Ron Hagood - Director, IR Randy Foutch - Chairman & CEO Rick Buterbaugh - EVP & CFO Jay Still - President & COO Dan Schooley - SVP, Midstream & Marketing.

Brian Gamble - Simmons & Co Dan McSpirit - BMO Capital Markets Neal Dingmann - SunTrust Robinson Humphrey Ipsit Mohanty - GMP Securities Matt Portillo - Tudor, Pickering, Holt Brian Singer - Goldman Sachs John Herrlin - Society Generale.

Welcome to Laredo Petroleum, Inc.'s Third Quarter 2015 Earnings Conference Call. My name is Janicia and I will be your operator for today. [Operator Instructions]. 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; Jay Still, President and Chief Operating Officer; Dan Schooley, Senior Vice President, Midstream and Marketing, as well as additional numbers 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, [Technical Difficulty] expectations, forecasts and assumptions are intended to be covered by the Safe Harbor provisions under the Private Securities Litigation Reform Act of 1995.

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

Reconciliations of GAAP net income to these non-GAAP financial measures are included in today's news release. Beginning January 1, 2015, Laredo began reporting production and proved reserves on a three-stream basis. In the news release issued this morning, financial and operating results and well results have been reported on a three-stream basis.

In the 10-Q issued this morning, third quarter 2015 results are reported on a three-stream basis, but third quarter 2014 results are on a two-stream basis. A conversion of production and unit cost data for 2014 from two-stream to three-stream is provided in the appendix of the Company's corporate presentation.

In the news release and in comments on this call, when volume-based comparisons between 2014 and 2015 are made, 2014 results have been converted to a comparable three-stream figure. Earlier this morning, the Company issued a news release detailing its financial and operating results for the third quarter of 2015.

If you do not have a copy of this news release, 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 third quarter 2015 earnings conference call. In the third quarter, the Company produced 44,820 barrels of oil equivalent per day, coming in above the high end of our guidance range driven by better than modeled performance of existing wells.

We continue to focus on enhancing well economics using the advantages afforded us by our contiguous acreage position and prior infrastructure and data investments.

Laredo is currently realizing savings due to drilling along production corridors with the 11-well project on the Reagan North Corridor demonstrating a further improvement in number of days to drill versus already reduced budgeted drilling times.

In the foreseeable future, as a result of careful planning in prior years that emphasized drilling to hold acreage, we expect to be able to drill the majority of our horizontal wells with 10,000 foot laterals along production corridors targeting the Upper and Middle Wolfcamp zones and utilizing the Earth Model.

The Medallion pipeline system in the Midland Basin, in which we own a 49% interest, continues to grow and is currently being expanded. Upon expected completion of the expansion in the first quarter of 2016, the system will be able to deliver more than 500,000 barrels of oil per day.

The system delivered approximately 70,000 barrels of oil per day in September and is expected to continue its impressive growth. I'm pleased with the Company's financial position. The recent redetermination of our senior secured credit facility resulted in a borrowing base of $1.15 billion and supports our $1 billion elected commitment.

Our strong hedge position and operating approximately within cash flow during the third quarter enabled the Company to exit the third quarter with more than $940 million in liquidity.

Additionally, we added additional hedges for 2016 and now have hedged approximately 85% of anticipated oil production in 2016 at a weighted average floor price of more than $70 per barrel with no short put positions. We also have no fixed debt maturities until 2022.

Laredo is benefiting today from long-term strategic decisions made almost 10 years ago at the Company's inception.

Core principles such as investment in data, infrastructures that reduce costs and build value and hedging production to protect cash flows are adding significant value to our shareholders today and we believe will continue to do so in the future. I would now like to turn the call over to Rick for the financial overview..

Thank you, Randy and good morning. As stated in our news release this morning, the Company reported third quarter 2015 adjusted net income of $15.4 million or $0.07 per diluted share which excludes the $906 million pretax non-cash impairment charge on a full-cost pool caused by lower commodity prices.

Production volumes increased 16% from the comparable volumes in the prior-year quarter and totaled slightly more than 4.1 million barrels of oil equivalent, exceeding the high end of our guidance range.

Although third quarter 2015 volumes decreased approximately 3% from the second quarter of this year, exploration and development investments were reduced by approximately 37% from the prior quarter. Along with reduced capital expenditures, we have continued to reduce both operational and administrative costs.

Total unit cash costs for the third quarter of 2015 were $12.15 per BOE, a reduction of 28% from the prior-year rate of $16.76 per BOE on a comparable three-stream basis. And cash costs declined more than 10% sequentially from the second quarter of this year also on a unit basis.

Unit lease operating costs for the 2015 third quarter decreased approximately 12% sequentially from the second quarter to $6.09 per BOE as we continue to realize the benefits from prior investments in our corridor infrastructure and our continuous improvement processes for our field operations.

Unit cash G&A expenses decreased approximately 34% from the third quarter of 2014 and approximately 3% sequentially from the second quarter of this year. DD&A expense which is substantially driven by the depletion component, is influenced by production volumes, the reserves at the beginning of the period and the net book value of our full-cost pool.

Therefore, DD&A expense in the third quarter reflects the impairment charge taken in the second quarter and our fourth quarter DD&A expense will reflect the third quarter impairment charge that we have taken.

In addition, as commodity prices have remained low and the 12-month average prices decline, reserves, primarily our undeveloped reserves, will be negatively impacted and therefore will somewhat diminish the impact of the reduced net book value of our full-cost pool on future unit depletion expense.

During the third quarter, the Company operated approximately within cash flow, exiting the quarter with more than $940 million in liquidity, up slightly from the second quarter level.

Cash flow from operations and proceeds from the nonstrategic property sale funded E&P capital expenditures of $74 million, a $45 million reduction in accrued capital expenditures, cash interest payments of approximately $24 million and $49 million for investments in the Medallion pipeline system.

A vital component of protecting our cash flows is our ongoing core strategy of hedging to reduce the variability of our anticipated cash flows due to commodity price fluctuations. In the third quarter, we received more than $66 million of cash settlements on maturing derivatives.

Our oil hedges provided an uplift of almost $34 per barrel to our realized price which equates to an increase of approximately 80%. In combination with our as hedges, this results in more than a 60% uplift to our realized price on a BOE basis.

Subsequent to the end of the third quarter, we placed additional oil put contracts for 3540 barrels of oil per day for calendar 2016 with a strike price of $45 per barrel. The Company now has approximately 85% of its anticipated 2016 oil volumes hedged at a weighted average floor price of almost $71 per barrel.

These derivatives consist of puts, swaps and collars, none of which are part of three-way or knockout collars or put spreads, so they truly provide protection in a volatile commodity price environment.

On October 30, in connection with the regular semi-annual redetermination of our senior secured credit facility, Laredo's borrowing base was set at $1.15 billion. The new borrowing base reflects the third quarter divestitures of non-operated non-strategic acreage and its associated production of approximately 670 BOE per day.

It also reflects approximately a $75 million increase in the allowable investments in the Medallion pipeline system in the Midland Basin.

As a reminder, an increase in the allowable investment in the Medallion system normally could decrease the borrowing base as our 49% ownership interest in Medallion's Midland system is not a pledged asset on our senior secured credit facility.

As in the spring redetermination, the Company, at our option, chose an aggregate elected commitment of $1 billion on this credit facility. Maintaining our liquidity for at least three years of operations in the current commodity price environment is paramount in our approach to our 2016 budget.

We're currently operating three horizontal rigs and view that this is an appropriate operational cadence as we enter 2016. This will enable us to take advantage of key turn drivers and drill a majority of our wells on multi-well pads along existing corridors which will target the Upper and Middle Wolfcamp zones with 10,000 foot laterals.

The capital expenditures to fund this program, along with associated infrastructure, land and other items, but not including potential additional investments in the Medallion system, should result in an approximate outspend of $75 million to $100 million. At this time, I'd like to turn the call over to Jay Still for an operational update..

Thank you, Rick. As Randy mentioned, third quarter production came in above the high end of our guidance range. During the quarter, we completed and brought on production 8 horizontal wells all targeting the Upper and Middle Wolfcamp zones.

We've seen an improved performance in our base production due to a focus on our use of centralized gas lift compression for artificial lift, fewer well failures and an optimized development program that reduces frac-impacted wells.

In the fourth quarter, activity will pick up significantly as we expect to complete 16 horizontal wells, although only 5 are expected to be completed early enough in the quarter to have a significant impact on production for the quarter.

All the horizontal wells expected to be completed in the fourth quarter will be 10,000-foot laterals and will target either the Upper or Middle Wolfcamp zones.

We have posted guidance for the fourth quarter which is adjusted for the divestiture that closed in the third quarter and some recent production impacts that heavy rains in the Garden City area caused over the past few weeks. Despite these issues, we're still maintaining our full-year guidance.

11 of the wells to be completed in the fourth quarter are part of the Reagan North corridor development. This project is a prime example of how we're working to increase value for stockholders by leveraging our corridor infrastructure and technology advances in a low commodity price environment.

We're taking advantage of our contiguous acreage base and previous infrastructure investments to focus on drilling 10,000-foot laterals on multi-well pads, all of which will be landed and geosteered using our Earth Model. The Earth Model results to date give us increasing confidence that we can deliver above-average well results.

Completing these 11 wells simultaneously allows us to more fully develop a larger area of our Upper and Middle Wolfcamp reservoir package maximizing drilling and completion efficiencies for multi-well pads and minimizing downtime due to offsetting frac impacts.

This completion program will require approximately 5 million barrels of water over 35 days. This water will be supplied from our water recycle facility and integrated water management system and flow backwater will be recycled or directly piped to saltwater disposal facilities for an approximate $4 million in capital savings.

An operation of this magnitude could not be accomplished without the build-for-purpose infrastructure.

We have thousands of high working interest drilling locations across our current Garden City acreage position, of which approximately 75% of our acreage supports 7500 foot or longer locations and about 33% of the acreage will support 10,000 foot locations.

More importantly, approximately 500 of these locations are along existing production corridors or a potential expansion of those corridors and are 7500 foot or longer locations targeting the Upper and Middle Wolfcamp zones, much like the 11-well project we just discussed.

We've been successful in netting up our interest in adding bolt-on acreage through purchases and trades that will allow us to increase the opportunity to drill longer laterals. In 2016, a majority of our development will be focused on 10,000 foot laterals targeting the Upper and Middle Wolfcamp zones on multi-well pads along production corridors.

We anticipate this development plan will deliver robust economics even in this low commodity price environment. The incorporation of our drilling operations into a horizontal development program has allowed us to efficiently maintain our leases across our acreage position.

The Company is continuing to see the benefits of investments to reduce operating expenses. Total operating expense in the third quarter declined 14% as compared to the second quarter.

A substantial portion of the savings were generated by getting more water and oil volumes on our corridor infrastructure for direct sales, recycle or disposal, consolidation of well site compression into larger and more efficient centralized compressors and optimization of field electrical systems.

Now I'll turn the call over to Dan Schooley to discuss Laredo Midstream Services..

Thank you, Jay. The Medallion pipeline system in the Midland Basin with less than 10 months of full operation has experienced rapid growth in 2015, both in miles of pipeline and volumes transported. The original connection into Colorado City, Texas has delivery capacity of 140,000 barrels of oil per day.

New connections associated with the most recent expansions announced in Martin, Howard, Midland, Upton and Reagan County, in which LMS is investing approximately $55 million, will provide delivery options off the Medallion system to downstream takeaway pipelines and refineries in Midland, Crane and Big Spring, Texas, enhancing Medallion's deliverability by approximately 375,000 barrels of oil per day.

In the third quarter, deliveries by the Medallion system averaged approximately 55,000 barrels of oil per day, including an average of approximately 70,000 barrels of oil per day in September.

Delays in the anticipated completion date of the expansions have temporarily restricted nominations for fourth quarter volumes to an average volume of approximately 75,000 barrels of oil per day.

It is anticipated that, upon completion of the expansions, nominations will return to expectations and the system will be delivering more than 150,000 barrels of oil per day by the end of 2016.

Revenue and operating margins are expected to continue to improve as throughput in the fourth quarter is anticipated to exceed 6.7 million barrels, up approximately 31% from the 5.1 million barrels reported for the third quarter.

The Medallion pipeline system continues to provide producers in the Midland Basin with optimal transportation options and exposure to the largest trading hubs in the Permian Basin. With that, operator, I'd like to turn the call over to you for any questions..

[Operator Instructions]. Our first question comes from the line of Brian Gamble from Simmons & Co. Your line is open..

A couple of CapEx questions, if I may. Rick, in your prepared remarks, you mentioned a $75 million to $100 million outspend for next year through a rig program, infrastructure included.

Can you maybe walk us through what a rig is now costing you on an annual basis or just flat out tell us what the CapEx expenditure within that outspend range is supposed to be? It seems like efficiencies would take a dollar for spending or dollar per rig spending up year-over-year.

What sort of ranges should we be thinking about?.

From an overall capital standpoint for 2016, we expect to announce our budget probably sometime mid-December of this year. As I mentioned, we're running on a 3-rig cadence currently and maintaining that 3 horizontal rig program. A horizontal rig is going to run in the neighborhood of $100 million per rig year.

Now that has actually gone up because of the efficiencies that we've been able to achieve and the fact that we're focusing our 2016 program, as well as the remainder of 2015's program, on long laterals along our corridors and we're looking at 10,000 foot laterals in most instances. We actually gain efficiencies and reduce the rig time.

Jay mentioned a little bit in his comments that the 11-well program that we're currently operating on our Reagan North corridor, we're actually seeing reduced drilling times.

Reduced drilling times from the multi-well pads on the corridors provide efficiencies which end up resulting in more wells per rig year out of each of those rigs and therefore, you have more pipe and more completions. So maintaining a 3-rig program would probably be in the neighborhood of $300 million plus just for the drill and complete costs.

In addition to that, we would have some additional midstream costs. We will have our normal land seismic investments that we make along with that. So somewhere in the neighborhood of $375 million to $400 million capital, I think, is an appropriate range. But as I mentioned, we will announce our budget sometime mid- December..

And Rick, that range would not include any additional Medallion spending.

Is that correct?.

That's correct. Now what we have done to date, we announced in our second quarter call that Medallion was expanding their system up to the north.

At that time, they had not proposed that to Laredo, so we had not included that in our update that we did in the second quarter, although we did allude to the fact that we have maintained our 49% investment in Medallion. We think that is a valuable asset that will continue to grow.

We're seeing additional operators recognize the value of that system and dedicate their acreage to that. They did propose that to Laredo. Our Board has approved that $55 million expenditure for our interest in that expansion. All that $55 million has been included in our third quarter capital number; although it is not completely funded.

There's probably about $20 million of actual cash calls remaining today on the cash funding of it. But from a cost incurred standpoint, it is already in our third quarter results..

And then I guess along those same lines, if you do assume the 3-rig program for next year, I'm assuming there will be some additional bigger projects, so production may be somewhat lumpy for drilling on the corridors doors and drilling lots of wells at the same time.

But from a total production standpoint in 2016, is a 3-rig program enough to hold year-over-year production flat?.

We have discussed previously that the 3 horizontal rig program will keep production relatively flat. We still anticipate that if that is the cadence that we run in 2016 that we would expect to actually exit 2016 above our exit rate in 2015..

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

A few questions on Medallion itself.

What is the timing of filling the 500,000 barrels a day of delivery capacity?.

Obviously, a long time, the delivery capacity of that pipeline gets you into Crane, Midland and up into Colorado City. The current throughput is about 77,000 barrels a day or so.

So it's going to be a long time before we get all of that capacity filled, but if you look at the statistics in the counties that we're in, about 40% of the rigs that are running in the Permian Basin are in the six counties where we have pipeline.

So we don't anticipate it to be an extraordinary long period of time, but we have got a lot of running room left in front of us..

And as a follow-up to that, is there maybe a rule of thumb or a quick and easy math that can be applied to get to an EBITDA margin on that throughput net to the Company's interest, LPI's interest? I ask in an effort to better value that asset..

Yes, the numbers that we utilize internally to estimate what we think the EBITDA is going to be is around -- our share being around $0.60 per barrel..

Our next question comes from the line of Neal Dingmann from SunTrust. Your line is open..

You guys have done a good job about -- you mentioned about the longer laterals. I know you have done some of these multi -- continue to do multi-well pads. [Technical Difficulty] as your slides allude to various pay formations in there. I'm just wondering about your thoughts on doing the stack laterals..

We've talked about the stack laterals and we've done a lot of four stacks and three stacks and what we've kind of decided to look at going forward is stacking the Upper and Middle and I'll let Jay amplify on that some. That allows us efficiencies on the drilling within the corridor.

It allows us efficiencies on the fracking and it still allows us, at our discretion, to come back at any point and look at the lower and then the Cline and the Canyon and other things..

Randy, that's exactly right. The 11-well project we have now is a stacked lateral in the Upper and Middle Six Uppers and five Middles being completed simultaneously. The Upper and Middle we look at as kind of a reservoir package that is -- we can optimize the recovery of that resource by combining those into a program.

There's quite a bit of difference, separation in between [Technical Difficulty], so it really makes a nice package to double those up to extract that resource..

And just my follow-up on that, is that -- you accomplished this through, just so I understand, through utilizing the Earth Model or is it just part of that is that geosteering or is it just because you have such great separation between that?.

The rocks matter. As you know, these shale plays are very heterogeneous and they differ a lot from just very short distances and finding the best rock with the highest hydrocarbon pore volume and the right rock mechanics, brittleness, etc. is important and that changes from where you land the well over the 10,000 foot that you're going to drill it.

So we've seen a lot of improvement in wells utilizing our Earth Model to stay in zone, to follow where the good rocks are and identify where the optimal landing points are across our acreage which it changes fairly dramatically as you run across the acreage position..

Our next question comes from the line of Ipsit Mohanty from GMP Securities. Your line is open..

When I just compare your prior guidance last release to this, it seems that the oil mix has come down a little lower, slightly lower.

If you can provide some color behind that, please?.

The wells that we bring on, the new production we bring on, the oil cut is in the mid-80s. As the wells decline over time, the [indiscernible] will go up. As you can imagine, these tight reservoirs, gas is going to migrate a lot easier than oil as the pressure declines in the reservoir.

So the longer the well is on and age of the reservoir, the GOR will go up. As we've seen the rig count go down, adjusting with the price environment, we had less flush production coming on and more aged PDP production which has a higher GUR, so the mix has come down..

Okay. And then I feel that this quarter you drilled in higher working interest areas than prior -- certainly prior -- certainly compared to second quarter, but in general and now you are talking about 100% working interest in 4Q.

Is that how it's going to be for 2016 as well?.

We've talked a lot about our high working interest and we've shown data on the 90% plus working interest average on everything we drilled and the package we did in the second quarter did have some other working interest owners in it, but we're basically 88%, 90% -- I don't know what the exact number is -- working interest historically and going forward.

So I think certainly with the divestiture of some of that non-strategic acreage, I think we're going to be having very, very high working interest going forward..

Our next question comes from the line of Matt Portillo from Tudor, Pickering, Holt. Your line is open..

Just a quick follow-up on the hydrocarbon mix shift, just wanted to make sure we understand kind of the context around that. I think you guys were guiding to about a 46% mix for Q3. Came in a little bit below that. I didn't know if there were any moving pieces around that versus your expectation.

We've kind of continued to see that trend down and I know you guys kind of addressed that with the completions, but I would assume that's been kind of baked into your forecast. So just trying to get some additional context around that or if everything is really performing in line with your expectation..

I think it's more or less around where we said it would be. The issue on that is, as Jay said and we've talked about publicly, if we complete and have some flush production at the first of the quarter not only does it increase production which has the rapid decline, but it also increases the oil content percentage.

And then as those flush production wells get six months on them or two years on them, the GOR changes. So I think we're roughly where we thought we would be. I think if we have a lot of flush production one quarter, that's reflected in the oil percentage. If it comes in at the end of the quarter then we're back to the base oil percentage.

So it's kind of what we expected.

Jay, do you want to --?.

That's exactly right, Randy. A lot of it depends on what we bring on. As we bring on this 11-well package, you are going to see probably the fourth quarter oil mix change. Depends on timing when things come online..

Yes. For example, that 11-well program, I think 5 of them will have some sort of meaningful production the way we're modeling it or so at the very end of the quarter, so most of that, if it rolls into the first quarter--.

Yes, it would be first quarter--.

Yes, it would be first quarter, so I expect that to bounce around some depending on completion cadence..

And then a follow-up to that, you talked about shifting the capital program next year into the Upper and Middle zones and I think you guys have mentioned in the past one of the things that has driven the hydrocarbon shift for you over the last 6 to 12 months has been some of the Cline wells flowing through.

I was wondering if you could provide any color on your thoughts heading into 2016 as you move to a program that is dominated by your Upper and Middle Wolfcamp programs, how that should change your hydrocarbon mix heading into next year?.

The pace of development is probably going to drive it more so than anything else. We produce about 45,000 BOE per day. For example, in the third quarter, we gave guidance that the oil component of that would be about 46%. It came in at 45% which is probably as close as we're going to be able to get.

So you have a big base of production and running a 3-rig program will keep that fairly consistent. Now as the activity level changes is when you would expect to see a change either up or down on that oil mix because of the amount of flush production.

The fact that your drilling multi-well pads causes production to be a little bit lumpier until you get up to a high rig cadence where you always have pads coming on.

But the guidance we gave that we released this morning for the fourth quarter of about 45% on the proved content I would expect will be in the neighborhood of what you would anticipate for 2016 as well..

And just last question here, we've seen some really strong well results offsetting your Northern Glasscock and Southern Howard County acreage. Sounds like you are going to focus the majority of your program next year in the Northern Reagan and Southern Glasscock position.

How do you guys think about that acreage that you have in the northern part of your asset base and how does that strategically fit into your portfolio over time?.

We've said for some time that we thought that acreage had value. We had a lot of data that said we had value. We've also started saying the last couple of quarters that we're thrilled to see the industry substantiate that value with the drilling being done by that.

So I think that northern acreage in Glasscock and Southern Howard is pretty exciting to us. I think we took the position that we have corridors built where we anticipate drilling going forward for a while.

We do have some discretion on how we and where we drill rigs, but I think it's just tremendously exciting for us in terms of the value of that acreage to watch finally other operators start drilling close to us..

And I guess from a crystallization of that value perspective, are there any thoughts around either getting [indiscernible] to the drill bit or potentially M&A opportunities to bring cash or crystallize that value?.

Yes. A lot of that southern acreage in Howard County is held by production mostly or principally. Some of it is held by production with the vertical program and all the leases are a little bit different, but that's substantive to most of the rights, if not all. So we've got optionality there on when we need to do something and what we need to do.

And I think, as we've said before, we're relatively agnostic about, if we're not going to be drilling there for a while, maybe we should think about doing something with the acreage. But our view is that, as we've said for some time, all of that acreage has pretty meaningful value. The industry is proving it up for us.

It's good to see people drilling not just Wolfcamp, but Cline and Canyon wells right beside our acreage. So we're pretty excited about all of that acreage base that we have not yet gotten time to drill..

Our next question comes from the line of Brian Singer from Goldman Sachs. Your line is open..

I wanted to follow up on one of the earlier questions with regards to production mix. I think you said you expect a similar production mix that you are guiding to for the fourth quarter to continue in 2016. Can you talk a bit more about the dynamics there? Obviously, that production mix has fallen and is relative to where you were earlier in the year.

Do you see 2016 as a sustainable production mix as we think about the resource base going forward? Are you in a gassier area or more NGL rich area and how should we think about that production mix in the context of the overall portfolio?.

Brian, we finished 2014 at a rig cadence that was 2.5, 3 times more than we're currently running. We made the decision early to cut our capital to be in a position of living more or less within cash flow. And as we said, the third quarter pretty much in cash flow other than Medallion.

We thought that was the right thing to do and when we did that, we talked a little bit then and certainly we've shown it in presentations that we were going to lose the benefit of a lot of the flush production which has a higher oil content.

We've been in this basin a long time on this acreage and with many of our wells now being past five, six years old, we were kind of one of the early people out there on this acreage. So I think it's a combination of things.

I think 2016 we've talked about how we're kind of -- guidance is a little bit impacted by flush production and when the flush production hits the quarter, but we see it kind of as we said it should be..

And then my follow-up question is with regards to the Earth Model, in particular the point that you made on the success that you are having with landing zone optimization and geosteering.

Do you expect -- and I know it's early -- that there will ultimately be EUR uplift, A? And then, B, do you also see the selection that the Earth Model is suggesting opening the door for downspacing or just getting better locations and better wells?.

I think what we anticipate and what we've said is that we think the Earth Model has the potential of being a pretty dramatic step up change which would lead to higher EURs.

We've seen evidence, early evidence, very early evidence that makes us want to keep talking about it and exciting, but we're a long way, in my view, from saying the Earth Model works. And I suspect, Brian, that given -- if you look at this acreage base at a 50,000 foot level, it all kind of looks the same.

As Jay said, if you get down and look at it well by well, you see some differences. So I think we will be integrating new data into the Earth Model for a long time to come. I think the message is that it's one of those things where we've spent a fair amount of time and effort and money. We're using it as we speak going forward.

I think it does help us pick landing zones. I think it has the potential to be meaningful. Early results look good, but it's too early for us to feel comfortable about it. We've talked about wanting to see 9 months, 12 months, 6 months meaningful production, not just a couple of weeks or so. 24 IPs really scare me. 30 days don't make me very comfortable.

I don't anticipate that in itself having a lot of impact on spacing. I think we chose our spacing early on. I think we've tested going broader on the spacing. I think we've tested some going narrow. I think the spacing issue to me takes several years before you get enough production and pressure data.

The Earth Model will help us, but I don't think it has a direct impact on spacing anytime soon..

Our next question comes from the line of John Herrlin from Societe Generale. Your line is open..

Just one from me because most things have been asked, with Medallion, can you give us a sense of what you think the throughput ramps will be through next year, quarterly, if you can?.

We certainly anticipate that the volumes and throughputs through the Medallion system will increase. Keep in mind that at least 75% or more of those volumes are coming from third parties outside of Laredo.

As they are in the process of setting their budgets and how many rigs they are going to be operating, that activity level is what really will drive the production growth or the throughput growth from Medallion..

Yes. That's what I assumed, Rick. I just was wondering if you had any indications. Thanks..

That concludes today's Q&A session. I would like to now turn the call back over to Ron Hagood for any closing remarks..

Thank you for joining us for our third quarter 2015 update call. We appreciate your interest and operator, you may now disconnect..

Ladies and gentlemen, thank you for attending today's conference. This concludes the portion of the conference. You may now disconnect. Everyone, have a great day..