Vital Energy Inc (VTLE) 2016 Q4 法說會逐字稿

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.

(Operator Instructions)

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 will be making forward-looking statements. These statements including those describing our beliefs, goals, expectations, forecasts and assumptions are intended to be covered by the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. The Company's actual results may differ from these forward-looking statements for a variety of reasons, many of which are beyond our control.

In addition, we will be making reference to adjusted net income and adjusted EBITDA which are non-GAAP financial measures. Reconciliations of GAAP net income to these non-GAAP financial measures are included in yesterday's news release.

Yesterday afternoon the Company issued a news release and presentation detailing its financial and operating results for the 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 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 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 volumes 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 produce 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 out-performance 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 than historic type curve expectations, leading the Company consistently exceeding production guidance throughout at the year.

We believe the multivariate Earth Model and the completions optimization uplift is repeatable and sustainable. Consequently, we raised the Upper and Middle Wolfcamp type curve 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 apply the Earth Model to optimize 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 high return wells in the Upper and Middle Wolfcamp.

We plan to continue leveraging our production corridor strategy to drive efficiency. Laredo expects all but one well in 2017 will be developed within multi-well packages, and almost all production and produced water from these wells to be gathered on pipe by LMS-owned infrastructure.

We believe the Company is extremely well-positioned for 2017 beyond. The demonstrated quality of our asset base supports a drilling program that we believe can grow production at 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 increase from the third-quarter 2016. As we have demonstrated throughout 2016, we have seen substantial production out-performance through the applications of our multivariate Earth Model to select locations and landing points and to optimize completion designs.

Reflecting this out-performance we have raised our type curves for 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, for 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 helped 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 contiguous acreage supports a substantial drilling inventory of 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 have 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 curves in older wells and have raised the natural gas recoveries in 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 the 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 and 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 coincidently.

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 and 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 flowback and produced water in the fourth quarter of 2016, eliminating more than 25,000 potential truckloads 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 costs 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 at 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 will turn it over to Rick for a financial update.

Thank you, Dan, and good morning. I believe the comprehensive press release issued last night 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 analyst expectations for adjusted net income and adjusted EBITDA for the fourth-quarter and full-year 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, which is detailed in our press release and corporate presentation, provides confidence to the Company in our expectation of continued growth and adjusted EBITDA in 2017, thus further reducing this leverage metric. As Ron discussed, our press release includes a 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 5/8% notes are now callable and the $500 million of 7 3/8% 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 have 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 delever 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 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.

(Operator Instructions) David Tameron, Wells Fargo.

Good morning. A couple of questions. Just on the oil cuts, the higher percentage you said for the type curves, I know you said flatter decline profile but what's driving that? Why is that happening versus earlier?

We've actually been talking about the way we view this for quite a while, David. We have been very, very careful in how we've talked about the oil content. I think I will get Dan and Jason to perhaps comment, but what we're seeing as we've become better at our fracs I think we are exposing more, we know where the oil is.

We know what the storage is in the formation. And I think we are 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 a 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 do 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 are 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 it just better placement of the proppant, more proppant, just all the above, like one of those all of the above better completions across the board type of better enhanced -- is it landing the lateral, is it just all 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 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 tie that in on what the best optimization is.

Okay, let me ask -- well, I will let somebody ask Magellan, let me ask one more question and then I will jump off. If I think about 14,000 foot laterals what operational are there any operational challenges in that going from a 10,000 to a 14,000? 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 with the thought being that we wanted to make sure that whatever lateral length was appropriate we would be able to drill it. And to be fair, at the time we were thinking 10,000, 12,000, that type lateral length and keep in mind some of our early history was on 4,000.

Our acreage as we said in the release is blocked up enough 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 or 2,000 or 3,000 feet. In fact, I'm a little bit surprised, David, on how that's 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 however you wanted to measure it, with the first 1,000 feet. So we have been pretty pleased with the way that whole process has worked and the operational -- we chose, as you know, we tended not to sign long-term contracts, but we did pick rigs that were already, I mean 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 a combination of our acreage allows us to do it and we've been pleased with the results.

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

Thank you very much.

Brian Singer, Goldman Sachs.

Thank you. Good morning.

With regards to the combination of the increased type curve, the success that you are 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 perspective 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, 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 are 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. So we are 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.

Then with regards to the increased type curve, and appreciate some of the disclosure on I think slide 4 of your presentation, 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 is natural gas specifically. Is that the way to look at it?

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

Great, thanks. And that's just a function of more gas is coming out than you thought or maybe it goes back to the recovery rate of whether you are recovering more of the gas in place but leaving more of the oil or if there is any additional color there?

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

Thank you.

Anthony Diaz, Raymond James.

Good morning, guys. Thanks for taking my question. I have two questions.

First question is regarding the Sugg package versus the Taylor package I know the Middle Wolfcamp portion of the Sugg 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 is outperforming the type curve by 24%, and then when you look at the Taylor package at 1,800 pounds per foot it looks like it was outperforming a little bit more again at the Middle Wolfcamp bench.

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

I'm a long way from thinking that we have reached the point of diminishing returns. I think we are still really trying to optimize the completion and optimize the spacing in the overall development of this -- you know, it's a thick, thick interval. And two points I will make is that, 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 have always been a little bit of -- 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 have done is gotten a little more aggressive on managed a drawdown on the first 90, 120 days. 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 are both above, and I think given our style and culture six months, nine months, a year from now, that's when we will start really getting confident in what the numbers mean.

Sure, that's fair. Then just for my follow-up question, I know AFE has been improving on the Cline given using the Earth Model and improving wellbore landing. I know 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 made our investment in the core doors and the infrastructure. We are 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 know produce. So I think our view is that we really want to try and figure out our capability in the Upper and Middle and 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 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 I don't want to just because of the fact that we are not drilling a lot of Cline in no way diminishes the significance of the Cline.

Now the good news about that is, as we've said before, we've spent 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 to 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.

All right, thanks guys. I appreciate the time. I will drop back in.

Joe Allman, FBR.

Thank you, good morning everybody. I know, Rick, you commented on the Medallion and seemingly the potential for a monetization, but could you guys give us some more clarification on what your thoughts on a monetization of Medallion, a 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 of years, and we try to keep ourselves in a position that we have flexibility and optionality that we don't have to do anything. But we are 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, had 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 have been an active part of the development of that Medallion system, recognizing the potential that it gives for producers. And as we 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 a 75% of 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 our Granite Wash property, it's not so much what is the specific value that you can receive for an asset but what are you going to do with the proceeds when you do receive it.

We have a great investment in Medallion. We think that's going to continue to increase in value. But we are 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 delever. 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, just 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? Would LOE go higher? Would you have a higher midstream expense? Just talk about, of course, ideally you get a bunch of cash in, but what would be the negative effects going forward?

If Medallion was divested 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. 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.

Very helpful. Thank you, guys.

Kashy Harrison, Simmons Piper Jaffray.

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

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?

You know, for us it's just pure economics and capital, as you said, capital efficiency. I don't think it's a necessarily a production number. Obviously, we are seeing increased early production with a lot of the things we do, and so you are just integrating the area under that curve with your type curve and if that yields you to a better economic outcome 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 doesn'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 of 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 really try and 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 are using the Earth Model as you know to predict what we are going to see production wise before we drilled 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. It 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 are 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 will probably defer talking about how it would be valued. We are not in a process. We do know what the market is out there, and I will let Dan answer some specifics.

But the facts are the Medallion-Midland Basin system is by far the best thing going out there if you look at the aerial extent of the acreage that's dedicated and where Medallion actually has its footprint. It's just hard to visualize a better placement of where Medallion actually physically has its footprint. Dan, do you want to talk about any comparisons?

Yes, as Randy said, it's hard to imagine being able to put a pipeline in a better spot than we have in the Medallion pipeline in those six counties. And added to that, the delivery optionality that it gives producers is unmatched. So we do feel like our system compared to 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. 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 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% interest 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 are paying on these notes?

This is Randy. I think Medallion has optionality. And, again, we are not predicting value.

We are not getting into that. But we have always been careful to say that historically at Laredo and other companies the midstream have been very, very important to 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 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's the optionalities that you mentioned plus there is the optionality of just a long-term position, holding our position in Medallion, and if medallion continues to grow then we at some point will have the EBITDA of Medallion to reinvest into our drilling program. The key to that is the other operators in the basin 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 yes, if you have someplace you are really interested in putting that capital to work.

Or can you hold onto it and sell it at a more opportune down the road or just told on it longer term? I think we have all those options available.

Rick, do you want to add? Hopefully that helped.

Yes, that helped. Thank you very much. And, again, congrats on a strong 2016.

David Beard, Coker and Palmer.

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

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

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

We have -- 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.

We've shown and normalized everything we've talked about to 10,000 because that's 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 of what percent would be above 10,000 in 2018?

No, we haven't talked any about 2018, but when you look at a couple of thousand locations greater than 10,000 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 if 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 will take advantage. Just the message is we have a lot of 10,000 foot wells to drill and longer and we are going to take advantage of it every chance we can because of the economics.

Understood. Thank you. I appreciate the time.

Blaise Angelico, IBERIA Capital Partners.

Hey, good morning everyone. Thanks for taking my questions. I just wonder if you could provide a little bit more detail on the inventory numbers that you guys disclosed in the release, specifically looking at the breakdown by horizon in that 3,500 location count?

I think we have -- it is 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.

It's principally going to be currently Upper, Middle and Cline. We know that we have a number of other zones, the Lower and some other things to look at.

So I think short term being the next two or 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 will 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 upside still on this acreage basin.

Got you. Thanks.

Just one quick follow-up on service cost side. On your current rig rates are seeing more pressure on that side as we go forward? If you are can you quantify that?

You know, we've said for some time that across my career service costs have always gone up. And it's a question of when they go and how fast they go. But I've said in terms of this cycle plus I said the same thing in other cycles is that the service industry really gets hammered on the front end and they desperately try and get prices coming out of it.

And they are going to get some but I think rigs, we've got the rigs we want, we 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.

We don't see problems getting rigs, and the numbers are we think we are 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 will be more service cost. If we see it be relatively flat, then I think the ability of service providers to get increasing prices is 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 in doing, seeing what we are doing.

We have them involved in thinking about how we should do this, all with the purpose of getting best performance. So we are 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 they are drilling in the year, that's basically the same rigs. And so it's not just a function of dayrate, it's trying to maximize the best performance by working with those service providers.

Got you. All right, thank you very much. I appreciate it.

Richard Tullis, Capital One Securities.

Thank you, good morning. Congratulations. Good quarter capping a good year for you guys.

Just two quick questions, Randy. So Laredo has been very effective lowering OpEx this year. I guess down probably better than 30% year over year 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 it's still, you've 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 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 are in that the range that we are in there's going to be some variability. We are even on the high end of that range, I think, Richard, that's a really good number to be in.

That's fair.

I am 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 benefits of those prior investments.

That's a good point. And just, lastly, how are things progressing in building that northernmost production corridor in Glasscock County? And are you planning to drill any wells in that area in 2017?

Yes, Richard, this is Dan Schooley. We are progressing along just fine. We are going to start the first test well April second quarter, we anticipate starting drilling in the second quarter.

So we'll have our infrastructure ready to go by then. And it will 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.

John Herrlin, Societe Generale.

Yes, thanks. Time for something esoteric, guys.

Regarding the rocks, you guys have done a lot of G&G work. It seems to me with your Earth Model that you are essentially recognizing, shall we say, petrophysical phases, if you will.

Have you given any thought to the depositional factor versus diagenetic factors in terms of what drives things? And are you starting to do more SEM work? I'm just curious.

We have. And I'm going to have I am 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 rock (technical difficulty). 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. 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 are playing catch-up?

It's difficult for me to say making comments on what our peers are doing. But all I can tell you is that we take an extensive amount of data, we are continuing to 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 to 7,500 foot laterals very, very capital efficiency.

And we also saw that that additional footage had tremendous impact on economics. Then we moved it 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, anytime you are drilling long-reach laterals you are going to have a problem on a well here and there. We moved to the 12,500s and huge benefit in economics our acreage gives us. And like we mentioned, we have now reached out to perhaps past 14,000.

So I think the way we are 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 are 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, frac them back-to-back. We have the capacity with our corridors to handle the production and everything else.

But when you start looking at drilling four or 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 are 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 there.

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 are glad we've got the acreage we've got at the cost we got. We are glad that the acreage prices are verifying that we are in the right place with the right acreage. And it is interesting to see what the market is.

Thanks, Randy.

At this time this does conclude the Q&A session. I would now like to turn the call back over to Mr. Ron Hagood for closing remarks.

We appreciate your sticking with us as the 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.