Vital Energy Inc (VTLE) 2015 Q4 法說會逐字稿

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 will 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 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 Midstream Markets, 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 today's news release.

Beginning January 1, 2015, Laredo began reporting production and crude 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 catalyst 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. 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 earlier 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 enter 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 will 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. 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 fourth quarter. During the fourth quarter of 2015, we essentially completed an 11-well project on a one-mile stretch of our Reagan North corridor. This project affectively 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 said earlier, we think we have made some pretty good progress this year. We grew production 18% while reducing our exploration and development cost incurred by 48%. By the second half of the year we had successfully transitioned the majority of our drilling program to 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 a 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 timeframe. These are sustainable improvements regardless of service costs or commodity prices.

During 2015, the Earth Model and our continuing improvement in completions were also a big catalysts for Laredo. We partially or fully utilized the Earth Model in 33 horizontal wells. Additionally, we used more sand per lateral foot in 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 expect to continue to optimize our completions by coupling 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 targeting the upper and middle Wolfcamp zones. The capital efficiency derived from the lower well costs and longer laterals that I 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 rated horizontal wells, our oil production as a percentage of total production dipped from approximately 50% to 45% in the third 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 continuous 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 from approximately 35% in the fourth quarter of 2014 to 46% in the fourth quarter of 2015. Every barrel gathered by LMS results in a $0.95 uplift in net back pricing and an additional $0.75 in gathering revenue to LMS.

The combined pricing uplift in 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 in 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 capital -- additional capital expenditure by LMS.

Laredo's water system also provides savings for transportation of flow back and produced water in our (inaudible). 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 costs for flow back 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 flow back in 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 estimates 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 a range of $0.48 to $0.52 per barrel for all of 2016.

With that I will 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 cost 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 an 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 1100 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, four 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 a 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 costs that we have 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 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 costs. We expect to drill approximately 80% of our wells on highly efficient multi-well pads reducing well costs by about $200,000 per well for a 7500 foot well and about $300,000 for a 10,000 foot well.

Efficiency gains and service cost reductions have reduced budgeted costs for upper and middle Wolfcamp wells drilled on multi-well pads to approximately $5.2 million for a 7500 foot lateral and about $5.9 million for a 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?

(Operator Instructions). Neal Dingmann, SunTrust.

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?

We kind of think the economics for us drilling within the corridor, drilling where we have water handling and recycling capability and can put our product in pipe is where we are 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 are kind of excited about what we are seeing and the data that other operators are providing for us.

So I think the message would be that I wouldn't, I would think that we are probably going to stick to where we see the best economics. But as we've said before at some point we are going to have to test some of that additional acreage but as long as we are getting data from other operators, I don't know that we need to be the first ones out there.

Sure. That is certainly what I was getting at, that other area we are certainly seeing some interest in things up there. And then just my follow-up, just wondering on -- I think on the CapEx you mentioned about the cut, about 39%. It has been around $345 million. Just your thoughts on how much more you think you would have to spend this year on Medallion and the other infrastructure?

We have said that we think Medallion is mostly built out although we have told the Medallion again -- we have a 49% and we are not the management but we like what they do. I'm sure there is going to pay some additional lines built to bring in tracking stations or whatever. But I don't anticipate Medallion to be anywhere near the spend it has been or a major spend this year. But we like the way the Medallion management has built out that system.

David Tameron, Wells Fargo.

Good morning. 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 it's on slide 10 of the new deck -- looks like there is 7500 foot lateral and you talked about this but $5.9 million to $5.2 million and then the longer laterals coming down almost $1 million as well, what exactly is driving that decrease? Can you just give us more color on that?

I think that is one of the things that we have been talking about for some time as one of the catalysts. We had a pretty good effort going on on really looking at any non-performance time on our drilling and completions operations and if you look at our operations group and there is a long list of people that were on that team and leading that effort, they did a really good job of trying to maximize efficiencies.

If you look at page 9 for example in our presentation that we posted, from 2013 to 2015 the average drilling foot per day is 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, a 20% improvement average stages per day and that was one of the things that we started seeing earlier in 2015. We said it was going to happen. It was one of the catalysts and we keep those efficiencies that is what is exciting to us about it, regardless of service costs and we are seeing still some pressure on the service cost providers.

Okay, and just following up there, Randy, how much do you think you have left as far as absent service cost? I know it is not a static environment because this capital goes up in prices go up, etc. it will 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 can squeeze out?

That is a wild guess I think to some degree but what we are seeing is and we have said this before and seen it before that when the service companies start cutting the compensation of the people they want to keep, it is getting kind of close to the bottom. There is not a lot left that they can do. 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 we also want them to continue to bring us new equipment.

The example that I used is if you had drilling rigs under contract or owned them, you would be stuck with something probably less than 5000 psi hydraulics. We are now using all 7500 PSI hydraulics; same thing on the amount of sand moved. So there is 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 is good for -- we think that we have a little bit of a preferential benefit for them also in that we are drilling within a corridor. Our corridors are such that when we do an 11-well program, they know exactly where they are going to be, the service providers on the pumping side, they are not having to drive from location to location 20 to 30 miles apart. So we think the corridor drilling also gives us a pretty big advantage on the service cost side.

Ryan Oatman, Cowen.

Good morning and thanks for taking my questions. I was wondering if you could elaborate a little on slide 11. You show the benefit of the enhanced completions and 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 cost we are looking at for these enhanced completions in the Earth Model versus the original type curve?

When we look at the enhanced completions, sand does cost more and we have got -- it is getting cheaper and cheaper to use more sand. But the good thing about the Earth Model which excites us is we have a team of people working it but we 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 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 lost him.

Brian Singer, Goldman Sachs.

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. Excuse me. Let me just add. 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 drilled and the resulting production that comes from that. Go ahead, Brian.

I had just two questions. The first is on slide 13, you talk about the changing production mix as related to your rig cadence. Can you just add any more color if there is anything geographical that is going on there or is it just a one quarter lag to the number of completions purely? And then if so, kind of how that reconciles with the third quarter?

And then my separate second question is if you could add some more color on the proved developed downward revisions and when in the lifecycle those wells become uneconomic if that is something that is 1 to 2 years out or 5 to 10 years out?

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 is literally as we have said before, just flush production off of new drilling brings -- the new wells coming on have a higher oil content.

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 a significant number of wells coming in, the net production that we received was not as much.

Great and on the proved developed bookings. Thank you.

Your second question, we have a number of vertical wells, some of which are eight or 10 years old or so 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, 30 years and 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 is just part of good operations.

Thank you.

Jason Smith, Bank of America Merrill Lynch.

Good morning, guys. Rick, I think you mentioned in your remarks the 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 on the upstream or midstream side?

This is Randy. We think there is still in the Midland Basin a fairly active A&D acreage market out there. There has 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 is an option for us. We haven't felt a lot of pressure to do things and especially as the industry -- for awhile we were kind of out there by ourselves drilling. But what we are seeing is that we are getting a lot of industry information in terms of the drilling in and around us as I said before. So I think that is 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 have said before that we think we are developing great optionality there. We think we are developing EBITDA which maybe we should just keep. Or we think at the end of the day there are 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 is no pressure for us to do that now.

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 will look at those -- each of those options as the need may occur but our overall goal is that we are going to self-fund a 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 is trading essentially at parity with WTI. Any reason for that?

Yes, Jason, this is Dan Schooley. There are several things going on. I think that our cost of transportation to the US Gulf Coast is a greater percentage of a lower commodity price. We saw a realization in December or from October through December dropped from 92% to 82% so we are 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.

John Herrlin, Societe Generale.

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, Randy?

That is an interesting question. We still view that there is incremental improvement going to happen on stimulations. We don't think we are done. We have actually done sand from 1100 pounds a foot up to over 1800 pounds I think a foot. And we have kind of done clusters, varied 3 to 5 and I think there is still some incremental improvement going on there. Our view is that you need more than 30 days production data to really hone in on which one of those is ultimately where we go. So yes, John, there is still some incremental improvements going on.

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

No. Early on a couple of years ago, we did a little bit of that. But no, we haven't changed proppant size or anything. And we are -- just to expand a little bit, we are doing some things with we have been looking at whether 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 length of that horizontal lateral successfully.

So I think we have got a pretty robust completions effort going on trying to really optimize and I suspect we will be talking about incremental optimization for some time to come.

Okay, that is 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.

We think this cycle is significantly different than the multiple ones we have seen in the past and we really felt that early on really at 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 d the absolute best when you have over 1000 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 are making a commitment that those are the wells that you anticipate and those 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 cells that make more sense that are going to be more value added for all of our stakeholders.

So we reduce the PUD bookings to a minimal amount. Those locations are still there, they are 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. When we 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 had 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 is some Upper Wolfcamp that is probably better than some of those others. So for us, it is a reflection of we know that the PUDs that we booked at the time we booked them, we had a plan. We know they were certain; we were going to drill them. But we just think it is better flexibility for shareholders to not have booked out a five-year commitment on drilling PUDs.

And to answer your question on terms of -- I think this is the fifth time as CEO we have seen this kind of price. Rick's correct, Laredo December 2014 just said we are going to adjust, budget, I think probably earlier than most. It 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.

Dan McSpirit, BMO Capital Markets.

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 in our group developed. There are no vertical PUD locations on our books.

And of 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 don't have the breakout of the actual volumes associated with that (multiple speakers) over 200 horizontal wells that we have.

Okay. 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 the root of some of the issues behind today's reserve report.

I think just in a gross sense without being definitive on numbers, we see in this Midland Basin a very typical first years declines pretty dramatic in the 75-something kind of range. And then over a matter of three or four years, that well probably has more like a 15% decline going to 5 or 6 decline on a terminal. So that is 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 down a little bit is if you look a well that is five or six years old and it is going to have a higher gas content than one that is 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.

David Meats, Morningstar

Thanks for taking the question. I just wanted to dig in quickly to the 1100 locations you think can get 12% or more in the current pricing environment. How many of those locations are 10,000 foot lateral locations?

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

Like a ballpark or rule of thumb.

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

And I think they are all 7500 foot or greater.

Okay. Would it be fair to say then that the other locations you have not included in this 1100 like the locations you talked about maybe at the end of 2014 something like that, but most of those locations are not 10,000 foot locations then?

No. Our acreage block -- I don't know that I would say most and let's just -- we think, we still think that the resource play that we had thousands of locations to drill. What we were trying to say was that these 1100 at today's strip do have a positive return and those are the ones that we will be looking at in this price environment to drill first.

The way the acreage has been blocked up, as you know we went from 4000 foot laterals to 5000 to 7500 to 10,000 and we have 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 don't think I would say that other than the 1100 the rest of them are going to be less than 10,000. Some of them maybe the majority of them will be 10,000 by the time we are done.

Got it. That makes sense.

Phyllis Camara, Pax World Funds.

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 is water and crude oil handling and 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 will see that the Laredo, the percentage of crude that goes through Medallion is actually very small. In fact, it is 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 is where the real excitement comes for Medallion in terms of increasing the value both from preserving, increasing EBITDA and just the value is that we have now tied in -- if you look on page 17, we've 500 miles of pipe, almost 300,000 acres dedicated to it and other, maybe as much as 2 million under an 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 of the crude oil coming out of the Midland Basin on a third-party basis.

Okay, okay. Thank you. Then the next question I had though too was 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 re-determination in May?

We have always taken a very active approach with our banks within our credit facility. And we have also taken a fairly conservative approach. You will recall over the last two borrowing base redeterminations, we have had a borrowing base assigned by our bank group well above what we actually elected in our total commitment. When we are looking at making that elected commitment, we are looking out multiple redeterminations, not just looking at what is the value that we can 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 is 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 have 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 are going to drill at least 36 to 38 wells just in 2016. We are 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 recognize 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. 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 are running.

Thank you. I'm showing no further questions at this time. I would 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.