropping your percentages..

Yeah. We think this cycle is significantly different than the multiple ones we've seen in the past. And we've really felt that early on really over a year ago when prices did start to decline. And because of that, the other difference is that we have a significant inventory of projects.

And what you want to do in this type of a cycle is make sure that you have the ability to constantly drill the absolute best when you have over 1,000 locations that you want the ability to drill the best of those locations. And what is the best changes with price changes, with cost changes, with the technological changes that takes place.

When you book out a full five-year period, you're making a commitment that those are the wells that you anticipate, the most specific wells that you anticipate drilling.

We don't want to be committed to drilling those specific wells when we may be able to identify those that make more sense that are going to be more value added for all of our stakeholders. And so we reduced the PUD bookings to a minimal amount, those locations are still there.

They're going to be drilled, but we want the flexibility of which ones of those locations we will drill on an annual basis..

John, let me give you a specific case. Several years ago, when we made an acquisition out there, we had a number of vertical wells booked as PUDs. We had reasonable certainty, and we knew how to fund those out for five years. Within a year, we'd figured out that there was better value for our shareholders in drilling horizontal wells.

And, again, we had PUDs there that we had reasonable certainty we knew how we were going to do it. We had a plan. And then the next year, we figured out well, okay, there's some Upper Wolfcamp that's probably better than some of those others. So, for us, it's a reflection of we know that the PUDs that we booked at the time we booked them. We had a plan.

We knew they were certain. We're going to drill them. But we just think it's better flexibility for shareholders to not have booked out a five-year commitment on drilling PUDs. And to answer your question on terms, I think this is the fifth time as CEO we've seen this kind of price. Rick's correct.

Laredo, December 2014, just said we're going to adjust budget I think probably earlier than most. Looks like most people are now doing what we did early on. PUDs are, I think in our view, with our understanding of the resource play, I think most of those locations get drilled in that resource play sooner or later.

We just wanted the flexibility to as we learn more on the completions, learn more on the Earth Model and so on and so forth, to drill the best ones first..

Makes sense. Thank you..

Thank you..

Thank you. Our next question comes from the line of Dan McSpirit of BMO Capital Markets. Your line is now open..

Good morning Dan..

Thank you, folks. Good morning. Thank you for taking my questions. Just a few follow-ups here.

Just to confirm, there are no reserves on the books today associated with vertical wells, correct?.

There's still some vertical locations at our proved developed and there are no vertical PUD locations on our books..

Okay.

The PDPs, what does that amount to?.

The PDPs in terms of which ones are verticals?.

Right..

There's about 470 verticals developed locations that are on our books..

Okay..

I mean I don't have the breakout of the actual volumes associated with that..

Got it..

Bulk of it would be with over 200 horizontal wells that we have..

Right. Okay.

And then just as a follow-up here, recognizing the company has operated a lot of wells in the Midland Basin, can you speak to the different first year decline rates on the oil, NGL, and natural gas streams of a typical horizontal Wolfcamp producer? And how does that oil cut change over time? I ask because that seems to be maybe the root of some of the issues behind today's reserve report..

Well, I think, just in a gross sense, without being definitive on numbers, we see in this Midland Basin the very typical first-year's declines, pretty dramatic, in the 75% something kind of range. And then, over a matter of three years or four years, that well probably has more like a 15% decline, going to 5% or 6% decline on a terminal.

So, that's the gross decline on production. The earlier periods of time have – just because the relative perm gas flows easier than oil, so over the first couple of years, the oil content has to compete with the gas flowing easier, so it runs down.

And just to complete that, Dan, a little bit is, if you look at a well that's five years or six years old and – it's going to have a higher gas content than one that's a year old. And so, when we drill flush production, we get the benefit of that near wellbore movable oil pretty quickly..

Very good. Thank you. Have a great day..

Thanks, Dan..

Thank you. Our next question comes from the line of David Meats of Morningstar. Your line is now open..

Hey, guys. Thanks for taking the question. I just wanted to dig in quickly to the 1,100 locations you can get 12% or more in the current price environment.

How many of those locations are 10,000-foot lateral locations?.

I don't know if I had the exact number..

Like a ballpark, a rule of thumb..

The bulk of them would be 10,000-foot locations, well over half. I think it's – I don't have the specific number, but probably three-quarters of them would be 10,000-foot locations..

And I think they're all 7,500 foot or greater..

Okay.

And would it be fair to say then that the other locations you have not included in this 1,100, like the locations you talked about maybe at the end of 2014, something like that, that most of those locations are not 10,000-foot locations then?.

Our acreage block – I don't know that I would say most, and let's just – we still think that the resource play – that we have thousands of locations to drill. What we were trying to say was that these 1,100 at today's strip, do have a positive return, and those are the ones that we'll be looking at, in this price environment, to drill first.

The way the acreage has been blocked up, as you know, we went from 4,000 foot laterals to 5,000 foot laterals to 7,500 foot laterals to 10,000 foot laterals, and we've been able to, over time, based upon some land trades and some arrangements and everything else, to expand our inventory of 10,000 foot laterals.

So I think – I don't think I would say that, other than the 1,100, the rest of them are going to be less than 10,000 foot laterals. Some of them will – and maybe the majority of them will be 10,000 foot laterals by the time we're done..

Got it. I think that makes sense..

Thanks, Dave..

Thank you and our next question comes from the line of Phyllis Camara of Pax World Funds. Your line is now open..

Hi. Thanks for the call. The Medallion pipeline is primarily used for your own purposes.

Do you have any intention to increase third-party throughput more than a minimal amount? Or is it your intent to keep it as your own source for getting oil?.

Phyllis, LMS, which is Laredo Midstream Services, is the services that we use that are principally for our own benefit. And it's water and crude oil handling (51:17) everything else.

Medallion, we made our investment in Medallion initially because we wanted to be able to take crude oil, first off, be able to market it outside of the Midland differential issue, and put as much of our crude oil in the pipe as we could.

If you look on page 17, you'll see that the Laredo, the percentage of crude that goes through Laredo – that goes through Medallion is actually very small. In fact, it's somewhere around 13% of the total.

So, Medallion has been from day one designed for our benefit, in terms of how we market crude, but it was always designed to be a big third-party carrier.

And that's where the real excitement comes from Medallion in terms of increasing the value both from preserving – increasing EBITDA, and just the volume is that we've now tied in – if you look on page 17, we've got 500 miles of pipe, almost 300,000 acres dedicated to it, another maybe as much as 2 million acres under AMI.

All of that acreage is acreage that ultimately, we think, most of it if not all of it, gets drilled. And we think that Medallion is going to capture a huge part of all the crude oil coming out of the Midland Basin on a third-party basis..

Okay. Okay. Thank you.

The next question I had, though, too, was if – with your reserves and your PV-10 value going down to the level it is, how do you think this is going to impact your borrowing base redeterminations in May?.

Well, we have always taken a very active approach with our banks within our credit facility. And we've also taken a fairly conservative approach. You recall over the last two borrowing base redeterminations, we've had a borrowing base assigned by our bank group well above what we actually elected in our total commitment.

When we're looking at making that elected commitment, I mean, we're looking out multiple redeterminations, not just looking at what is the value that we could get at the next determination. One of the things to keep in mind is that the value of our reserves associated with our borrowing base is not what is used in a PV-10 calculation from the SEC.

The credit facility group gives credit for our hedges which are substantial. And as I said earlier, it's about $280 million today in value. That $1.15 billion that we had at the last fall redetermination, the bulk of that is based upon our proved developed value.

They are also looking at the cadence of which we are developing over the next several years. And with the significant location inventory, as we've discussed that we have and the ability to drill the best of those, although our PUD reserves are not – from an SEC standpoint are limited to just 38 wells.

We're going to drill at least 36 wells to 38 wells just in 2016. We're going to maintain some cadence going forward that would add multiple wells somewhere in the 200 wells range that could be drilled over the next five years.

With the large inventory that we have and with the success that we have had in our total acreage where we have yet to drill an unproductive well, the banks recognized that the fact that our SEC reserves have gone down on a PUD basis does not impact the value enhancement opportunities that the company has in its overall drilling program for multiple years.

The other thing to keep in mind is that the Medallion interest that we have is not part of our borrowing base today.

And so, we believe that there is still substantial value supporting whatever the banks may choose in the next redetermination, but certainly, we have a very high level of confidence that we have adequate liquidity for multiple years with the type of programs that we're running..

Thank you. I'm showing no further questions at this time. I'd like to hand the call back over to Ron Hagood for any closing remarks..

Thank you for joining us for our 2015 fourth quarter and year-end earnings call. We appreciate your interest in Laredo and good morning..

Ladies and gentlemen, thank you for participating in today's conference. That does conclude today's program. You may all disconnect. Have a great day everyone..