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 - Analyst, SunTrust Robinson Humphrey, Inc..

John A. Freeman - Raymond James & Associates, Inc. David Earl Beard - Coker & Palmer, Inc. John P. Herrlin - SG Americas Securities LLC Daniel Eugene McSpirit - BMO Capital Markets (United States) Chris S. Stevens - KeyBanc Capital Markets, Inc..

Good day, ladies and gentlemen, and welcome to the Laredo Petroleum, Inc.'s First Quarter 2016 Earnings Conference Call. My name is Ronya, 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, 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 & 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, forecast and assumptions are intended to be covered by the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995.

The company's actual results may differ from these forward-looking statements for a variety of reasons, many of which are beyond our control. In addition, we'll be making reference to adjusted net income and adjusted EBITDA, which are non-GAAP financial measures.

Reconciliations of GAAP net income to these non-GAAP financial measures are included in today's news release. Yesterday afternoon, the company issued a news release and presentation detailing its financial and operating results for first quarter 2016.

If you do not have a copy of this news release or presentation, you may access it on the company's website at www.laredopetro.com. I will now turn the call over to Randy Foutch, Chairman and Chief Executive Officer..

Thanks, Ron. And good morning, everyone. Thank you for joining Laredo's first quarter 2016 earnings conference call. The first quarter was an outstanding quarter for the company as strategic, value-creating investments in data and infrastructure continue to be positive catalysts.

Total production of 4.2 million barrels of oil equivalent exceeded our guidance midpoint by 9%, and exceeded the high end of guidance by 5%. Daily production of 46,202 barrels of oil equivalent per day was 14% higher than the fourth quarter of 2015.

More importantly, oil production of 23,046 barrels of oil per day was 23% higher than the fourth quarter 2015.

Cost came in well below guidance, with what we believe is among the lowest LOEs, $4.88 per barrel of oil equivalent, being 22% lower than the midpoint of guidance, as field infrastructure investments continue to positively benefit operating expenses.

General and administrative expenses of $4.63 per barrel of oil equivalent were 23% lower than the midpoint of guidance, and total cash cost of $10.26 per barrel of oil equivalent were down 16% from the fourth quarter of 2015 and down 27% from the first quarter of 2015.

Quarterly production results were driven by using our proprietary Earth Model in combination with optimized completions.

As detailed in our earnings release, the nine wells completed this quarter all employed the Earth Model/optimized completion combination and had 30-day average initial production rates that as a group were approximately 29% better than our 1 million-plus barrel of oil equivalent type curves.

Both production and cost benefited from our robust field infrastructure. Production downtime was minimized, as our centralized compression stations and upgraded electrical infrastructure reduced loss production from individual gas lift compression failures and power outages.

Lease operating expenses were down 16% from the fourth quarter of 2015 and were also helped by centralized compression in our water takeaway and recycling infrastructure. The radar remains intensely focused on capital efficiency. Our contiguous acreage base enables us to drill primarily (04:18) 10,000 foot or longer laterals.

And up to date, we have drilled 33 wells with laterals of approximately 10,000 feet. Within 80% of our acreage supports laterals of 10,000 feet or longer in multiple zones, and we have successfully drilled wells longer than 12,500 feet.

Additionally, more than 80% of our acreage is also held by production, and we have managed our drilling obligations to minimize the need to drill vertical wells. In fact, at our current drilling cadence, we have no near-term plans to drill any vertical wells.

We are constantly working to improve our drilling efficiency and continue to see the number of days to drill a well decrease, even as average lateral length increases. For 10,000 foot laterals in the upper and middle Wolfcamp zones with the standard completion, we are budgeting well cost at $5.9 million.

Completion optimization, including more sand, generally, can add between $250,000 and $1 million to the cost of a 10,000-foot lateral depending on stage and cluster spacing.

We were very encouraged by the results we were seeing and data we are gathering from the Earth Model/completion optimization combination and expect to implement it in all wells completed in the second quarter. Each completion is uniquely tailored to the individual well and optimize for true economic benefits.

To date, we have 18 wells that have used the Earth Model in combination with optimized completions and they are, on average, performing at more than 130% of type curve. We continue to employ various methods to optimize the completion of our horizontal wells.

These include utilizing up to 1,800 pounds of sand per foot during the number and spacing the frac stages and clusters, and employing various additives to reduce the amount of water used.

In addition, we're very excited about the recent opportunity to lead the design, execution and operation of a program that furthers our understanding of the potential on our acreage.

Beginning in the third quarter 2015, Laredo provided the operational expertise for the $18 million research project sponsored by public – private consortium led by the Gas Technology Institute. This testing program was hosted at the side of the 11-well project already scheduled to be drilled along our Reagan North production corridor.

Through this project and at no direct cost to us, we have been able to collect a comprehensive proprietary dataset that would provide valuable insights into the understanding of fracture propagation.

Of particular note, during the data acquisition phase, Laredo successfully recovered almost 600 feet of core, directly offsetting two completed wells in order to better understand the interaction between hydraulic and naturally occurring fractures.

While the majority of the testing has been completed, certain aspects of the program will be monitor to the next 24 months. The proprietary data obtained in this unique program are key value drivers and are being incorporated within our Earth Model, completion optimization practices and lateral spacing design.

As I mentioned, we are very encouraged by our operating results this quarter as the catalysts we've been highlighting continue to add value.

The company's long-term investments in data and our proprietary Earth Model are continuing to have a meaningful positive impact on our well productivity improving upon what were already some of the highest EURs in the Midland Basin.

Prior to the first quarter of 2016, Laredo had drilled 49 wells with an EUR of approximately 1 million barrels of oil equivalent or higher, eight of which were approximately 1.5 million barrels of oil equivalent or higher.

In the first quarter, we have added nine additional wells, of which eight of them had EURs of at least 1.5 million barrels of oil equivalent based on production to-date, which is still improving as the wells gain more production history. In total, the company now has 57 wells with EURs of approximately 1 million barrels of oil equivalent or greater.

I would now like to turn the call over to Dan for a Midstream and Marketing update..

Thank you, Randy. The company continues to recognize significant benefits from its decision to invest in field infrastructure, such as oil and gas gathering, centralized compression and water handling and recycling facilities, taking full advantage of its contiguous acreage position.

In the first quarter of 2016, we recognized cash benefits that increased revenue and capital savings and reduced LOE, generating cash benefits totaling more than $6.2 million. For full year 2016, we forecast these benefits will total more than $21 million.

As we continue to focus drilling around highly efficient production corridors, we anticipate these benefits will grow accordingly. The growth of the Medallion-Midland Basin pipeline system, in which LMS owns a 49% interest, maintained its impressive pace, as transported volumes grew approximately 20% in the first quarter of 2016.

It is anticipated that transported volumes will exceed an average of 105,000 barrels of oil per day in the second quarter of 2016, an anticipated increase of approximately 27%. Drilling permits activity in the Permian Basin stands to further benefit the Medallion-Midland Basin pipeline system's long-term growth.

58% of all Permian Basin permits issued in the first quarter of 2016 were in the system's six-county operating area. Of those permits, almost 40% were issued to operators with acreage dedicated to the system.

While fluctuations in drilling activity can have a short-term effect on the pipeline system's transported volumes, the concentration of permitting activity in its operational area reinforce that Medallion-Midland Basin is the premier pipeline in a world-class basin. I will now turn it over to Rick for a financial overview..

Thank you, Dan, and good morning. As reported last night in our first quarter 2016 earnings release, the company posted impressive operating and financial results, even in a somewhat challenging commodity price environment.

For the first quarter of 2016, we reported adjusted net income of $17.3 million or $0.08 per diluted share, a 33% sequential increase from the comparable fourth quarter 2015 amount.

Cash flow from operations before working capital changes totaled approximately $66 million, funding approximately 75% of the $90 million in capital expenditures accrued during the first quarter. Adjusted EBITDA for the period totaled approximately $96 million.

With the proven performance of our field operations that Randy discussed, we have increased our total year 2016 production guidance by approximately 3%. In addition, we believe that much of the reduction in total cash costs to $10.26 per BOE for the quarter, which are down 21% from the average of $13.03 per BOE in the 2015 year, is sustainable.

However, we do anticipate that both unit LOE and G&A will increase some from first quarter rates, as reflected in our second quarter guidance.

Yet for the full year, the combined impact of increased production, lower cash costs and improved NGL pricing leads us to expect that full year cash flow from operations will now fund approximately 90% of our budget capital expenditures.

Laredo continues to have a very strong hedge position that not only covers a substantial portion of our oil and natural gas production, but does so at extremely beneficial floor values.

For the first quarter of 2016, these derivatives provided an 88% uplift to our average realized price on a BOE basis, resulting in an average hedge price of $32.64 per BOE. As we have discussed in the past, our derivative program uses a combination of puts, swaps and collars, none of which are three-way or knock-out collars.

Therefore, the substantial value of these derivatives can be relied upon. Additionally, as in the past, we have maintained an ongoing active hedging program that extends for several years.

We continually evaluate hedging opportunities through the framework of maintaining a capital program that holds our core acreage position together, sustains drilling efficiencies, covers our debt service and retains talented personnel. In that light, we have successfully executed a hedge restructuring in March 2016.

In doing so, we lowered the floor price from $80 per barrel to $60 per barrel on 6,200 barrels of oil per day in 2017 and purchased a $60 put option on 2,875 barrels of oil per day in 2017 and purchased a comparable $60 put option on 2,875 barrels of oil per day in 2018, all at no cost to the company.

And we eliminated a $4 million deferred premium in 2017.

Earlier this week, our 18-member bank group completed the regular semiannual redetermination of the company's senior secured credit facility, reflecting substantially lower commodity prices, lenders signed a borrowing base of $815 million based upon our proved reserves at December 31, 2015, but not including our – as collateral, our 49% ownership interest in the Medallion-Midland Basin pipeline system.

As of May 4th, the company had drawn $210 million on this revolving credit facility. Since mid-2015, Laredo has essentially funded its upstream operations through internally generated cash flow and an asset sale in the third quarter of 2015.

The $85 million we have drawn on the facility since mid-2015 reflects investments in the Medallion-Midland Basin pipeline system during that time period. At this time operator, would you please open the calls for any questions..

Thank you. And our first question comes from the line of John Freeman from Raymond James. Your line is now open..

Good morning, guys..

Good morning, John..

First question I had, on Medallion, looking at kind of the year-end volume expectations of 140,000 barrels of oil per day to 150,000 barrels of oil per day, which is pretty close to kind of where you're expecting year-end Medallion volumes to be when you all sort of last updated us back in February.

And I'm just curious based on how much better the oil price environment is when you last kind of touch base with everybody in February, and given how much of those volumes are third party, just, I guess, I'm kind of interested in how much color you have on maybe recent conversations or whatever you're doing to channel check on the third-party volumes and the potential for maybe volumes to be better than what you're guiding to?.

John, this is Randy. The way the Medallion system works is, we're not the operator. We're a 49% non-operator owner. We're very pleased with the way Medallion management has built the pipeline. We're very pleased with the way they've done contracts.

The facts are that there are – the core group of operators, and some have talked about when they would increase their drilling activity, some have talked about kind of being consistent. But until those third-party E&P operators actually increase their drilling activity, we think these volumes are our best guess.

If they do increase, then obviously, that acreage, in many cases, is either dedicated or under an AMI with Medallion. So, in those core six counties or so in the Midland Basin, if activity goes up, Medallion benefits beyond what we forecast..

Okay. And then, my follow-up question, I believe, at the moment all of the rigs you have running are on well-to-well contracts, which obviously gives you significant flexibility.

And I'm just curious kind of how you all internally think about balancing that flexibility with potentially looking at moving somebody's rigs to maybe term contracts, given the kind of the firming in the oil outlook?.

We actually went back a couple of months ago and put one rig on a six-month contract. And from a company point of view, we've always been very hesitant to sign long-term service contracts in good times or bad times.

There is – we're pretty particular about the rigs we want in terms of the capacity and capabilities of the rig, but I doubt if you see Laredo anytime put in longer-term contracts than the six-month. The other rigs are on month-to-month. I think as just kind of as a core part of our businesses, we want flexibility..

Thanks. I appreciate it. Nice quarter..

Thank you..

And our next question comes from the line of Neal Dingmann from SunTrust. Your line is now open..

Hi, guys. Neal Dingmann. Hey. Just a question I had on your enhanced completion. I'm trying to get an idea of – the costs are coming down.

Two questions around these enhanced completions, around how much sand per foot are we talking? Is – are you thinking about continuing to add more, or you think you had an optimal level there? That's my first question..

The interesting thing about the way the costs have moved is, obviously part of it is service cost reductions, but we're getting our costs down, even as we're drilling longer laterals. We're just getting more efficient, and we keep those efficiencies irrespective of what service costs might do.

And I think as you know, we were testing a number of different completion optimization processes literally three years and four years ago with different sand – resin sand and so and so forth. And we've used different sand amounts. We've used different water amounts. We've used some different additives. We've changed stages. We've changed clusters.

And I think the answer is that, obviously, more sand has had results. More sand costs more.

I think the answer is that with the Earth Model, with our database that we've been collecting for years, and now with the possible influence of the data from the GTI study, we're going to be optimizing those completions probably forever, but I think the message is that, if you look at the results, what we're doing is working..

No. I would agree, certainly, Randy. And then just to follow up, you guys continue looking at the hedges all the way out to 2018, continue to be pretty active on that.

Your thoughts as far as if oil stays at the kind of $45-plus, would you add more hedges around there? And would that give you confidence to potentially boost activity around knowing that you've got more hedges around that?.

We've always viewed – as you know, we've always been a hedger. And we view it as a way to make sure we can always pay debt and always have some capital program and always pay salary. Generally, we've been – I think, most quarters, you'll see us having added some hedging. I think the hedging does give us a lot of comfort.

We're probably as well hedged as anybody we know. But I think the answer on increasing activity is partially a function of how far out you can hedge and do you see enough stability on prices to go ahead and increase activity, and I think I've mentioned before that in my experience we've seen people get too aggressive on ramping up activity too soon.

And many times in the past, they've regretted spending that capital before price has had some stability on a direction..

Makes sense. Thanks so much, Randy..

And our next question comes from the line of David Beard from Coker & Palmer. Your line is now open..

Hi. Good morning, gentlemen..

Good morning..

A little question looking out to next year in 2017. And I'm just trying to get your sense on total capital spending, including the Medallion. I had a theory that eventually this – the spending is going to tail-off and you're going to get some leverage there.

I know it's far out, but just wanted to get your thoughts relative to spending next year?.

We – I'll let Rick back up my answer, but I think we've said consistently that we want to be drilling more or less within cash flow. The good thing about Medallion is, as you said, that we think we've captured most of the bases.

And any expenditures, we see going forward, we kind of have a view it will probably be on the additive side in terms of capturing more trucking facilities and extensions rather than major outbuild. The good about our drilling inventory in terms of increasing activity is the infrastructure is there to a very meaningful way.

We can add activity without having to add electrical or certainly do a lot with water, or do a lot of gas lift compression inside the infrastructure. So, we have that flexibility, but I think the message is that we probably – you should be – U.S. is drilling more or less within cash flow.

Rick, do you want to add?.

The only thing I'd add to that, I mean, that is kind of the overriding concern for the companies that we do want to self-fund, the majority of our capital program and look at our capabilities to fund any outspend, certainly very comfortably within the new borrowing base that we have.

Looking forward to 2017, if we maintain the 2.5 rig program, we would actually expect the capital expenditures to come down on a comparable basis. Keep in mind that in the first quarter of this year, we had additional capital that really related to some of the carryover capital from some of the activities late in 2015.

We are – have always been basically current on our completions relative to our drilling. So, we don't carry a big PUD inventory. But just based upon the number of wells that are drilled on a pad, there is well some carryover activity at the end of 2015. That raised our capital spend in the early part of 2016.

So, we would actually expect on a comparable basis of activity level that our capital in 2017 would go down slightly.

As far as the Medallion capital, as we have talked about before, we do not actually budget that, because we don't propose those capitals, we elect whether or not we're going to participate in any future capital expenditures that Medallion would have.

However, we do believe that, the bulk of the system is built out, would anticipate small amounts of capital to be able to further enhance that system either through additional pumps or being able to connect some of the major lines to additional acreage that would better utilize the capacity of that system. But nothing from a material standpoint..

All right. Good. I appreciate the extensive answer. Thanks for the time..

Thank you, Dave..

And our next question comes from the line of John Herrlin from Societe Generale. Your line is now open..

Yeah. Hi, Randy. I was wondering how the gas research thing came about, just curious..

John, that's an interesting – we had been – we had, had conversations with GTI about some of their desires to collect this data in another part of the Permian. And that deal was not able to get adequately funded, and some other issues. So, we went back to them pretty aggressively and said, we've got blocked-up acreage.

And we've got a pretty extensive dataset already. We've had joint ventures with a number of service companies over the years. We're getting ready to drill an 11-well package that has very close spacing, in some cases, 400-plus feet apart, 660 Chevron (27:25) and in a couple of different zones.

And in many ways it was a perfect test-bed for the data that we collected. We were involved in the design of what data we wanted to collect. We executed that, and we're still – we'll be collecting data for a couple of years. And that's going to be proprietary to the consortium for a couple of years to come.

So, we thought it was a great way of a company our size getting access to that type of data. We're pretty excited about it..

Will this be a time series base thing?.

I think we've collected a lot of the data already. And some of the things we're doing, do have a relationship to what we see over time, mostly in terms of some pretty detailed pressure analysis. It'll be interesting to see how that works. The core we cut was kind of a diagonal well that went across two already fracked wells.

We'll be monitoring pressure for some time to come. And, again, John, the good news about this is, we – it was at no direct cost to us. We did have to do the operations, which we were effectively doing anyway. We did dedicate some internal people to the project, so it took us some time, but this was done at no cost to us..

Right, but the one thing that you said in your release, it's in the core of your area, so clearly beneficial?.

It was right in the core of the area. It was right in a corridor, so we think it adds to the database that we already have with our Earth Model. We think it's – we're very, very excited about the possible outcome of this..

Good.

My other question is, are you finding that the services companies are more willing to talk to you about longer term just for activity, and given the fact that they know you'll remain active? Are you sensing a different level of communication perhaps less antipathetic than in the past?.

It's interesting to us, John. That's a very good question. We think we've had long term and very good relationships with a number of service companies that go back, literally, decades. And one of the things that's interesting is how often the conversation goes along the lines of – we understand that we're in this together.

They, obviously, want to make money for their company, but they also want to make sure that they're competitive enough that companies like Laredo that are going to be around for a while with a long-term drilling inventory and a desire to do things right, they want to make sure that we're their partner and their client as we go forward.

So, the conversations continue. In some cases, depending on what we're doing, they get fairly intense on pricing. But we're pleased with the way we work with the service companies, and not only their operations people, but their research people..

Okay. Thanks, Randy..

Thank you, John..

And our next question comes from the line of Dan McSpirit from BMO Capital. Your line is now open..

Hello, Dan..

Hey. Good morning.

How are you?.

Good. We're good..

On the Midstream, just quickly here, what do you see to be the EBITDA margin these days on the current throughput, maybe expressed in dollars per barrel and net to the company's interest? Is $0.60 a barrel still good?.

Hey, Dan. This is Dan Schooley. We had in first quarter about $0.51 a barrel EBITDA net to us, but we're – that will continue to go down a little bit throughout the year. So we think the year will probably average about between $0.45 a barrel and $0.48 a barrel..

Okay. Great. Much appreciated. And then just as a follow-up here.

Regarding the 18 wells that are outperforming your type curve, how much of that outperformance would you attribute to the Earth Model versus simply pumping more sand down hole versus any other change in the completion technique?.

Well, I'm not sure that we fully have answered that question internally. Obviously, the Earth Model is – got huge step-up in economics, because we're not putting more expense involved. Sand costs more, so there is a little bit of an economic judgment when you're using more sand.

But I think the message is the Earth Model allows us to pick literally better laterals and better zones to put more sand in. So, that's a question that we think it's a combination of both. We very much like the incremental economics of the Earth Model. You would think more sand would add more reserves, so it's an economic question.

But keep in mind, we're seeing a lot of benefits from the way we've gone about collecting data in the Earth Model besides just more sand..

Very good. Thank you, and have a great day..

Thank you, sir..

And our next question comes from the line of Chris Stevens from KeyBanc. Your line is now open..

Hey. Good morning, guys. It looks like you guys are currently drilling a well under northern Glasscock acreage, pretty close to the Howard County border up there.

Can you just talk about maybe what zones you're testing, if there's any infrastructure, or is this just more of a delineation well at this point, and what's the impetus for drilling up there?.

That – we have seen a lot of drilling going in and around of lot of our acreage that we don't have a lot of activity in. So, it's kind of an exploratory delineation well. We've drilled up there a number of vertical wells. So I think we kind of know a little bit about what's going on there.

But I think we still have on our acreage set a lot of exploratory kind of activity that, at some point, we've got to drill. We're very happy drilling within our corridors. We think that's great economics, a lot of reduction in cost. But that well is probably more of an exploratory well. It is a 50% working interest well for us. We're the operator.

That's in itself pretty dramatically different, because most of our activity goes to 100% working interest wells or close to 100%. So, I think we've said in the past that most of our drilling is going to be inside corridors. Most of it's going to be where we have infrastructure in development drilling. But we still have a number of zones to drill.

I think we mentioned in the earnings release that some of the best wells we've drilled recently were Cline and Middle Wolfcamp. So, we've got lots of opportunities to look at other zones..

Got it. Okay. And I guess, there's probably not much infrastructure up there at this point.

If you see success with this well, is this acreage your mark for sale, or do you go ahead and build out some infrastructure? And then just separately, any additional plans to test the Lower Spraberry again on your acreage at some point?.

Yeah, we – I mean, we do know that the Lower Spraberry produces, because we've drilled it so many times vertically. I think, it's – I think the outcome of that northern acreage is still to be determined. The infrastructure, we've got the access to Medallion and so on and so forth.

We could add in additional infrastructure if we thought we were going to do that, but I think the real answer is we've got a lot of optionality either way. We could – if we thought it was best for shareholders, we could sell that acreage. If we thought, it was best for shareholders we could keep it in development.

We're not in any hurry, in terms of what we need to do there from a held-by-production point of view. So, we'll test other zones in years to come and make decisions on what we should do with that acreage depending on the data we see..

Okay. Got it. Thank you..

Thank you..

And I'm not showing any further questions. I would now like to turn the call back to Mr. Ron Hagood for any further remarks..

Thank you, Ronya. As a reminder, we'll be hosting a field tour investor meeting on June 13th and 14th in Midland, Texas for our institutional investors and sell-side analysts. We'll be providing a tour of Laredo's key infrastructure projects within our Permian-Garden City operations.

Event details and registration information can be found on the company's website at www.laredopetro.com. Thank you very much for joining our first quarter call..

Ladies and gentlemen, thank you for participating in today's conference. This concludes today's program. You may all disconnect. Everyone have a wonderful day..