Ron Hagood - Randy A. Foutch - Founder, Chairman and Chief Executive Officer Jay P. Still - President, Chief Operating Officer and Director Daniel C. Schooley - Senior Vice President of Midstream & Marketing Richard C. Buterbaugh - Chief Financial Officer and Executive Vice President.

Brian Singer - Goldman Sachs Group Inc., Research Division Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division Gilbert K. Yang - DISCERN Investment Analytics, Inc Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division Ipsit Mohanty - GMP Securities L.P., Research Division Brian D.

Gamble - Simmons & Company International, Research Division Michael Kelly - Global Hunter Securities, LLC, Research Division David Martin Heikkinen - Heikkinen Energy Advisors, LLC Richard M. Tullis - Capital One Securities, Inc., Research Division John P. Herrlin - Societe Generale Cross Asset Research Matthew Portillo - Tudor, Pickering, Holt & Co.

Securities, Inc., Research Division.

Good morning, ladies and gentlemen, and welcome to Laredo Petroleum, Inc. Second Quarter 2014 Earnings Conference Call. My name is Ryan. I will be the operator in the event today. [Operator Instructions] As a reminder, this conference is being recorded for replay. Now it's my pleasure to introduce Mr. Ron Hagood, Director, Investor Relations.

You may proceed, sir..

Thank you, Ryan, 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; and Dan Schooley, Senior Vice President, Midstream and Marketing; as well as other -- as well as additional members of our management team.

Before we begin this morning, let me remind you that during the today's call, we'll 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 today's news release. Also, as a reminder, Laredo reports operating and financial results, including reserves and production on a 2-stream basis, which accurately portrays our ownership of the oil and natural gas produced.

Therefore, the value of the natural gas liquids is included in the natural gas stream and pricing, not as part of oil and condensate or included in the combined liquids total.

If reported on a 2-stream basis, Laredo's barrel of oil equivalent volumes for reserves and production, including initial production rates and EURs would increase by 15% to 20%, which you should keep in mind when comparing to companies that report on a 3-stream basis.

Additionally, Laredo's unit cost metrics will appear higher when compared to companies that report on a 3-stream basis. However, the economic value is the same. Earlier this morning, the company issued a news release detailing its financial and operating results for the second quarter of 2014.

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'll now turn the call over to Randy Foutch, Chairman and Chief Executive Officer..

Thanks, Ron, and good morning, everyone. I'd like to thank you for joining Laredo's Second Quarter 2014 Earnings Conference Call.

In the second quarter, Laredo made meaningful progress on our plan to tradition -- to transition into the efficient full-scale development of our Permian-Garden City asset and enhance our ability to realize the value from the more than 1.6 million barrels oil equivalent of resource potential that we identified to date from the initial 4 horizontal zones.

A critical component of our plan is proving our ability drill stacked laterals and complete them simultaneously to maximize drilling completion and operating efficiencies and minimize future frac impact as this vast resource becomes more and more developed.

We confirm many aspects to our plan during the second quarter, including the drilling and simultaneous completion of our first 4-stacked laterals pad, and approximately 80% of our second quarter activity was associated with multi-well pads.

We tested even longer laterals, continued to build out our infrastructure for water and fuel supply and product takeaway. And we broke ground on our water recycling facility.

We have upgraded our horizontal drilling fleet and focused our data-gathering projects to help us further optimize our completion techniques and the value enhancements per dollar spent. The movement to concentrated pad development enables us to truly evaluate the impact of any modification in completion designs with adjacent wellbores.

This reduces the variability inherent in geology across an area of more than 1,700 square miles. Additionally, since the beginning of the second quarter, we have added or committed to the acquisition of more than 9,700 net acres, approximately 7,700 which will bolt on to our existing acreage or increases our working interest in existing leasehold.

Much of this acreage is concentrated around our development corridors currently under construction and facilities -- facilitates the drilling of long-lateral horizontal wells with increased working interest. All of these factors are consistent with the plan we began working on to maximize the ultimate value of our Permian-Garden City asset.

As we've discussed before, the transition to multi-well pad drilling creates significant lumpiness to our production growth due to the timing of the production startup for each pad. Increased cycle time during the second quarter resulted in reported quarterly production to be at the bottom end of our expected range.

However, the quality of our acreage remains intact as well results, on average, continue to perform in line with our expectations.

As we accelerate into development mode, we remain focused on our plan to develop the entire resource at the highest return while also continuing to refine our drilling and completion techniques to take advantage of the newest technology. Now I'll turn the call over to Jay Still to discuss the development operations in greater detail..

Thank you, Randy. In the second quarter of 2014, we continued to accelerate activities while focusing on projects and efficiencies that are laying the groundwork to support expanded operations in the future. We completed 19 horizontal wells with an average 2-stream, 24-hour IP rate of 1,054 barrel oil equivalent per day.

A mean 30-day average IP rate is 702 barrel oil equivalent per day and an average oil cut of 75%, again, confirming the quality of our acreage. 15 of the wells were drilled as stacked laterals on 5 multi-well pads.

One of these was our first 4-stacked lateral targeting the Upper, Middle and Lower Wolfcamp and Cline zones, which produced a total 30-day average IP rate of 2,653 barrel oil equivalent per day.

As we completed our first 2 extended long laterals targeting the Upper Wolfcamp and Cline zones, these wells were drilled as 2-stacked laterals, with the Upper Wolfcamp and Cline zones producing 30-day average IP rates of 1,155 barrel oil equivalent per day and 1,463 barrel oil equivalent per day, respectively.

We will continue to monitor the performance of the extended long laterals and evaluate them for consideration in our 2015 drilling program. Our continuous acreage position in production corridors allow us the ability to extend long-lateral lengths and drill continuous lengths of multi-stacked horizontal wells.

Wells drilled as stacked and adjacent laterals continue to perform well, with the 16 Wolfcamp wells performing in line with our type curve on a BOE per day per 1,000 foot and the 3 Cline wells, all above expectation at an average of 121% above-average type curve on a BOE per day per 1,000 foot.

The Middle Wolfcamp is around 500 to 600 feet in thickness over our development area, and we have had success with multiple landing points within the zone. We are optimizing the landing points and may eventually support the need for more than one lateral well within the zone to effectively drain the resources in place.

We've invested in outside resources this year to help us accelerate moving to best drilling and completion practices. This is a short-term impact on 2014 G&A that has resulted in a 7% to 25% improvement in drilling times year-to-date over 2013 performance and an improved overall completions efficiencies.

We've already seen a positive return on this investment. This has been driven by operational improvements and pad drilling efficiencies. We have also improved our completion efficiencies and savings through the increased numbers of zipper fracs. The cost reduction will probably offset by the upward pricing trend and completion services materials.

Over that last quarter, we've seen an increase in pricing and greater competition for completion crews. As a result of this, our inventory of vertical wells waiting on completion has increased and as we have focused on keeping the higher rate of return of horizontal well inventory to a minimum.

This is a factor resulting in some of the delayed productions for the year. This year, we are rapidly transitioning into full development of our significant resources through pad drilling in the 3 Wolfcamp zones and Cline formation.

This has allowed us to bring in -- testing different completion techniques to further optimize our well rates and recoveries. We're experimenting with higher-strength proppants, resin-coated sand, engineered fracs, coiled tubing fracs, utilizing greater sand concentrations and more perforated [ph] clusters.

We've also invested in additional formation valuation dated to better understand rock mechanics along the lateral wellbore, which include production logs, tracer surveys to ultimately improve the effectiveness of our stimulations. This will take time for well performance data to identify optimal techniques.

It is extremely important to make this type of investments early. It is anticipated that the results will ultimately lead to improve rates and ultimate recoveries. We're currently operating 7 horizontal rigs, with most drilling stacked laterals on multi-well pads.

As you may recall, our 6 and 7 fit-for-purpose horizontal rigs were was delayed about 3 months earlier in the year. We mitigated some of the resulting production delays by predrilling intermediate sections of a number of wells.

The rig delays, along with cycle time delays, are driven by the tight pressure pumping market in the Permian Basin and has resulted in a lower production guidance for 2014. The increase in cycle times are pushing some of our expected production increases into 2015, but actual well performance has delivered as expected.

Our lower production guidance builds in a completion schedule that includes longer times from rig released to first production than we had previously anticipated.

Given the competitive pressure pumping environment, we have entered into a long-term agreement with a major stimulation service provider that, we believe, can provide us with the consistency of crews and logistics strength to offset demand pressure in the spot market.

Since the beginning of the second quarter, we have acquired or signed agreements to add more than 9,700 acres to our Permian-Garden City acreage position. The majority of the additions are either bolt-on acquisitions or increases in working interest of existing leaseholds.

The new leases added approximately 280 gross long-lateral horizontal drilling locations in more than 140 million BOE, an increase of nearly 10% to our existing resource base. The significant advantage of these acquisitions is to fill the gap and extend our leasehold to give us even more contiguous acreage position that's under development.

We will continue to selectively add acreage that is accretive to our development efficiencies, such as these.

Production corridors are a key part of our Garden City manufacturing process as they allow for oil, gas and water movement off the pads and process high- and low-pressure gas back on the pads for artificial lift and rig fuel, as well as recycle water back on location for completions.

At this time, I'd like to turn it over to Dan to discuss our corridor development in more detail..

First, centralized gas compression increases the run time of the compression utilized for the gas lift system, which reduces downtime and makes production more predictable. Secondly, this system eliminates rental compressors for individual wells, saving $2,000 per well per month.

The third system on the corridor to start up in the second quarter was a rig fuel supply facility. This system supplies natural gas for dual-fuel drilling rigs, partially displacing the use of diesel. As we begin to utilize dual-fuel rigs in the corridor, we expect the capital savings to be approximately $75,000 per horizontal well.

The 3 remaining production corridors, ranging from 3 to 6 miles in length, are in various stages of completion.

One corridor will support development drilling in Southern Glasscock County, one in Southern Glasscock, Northern Reagan County, and the third is in southern portion of our acreage in Reagan County and will be expanded into an area where, as Jay indicated, we recently committed to lease agreements for acreage that blocks up the high working interest area.

The 3 additional corridors combined are designed to handle approximately 740 future horizontal wells. As we have previously discussed, LMS has entered into a firm transportation commitment on Medallion pipeline for transportation to Colorado City. This will connect our acreage directly to Colorado City, bypassing the already congested Midland market.

From Colorado City, we have the option to access more liquid in premium markets in both Cushing and the gulf coast, which, year-to-date, would have yielded a price increase of approximately $4 a barrel.

The pipeline is expected to be operational at the end of 2014, and we have firm transportation of 10,000 barrels of oil per day on Medallion, increasing to 30,000 barrels per day in 3 years. With that, I'll turn it over to Rick Buterbaugh..

Thanks, Dan. As detailed in this morning's news release, we reported adjusted net income of $19.4 million or $0.14 per diluted share.

Adjusted EBITDA was approximately $118 million, an increase of approximately 6% from the first quarter of 2014 after adjusting for the $76 million benefit associated with the unwinding in the Brent-based derivative contract during the first quarter.

Total average daily production was a company Permian Basin record of 28,600 barrels of oil equivalent per day, an increase approximately 13% from the prior year quarter and up 6% sequentially from the prior quarter.

Total oil and gas sales of approximately $183 million were up nearly 6% from first quarter of 2014 due to higher oil and gas volumes, coupled with a 3% increase in realized oil prices that were partially offset by an approximate 14% drop in realized gas prices.

Total lease operating expenses of approximately $20 million in the second quarter was down 7% from the first quarter even as production volumes rose and resulted in an approximate 14% reduction in unit lease operating cost to $7.74 per BOE on a 2-stream basis.

The primary driver of this decrease was reduced workover activity, which was the result of the preventative interventions that we performed in early 2013.

We do expect workover cost to increase slightly in the third quarter as we proactively continue this maintenance program, which we believe can further reduce our well failure rate, thus not only reducing future cost but provides better run time on our existing wells.

Cash, general and administrative expenses of approximately $23 million were essentially flat with the first quarter end [ph] and decreased more than 7% on a unit basis.

The non-cash portion of G&A, primarily related to stock-based compensation, increased approximately $2 million, reflecting new grants for existing and newly hired employees, which vest over various terms of up to 4 years. Quarterly Midstream Service expenses increased approximately $700,000 sequentially in the second quarter of 2014.

The increase primarily relates to startup cost for LMS gas and water handling systems. We do expect these costs to increase in the third quarter, as detailed in the guidance included in this morning's news release, and they will begin to decrease on a per unit basis as we increase the utilization of the LMS system.

We expect the cost to be more than offset by enhanced realizations, as Dan described, and increased uptime for our wells. Capital expenditures for the first half of the year have totaled approximately $466 million, excluding acquisitions. We now expect to accelerate slightly expenditures on pipeline infrastructure to support our ongoing development.

In addition, we have expanded the scope of some drilling and completion activities and are beginning to experience pressure on some of our service cost. As a result, we now anticipate total capital investments in 2014 will be approximately $1.1 billion, exclusive of acquisitions.

At the end of the second quarter, we had cash-on-hand of approximately $400 million and 100 -- and an undrawn senior secured credit facility with a borrowing base and elected commitment of $825 million, resulting in total liquidity of more than $1.2 billion. At this time, Ryan, we'd like to open the call for any questions..

[Operator Instructions] Our first question comes to you from Brian Singer with Goldman Sachs..

Just trying to further juxtapose the strong well results relative to the more muted production expectations as it seems like you're highlighting completion delays that are pushing out cycle times here. And then I just had a couple of questions on that.

Are -- is there any impact that you're seeing at all on decline rates for horizontal or vertical wells versus your expectations? And then can you just talk about what cycle times you were building in, what you're seeing now and then what you're building in going forward?.

Yes. Brian, as far as well performance, our wells really have done quite well. Second quarter wells are right in line or above expectations on the 24-hour IP, more importantly 30-day, and more importantly as the wells continue to produce.

So we're very pleased with the well performance, the cycle time that we've run into mainly due to the pressure in the pumping service market in the Permian Basin.

We had long-term providers who'd been working with, lost one of them last quarter that threw us into the spot market and really caused inventory build in our horizontal wells and our vertical wells.

Subsequently, this quarter, we worked down that horizontal inventory build to a minimum, and -- but the vertical inventory, we have not been able to work down in the current market. It's just difficult to find pressure pumping service that will frac vertical wells.

There's so much demand in the horizontal wells that it's hard to find companies who will spend any time with you on vertical wells. So we're -- that's really one of the drivers in the cycle time build. We have contracted services in the third quarter to help us reduce that inventory.

We've included this in our models going forward as more conservative assumption of rig release to put on production time that we think we can -- we'll be able to meet by the end of the year..

Okay.

And then the combination of the cycle time and the services contracts that you mentioned you signed, does that have any impact on either CapEx or on your long-term production growth outlook, I think 30% to 35%?.

It has an impact on production growth output. The prices are -- completion prices are going up, and we've made a lot of progress in improving our drilling time. As I mentioned, it really improved our cycle despite the rig release time on all zones and vertical wells, significantly.

For the drilling side, we feel pretty comfortable with the completion side as we're getting a lot of price pressure and we've seen in last quarter, along with about 12% increase in pumping service cost.

So we're -- that's why we've entered the -- a longer-term relation with a major pumping service provider so that we can -- they have people in our offices that we can do a better job planning and allowing for the increases and decreases of service that are required as we bring on pads mark-to-market..

Next, we have Ryan Oatman with SunTrust..

Historically, you've been hesitant to pay in acquisitions over a $1,000 an acre.

Can you describe how your thought process is changing? And what made these acquisitions in this time in your history compelling enough to pull the trigger?.

I don't know that we've had a $1,000 an acre kind of a hard number. What we've said is that we needed to make sure that what we were acquiring was equivalent in value to -- and added to what we already had. The 7,700 acres that we picked up are -- that's an area that we know we have 4 proven resource potential kind of horizontal targets to drill.

We think there may be other upside. So it was -- it blocked out our acreage some, but it also increased our average working interest. As you know, we enjoy a pretty high working interest.

So in this case, it clearly was value added to pay the price, and we felt like it -- not only was it -- it's pretty good acreage, as good as we have, but it also allowed us to extend production -- a production corridor, which will have benefits for years to come..

Very good. And then a much more granular follow-up.

What was the average lateral length for your 4-well stacked test?.

There were about 7,300 foot probably on average..

Next is Gil Yang with DISCERN..

Do you have -- can you provide the 30-day rates for the 9 3-stacked laterals in the 4 single-zone wells?.

I'm looking around the table, Gil, and I'm not sure if we have that here..

Okay. I can follow up later if you can get that. If I look at the 4-stacked well's performance, it's a little bit below that 700 average if you take out the longer laterals. Or is it -- as far as that based on the numbers you gave.

Is there any sort of concern that the stacked laterals are showing interference between the different zones? Or what are you seeing in terms of frac-ing into adjacent zones?.

As I mentioned in the discussion, the Middle Wolfcamp is really exceptional. We have landed in a different take-point in that Middle zone. In the stacked lateral, we'd landed the well towards the upper part of the Middle, probably 280 feet from the Upper completion. We did see -- we have seen some production interference from that Middle and the Upper.

The Upper has performed lower. Middle has actually performed better. So we are seeing interference between the Middle and Upper depending on where we land the laterals. But we've gotten really good results, and we have landed the lateral -- or more separation away from the Upper, where we don’t see interference. And that's why I've mentioned it.

At some point, we may have to be putting more than 2 take-point laterals in that Middle formation because it's -- because of its thickness and because of optimally draining our resource there..

In other words, when we moved up to the top of the Middle Wolfcamp with the landing point, we did see, we think, some changes in the landing point with the Upper or interference. But the good news as Jay says, the Middle has got -- is pretty thick, and we actually have more than one choice of where to land within that. So we....

So the Middle is not interfering with the Lower? And is there any indications that Lower is interfering with the Cline or vice versa?.

No. The Middle is not interfering with the Lower, and we don't -- keep in mind, the Cline is separated by another shale package from the Lower. So we're pretty comfortable with all the data that we've acquired and the work we've done on the simulation.

We understand what caused the little interference that we've seen, and don't view that as really anything significant..

Okay.

So you can -- at worst, you can just move the landing zone in the Middle, just a little bit lower to avoid that? At best, you can put stacked -- you can put 2 laterals in there?.

land the Middle Wolfcamp a little lower and not see any interference..

Okay. And then last question is just, you -- in the last quarter, you gave guidance on a number of completions you anticipated. Can you -- it sounds like 20 for the third quarter.

How many are you anticipating now for the fourth quarter?.

Fourth quarter or...

Third quarter?.

Third quarter, you said 20, I think.

But what's the number for the fourth quarter?.

I don't have the number right in front of me. I think it's about -- it's closer to same, maybe a couple less, maybe around 20 -- 17 to 20..

Okay, great..

And the 20 completions that we've identified in the third quarter, those are the ones -- I mean, there may be additional completions at the end of the quarter that really won't have any impact on that third -- those third quarter volumes.

So the 20 completions relate to the ones that we believe will be completed, cleaned up and contributing actual identifiable volumes in the third quarter..

Next is the Bob Brackett with Bernstein Research..

I had a question on the stacked laterals. When you talk about these 4-stacked laterals, they are not flowing through a single vertical wellbore.

There's 4 separate vertical wellbores?.

That's correct. What we've done is set up on a pad, drill the vertical part and the horizontal part, skid the rig, walk it, whatever, 25 feet, drill another vertical well and horizontal..

But why not just -- if you know the Upper Wolfcamp's the better EUR, why not hit that Upper Wolfcamp 4x instead of scatter across 4 different quality zones?.

There's a number of reasons that we've talked about, Bob. One of them is what we just talked about. We're fairly confident that if we go through there and complete the 4 zones or 3 in the Wolfcamp, we really minimize any chance of frac interference.

There's an argument that if you just complete the Upper then try to come back in some period time, years or whatever, after that you will not have as effective the frac in the Middle or the Lower simply because of a little more pressure depletion. And we -- some people are seeing that. So there's a number of reasons, operationally, also.

We can set up -- we have the ability to frac 4 zones. We've got the water capability. So we can move everything we need in on that pad, drill the wells, zipper frac them all back-to-back. That's efficient reservoir engineering process. It's very efficient, operationally, too, and we're set up to do that..

You're not doing it to hold acreage, right of deepest capture. It's nothing around that.

It's just purely the engineering side?.

Purely the economics of doing it all at one time with the efficiencies you get in the frac and the reservoir engineering parameters. Our acreage position, we can -- we're 60-plus percent held by production. I don’t have the exact number here. And we can hold our acreage position by just running 4, 5, 6 vertical wells for another couple of years.

So we do have some continuous drilling obligations that we pay attention to, but we're effectively drilling horizontal wells. They do help us occasionally, but the -- held by production is not an issue..

And does it help you frac [ph] the wells better? If you got basically the same earth model, you can land those 4 wells and you've got a pretty good view of the geology?.

Exactly. Keep in mind, we've got great 3D, which we use a lot. We also have a pretty good set of well log -- enhanced well log that others apparently don't have. We have a lot of core information. And then we've done a lot of single-zone testing. So we've got a pretty good database that's helping us figure out what we need to do..

So for example, if you saw a fault on one of those laterals, you could update your geosteering for the other 3 to kind of avoid it?.

If the decision was to avoid it, yes. We do take what we get from each well, flip it back through our database in 3D and other database pretty quickly..

Next is Ipsit Mohanty with JPM Security [GMP Securities]..

It's actually GMP Securities.

When I look at your longer lat, I'm just curious to know how are you going to -- and I apologize if I missed this, but can you give sort of a guidance of the percentage, the proportion of long laterals you plan on doing in '15? And then in any association with that, how -- I'm curious to see how you're going to apply the pressure tack [ph] in terms of your 2, 3 and 4 well stacks as you go ahead in '15..

We've been -- I mean, we started drilling our horizontals to go back in 2008 and '09 or over 2010, and we were drilling very -- 4,000-foot 10-stage. And we pretty quickly saw that 75 longer laterals was better. And we're still in the optimization process.

We think early in the optimization process for completion, which is one reason why we're gathering all the data we have. Our view is that it takes significant production data to know what really optimizes that -- just a 24-hour IP. And I think, Jay mentioned, we have drilled 2 roughly 10,000-foot laterals.

And the early indications were that that's something we need to very carefully look at. So one thing that I will say is that on most of our acreage, we're set up and blocked up. We're building our production corridors, and we're -- we have the capacity to drill longer than 7,500-foot laterals if we think that's the best economic link for us to drill.

Obviously, it costs a little more, and I guess there's a little more mechanical risk. But we're set up such that we have the optionality and the acreage base to drill the 10,000-foot laterals over the 7,500..

Okay. And then my follow-up is basically more of a strategy question. If I look at the side that -- it seems to me like your drilling completion program is bordered around your production corridors. I'm just wondering then what's the motivation to go and delineate the northern part of your acreage.

Or is it going this time [ph] 3 various zones versus that you're going [ph] up and developing around the production corridor system.

So would you do -- go ahead with those programs? Or would you do similar acquisitions that you just did?.

I think -- if I understood all the question, I'll try and answer you. We've allocated about 10% of our budget to other zones and to additional acreage outside of the area that we called de-risked. Within the area that we de-risk, as we said earlier, we've got something like 1.6 billion barrels of oil equivalent to look at.

So our -- the acquisition that we announced was in a production corridor. It just allowed us to extend it -- some. It helped block up some additional acreage. And those are the kind of things that we'll do. And we'll just roll that acreage into our current plan to continue drilling within the production corridor.

Jay, do you want to add?.

I mean, those -- if you look at those on the map on the presentation, you can see how it really fills in the gap and it allows us to drill 7,500-foot or 10,000-foot laterals as we chose, as compared to a single section that we kind of limit to the 4,000-foot lateral..

Got you.

Did the Bakken -- did the small blocking -- it didn't [ph] have to come as a package? Or are there any plans to develop there?.

That came as a package, but we also see that area as a prospective area that we'll be evaluating..

Next up is Brian Gamble from Simmons & Company..

A couple of questions. One, you're trying to alleviate the pressure pumping delays by signing the agreement, obviously, a good step moving forward.

The length of that agreement that you signed and -- how much of the -- of your prior [ph] pressure pumping needs on quarterly basis does that cover?.

The length of -- what we've done with the company is pretty much put in an evergreen-type of contract. The terms can float with market conditions up or down. So that we're not trying to bid out a package of wells at a time. What's really important about that is it comes down to the crews that are actually performing the work.

And that's where your real efficiency comes in. And having consistent crews on a long-term basis could really improve the cycle times just from producing and then becoming more efficient with each job.

So the other benefit of that is that they've got engineers in our office that's funded [ph] to the company that we can plan out further in advance the next 2 to 3 months of work from the rig schedule and plan on additional crews as needed when -- say, we have 2, 3 or 4 well pads, finish drilling at the same time, you're going to need 2 crews instead of 1.

And we can better plan for that. So all of that, we think, can greatly reduce cycle times..

Great.

And then does that -- I guess, my question originally was going to be, does it -- does the inability to get vertical wells completed make you rethink the vertical strategy moving forward or reduce it at all? But does that agreement alleviate the need to go down that path and rethink total horizontals versus total wells in a given quarter or given year?.

Well, our vertical wells are drilled primarily to hold the acreage position, again. We've got about 2 more years running 4, 5 vertical rigs, and that drops off exponentially as we move into 85% of our acreage held by production. So we -- the vertical wells have to be drilled just to hold the acreage positions together.

But we do have plans and contracted companies to come in that can reduce that inventory. But that's not more. That's like in a couple of weeks so that inventory will build. I think that will continue to be a challenge for us.

And it's just the question and you -- do you delay the production or do you sell with money [ph]? So that's going to be a tightness in the market going forward..

And then on the acquisition, just looking at the slide, there's the few acres over in nearion [ph].

Does that -- were those acres part of something you bought and Reagan? Or was that area in acreage purchased separately and intentionally?.

That was a package deal, and there is some potential on that acreage. We haven't counted it in well counts. Or we haven't counted it in resource potential. In terms of us going after it today, it does add potential, I think, but we're not going to aggressively be going there..

Next is Mike Kelly with Global Hunter Securities..

On the cycle plans, it's -- looking at your slide deck right now you've got on Page 31, you've got what you've budgeted in terms of days. I think you've got 15 days budgeted from rig release to the start of completions and 18 days to frac. And maybe you could just quantify some of these delays that you've seen, what kind of your actual times were.

And then with this new long-term service contract, how quickly do you think you can get back to these budgeted times?.

I'll let Jay give you specific details, but just to clarify 31, that's as much as anything in the intent to show what the efficiency gain is from drilling a 4-stacked lateral versus having 4 wells drilled, scattered across the acreage. And it shows the -- how you minimize the rig moves and those kind of things.

Do you want to talk about cycle?.

Yes, I think -- I'll tell you here's the data from our 4 well, stacked pad as compared to what you see on this page. The -- we -- in actuality, our first 4 wells took 15 days longer than what is laid out on this chart, at 15 days, was due to delay in frac company getting on location a couple of days.

We had a couple of days downtime with wellhead issues, getting 4 wellheads rigged up and manifolded for a combination zipper frac. We frac-ed all of those wells, essentially, simultaneously, and then getting those everything moved off. So that comes from -- this is the first time we ever did a 4-stacked well and missed it 15 days.

I think that's the importance of having consistency of completion crews as they learn along with us with how to become -- more efficiency, reduce unproductive time and, therefore, reduce total cycle time..

And just on the longer laterals, just maybe if you could frame this in terms of what you ultimately think the -- I know it's early, but the ultimate economic uplift that you could potentially see from going to a longer lateral program. I think you've got about 50% rate of return, kind of a $90 oil for a 4-stacked pad with 4 wells on it.

What do you think that ultimately could be? I'm trying to get this -- potentially, a meaningful, kind of game-changing type deal if we've got all the longer laterals because those 30-day rates look really good..

Yes.

And not to avoid the answer, but I think it's way too early for us to even internally to be thinking about -- we have the ability to adjust our drilling program in terms of our acreage, in terms of our production corridor, in terms of rigs we have, but we'll need to see longer performance data than we have before we make those kind of decisions and arrive at those kind of answers..

Next is David Heikkinen with Heikkinen Energy..

And you guys have hit a lot of the operating side. What I was thinking through is the next couple of years. You have plenty of cash on hand and borrowing capacity.

I wanted to talk about how your borrowing base grows and really how your cash flows grow given your outspending a lot this year, just really trying to think about how you think about the multiyear financing of the company, either Rick or Randy..

Yes, David. On the -- we do have significant cash on hand. We've got our credit facility. We have actually elected to limit that at $825 million to date. It actually has a full borrowing base and a borrowing capacity based upon our 12/31/13 reserves, up $1 billion.

We didn't -- certainly didn't anticipate and still do not expect to need that or access that this year. So we did not want to pay for it. So we limited it at $825 million.

We have a semiannual redetermination to our credit facility, which takes into account an update our borrowing base based upon the drilling activities that have taken place since last redeterminations. So we do have the redetermination that's coming up in October.

That will include then the drilling activities that have taken place in the first half of 2014. We'd anticipate that, that $1 billion borrowing base that they have granted us to date would be expanded.

At the appropriate time, we will likely increase the elected capacity or the elected commitment as that borrowing base expands but don't see the need for it today. Right now, looking forward, we see our liquidity certainly towards any outspend that we would have in 2014 and anticipated in 2015. So we're covered at least over the next 18 months now.

We're obviously going to make sure that we maintain significant liquidity at the company. We make sure to -- we guard against damaging that with significant hedge positions. But overall, our philosophy is that we do have very strong economics on these wells.

We need to accelerate the recognition of the value associated with them, and we'll do so appropriately, which means that we'll likely outspend cash flow. This year, we had anticipated we'd outspend cash flow by about $500 million. We prefunded that with some capital raised last year and the debt offering that we put in place in January.

We will go a little bit beyond that with the announced acquisitions that we've talked about. But that's incorporated into our expectations for overall capital spend and net outspend that we will have. And when I'm talking about the liquidity being sufficient for the next 18 months, that's taken into account.

I would anticipate -- and obviously, we're working through our 2015 budget and looking at things, such as what type of wells and the lateral lengths that we're going to be drilling and what's the cost of that and potential savings. The outspend would likely be somewhere in the range of $500 million or so.

So on a -- but that's going to be flexible as far as what the projects we have. The overall goal is that we're going to be able to self-fund a greater and greater percent of our capital expenditures on a year-over-year basis, excluding those strategic acquisitions or selective acquisitions that we think benefit our overall acreage position..

Next is Richard Tullis with Capital One..

Randy, going back to acreage acquisition that was in the release, was there a range of cost paid for this acreage? If so, where and how much was the higher cost acreage?.

The way we -- Rick, we went about that internally. We kind of high-graded what we thought about the acreage. But in terms of approaching the seller, we did it on a uniform basis. We didn't differentiate..

Okay. Going back to the completion schedule for the horizontal wells, I know you touched on what you expect and now for the third quarter.

Is the fourth quarter still kind of matching up with what you had at the last update, 20 to 25 wells in the fourth?.

Yes, it will be in that range. You may have missed the comments earlier that the 20 wells that we expect to complete in the third quarter, those are the wells that we actually think that we'll be able to add -- that will be completed in time during the quarter that would really have -- be able to add noticeable volumes in that quarter.

Our overall number of completions for the year has really not changed..

Okay.

And then just lastly, what was the cost for those extended lateral wells, the 2 that were mentioned in the release?.

They were right at $9 million..

Next is John Herrlin with Societe Generale..

Most things have been asked, but I just wanted to clarify some things.

In terms of the second half production reduction, percentage-wise, what was vertical versus horizontal in terms of this play?.

We're -- John, I'm going to have to get back to you on that. I don’t have the split with me..

Okay, that's fine. With respect to the production corridors, as you started up and build gas lift systems and all of that, these things generally just don't start immediately.

Given -- does that slow some of your output growth, too, as you're bringing these pads on because you're bringing on the systems as well? Can you address that?.

John, this is Dan Schooley. The systems were in place and capable of handling the production. So I don’t think it had any impact on slowing down -- slowing the production growth..

Okay. And lastly, you had a lot of completion-design-type questions as well.

Have you been watching or following or trying the more sand or greater frac density approach that we're hearing so much about from many of your peers? Are you looking at that, as well as also doing yourselves [ph]?.

Yes, we are, John. We've got a range of things we're trying, including different proppants, greater sand concentration, more clusters. We're trying to create more frac density around the wellbore, more complexity around the wellbore.

We've got a number of those tests that we've done, and the nature of these -- it takes a while to really understand the results -- incremental results of the investment on the return. So we really need 6 to 9 months of production to understand if we're being successful with the things we're trying or not..

You also mentioned that you might be using ceramics as well as part of this approach?.

In the modeling work that we've done, we've shown that it would just -- light sand or extra [ph] brown sand, you lose connectivity -- conductivity through time pretty substantially. And we've done a couple of wells with ceramic- or resin-coated sand. Early results were really good.

But of course, you really -- before we change to that program, you're adding about $3 million a well with ceramics. So you really -- we really want to make sure that is an incremental positive return on that investment..

Next is Matt Portillo with TPH..

Just one quick question from me. You mentioned -- and I know you guys have done a great job of getting in front of logistics at the field level, particularly with some of the initiatives you have on water systems, et cetera.

I was curious, as you guys think about the service market and some of the tightening you're seeing on the pressure pumping side, some of your plans you're putting in place to make sure you secure capacity on the rig front in order to accelerate development.

And I guess the second question, as the industry continues to accelerate the use of proppants, how you guys are thinking about the logistics of potentially getting in front of any bottlenecks that may occur on that front?.

On the rig front, we -- hitting the market right now for a spot rig or horizontal walking rig is pretty much 0. We have arrangements next year to bring additional rigs as new build rigs for the queue for those deliveries. So that's how we're looking at our -- playing our rig business has got to be 1 year out ahead of that.

As far as profit, that's one of the reason we signed a long-term agreement really -- evergreen agreement with a large completion pumping service company that has the logistic strength to minimize the delay or shortage and profit that we would see working directly with the proppant supplier to secure that profit well in advance.

So all of those kind of things, we're trying to take those risks -- execution risk off the table..

We have no other question in the queue. So I'll pass it back to Mr. Ron Hagood for any closing remarks..

Thank you, Ryan. In the next month, we'll be presenting at 2 upcoming conferences, EnerCom's Oil & Gas Conference on Monday, August 18, at 3:10 p.m. Mountain Time; and Barclays CEO Energy/Power Conference on Tuesday, September 2, at 1:05 p.m. Eastern Time.

Also, we will release our third quarter 2014 earnings on the morning of November 6, and host a conference call that morning at 9:00 a.m. Central Time. Thank you very much for joining us for our second quarter earnings call..

Everyone, thanks for your time and your participation, and have a great rest of the day..