Ron Hagood - Randy A. Foutch - Founder, Chairman and Chief Executive Officer Richard C.

Buterbaugh - Chief Financial Officer and Executive Vice President Jay P. Still - President, Chief Operating Officer and Director Patrick J.

Curth - Senior Vice President of Exploration & Land Daniel C. Schooley - Senior Vice President of Midstream & Marketing

Ipsit Mohanty - GMP Securities L.P., Research Division Joseph D. Allman - JP Morgan Chase & Co, Research Division Bob Brackett - Sanford C.

Bernstein & Co., LLC., Research Division Dan McSpirit - BMO Capital Markets Canada Sameer Panjwani - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Jeffrey R.

Connolly - Clarkson Capital Markets, Research Division John P. Herrlin - Societe Generale Cross Asset Research Brian Singer - Goldman Sachs Group Inc., Research Division David R.

Tameron - Wells Fargo Securities, LLC, Research Division

Thank you, and good morning. Joining me today are Randy Foutch, Chairman and Chief Executive Officer; Jay Still, President and Chief Operating Officer; Rick Buterbaugh, Executive Vice President and Chief Financial Officer; Pat Curth, Senior Vice President, Exploration and Land; Dan Schooley, Senior Vice President, Midstream and Marketing; Ken Dornblaser, Senior Vice President, General Counsel; and -- as well as additional members of our management team.

Before we begin this morning, let me remind you that during today's call, we will be making forward-looking statements. These statements, including those describing our beliefs, goals, expectations, forecasts and assumptions, are intended to be covered by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995.

The company's actual results may differ from those 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. Earlier this month, Laredo announced that beginning January 1, 2015, it will report production and proved reserves on a 3-stream basis, and the press release issued this morning, financial and operating results have been reported on a 2-stream basis.

Well results have been converted to a 3-stream basis to facilitate comparisons with the 3-stream type curves provided in the February 2015 presentation. Additionally, a conversion of production and unit cost data for 2014 from 2-stream to 3-stream has been provided in the appendix of the updated corporate presentation released this morning.

This morning, the company issued a news release detailing its financial and operating results for the fourth quarter and full year 2014. If you do not have a copy of this new 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. Thank you for joining Laredo's Fourth Quarter and Full Year 2014 Earnings Conference Call.

During 2014, the company capitalized on its full field development strategy for our Permian-Garden City asset. Approximately 70% of operated horizontal wells were efficiently completed as stacked laterals, driving a 29% growth in annual Permian production.

We started construction on 3 additional production corridors, taking advantage of our contiguous acreage position, and commenced operations on the Medallion Wolfcamp Connector Pipeline system during the fourth quarter. We have protected a significant portion of our revenue with hedges in 2015, 2016 and 2017, and the company has maintained an active hedging position in a wide range of commodity price environments.

The cornerstone of Laredo's hedging velocity is to mitigate the impact of commodity price fluctuation by having enough hedges in place to cover debt service, overhead and a reasonable capital program for multiple years. Our philosophy also insists on service contracts with terms of 1 year or less.

This has enabled us to rapidly adjust to the current commodity price environment and quickly take advantage of service cost reductions. The Medallion Pipeline, in which we have a 49% equity ownership, commenced operations in the fourth quarter.

We have an initial commitment of 10,000 gross barrels of oil per day, an expansion to third-party producers are expected to be operational soon. Additionally, we completed a successful horizontal test of the Canyon formation, one of several additional zones we have identified to further expand our resource potential beyond the initial 4 zones currently under development.

We are also continuing to analyze the data we have gathered from our wells and integrated it with high-quality 3D seismic within our Earth Model. We expect to utilize this data to optimize the landing and steering of 90% of the horizontal wells we plan to drill in 2015.

Initial results, although still early, are encouraging and may have a meaningful positive impact on our future development if, as expected, they optimize production and resource recovery. As previously announced, we have engaged an adviser to assist us on structuring a possible transaction involving a portion of our northern Garden City acreage and potentially additional operational locations in our southern area.

Discussions with potential counterparties are ongoing and have centered on terms associated with funding development opportunities, specifically drilling funds. However, these discussions remain preliminary, and no conclusions on size, structure or timing have been made.

And there can be no assurances that any transaction will occur. I will now hand the call over to Rick.

Thank you, Randy, and good morning. As stated in this morning's news release, Laredo reported fourth quarter 2014 adjusted net income of $21.5 million or $0.15 per diluted share and adjusted EBITDA of $150.5 million.

For full year 2014, adjusted net income was $132 million, with a company record for adjusted EBITDA of $598 million for the year. These results were primarily driven by record production for both the fourth quarter and full year of 2014.

The record oil and gas sales volumes achieved in the 2014 fourth quarter of 3.7 million barrels of oil equivalent was up 63% from the prior year quarter and up 21% sequentially from the third quarter of 2014. As a result, full year volumes were a record 11.7 million barrels of oil equivalent, up 29% from 2013 Permian production.

In the fourth quarter of 2014, Laredo's increased production volumes overcame the 27% decrease in average realized prices, resulting in an increase in total oil and gas sales of approximately 18% from the prior year quarter. Total oil and natural gas sales for 2014 increased approximately 11% from 2013 to $737 million.

The increase resulted from both higher production and slightly higher average realized prices. Fourth quarter 2014 cash operating expenses decreased to $16.13 per barrel of oil equivalent, down 15% from the prior year quarter and down 18% sequentially from third quarter 2014.

Reduced overhead costs, coupled with lower production taxes, were the primary drivers of these savings. Laredo announced in January of this year the closing of our Dallas office and a workforce reduction of approximately 75 employees.

We expect to take a onetime restructuring charge of approximately $7 million in the first quarter of 2015 as a result of these measures. You will note that our corporate tax rate for deferred income taxes for the fourth quarter was 39% versus 35% in the third quarter of 2014.

This was primarily the result of the $329 million gain on derivatives that we recorded in the fourth quarter of 2014. Derivative gains are subject to Oklahoma tax and therefore will tend to increase our effective tax rate in periods of declining commodity prices, due to our outstanding hedge position for 2015 through 2017.

However, you should also keep in mind that we are not a current taxpayer. We use commodity derivatives to mitigate the variability of our anticipated cash flows due to fluctuations in commodity prices.

We actively monitor our hedging program and utilize a combination of puts, swaps and collars, none of which are 3-way collars to hedge our production. At December 31, 2014, the company had in place for calendar year 2015 approximately 7.7 million barrels of oil at a weighted average floor price of approximately $81 per barrel, representing more than 95% of anticipated oil production for this year.

Laredo has also hedged about $28 million MMBtu of our anticipated liquids-rich natural gas production for calendar year 2015, effectively representing more than 63% of anticipated natural gas and natural gas liquids production at a weighted average floor price of $3 per MMBtu. Additionally, we have recently added basis swaps for the months of March 2015 through December 201,5, for a total of approximately 3 million barrels of oil to hedge the Midland-WTI basis differential at WTI less $1.95 per barrel.

We believe this basis swap covers that portion of our expected oil production that is not sold into the Gulf Coast market. As we begin 2015, keep in mind that as of January 1, Laredo will report all production, operational and financial results in 3 streams.

In our news release this morning, we provided detailed guidance for the first quarter of 2015 for volumes, realizations and unit costs on a 3-stream basis. We also reiterated our guidance for greater than 12% year-over-year increase of total production volumes on a comparable 3-stream basis.

We confirm this growth rate despite ending 2014 at higher than previously projected volumes. Our projected growth is based upon activities associated with the company's board-approved 2015 capital budget of $525 million.

This budget was developed using actual service costs experienced during the second half of 2014 and does not reflect potential savings as service costs decrease to align with current commodity prices. The budget also reflects a disproportionate amount of activity and spend during the first half of 2015 as we complete multi-well pads that we began in 2014.

We expect to fund this capital program primarily through operating cash flow, and have rapidly adjusted our activities to balance capital investment with cash flows by year end of 2015. At this time, I will turn the call over to Jay Still for a more detailed review of our operating results and plans for 2015.

Thank you, Rick. During the fourth quarter, we completed 26 horizontal wells in the Upper, Middle and Lower Wolfcamp and Cline shales and an exploratory horizontal well in the Canyon, bringing our total horizontal completions in those zones in 2014 to 80.

Additionally, we completed 34 vertical wells in the fourth quarter, bringing the total for 2014 to 115. During the year, approximately 70% of the horizontal wells we completed were stacked laterals.

As we had planned, our 2014 completions would be weighted to the second half of the year. The cycle times for multi-well pads are longer than those of single wells.

This led to a fourth quarter production of 39,722 barrel of oil equivalent per day on a 2-stream basis, an increase of approximately 20% from the third quarter of 2014. During the fourth quarter, we completed a horizontal well in the Canyon formation, which is stratigraphically located between the Lower Wolfcamp and the Cline.

The Canyon lies at a depth of 8,250 to 9,000 feet and has a gross thickness of 600 to 900 feet across our acreage. The well, the Glass 22A - Aeromotor 27 #7SP, located in southern Glasscock County, recorded a peak 30-day average IP of 1,151 barrel oil equivalent per day on a 3-stream basis.

Identifying and successfully drilling of horizontal well in the Canyon is a great example of Laredo's data-driven approach to exploration and development. After extensive evaluation of open-hole logs from vertical wells and corresponding production logs, we were encouraged with Canyon's potential.

This led us to extracting a full core of the Canyon formation in March of 2014. By calibrating all of the data and integrating the petrophysical analysis into our 3D seismic subsurface mapping, we now believe the Canyon may be perspective on at least 50,000 net acres of the company's Permian-Garden City leasehold.

We will drill an additional well in 2015 to further delineate the formation. Additional drilling will be needed to assess the zone's full development potential and to determine how it will be integrated into our existing development plans.

The company's 2015 drilling and completion budget, as announced in December, was approved at $430 million. Approximately $100 million of the budget is allocated to activities begun in 2014.

In 2015, we expect to complete approximately 45 to 50 gross horizontal wells and approximately 40 gross vertical wells. We anticipate drilling approximately 25 to 30 gross horizontal wells and approximately 30 gross vertical wells.

The company has embarked on several initiatives to reduce costs, well costs. None of which have been factored into the approved drilling and completion budget of $430 million.

Foremost, we are ongoing -- we are in ongoing negotiations with all of our service providers to reduce costs in light of fall of commodity prices. We've already reduced costs in most services and expect to see at least 20% reduction on average by mid-2015.

Additionally, we continue to see efficiency gains in our drilling operations, reflected in the reduced number of days needed to drill and complete a well that should also contribute to reduce the capital expenditures. We also anticipate that our drilling and completion investments will be lowered by a reduction in partnership wells operated by others.

Factoring in these reductions, we believe our drilling and completion investments could be reduced as much as $50 million, while maintaining a greater than 12% production growth in 2015. Our operating drilling plan is primarily focused on meeting drilling obligations to hold acreage by production and to meet continuous drilling clauses contained in some of our leases.

This drilling program will enable us to hold all of our core acreage in 2015, with the exception of some limited potential fringe acreage that will be allowed to expire. Laredo still anticipates 70% of its completion activity will be in the first half of the year.

In the first quarter of 2015, we expect to complete approximately 14 horizontal wells, with 9 achieving a full month of peak production during the quarter. In the second quarter, we anticipate completing approximately 16 horizontal wells.

The majority of these wells are in a development area where we have a lower working interest than normal. Consequently, second quarter completions will average approximately 65% working interest instead of the historical 90% plus average working interest of our operated wells.

We are addressing operating cost reductions through service cost negotiations and investing in infrastructure and new development areas where the power grid can be built out to replace generators, consolidating compressors and running pipelines to saltwater disposal wells to eliminate trucking costs. I'll now hand the call over to Pat Curth to discuss our Earth Modeling efforts.

Thanks, Jay. Since our Midland-based plays inception, as an integral part of our culture, Laredo recognized the need to develop an extensive proprietary database in order to better understand the multi-stacked reservoirs we are targeting.

The company has made a significant investment in obtaining data such as high-quality 3D seismic, whole and sidewall cores, dipole sonic logs and multiple single-zone and production tests. It is critical to understand that much of the data such as our dipole sonic and production logs can only be obtained in certain points during the initial phases in a well's life or the opportunity is lost forever.

Laredo has employed an integrated workflow, combining geoscience and engineering data with multivariate statistics to build an Earth Model. Analyzing more than 80 different seismic, petrophysical and reservoir attributes, we have developed the model that correlates this technical data to production in the Upper, Middle and Lower Wolfcamp and Cline intervals.

Initial look-backs, where we tie model results to wells previously drilled, have resulted in an average 85% correlation coefficient for all 4 zones. Subsequent tests, in which inputs from the model were used in the drilling of 7 additional horizontal wells, resulted in an average correlation coefficient greater than 95%.

The company expects to utilize the Earth Model and approximately 90% of its horizontal wells to be drilled in 2015. It's anticipated through the utilization of the Earth Model, such as picking landing points and geosteering to stay in zone, both initial production rates and EURs will be enhanced.

Thank you. And I will now turn it back over to Dan.

Thank you, Pat. During the fourth quarter and all of 2014, the company continued to invest in production corridors to facilitate the development of our Permian-Garden City asset with stacked laterals on multi-well pads.

In 2014, we advanced the buildout of 4 production corridors, 2 in Glasscock County and 2 in Reagan County. At the end of 2014, there were approximately 105 horizontal wells on these 4 corridors combined.

These 4 corridors, as currently constructed, can accommodate more than 600 horizontal wells and, when expanded as designed, will be able to accommodate approximately 1,200 horizontal wells. Should additional zones be delineated for development, such as our recent Canyon discovery, the corridors will be able to accommodate with minimal additional capital expenditure required.

To facilitate the movement of our crude oil out of the congested Midland market, Laredo has participated as a joint venture partner and as a firm shipper on the Medallion Wolfcamp Connector Pipeline system. This pipeline, initially 88 miles in length, now traverses more than 200 miles from southern Reagan County and eastern Midland and Upton Counties through Laredo's acreage and on to the Colorado City hub located near Colorado City, Texas.

With current capacity of 65,000 barrels a day, expandable to 135,000 barrels a day, this pipeline avoids the congested Midland market and provides Laredo with firm, non-interruptible transportation to the Colorado City hub where crude oil can then move to the U.S. Gulf Coast, Upper Midwest and Cushing markets.

Nominations on the pipeline for March are 19,000 barrels of oil a day, including only a portion of the projected volume from the recently announced Santa Rita Lateral. Additional production from the dedicated acreage on the Santa Rita Lateral and the startup of the Midkiff Lateral during April and May of this year will significantly increase the throughput on the Medallion Pipeline system.

Laredo's investment in our fluid management systems in the production corridors has resulted in greater capital efficiency and enables Laredo to execute complex completion operations on multi-well pads. Similarly, our investment in natural gas and crude oil systems provides us with optionality on our takeaway capacity, and our investment in the Medallion Pipeline system provides us with key takeaway capacity for our crude oil on a firm basis and provides us access to multiple markets in Colorado City, Texas.

Operator, at this time, please open the line for any questions.

If you can, could you split -- could you kind of split your number of completions in 2015, number of drilled and completed wells in 2015 zone-wise, in terms of how many of them would be Cline's versus, say, Wolfcamp?

I'll let Jay perhaps give a little more detail. But we tend to be pretty fluid in exactly which zone and exactly which we try and complete.

We do have a budget that runs out. So when we talk about those, they're not fixed.

And as we get data, see what we're doing, we may adjust. Jay, do you want to add?

Yes. Some of our -- as I stated in the discussion, the focus of our drilling program in 2015 is on satisfying leasehold obligation and holding our core acreage together.

Some of those leases, you hold by the deepest depths, which would drive you to drill more Clines. Some are just continuous drilling programs.

So it's going to be a mix of both, depending on where we are in our acreage position.

And my follow-up would be, would that mean that in order to hold acreage, you would go probably on single-well pads versus your stacked development that you're used to?

Yes. The majority -- unlike 2014, the majority of our wells will be drilled on single-well pads in 2015.

First, could you describe the modifying of completions? Could you give us details?

You talked about in your press release completing 12 wells. And I just -- it sounds as if you're deferring completions.

So could you take us through the year? And also, it sounds as if you're reducing your working interest.

But take us through the year and help us just understand fully what you mean by modifying your completions.

We started the -- surge of 2014, in the third and fourth quarter, we were drilling a lot of wells. And so we have a pretty good inventory of completions to focus on efficiency.

We could have brought in 3 different frac fleets to knock out that inventory. We chose to pretty much focus on 1 frac fleet to utilize them 100% throughout the year and delayed completing that inventory so that we can do that and focus on cost efficiencies that, that brings.

Okay. And then -- all right, that's helpful.

And as a follow-up to that, and I just have -- I'm going to add another one. So help us understand how many wells you had drilled but not completed at the beginning of the year and how many you plan to have at year-end '15.

And then early in the prepared remarks, you described the sales process that's ongoing with your acreage position. And I know you said you haven't determined size.

But I didn't quite catch exactly -- I didn't understand exactly what you were talking about. You're working with someone and you're discussing kind of development ideas.

Could you just describe that more fully for us?

Joe, this is Randy. And just to be clear, we've never described it as a sales process.

We've been very careful to characterize it as a possible transaction. We've said consistently that we view all financing alternatives frequently, and that includes debt, that includes equity, that includes joint ventures, that includes asset sales.

And my view has been fairly consistent is that we've got a 50-year or 40- or 60-year inventory, whatever the number is, we keep adding to it. For example, with the Canyon Sand, we know that there's other zones that produce vertically.

We've tested them in single zone [indiscernible]. So I think our job was to, at the right point when we had the right data, and we've said all along that we view data as driving these decisions, that we would start looking for a way to add to the NAV perhaps by a joint venture or sale of acreage or whatever we have.

So the transaction that we're in the middle of has not been characterized as a sale. I think we've appropriately said that our job there was to try and get value for things one way or another, that it may be decades before we drill.

Did that help, Joe?

Yes, that's very helpful, Randy. You've been very clear about describing it as a transaction, so that's just my poor choice of words.

But you did describe something earlier in your prepared remarks about you're working on kind of development ideas. I think it's what you said.

So could you just describe that more fully? And then back to the other question about waiting on completion inventory at year-end 2015 versus year-end 2014.

I think I'll leave the conversations about a possible transaction, Joe, exactly as we left them. It's -- I think it's way premature for us to comment on what that might look like or any details.

And again, we're not sure that anything happens. For us, it's -- again, we look at all of those financing vehicles pretty much as we're ambivalent and view them as costing us barrels, and we'll decide when we get there whether there's a transaction that we want to do or not.

So I'll leave that one as is. And I think your question about completions at 2015, I don't think we're prepared to really focus on that a lot.

Rick's going to make a comment.

The only thing I'd add to that, Joe, is that we've not changed the number of completions that we anticipate to have done in 2015. We have moved a little bit from quarter-to-quarter to be able to take advantage of efficiencies in -- as Jay was mentioning, in using 1 frac crew and also as costs decline for various services.

On the inventory, we do not have a substantial inventory of wells that are drilled but uncompleted at year-end '14 nor do expect one at the end of 2015. There is a normal amount of inventory of drilled but uncompleted wells associated with multi-well pads, and that is the only inventory, say, that we have that is leading up to the 12 well completions that Jay talked about in his prepared remarks.

Yes, a question on the Canyon. You mentioned the Canyon Sand.

Is that a sand across the whole area? I've heard other people refer to it as a Canyon Lime target.

So what's the lithology?

The lithology on the well, our initial well, is more of a limey shale. And there -- it varies across the acreage.

On the northern half, it's more of a limey shale. And on the south half, it's more of a sandy shale.

Got you. And then a question at a higher level.

You've chosen to sort of de-risk the Canyon Lime ahead of de-risking the Spraberry. A lot of other operators are out there talking up the Spraberry.

What are your plans to de-risk that zone?

We have -- some effort went into the Spraberry. This was our first Canyon horizontal well.

But I think we've said something along the lines in the past a number of times, Bob, that we have 4 primary zones that we are focusing on, and those give us -- we started off talking about a 20-year inventory, then we went to 30, then we went to 40, then we went to 50. And I don't know where it is today at whatever rig cage you're talking about.

We know that we have 7, 8, 9 zones in total that are capable of production, maybe more. And the reason we know that is because we've tested them, single-zone tested them in vertical wells, and we've run production logs, a lot of them in vertical wells.

And so we took the posture that with the 4 primary initial zones we focused on, which were the Upper, Middle, Lower Wolfcamp and Cline, that we weren't in a particularly big hurry to add another decade of drilling to something that is a 40-, 50-, 60-year kind of an inventory. So we -- we've said that we were going to be slow to work on the additional zones.

We've done a little work on the Spraberry. We've done some on the Canyon.

We have other targets out there that, at some point, we need to go test and add to that decades of drilling we've already identified.

But not a big priority for this year?

I don't think it's a priority for us simply because our -- it's interesting to me. When we say we have 3,000 or 4,000 or 5,000 locations, horizontal locations to drill, that's backed up with substantive data.

That's not just taking the acreage and dividing it by the 120-acre spacing. So I think those are locations that are very well identified, very well backed up with data and we'll be adding to them.

And it's just not a huge priority for us.

How proprietary is the company's Earth Model? And if the intellectual property, for lack of a better term, is truly proprietary, does the application of the Earth Model mean the company's production forecasts are not only more accurate than not but maybe more accurate than what other producers can create?

I'll take a 50,000-foot comment, then I'll have Pat address some things. If you look at our EURs, for example, we pushed out the EURs 3 years ago based upon a tremendous amount of data.

We pushed out, I think, the 120-acre spacing, 660 across there, several years ago that was based upon a tremendous amount of data. The industry is kind of settling, I think, on the 120, and EURs seem to move around some.

Those are all examples to where our data collection that we've literally done since day 1 at this company and others, we think, have allowed us to make much, much better decisions. A lot of that data that we collect, you can only get it at a certain time during the well's history.

And so it's proprietary. A lot of what we do with that data is proprietary.

But there's also a real issue of can you actually collect the data at a point in the well's history. Pat, do you want to...

I'll just add that when we started our project in the Midland Basin, we realized it was a pretty unique situation with the multi-stack potential. And going back to what Randy just said, we initiated collecting a lot of data years ago.

And we realized that we had to have some process by which we can bring all these data together under 1 model. That's what we talk about in the Earth Model.

The data we've collected is proprietary. How we're using the data is proprietary.

I can tell you, the attributes that we look at that go into our Earth Model are -- on a general basis are the standard a lot of people look at, brittleness, fracturing, lithology, reservoir engineering. But we've been working on this project for over 3.5 years now, and we're finally to the position that we're bringing it forward.

And at the end of the day, we do believe it will enhance our abilities to improve our EURs and our production.

And just to kind of talk about that a second. The example that I used is, is we shot 3D out there very, very early, and we shot extremely high-resolution 3D.

We were criticized or at least commented on that other people didn't think 3D was a benefit. We -- Pat and I have been doing this together a long time.

We've seen it be a huge benefit to us, tremendous data benefit from it. And now what we're seeing is a lot of other people shoot 3D.

But if you're not shooting extremely high-resolution 3D, you don't get the answer. So 3D is not -- our 3D is proprietary.

Anybody could shoot on their acreage. But I think what we do with it once we get it and the high-quality that we get help us in the overall Earth Model.

Sorry if I went too deep on that, but I think it's important to understand there's -- you can't get dipole sonics, for example, after casing is run. I mean, there's lots of examples to where not only is what we're doing proprietary, but there's also a real sense of you only get 1 chance to collect it.

I appreciate the detail. And if I may, a follow-up question.

Can you review the number of wells a production corridor can accommodate initially and then, ultimately, accommodate and how and why the number of location increases?

I'll take first crack and then maybe get Jay and Dan. If you look at the corridor that we're probably the furthest along on it in that we have all of the fluid handling facilities in place, including water recycling, that's one where we've drilled, I think, something like 100 horizontal wells.

And I won't be exact on that. It has potential just on the 4, Upper Middle, Lower Wolfcamp and the Cline, and some Canyon to have another 500, 450 wells, horizontal wells drilled on it.

And those get to be very, very, very efficient in that you're really manufacturing all the products, all the water is all moved around in pipe. Jay, why don't you talk about the 12 wells?

And Dan, you can add on that if you...

Well, just to build on what Randy was saying, and when you look at this concentration of resource, the fluid management system is absolutely critical, and it's going to drive the pace of what you can do. As Randy mentioned, we have 450 to 500 locations just in our largest corridor.

Running 4 to 6 rigs on that requires frac jobs of 2 million to 3 million barrels of water at a time. In order to manage that water, you have to have the infrastructure in place, that you can actually do that with recycled water and manage the pace of your development.

We currently have 12 wells that we've drilled to fully develop out in Upper, Middle across the section at 660-foot spacing. We will commence the completion here shortly.

We have built a corridor that can handle that, and that will enable us to do 12 well completions at a time to manage that type of fluid volume. But you can only do this if you really have contiguous acreage that makes this efficient.

Dan, you got anything to add to that?

Well, just on the oil and gas side, too. The thing that we found, and as we were developing these multi-stack pads, is when we bring all of that production online, we were knocking off all of the legacy production that was on the existing poly pipes that were out there by the purchaser.

So by putting in the corridors, we're able to take this gas and crude oil to central -- big centralized facilities and go directly into the bigger high-pressure lines of the purchasers and keep the oil and gas off of infrastructure that was not really designed for these kinds of wells. So we're also picking up quite a bit of efficiency around oil and gas gathering and optionality as well.

I know you've only just drilled 1 well in the Canyon, but just to get a few more details on that, as a start-off, what was the lateral length of the well that you guys drilled? And then also, how was the decline performing compared to the other formations around it?

And how is the well control?

Yes, Sameer. The -- it was a nominal 7,500-foot lateral.

The well has been on about a little over 90 days, and it's looking very comparable to the other wells that we drilled in the Upper, Middle, Lower Wolfcamp. But that's a -- we're encouraged but that's 1 well.

We're not ready to declare victory yet until it's further delineated, but we are very encouraged by the results.

Okay, great. And then I guess could you just talk about the strategic importance of your midstream assets?

We think that when you look at our midstream assets, and this is something we started again very, very early at Laredo, it's something that we'd also done at my other companies, we initially view the strategic importance primarily as it gave us great operational control on if we decided to frac a well, we knew that the necessary midstream facilities would be there. We weren't waiting on someone else who may not have exactly the same priority we had.

When we recognized 3 or 4 years ago that our Garden City acreage was world-class and some of the best acreage out there, we also recognized that handling water was going to be very, very important. And so the strategy of bringing the water handling within the midstream and making sure that we were able to move water not only up and down with the corridor but perhaps between corridors got to be pretty important to us just from an operational point of view.

We also think it adds significant value. And there's lots of examples of that we've talked about in the past.

The lack of trucking cost, the -- those type of things add value, lots of ways through the point. And then I think the LMS and our 49% ownership of Medallion has amplified what we think the strategic benefit of that through.

Okay, great. And then one more if I could.

And I don't know if you guys have broken this out before, but just on an adjusted EBITDA basis, is there any annualized run rate number you can provide for the midstream?

The midstream activities are just really beginning to ramp up. For 2015, we anticipate that the midstream activities will represent about 5% of our overall EBITDA as we continue to drill.

And as third party volumes, which are just beginning to start flowing through the Medallion system, we believe that can ramp up relatively quickly.

One on the Canyon. Do you think it's a distinct zone?

And then what gives you confidence that it's not producing from either the Lower Wolfcamp or the Cline?

Yes, we're sure it's a distinct zone, and it goes back to the whole -- to our tremendous database that we've acquired out there. When you look at the number of open-hole logs that we've run, when you look at our 3D seismic, when you look at the cores, I mean, we've taken -- internally, we have over 3,700 feet of whole cores and over 700, 800 sidewalk cores.

So this is how we've operated in the past, this is how we bring forward the potential, but you have to have the extensive technical database that we have. So we have a high degree of confidence.

It's a distinct zone that we can map across our acreage. And we have a high degree of confidence based on the information we had and especially in offset cores, Jay mentioned, that we thought we would have very positive results there as indicated by that first well.

Keep in mind, it's 1 well. And keep in mind that we've said publicly a number of times that we're not too excited about 24-hour IPs.

We don't think that's sanitary data. 30 days give you a little more comfort.

We're going to watch this well and really see what production does before we start pounding the table a whole lot on it, although we're pretty enthused about what we've seen so far.

And we know the -- in our particular area, we know the Canyon produces. There are 2 prolific Canyon fields, gas fields, up dip from us over in Sterling County.

So one of the beauties of working in the Permian Midland Basin is that we go 80, 90 years of vertical history in wells that we can key off.

All right. That was helpful.

And then last year, you had a couple of different completion design tests going on. What does the standard completion look like for 2015?

Let me set the stage, and I will let Jay follow up. But we announced that we tested white sand.

We announced that we tested brown sand and different amounts and different amounts of water. We had talked about using resin-coated sand.

We talked about using ceramics. We're still working on what's -- how that works.

What we saw was in a number of cases that different -- your resin-coated sand gave you a higher, perhaps 30-day IP, but that the curves reverted to mean pretty quickly. And that our view was that when you look at things over 6 months, 9 months or 1 year, those didn't have an economic benefit.

What Jay will tell you is that what that verifies is that our initial data, interpretation and data set, we came up with a frac plan that seems to be working pretty well.

I agree, Randy. Our design is pretty good.

We have not found any silver bullet that we're ready to say, "Eureka, we've -- this is the way we should do it, and it's a lot better than what we're doing now." So we've tried -- as Randy said, we've experimented with a lot of different designs and different early results, but in the end, they all kind of come back to meet the average of what we're doing now.

So what we're doing now is pretty good frac design.

Three quick ones. For doing your Earth Model, how much more incrementally is the cost per well?

Just kind of front-end, what do you think it costs you?

We've invested -- that's it. I like that question a lot because, John, we've already invested, by far, the majority of the money.

Now there will be some additional, I don't know, reprocessing or some manpower work. There's a lot of software.

We've got to keep up-to-date. But probably going to be some testing here and there some things.

But overall, with data collection and the attribute selection and work is all behind us. So go forward, it gets to be a relatively minor piece of our data.

If you look at it in an aggregate, we're talking about a few thousand dollars per well. So we think, and this has been true for me through most of my career, that better data helps you make better decisions.

And again, we're pretty enthusiastic about what we're seeing, although it's too early.

Okay. That's fine.

I didn't think it will be much, but ultimately, it does matter a lot in my view. With the Canyon...

John, let me just clarify one thing on it. When we're talking about several thousand dollars per well, that is all the data that we've been able to gather, spread over the 3,500-plus wells that we've identified to date, and we think that number of locations is actually growing.

But when you put it in that perspective, we think those are dollars that are extremely well spent to be able to potentially improve the results of the substantial inventory, of projects that we have.

I agree. Look, it's PV enhancing.

I just didn't think there was much cost. That's what I wanted you to address.

You addressed the lithology of the Canyon. How about the thickness?

Is it uniform throughout?

Well, we've -- as we stated earlier, the -- it is basically about 800 to 900 feet thickness. It's pretty uniform -- I'm sorry, 600 feet, 600 to 900 feet.

Okay, great. And last one for me.

You have a lot of long-dated inventory in reserves. And with respect to the potential transaction, I know you don't want to be very specific, are you trying to come up with a funding mechanism that is, shall we say, more equitable or that doesn't give up the upside?

We view funding mechanisms. The answer I think is, we think no matter what we do, we're giving up barrels one way or another.

If we do equity, if we do data, if we do revolver, if we do sell acreage, if we do drilling funds, whatever that you can think of, John, I think the answer is, one way or another, we -- our payback is in barrels. And I think our view is that when you look at our location inventory, it's pretty high-quality.

We think the barrels that we talk about in resource potential in our presentations are well backed up with a lot of data and not just, again, acreage divided by some spacing unit, but very, very high-quality barrels. And so yes, we -- when we look at whatever we're looking at it, we definitely look at it in terms of how do we preserve shareholder value.

If we're giving up upside, there's a real cost, and we'd like to keep as much of that as we can. But we recognize whatever financing we do, whatever development, whatever sale relates to barrels.

Apologies if you discussed this earlier. But on the balance sheet, can you talk to your goals for the end of the year, whether you expect the JV to accomplish this or whether you see equity as needed or a viable option to get there?

Well, I think what we would say, Brian, is that we're always pleased to see that the equity market is open and that the debt market is open. But I think our view is just like I just said, that when we look at whatever financing alternatives we're talking about, whether it's debt or equity, high yield or joint ventures or asset sales, we look at them in terms of -- we're kind of agnostic.

We look at them in terms of what's best in our view for shareholders. We haven't made a decision or ruled out anything.

That's kind of been our plan for a long time. But one of the things that I think separates us a little bit is we reported our hedges in that we're -- the numbers are in the filings roughly 100% hedged for 2015 at 80, whatever it is, plus.

We're very deeply hedged in '16 and '17. And so that gives us, I think, a lot of opportunities to be fairly selective going forward on how we view financing alternatives.

That makes sense. And then my follow-up is a question on the cost side of the equation, on the operating cost side.

We saw a step-down in SG&A during the fourth quarter. First quarter guidance seems to have it back up and was wondering if you could talk to the trajectory there.

And then on lease operating costs, you talked to some of the efficiencies from fluid volume management and wondered if you see over the course of the year your lease operating expense per BOE falling, rising or staying the same.

Brian, as far as the fourth quarter G&A, we did have meaningful reductions impacting the quarter. As we had talked about before, we had a number of projects that were going on in 2014 where we had some outside consultants coming in on some best practices work to improve our efficiencies in the field.

Those projects really finished up in -- at the end of the third quarter. So that was part of the meaningful reduction.

We also had reduced impact in our overall compensation expense, were the primary drivers of that. In 2015, as we roll forward, as we talked about, we have made reductions in our workforce by a meaningful amount.

We will have the charge in the first quarter but then anticipate continued reduction in some of our G&A charges and, really, a very focused approach on reducing those charges.

Brian, this is Jay. I'll address your second question in regards to LOE.

Just like on the well cost, drilling completion cost side, we're working with the vendors to reduce cost in this more challenged environment, and that will work through the system as -- through the years as long as prices stay down. So that's a continuing effort.

And then I also mention, there's a number of newer areas we brought under development that we can take costs out of the system by consolidating compressors with centralized compressors, running, getting wells on power grids instead of individual generators and getting more water lines connected to disposal well or a recycled system so that we can take trucks off the road. So those will -- we'll be working on those diligent through the year and probably can look at another 10% out of our reduction on our LOE costs.

And one last one, just to follow up on your SG&A response. In the first quarter guidance, does your dollar per BOE guidance assume the charge that you discussed?

Or is the charge separate from that?

The charge is a separate onetime charge.

I think most have been asked, but just one question. It seems like people are dancing around a little bit.

This midstream, it took a little more prominent role in the presentation recently. I know you've been talking about it for a while.

But is this something that you're looking to monetize at some point?

I think, again, David, thanks for the question. We've recognized the strategic advantage of that from us.

From an operational point of view, we recognize the economic advantage it gives us as the operator upstream. And I think our view of LMS is we started talking about it a little bit more because in the past, we were putting money into it, getting ready and we weren't really able to articulate all the benefits with data.

Now we can articulate the benefits with data. But having said that, I think we view LMS as something we put money into.

We want to do what's best for shareholders long term. There are no plans to monetize or anything like that, but we recognize that there is tremendous value creation, at least in our minds.

Thank you, Greta. Laredo Petroleum will be participating in 3 industry events during the first half of March.

Randy Foutch and Rick Buterbaugh will represent the company at the Simmons Energy Conference in Las Vegas March 4 and 5, Wells Fargo Exploration & Production Forum in Boston on March 10 and the Global Hunter E&P Day in Boston on March 11. We'll release first quarter 2015 earnings and financial results and host a conference call on Thursday, May 7.

Thank you for joining us for our fourth quarter and year-end call.