Ronald Hagood - Laredo Petroleum, Inc. Randy A. Foutch - Laredo Petroleum, Inc. Daniel C. Schooley - Laredo Petroleum, Inc. Richard C. Buterbaugh - Laredo Petroleum, Inc. Jason R. Greenwald - Laredo Petroleum, Inc. James R. Courtier - Laredo Petroleum, Inc..

David R. Tameron - Wells Fargo Securities LLC Brian Singer - Goldman Sachs & Co. Anthony Diaz - Raymond James & Associates, Inc. Joseph Allman - FBR Capital Markets & Co. Kashy Harrison - Piper Jaffray & Co. David Earl Beard - Coker & Palmer Investment Securities, Inc.

Blaise Matthew Angelico - IBERIA Capital Partners LLC Richard Merlin Tullis - Capital One Securities, Inc. John P. Herrlin - Société Générale.

Good day, ladies and gentlemen and welcome to the Laredo Petroleum, Inc. Fourth Quarter and Full Year 2016 Earnings Conference Call. My name is Amanda 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; Dan Schooley, Senior Vice President, Operations; as well as other 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 the GAAP net income to these non-GAAP financial measures are included in yesterday's news release. Yesterday afternoon, the company issued a news release and presentation detailing its financial and operating results for fourth quarter and full year 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'll 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 2016 earnings conference call. 2016 was an outstanding year for Laredo. We grew production 11%, funded our entire 2016 drilling and completion budget out of cash flow from operations.

We grew proved developed reserves at a cost of $5.12 per BOE, and well performance during the year led us to raise our Upper and Middle Wolfcamp type curves to 1.3 million BOE. LMS field infrastructure investment and production corridor strategy helped drive a 39% reduction in LOE. And the Medallion-Midland Basin system grew by about by 87%.

Our hedge settlements generated almost $200 million of cash and we currently have approximately $825 million of liquidity. In short, adherence to our long-term strategy produced significant value for our shareholders.

Our impressive operational performance during the year was a direct result of consistent strategy decisions to focus on building a contiguous acreage base and making investments in data and infrastructure.

The company's ability to drill long laterals and the operational efficiencies from our field infrastructure and production corridors drove down cost and increased returns.

These lower costs and the production outperformance generated an average anticipated field level return for our 2016 development drilling program exceeding 40% with wells drilled in the second half of the year generating anticipated field level returns exceeding 55%.

The company's long-term strategy to acquire, interpret and utilize data enabled the development of our proprietary multivariate Earth Model.

Continued refinement of the Earth Model and its utilization for locations and landing point selection, along with completions optimization drove enhanced well performance higher and historic type curve expectations, leading the company consistently exceeding production guidance throughout the year.

We believe that multivariate Earth Model and the completions optimization uplift is repeatable and sustainable. Consequently, we've raised Upper and Middle Wolfcamp type curve to 1.3 million barrels of oil equivalent. Dan will provide more details on this in his update.

Our 2017 capital budget will focus on continued utilization of the investments in technology and infrastructure that drove performance in 2016. We expect to plan the Earth Model optimized location and landing point selection, completion design on every well.

We also anticipate utilizing it to test the co-development of multiple landing points within the same targets, possibly increasing the company's inventory of how we turn wells in the Upper and Middle Wolfcamp. We plan to continue leveraging our production corridor strategy to drive the efficiency.

Laredo expects all but one well in 2017 will be developed within multi-well packages and almost all production and produce water from these wells to be carried on time by LMS-owned infrastructure.

We believe the company is extremely well-positioned for 2017 and beyond, the demonstrated quality of our asset base supports the drilling program that we believe can grow production more than 15% in 2017 while maintaining similar field level returns as those generated in 2016, and at the same time keeping in mind what is best for development of our entire resource potential.

I would now like to turn it over to Dan for an operational update..

Thank you, Randy, and good morning. Once again, the company reported record quarterly production with fourth quarter production of 53,141 BOE per day, an increase of 32% from fourth quarter 2015 and a 4% sequential improvement from the third quarter of 2016.

As we have demonstrated throughout 2016, we have seen substantial production outperformance through the applications of our multivariate Earth Model to select locations and landing points and to optimize completion designs.

Reflecting this outperformance, we have raised our type curves to the Upper and Middle Wolfcamp to 1.3 million BOE from 1.1 million BOE and 1 million BOE, respectively. Throughout the rest of my remarks, I will be referring to this new 1.3 million BOE type curve.

Fourth quarter production was positively impacted by the seven-well Sugg 171/185 package that was completed near the end of the third quarter of 2016. The seven-wells targeted the Upper and Middle Wolfcamp and were completed with 2,400 pounds of sand per foot.

Additionally, four of the wells had drilled lateral lengths greater than 13,000 feet and averaged 18 days of drilling from rig acceptance to rig release, the best of which was drilled in 16 days.

These wells help drive company drilling efficiency to an average of 977 feet per day, an increase of 16% from the fourth quarter of 2015 and drove our drilling cost per foot to an all-time company low of $108 per foot in the fourth quarter, a 23% decrease from the fourth quarter of 2015.

These wells are currently outperforming our new type-curves by 42% on oil and 23% on a three-stream basis adjusted for lateral length. Very importantly, as we continue to drill longer laterals, we are seeing performance on a production per foot basis remaining consistent.

Our continuous acreage supports the substantial drilling inventories 10,000 feet and greater locations. The economic advantage of longer laterals as depicted on page 10 of our presentation is clear and the company expects to continue targeting longer laterals.

In the first quarter of 2017, we expect to complete a horizontal well with a drilled lateral length greater than 14,000 feet. Laredo's 2016 development drilling achieved anticipated field level returns on invested capital exceeding 40%, with the second half of 2016 average returns exceeding 50%.

Laredo estimates that it has a decade of drilling on our current leasehold that will generate field level returns of greater than 50% at current rig cadence, commodity price forward curves, and service costs. We've utilized 2,400 pounds of sand per foot on nine completions.

In aggregate, the nine wells are outperforming our type curves by 43% on oil and 35% on a three-stream basis adjusted for lateral length.

We are very encouraged by the results of these larger completions and plan to conduct additional testing of various completion designs that utilize the higher sand concentrations as we continue to utilize all of our data to evolve and optimize these completions.

The type curves for the Upper and Middle Wolfcamp reflect a 10% increase in the oil and natural gas EURs based on the performance of wells utilizing the Earth Model. Additionally, we have seen a flattening of the natural gas curve in older wells and have raised the natural gas recoveries in the later years.

The production mix of the new curve is slightly oilier in the first five years of production. For example, our 64% oil cut in the first six months.

The year-end 2016 reserves prepared by Ryder Scott reflect these new curves, and the addition of natural gas reserves in later years of the curves has positively impacted the implied rates of return, although it has lowered the oil percentage of our total reserves.

In 2016, we grew our proved developed reserves by 41% from year-end 2015, or 41 million BOE. Proved developed oil reserves grew by 13 million BOE or approximately 31% from year-end 2015.

Well performance driven by the application of our Earth Model in infrastructure and efficiency-related cost controls enabled us to add proved developed reserves at a finding and development cost of $5.12 per BOE.

Throughout the development of our proprietary Earth Model, Laredo has utilized the workflow to select the optimal landing points in each formation. Within the Upper and Middle Wolfcamp and Cline, we have successfully tested two to three landing points in each target.

As the Earth Model has advanced to include completions optimization in the vertical and horizontal spacing information that is generated, the company believes that the multiple identified landing points can be developed coincidentally. The company expects to test this concept in 2017 drilling multiple Chevron wells in the Upper and Middle Wolfcamp.

Laredo's production corridor strategy and infrastructure assets continue to drive unit LOE lower. In the fourth quarter of 2016, unit LOE was $3.56 per BOE, a 39% decrease for the fourth quarter of 2015 and an 8% decrease sequentially from the third quarter of 2016.

We estimate the benefits from the company's infrastructure assets reduced unit LOE approximately $0.51 per BOE. These savings are primarily associated with crude oil and water transportation and artificial gas lift systems.

And as such, we believe these are permanent benefits that we will retain and would expect savings to increase should costs begin to rise. A key component of the operational financial benefits generated by LMS assets is the water infrastructure.

This consists of a network of more than 78 miles of pipeline linking water storage, disposal and recycling facilities that gathered 65% of total flow back and produced water in the fourth quarter of 2016 eliminating more than 25,000 potential truck loads of water.

Our total financial benefit from the water infrastructure in the fourth quarter of 2016 was approximately $2.6 million. The Medallion-Midland Basin pipeline system in which we own a 49% interest continued its impressive growth trajectory.

Fourth quarter 2016 volumes of approximately 129,000 barrels of oil per day were an increase of 87% from the fourth quarter 2015 volumes. The system generated income of $3.1 million and $6.4 million of adjusted EBITDA in the fourth quarter of 2016 net to our interest.

As we have mentioned in prior calls, we feel one of the aspects that makes the Medallion-Midland Basin system so valuable is its reach into many of the most productive areas of the Midland Basin. As activity by operators that have dedicated acreage to Medallion is expected to increase, the system's growth rate should benefit.

The Medallion-Midland Basin pipeline system exited 2016 at approximately 133,000 barrels of oil per day and is now expected to grow exit-to-exit at more than 75%, up from a previously expected growth rate of 50% to 60%. To summarize, 2016 proved to be a transformative year for Laredo.

We were able to grow production to a company record 53,141 BOE per day. We achieved a company record drilling efficiency with average drilling cost of $108 per foot during the fourth quarter of 2016, while simultaneously increasing our average lateral lengths to approximately 10,000 feet.

We successfully drilled and completed four wells with lateral lengths in excess of 13,000 feet and an average of 18 days from rig acceptance to rig release. We continued to advance our optimized completions with 2,400 pounds of sand per foot and tighter cluster spacing.

We reduced LOE to a company record and likely a peer-leading $3.56 per BOE in the fourth quarter of 2016. We continue to benefit from the exceptional volume and EBITDA growth of the Medallion-Midland Basin pipeline system. With that, I'll turn it over to Rick for a financial update..

Thank you, Dan, and good morning. I believe the comprehensive press release issued by tonight, coupled with the strategic and operational details provided by Randy and Dan this morning, demonstrate the meaningful progress that Laredo has made throughout 2016 to enhance the value for all of our stakeholders.

It is consistent with the company's all encompassing approach for building long-term sustainable value, regardless of the commodity price cycle. As reported in our earnings press release, although we reported a GAAP net loss, we exceeded analysts' expectations for adjusted net income and adjusted EBITDA for the fourth quarter and full year of 2016.

Adjusted EBITDA has grown steadily throughout 2016 while total debt has declined. At year-end, net debt to adjusted EBITDA on a trailing 12-month basis stood at 2.9 times and annualizing our fourth quarter adjusted EBITDA reduces this further to about 2.5 times.

As Dan highlighted, our solid operational performance and reduced capital intensity, coupled with our strong hedge position, we just detailed in our press release and corporate presentation, provides confidence to the company in our expectation of continued growth in adjusted EBITDA in 2017, thus further reducing this leverage metric.

As Ron discussed, our press release includes reconciliation of these and other non-GAAP measures. Keep in mind that our debt is essentially all long-term notes with no maturities for five years. However, 73% of these notes representing $950 million either are today or will become callable within the next three to four months.

As a reminder, the $450 million of 5.625% notes are now callable and the $500 million of 7.375% notes become callable on May 1 of this year. In addition, we have $800 million of undrawn capacity on our senior secured credit facility, which is supported by an $815 million borrowing base.

This borrowing base was set in the spring of 2016 and does not reflect the 41% increase in our proved developed reserves as of year-end 2016 nor does it include any pledge of our Medallion ownership interest. Each of these items provides the company with significant flexibility and optionality.

A portion of our debt is attributable to the long-term investments that we had made in our corridor infrastructure and our 49% ownership interest in the Medallion-Midland Basin system.

As shown throughout 2016, these investments are paying increasing dividends to the company in the form of improved efficiencies and reduced capital and operating costs in our operations.

And the significant value of the Medallion system is beginning to be recognized by other Midland Basin producers, who now represent approximately 80% of the throughput volumes that are shipped. Separately, Medallion's value has also been noticed by multiple private investment and midstream companies.

The explosive growth in throughput on the Medallion system, which is expected to grow an additional 75% by year-end 2017, creates additional EBITDA growth potential that we anticipate will be disproportionate to future investments in the system.

We believe that this provides added flexibility for Laredo to in essence, fund accelerated drilling activities when we deem appropriate.

In addition, we believe our 49% ownership interest in Medallion offers a significant potential resource for Laredo to either further de-lever the balance sheet or substantially accelerate drilling activities or a combination of both. Laredo's focus on development efficiencies and cost controls enable the company to do more with less.

With 85% of our acreage held by production, we have the ability to concentrate on truly value-enhancing activities.

In 2016, we completed more wells and outperformed production targets by reducing operating costs and taking advantage of existing infrastructure, resulting in an actual drilling and completion capital spend that was approximately 80% of our 2016 capital budget.

This enabled us to achieve another of our financial objectives which was to operate our field development essentially within cash flow from operations. Since late 2016, the commodity price trend has begun to improve, but pressure on service cost is also increasing.

We believe the operating efficiencies we have created are sustainable and can mitigate any cost increase to some extent. The only certainty is that volatility will continue. We have experienced many of these cycles over our management team's 40-plus-year history within this industry.

As a result, we would remain well hedged in 2017 and continue to build our long-term hedge position, protecting the downside while maintaining significant upside potential.

We believe Laredo is very well positioned with both operational and financial flexibility that enables the company to take a measured approach to ensure all investments are truly value-enhancing while maintaining the ability to capitalize on new opportunities. At this time, operator, we would like to open the call for any questions..

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

Good morning..

Good morning, Dave..

A couple of questions, just on the oil cuts.

The higher percentages you set for the type curves, I know you said flat or declining profile, but what's driving that? Why is that happening versus earlier?.

We've actually kind of been talking about the way we view this for quite awhile, David. We've been very, very careful in how we've talked about the oil content.

I think I'll get Dan and Jason to perhaps comment, but what we're seeing is we've become better at our fracs, I think we're exposing more – we know where the oil is, we know what the storage is in the formation, and I think we're exposing more of the rock to produce.

And as we do that, I think it has the potential to have these kind of changes on the oil cut and the gas cut but also I think there's a little bit of the fact that we have a tremendous amount of data production history, pressure history than a lot of people out there and we use that pretty intensely in how we do this.

Dan, Jason, you want to say anything?.

Hi. This is Jason. The only thing I would add to that is that as we continue to optimize our completions, we're seeing better and better productivity from the wells and this allows us to maintain our initial oil cuts for longer with those better productivities..

Okay.

So, is this just better placement of the proppant, more proppant, just all of the above – like one of those all the above better completions across the board type of better enhanced – is it landing, land or it's just all of the above?.

I think it's all of the above. I think it's hard to distinguish what one piece of our data, but we know the Earth Model is allowing us to pick better landing zones. We know that the Earth Model is allowing us to optimize the completions. We've spent – as you know, we attempt to optimize the completion on each and every well.

And so, we've been doing that for 275-plus horizontal wells, so we have a pretty substantive database on optimization. Now, we just need substantive number of wells and substantive production history to kind of tie that in on what the best optimization is..

Okay. Let me ask – I will let somebody ask Magellan. Let me ask one more question then I'll jump off.

If I think about 14,000 foot laterals, are there any operational challenges in that going from a 10,000 foot of 14,000 foot? And if so, what's going to be the nuance there as far as on the operational side?.

It's interesting to us that we bought our acreage literally coming on a long time ago. The thought being that we wanted to make sure that whatever lateral length was appropriate, we'd be able to drill it.

And to be fair, at the time we were thinking 10,000 feet, 12,000 feet that type of lateral length, and keep in mind, some of our early history was on 4,000 feet. Our acreage, as we said it in the release is blocked up and that from an operational acreage point of view we have a lot of long laterals we can drill.

And what we have seen so far is that it's really not a big issue to drill that additional 1,000 feet or 2,000 feet or 3,000 feet. In fact, I'm a little bit surprised, David, on how's that worked.

And we've also, as you would expect, spent a fair amount of time trying to make sure that the last 1,000 feet produced on a barrels per foot or ever how you wanted to measure it with the first 1,000 feet. And so we've been pretty pleased with the way that whole process has worked.

And the operational, as you know, we tended not to sign long-term contracts, but we did pick rigs that were already – we went to 5.5-inch drill pipe years ago. We did all those things that we needed to do on our selection of rigs to make sure that, operationally, we could actually get longer laterals done.

So it's a combination of the way we've gone about the buildup. It's combination of our acreage allows us to do it, and we've been pleased with the results..

All right. Well, congrats on what was a good 2016. I know you took a lot of heat from the Street over the last couple of years, at least from a Street perception. Congrats on delivering a solid year in 2016..

Thank you very much..

Thank you. And our next question comes from the line of Brian Singer from Goldman Sachs. And your line is open..

Thank you. Good morning..

Good morning, Brian..

Good morning..

With regards to the combination of the increased type curve, the success that you're having with the Earth Model and the multiple landing zones that you now see, can you give any comment on what your expectations are for where we are from a recovery rate perspectives and then what the upside is from further use of the Earth Model technology?.

That's a good question, and we spend a fair amount of time thinking about that going forward. What we do know, because we've tested it and we have production that there are multiple landing points in the Upper, in the Middle, and perhaps the Cline. We know they are productive, so we've used the Earth Model and the optimized completions to verify that.

We do have a view on recovery factors, but I think, as everybody knows, recovery factors are, in this type of a play, a little harder to pin down. There are some assumptions you make. We've had pretty intensive effort with modeling to work on that.

So I think what we're trying to figure out today and going forward, and it's not a 90-day or six-month answer, is what's the best NAV in terms of trying to get these multiple landing points and maximum optimization on NAV.

And so we're actually, as we said, drilling some Chevron wells today where we are going to stack and offset a couple of these different landing points within the same formation and see what we get to. The goal there obviously is to increase the recovery factor out of that entire section..

Got it. Thank you. And then with regards to the increased type curve and appreciate some of the disclosure on, I think, on slide four of your presentation.

But just to make sure we understand, the type curve goes up 10% across the board without any change in production mix and then the remainder to get to the 20% or 30% increase is with regard (29:43) is natural gas specifically.

Is that the way to look at it?.

This is Jason Greenwald, Vice President-Reservoir Engineering, and that's a correct characterization..

Great. Thanks.

And that's just a function of more gasses coming out than you thought or mainly because that's the recovery rate of whether you're recovering more of the gas in place or leaving more of the oil or if there's additional color there?.

I think it's more a function of the optimization of the actual frac and exposing more the rock such that it's able to be produced..

Thank you..

Thank you..

Thank you. And our next question comes from the line of Anthony Diaz from Raymond James. Your line is open..

Good morning, guys. Thanks for taking my question. I have two questions. First question is regarding the Sugg's package versus the Taylor package. I know the Middle Wolfcamp portion of the Sugg's package, I know that whole package was mostly developed on 13,000 foot laterals and 2,400 pounds per foot of sand.

On the Middle Wolfcamp portion it looks like it's outperforming the type curve by 24% and then when you look at the Taylor package at 1,800 pound per foot, it looks like its outperforming a little bit more again at the Middle Wolfcamp bench.

Is there any read-through on that? At least for the Middle Wolfcamp, have we found that point of diminishing return, or can you point me in the right direction there?.

I am a long way from thinking that we've reached the point of diminishing returns. I think we are still really trying to optimize the completion and optimize the spacing and the overall development of this pretty – it's a thick, thick interval and we're doing it.

And two points I'll make is that we – well, for one, you should expect some variability and the type curve is the average across a pretty broad data sampling a number of wells. So some variability on that would be natural.

But the other thing is, I think, we've always been a little bit of a – we weren't too crazy about the initial 24-hour IPs that some people were striving to get. We felt like that had a little bit of perhaps a long-term negative impact on production.

So what we've done is gotten a little more aggressive on managed drawn down on the first 90 days, 120 days. And so what that does, it also influences what those early production rates are compared to the type curve.

I think the good news is they're both above, and I think given our style and culture, six months, nine months, a year from now, that's when we'll start really getting confident in what the numbers mean..

Sure, sure. That's fair. That's fair. And then just for my follow-up question. I know AFEs have been improving on the Cline given using the Earth Model and improving wellbore landing.

I know that you have one well planned for 1Q 2017 in the Cline, but how do you see the development pace on that bench progressing in 2017, and how will it compete for capital during the year?.

That's also an interesting question. And we chose in 2016 to concentrate where we already had substantive – or made our investment in the corridors and the infrastructure. We're carrying a lot of that through in 2017.

We've known for some time that it's not only the Cline, which is in fact some of our better wells, but we also have a couple of other zones that we now produce.

And so I think our view is that we really want to try and figure out our capability in the Upper and Middle and then perhaps the Cline on drilling these Chevron wells and seeing if we can get the maximum NAV from the Upper and the Middle.

We do have very strong confidence that from all the work we've done on the regional analysis and the way we look at the risk assessment that the Cline is going to be important to us. It's pretty significant. So just because of the fact we're not drilling a lot of Cline, it no way diminishes the significance of the Cline.

Now the good news about that is, as we've said before, we spend a fair amount of time trying to make sure that I think our acreage is something north of 80% held by production. We still have some continuous drilling obligations. We've gone through a lot of trouble to try and hold as much of the deep rights as we can.

So we have these other zones somewhat protected and we can get to them. But the Cline is pretty important to us..

Okay. All right. Thanks, guys. I appreciate the time. I'll drop back in..

Thank you..

Thank you. And our next question comes from the line of Joe Allman from FBR. Your line is open..

Thank you, and good morning, everybody..

Good morning, Joe..

Hey, Joe..

I know, Rick, you commented on the Medallion and seemingly the potential for monetization, but could you guys give us some more clarification on what your thoughts are on the monetization of Medallion, potential monetization of the water business? Is there any formal process underway? And if you were to monetize one or both of those assets, would it be a 2017 event? Might it be a 2018 event? And would there be any reason to not monetize those assets? And, lastly, would there be any other assets that you could also monetize?.

Well, as we've laid out, not only this call, but really over the last couple years, we try to keep ourselves in a position that we have flexibility and optionality that we don't have to do anything, but we're certainly aware of the potential options that are available to us.

We got into the Medallion pipeline system because we wanted to make sure we had the ability to move our product out of the Midland Basin, have the flexibility to price it in different markets that would be the highest value for the product and for our shareholders. Today the purpose of getting into that system we've really satisfied.

We have that capability. We have firm capacity to get 30,000 barrels a day of crude oil out of the basin. So we do not need to really own that anymore. We've been an active part of the development of that Medallion system recognizing the potential that it gives for producers.

And as we've mentioned on the call, about 80% or so of the throughput in that system is now coming from third-party producers. The growth that we anticipate of additional throughput in that system over the next year, as Dan mentioned, is about 75% or more exit-to-exit from 2016 to 2017.

So we believe that the EBITDA is going to grow substantially there. It may be a bit early to divest it, but it's an option available to us.

It's never, as you saw in 2013 when we divested of our Granite Wash properties, it's not so much what is the specific value that you can receive for an asset or what are you going to do with the proceeds when you do receive it? We have great investment in Medallion.

We think that's going to continue to increase in value, but we're also seeing tremendous results in our drilling activities that at the right time we could redeploy additional capital to further accelerate those activities. And it also provides optionality for the company if we choose to de-lever.

We have as I mentioned $950 million of notes that become callable this year. Our debt, although it is higher than some of our peers, it is something that we are very comfortable with. But we do like the optionality that Medallion or the other infrastructure that we have provides for the company..

That's helpful.

And as a follow-up, is there any formal process underway? And could you also comment on the water business and might you throw that into the mix with Medallion or is there a potential to monetize that on its own? And, what would be, if you were to monetize Medallion, what would be the negative effects on your reporting if you were to do that? I mean, would LOE go higher? Would you have a higher midstream expense? Just talk about the – of course, ideally, you get a bunch of cash in, but what would be the negative effects going forward?.

If Medallion was divested of, the only thing that you would see would be the line item that we have on our income statement as well as on our balance sheet on the investment in the equity – the equity invested in our variable interest entity. It would not impact our LOE.

And no, there is not a formal process or any process regarding either the Medallion interest or any of our other infrastructure..

Okay. And if you could just address water. Any thoughts about monetizing that, and that's all I've got..

It's an option available to us. We've seen significant value in controlling that infrastructure in the past, and in Randy's prior companies. It's added value both from an operational standpoint and just an overall value standpoint for the entity..

Okay. Very helpful. Thank you, guys..

Thank you..

Thank you. And our next question comes from the line of Kashy Harrison, Simmons Piper Jaffray. And your line is open..

All right. Good morning. Congratulations on ending 2016 on a strong note..

Thank you..

There's some – something that was prevalent last year for the Laredo story was improving capital efficiency.

And so, to that point, when you look at the 2,400 pounds per foot completions, how much of a production uplift do you need to eventually see relative to the revised reference type curve to justify completely transitioning to those 2,400 pounds per foot completions over time?.

For us, it's just pure economics and capital. As you said, capital efficiency. And I don't think it's a – necessarily a production number. Obviously, we're seeing increased early production with a lot of the things we do. And so, you're just integrating the area under that curve with your type curve.

And if that yields you to a better economic outcome than you – than your type curve after the cost of the increased sand and everything else, then it's a pretty easy decision. I think, when we talk about capital efficiency, we talk about that in terms of – we've got some great advantages with the longer laterals.

We've got some great advantages with the corridors and our infrastructure, Medallion and our LMS. The early indications, and we've seen this a number of times throughout my career, on what people in the industry does sometimes don't actually pay out through the course of time.

In other words, the additional money is not a really good capital efficiency. So, I think, for us, there's a couple questions that we think a lot about.

How long do we have to produce those 2,400-pound sands before we know that that's been a capital-efficient investment? And I think we also need to think about, it wouldn't – the way we look at this is we're really trying to optimize the completions for each well depending on what we see on the Earth Model and what we actually see when we drill the well.

And we're using the Earth Model, as you know, to predict what we're going to see production wise before we drill, and then, we use it to calibrate what we see after we drill a well. So, it could be that we have some zones that make sense to use 2,400. Could be that we have some zones where it makes sense to use 1,800 or maybe more than 2,400.

I think, the point is we're a long way from optimizing, but we are seeing substantive, better early results..

Got it. And then, maybe switching gears to the midstream side of things.

Over the past few months, we've seen a few midstream transactions from the E&Ps, and so I was just wondering -- can you walk us through some of the higher level similarities and differences between Medallion and maybe a system like Alpha Crude, the Alpha Crude Connector in the Delaware and how would that translate into how this asset would be valued one way or another?.

I think, we'll probably defer talking about how it would be valued. We're not in a process. We do know what market is out there, and I'll let Dan answer some of the specifics. But the facts are the Medallion-Midland Basin system is by far the best thing going out there.

If you look at the early extent of the acreage that's dedicated and where Medallion actually has its footprint. It's just hard to visualize better placement of where Medallion actually physically has its footprint.

Dan, do you want to talk about comparisons or talk about...?.

Yeah. As Randy said that it's hard to imagine being able to put a pipeline in a better spot than we have the Medallion pipeline of six counties. And, added to that, the delivery optionality that it gives producers is unmatched.

So, we do feel like our system compared to the – some of the recent transactions, we have more optionality and delivery point flexibility for the producer. We do have, in the Medallion system, tremendous growth potential where we came out of 2016 at 133,000 barrels of oil per day.

With the existing backbone infrastructure and the delivery points we have, you could potentially deliver up to 500,000 barrels a day. So, the growth potential on Medallion is tremendous relative to other assets that we've seen in the marketplace lately. We have higher EBITDA, higher volume than what you've seen in recent transactions.

You go down a whole list of things. Mileage, we have more miles. We have more storage. So, it's – I think, the comparison to anything that's happened so far, Medallion would probably stand head and shoulders above those particular transactions..

That's excellent. Thank you. And then, maybe if I could just sneak one more in. In the prepared remarks, you mentioned that you believe the 49-percentage risk in the system could be used to delever, accelerate or some combination of both.

Could you just provide some color on what would drive the decision to take one action or another or both? Are you just looking at incremental well returns relative to the interest that you're paying on these notes?.

This is Randy. I think, Medallion has optionality. And, again, we're not predicting value. We're not getting into that.

But we've always been kind of careful to say that, historically, at Laredo and other companies, the midstream had been very, very important for us for operational point of view in that we wanted to make sure we could put our products into pipe without having to truck on the natural gas liquid side.

And we wanted to make sure that we had exposure to a number of places to take it such as if one plant went down, we weren't captive. We also clearly wanted to make sure that we could take our crude out of the Midland Basin in case the differential blew out. And, as you know, it's not much now, but two years ago, there was a pretty big differential.

So, the investment was originally made for operational things which has paid off very, very nicely.

We think there is the optionalities that you mentioned plus there is the optionality of just the long-term position, holding our position in Medallion and Medallion continues to grow then, we – at some point, we'll have the EBITDA of Medallion to reinvest into our drilling program.

The key to that is the other operators in the basin that are – that have their production going through Medallion are all talking about increasing activity, drilling more wells, and that ultimately leads to greater EBITDA growth on Medallion. So, the way we look at it is we've satisfied our operational goals, checked that box.

Now, it's a question of is it an attractive asset? Probably, very attractive asset. Are you going to sell it knowing that you have tremendous EBITDA growth going in front of you? As Rick said. Yeah. If you have some place you're really interested in putting that capital to work.

Or can you hold on to it and sell it at a more opportune down the road? Or just hold on it longer-term. I think, we have all those options available. Rick, do you want to add? Hopefully that helped..

Yeah. That helped. Thank you very much. And again, congrats on a strong 2016..

Thank you..

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

Hi. Good morning, gentlemen. I'd also like to echo the strong operational improvements especially versus a year ago. So, kudos to the team..

Thank you, Dave..

Thank you..

My question really relates to the long laterals, 13,000 foot, 14,000 foot, how many do you think you have or identified? And what percent might be long laterals in terms of next year's drilling locations? Drilling budget? Thanks..

It's interesting to me and I'll see if one of the guys have a little better number. But we show in there in our presentation how many we currently have greater than 10,000 feet, and it's a huge number. We've got like 2,000 plus locations today that are north of 10,000 feet.

We have – well, there are some places where it would take just a minor amount of land work to where we could add to that pretty substantively. Within our current acreage, we have a lot of laterals longer than 10,000 feet.

We've shown and kind of normalized everything we've talked about to 10,000 feet because that kind of seems to be a good number for most, but this acreage block allows us to drill a lot of long laterals and extended reach laterals. That's pretty important to us..

Great. Thanks.

And any sense, what percent would above 10,000 feet in 2018?.

No, we're not – we haven't talked any about 2018, but – so when you look at couple of thousand locations greater than 10,000 feet and you look at our rig cadence, it's going to – we've got a lot of drilling to do that's 10,000 foot or longer even. It's just a really good position to have.

The long laterals make it so much more efficient in terms of what we do. And we'll take advantage. Just the message is we have a lot of 10,000-foot wells to drill and longer, and we're going to advantage of it every chance we can because of the economics..

Now understood. Thank you. I appreciate the time..

Thank you..

Thank you. And our next question comes from the line of Blaise Angelico from IBERIA Capital Partners. Your line is open..

Hey. Good morning, everyone. Thanks for taking my questions.

I just wondered if you could provide a little bit more detail on the inventory numbers that you guys disclosed in your release, specifically looking at the breakdown by horizon in that 3,500 location count?.

I think, we have – it's interesting to me to see how we think about that in that we have a lot of other zones that only need a little bit of higher pricing or a little more optimization or something like that to make them become part of that inventory that we haven't counted yet.

So, I think, there's much, much more upside on that inventory than is contained just in that number. And it's principally going to be currently Upper, Middle and Cline. We know that we have a number of other zones to lower and some other things to look at.

So, I think, short term, being the next two years to three years, it's probably an Upper, Middle and Cline inventory.

But I don't want to lose sight of the fact that we have a lot of other formations within our acreage that we know produce, we know a lot about them in some cases, in some cases we need to do some more drilling to test them and verify them.

But with a little bit of improvement in economics, we'll add substantively to that location count, and the improvement in economics could be pricing, could be the margin or it could be the way we use our Earth Model and optimize the completions. Lots of upsides still on this acreage base..

Got you. Thanks. And just one quick follow-up on service cost side.

What are your current rig rates, and then are you seeing more pressure on that side as we go forward? If you are, can you quantify that?.

We've said for some time that across my career, service cost have always gone up. It's a question of when they go and how fast they go.

And what I've said in terms of this cycle, plus I said the same thing in other cycles, is that the service industry really kind of gets hammered on the front end, and they desperately try and get prices coming out of it. And they're going to get some, but I think rigs, we've got the rigs we want.

We'd like the technical makeup of the drilling rigs we've got. We tend not to sign long-term contracts. For us, a year is a pretty long-term contract. Don't see problems getting rigs. And the numbers are, we think, we're paying a fair price. Other service cost, there's been some movement in prices. Part of that is just based upon logistics.

I think service costs are a little bit of a function of what commodity prices do. If we see a continuing increase in commodity prices and margins, there'll be more service cost. If we see it be relatively flat, then I think the ability of service providers to get increasing prices is kind of muted.

But we really think we have some pretty good partnerships with the service companies. We try and work with them a lot. We have them involved and seeing what we're doing, we have them involved in thinking about how we should do this, all with the purpose of getting best performance.

So, we're a little more focused, if you look at our presentations and how the same rigs that we were using have what, 2.5 times or 3 times increased the amount of horizontal footage that we're drilling in a year, that's basically the same rigs.

And so, it's not just a function of day rate, it's trying to maximize the best performance by working with those service providers..

Got you. All right. Thank you very much. Appreciate it..

Thank you..

Thank you. And our next question is from the line of Richard Tullis from Capital One Securities. Your line is open..

Thank you. Good morning. Congratulations..

Good morning. Thank you..

Good quarter cap and a good year for you guys. Just two quick questions, Randy. So Laredo's been very effective lowering OpEx this year, I guess down probably better than 30% year-over-year and followed by a good quarter 4Q.

What's driving the LOE range in the first quarter guidance? I guess it's a little bit higher at the midpoint than what you achieved, say, in the second half of 2016..

Even with that being a little bit higher, I think you still got to notice how low it is.

And our ability to drive that cost lower is a function of, one, the people we have working that and the way they go about their business, but the infrastructure investments that we've made over time, the drilling within the corridor have all been very helpful on that LOE, and that's kind of been a characteristic.

That was an early characteristic of Laredo and my other companies is that we pay attention to that. So, I think if you're in the range that we're in, there's going to be some variability even on the high end of that range, I think, Richard, that's a really good number to be at..

That's fair..

I'm not predicting beyond what we've given in our guidance, but when we look at the benefit of our infrastructure and look at the benefit of the corridors, there are still some things that we need to look at on the LOE side in terms of making sure that we keep and maximize the benefit of those prior investments..

That's a good point.

And just lastly, how are things progressing building that northernmost production corridor in Glasscock County and are you planning to drill any wells in that area in 2017?.

Yeah. Richard, this is Dan Schooley. We're progressing along just fine. We're going to start the first test well April..

Second quarter..

Second quarter. We anticipate starting drilling in the second quarter, so we'll have our infrastructure ready to go by then, and it'll be a corridor that will deliver the similar kind of benefits that we've seen in our Reagan South corridor with crude oil and water handling providing most of the benefits..

All right. Well, thank you. I appreciate it..

Thank you..

Thank you. And our next question is from the line of John Herrlin from Société Générale. Your line is open..

Yeah. Thanks. Time for something esoteric, guys..

Hello, John..

Regarding the rocks, you guys have done a lot of G&G work. It seems to me with your Earth Model that you're essentially recognizing, shall we say, petrophysical faces (1:01:39) if you will. Have you given any thought to the depositional factor versus diagenetic factors in terms of what drives things? I know you're starting to do more SEM work.

I'm just curious..

We have and I'm going to have, I'm going to ask James to respond to your question. He's going to find a microphone here..

This is James Courtier, Vice President Exploration and Geosciences Technology. So, John, we look at everything. So, that includes depositional phases, diagenesis, anything that affects the rocks.

So, as Randy said many times, we have an extensive database that enables us to really characterize the rocks extremely well by landing point across all of our properties. And so, we integrate that into every piece of the development planning work we do..

Okay.

Do you think a lot of your peers are doing the same or they're playing catch up?.

It's difficult for me to say, making comments on what our peers are doing, but all I could tell you is that we take an extensive amount of data.

We continually try to improve our understanding by getting new data to answer questions that are important to us like we discussed multiple landing points within the same formation and continue to integrate that into our development planning process..

Okay. Great. Thank you. Next one for me is on lateral length.

What do you think the physical limit will be on the horizontals, 15,000 feet or do you think you could go further?.

That's an interesting question. And John, as you know, we were drilling 4,000-foot laterals questioning whether we could get 7,500 foot. And then, we figured out how to drill the 7,500-foot laterals very, very, very capital efficiency, and we also saw that that additional footage had tremendous impact on economics.

Then we moved to the 10,000 foot, and the same kind of attitude. We were careful to make sure that we got it done engineering-wise, didn't have any real problems. Obviously, any time you're drilling long-reach laterals, you're going to have a problem on a well here and there.

We moved to the 12,500s foot and huge benefit in economics our acreage gives us. And like we mentioned, we've now reached out to perhaps past 14,000-foot.

So, I think the way we're viewing that is we see that we can do it, we see that it has tremendous economic benefits, so then it becomes a question of how much risk dollars you're willing to put into one wellbore in case something bad did happen to that.

And where it gets a little more tricky, John, I think the way we look at it is we really do like drilling packages of wells for a variety of reasons. Drilling four, five, six, seven wells, we have the capacity on our water system to frac that number of wells if we frac them back-to-back.

We have the capacity with our corridors to handle the production, everything else. But when you start looking at drilling four, five or six greater than 14,000-foot wells, you can see the economics are pretty favorable as long as everything goes right.

So, I think for us we're not yet discernible – in my mind, we haven't yet discerned what the real risk reward of drilling very many of those long laterals. We may get....

Thanks Randy. Last one for me.

Given all the high-priced acreage acquisitions, are you suffering from sticker shock in the neighborhood?.

I think our view is that we're glad we've got the acreage, we got at the cost we got, we're glad that the acreage prices are verifying that we're in the right place with the right acreage, and it is interesting to see what the market is..

Thanks, Randy..

Thank you, John..

Thank you. And, at this time, this does conclude the Q&A session. I'd now like to turn the call back over to Mr. Ron Hagood for closing remarks..

We appreciate you sticking with us. This call has run a bit longer than scheduled. If you have any questions that weren't addressed, please give us a call. Thanks for your interest in the company and hope to see you at upcoming conferences. Thank you, and good morning..

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