Vital Energy Inc (VTLE) 2014 Q2 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Laredo Petroleum's Incorporated second quarter 2014 earnings conference call. My name is Ryan and I'll be the operator for 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 is 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, forecast, and assumptions, are intended to be covered by the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. The Company's actual results may differ from these forward-looking statements for a variety of reasons, many of which are beyond our control.

In addition, we 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 two-steam basis is 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 are included in a combined liquids total.

It reported on a two-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 company's that report on a three-stream basis. Additionally Laredo's unit cost metrics will appear higher when compared to companies that report on a three-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 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 of oil equivalent of resource potential that we've identified to date from the initial four horizontal zones.

The critical component of our plan is proving our ability to drill stacked laterals and complete them simultaneously to maximize drilling completion and operating efficiency and minimize future frac impact as this past resource becomes more and more developed. We confirmed many aspects to our plan during the second quarter including the drilling and simultaneous completion of our first four-stacked lateral pad and approximately 80% of our second quarter activity was associated with the multi-well pads.

We tested even longer laterals, continue to build out our infrastructure for water and fuel supply, and product takeaway and we broke ground and our watery recycling facility. We have upgraded our horizontal drilling fleet and focused our data gathering products 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 modifications in completion designs with adjacent well bores.

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 or approximately 7,700 which will bolt-on to our existing acreage or increases are working interest in existing leasehold. Much of this acreage is concentrated around our development corridor is currently under construction and facilitates the drilling of long lateral horizontal wells with increased working interest. All of these factors are consistent with the plan we've begun 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 start up 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 the 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 continue 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 two-stream, 24 hour IP rate of 1,054 barrel of oil equivalent per day. A mean 30-day average IP rate of 702 barrel of 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 five multi-well pads. One of these was our first four-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 of oil equivalent per day. As we completed our first two extended long laterals targeting the upper Wolfcamp and Cline zones. These wells were drilled as two-stacked laterals with the upper Wolfcamp and Cline zones producing 30-day average IP rates of 1,155 barrel of oil equivalent per day and 1,463 barrel of oil equivalent per day respectively.

We will continue to monitor the performance of the extended long laterals and evaluate them in consideration in our 2015 drilling program. Our continuous acreage position and production corridors allow us the ability to extend long lateral lengths and drill continuous lengths at multi-stacked horizontal wells. Wells drilled as stacked in adjusted laterals continue to perform well with the 16 Wolfcamp wells performing in line with our tight curve on a BOE per day per 1,000 foot and the three 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 the moving to best drilling and completion practices.

This is a short-term impact on 2014 G&A but has resulted in a 7% to 25% improvement in drilling times year-to-date over 2013 performance and an improved overall completions efficiencies. We have already seen a positive return on this investment this has been driven by operational improvements in pad drilling efficiencies. We've also improved our completion efficiencies and savings through the increased number of zipper fracs, but the cost reductions will probably be offset by the upward pricing trend in completion services and 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 completion has increased and as we have focused on keeping the higher rate of return and horizontal well inventory to a minimum. This is a fact resulting in some of the delayed production for the year.

This year we are rapidly transitioning into full development of our significant resource --resources through pad drilling and the three Wolfcamp zones and Cline formation. This has allowed us to bring in different -- testing different completion techniques to further optimize our well rates and recoveries. We're experimenting with higher strength proppants, resin-coated sand, engineered fracs, coil tubing fracs, utilizing greater sand concentrations and more (inaudible).

We've also invested in additional formation evaluation data to better understand rock mechanics along the level of well bore which include production wells, tracer surveys, to ultimately improve the effectiveness of our stimulations. This will take time for well performance data to identify optimal techniques as it is extremely important to make these type of investments early.

It is anticipated that the results will ultimately -- to improved rates and ultimate recoveries. We are currently operating seven horizontal rigs with most drilling stacked laterals or multi-well pads. As you may recall, our six and seven Fitrah purpose horizontal rigs were delayed about three months earlier in the year. We mitigated some of the resulting production delays by pre drilling intermediate sections of a number of wells.

The rig delays along with cycle time delays have driven by the tight pressure pumping market in the Permian Basin 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 release 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 the logistic 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 leasehold.

The new leases add approximately 280 gross long lateral horizontal drilling locations and 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 continuous 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 processed 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.

Thank you Jay. Laredo midstream services, or LMS, has continued to make additional investments in our Garden City infrastructure to facilitate the production and sales of the Company's crude oil and natural gas and is currently building out core production corridors three of which are partially in service. The first production corridor, approximately 7 miles long, is now almost fully operational. As you may recall, we commenced operations at low pressure natural gas gathering in this corridor during the first quarter and we are currently gathering 11 million cubic feet a day.

This system allows us to maximize field production by isolating our high-volume, higher pressure, horizontal wells from the lower pressure vertical wells on the legacy poly gathering system. Just so we utilize our corridors to move oil and gas off our leases we also use them to feed natural gas to our gas-lift and rig-fuel facilities in the corridor.

In the second quarter, three additional systems commenced operations. The oil gathering pipelines, centralized gas-lift, and rig-fuel supply. Oil gathering pipelines are currently delivering approximately 6,000 barrels of oil per day and facilities are being expanded to accommodate up to 15,000 barrels of oil per day. The oil gathering pipelines eliminates the need for truck transportation more reliably and safely delivers oil to sales while providing a $0.95 per barrel uplift in our realize pricing.

Centralized gas-lift facilities system also begin operation during the second quarter and to date, 16 horizontal wells have been tied into the facility. The benefits of this are two fold. First, centralized gas compression increases the runtime of the compression utilized for the gas lift system which reduces downtime and makes production more predictable.

Secondly, this system eliminates compressors for individual wells saving $2,000 per well per month. The third system on the corridor started up in the second quarter was a rig-fuel supply facility, This system supplies natural 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 three 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 the 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.

Three 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 and premium markets in both Cushing and the Gulf Coast which here, to date, would have yielded a price increase of approximately $4.00 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 three 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 of the Brent-based derivative contract during the first quarter.

Total average daily production was a company and 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 her proximally $183 million were up nearly 6% from the 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 costs to $7.74 per BOE on a two-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 costs but provides better runtime on our existing wells. Cash, general and administrative expenses of approximately $23 million were essentially flat with the first quarter expense 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 four years.

Quarterly midstream service expenses increased approximately $700,000 sequentially in the second quarter of 2014. The increase primarily relates to start up costs 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 costs 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 costs.

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 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)

Brian Singer, Goldman Sachs.

Good morning Brian.

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

Is there any impact that you're seeing at all on decline rates were 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. 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 times that we've run into mainly due to the pressure in the pumping service market in the Permian Basin. We had a long-term providers who'd been working with. Lost one of them last quarter that threw us into the spot market and really caused an inventory build in our horizontal wells and our vertical wells. Subsequently this quarter we've worked down that horizontal inventory build to a minimum but the vertical inventory we have not been able to work down. And in current market it's just difficult to find pressure pumping service that will [frac] in vertical wells.

There's much demand in the horizontal wells that it's hard to find companies who'll spend any time with you on vertical wells. So 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. A much more conservative assumption of rig release to put on production time that we think we will be able to meet by the end of the year.

Okay. Thanks. And then did the combination of the cycle times 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%.

I don't think it has an impact on production growth output. The prices -- completion prices are going up and we've made a lot of progress in improving our drilling time as I mentioned. Really improved our cycle spud-to-rig release time on all zones and (inaudible) wells significantly. With the drilling side we feel pretty comfortable with the completion side, as we're getting a lot of price pressure we've seen in the last quarter along at about 12% increase in pumping service costs. So that's why we've entered 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 from month to month.

Thank you.

Ryan Oatman, SunTrust.

Hi. Good morning.

Good morning Ryan.

Historically you've been hesitant to pay in acquisitions over $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 $1,000 an acre 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, that's an area that we know we have four proven resource potential 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 not only was it -- it's pretty good acreage. As good as we have. But it also allowed us to extend a production corridor which will have benefit for years to come.

Very good. And then a much more granular follow-up. What was the average lateral length for your four well stacked test?

There were about 7,300 foot probably on average.

Very good. Thank you.

Thank you.

Gil Yang, Discern.

Good morning everyone.

Good morning Gil.

Do you have -- can you provide the 30-day rates for the nine three-stacked laterals and the four single zone wells?

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

I can follow up later if you can get that. If I look at the four-stacked wells performance -- it's a little bit below that 700 average if you take out the longer laterals. Or rather based on the number you gave. Is there any sort of concerned that the stacked laterals are showing interference between the different zones? Or what are you seeing in terms of fracking into adjacent zones?

As I mentioned in the discussion, the middle Wolfcamp is a really thick section. We have landed in different take-point in that middle zone. In the stacked lateral we 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 is performed lower -- middle has actually performed better.

So we are seeing interference between the middle and the upper depending on where we land the laterals but we've gotten really good results as we've landed the lateral more separation away from the upper where we don't see interference. And that's why I've mentioned at some point we may have (inaudible) more than two take points laterals in that middle formation because of its thickness and because of optimally draining our resource there.

Okay. 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 for the upper or interference. But the good news, as Jay says, the middle has got -- it's pretty thick and we actually have more than one choice of where to land within that. So, we just --

So the middle is not interfering with the lower and is there any indication that the lower is interfering with the Cline or vice versa?

No. The middle is not interfering with the lower. 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 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 two laterals in there.

I'm not 100% sure that we will put two laterals in the middle. But we do have more than one landing. We do have more than two landing points so that's set something we still have to discern going forward. But we know we can go back to what we were doing. Land the middle Wolfcamp a little lower and not see any interference.

Okay. And then last question is just in this last quarter you gave guidance on the 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 close to the same. Maybe a couple less. Maybe around 20. 17 to 20.

Okay. Great. Thanks.

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 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.

Got you. Thanks for that clarification, Rick.

Bob Brackett, Bernstein Research.

Yes. I had a question on the stacked laterals. When you talk about these four-stacked laterals, they're not flowing through a single vertical wellbore. There's four separate vertical wellbores?

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

But why not just, if you know the upper Wolfcamp's the better EUR, why not hit that upper Wolfcamp four times instead of scatter across four 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 four zones, or the three in the Wolfcamp, we really minimize any chance of frac interference.

There's an argument that if you just complete the upper, then try and come back in, some period of time -- years or whatever -- after, that you will not have as effective a frack in the middle or the lower, simply because of a little more pressure depletion. And some people have seen that.

There's a number of reasons operationally, also. We can set up -- we have the ability to frac four zones. We've got the water capability.

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 frack and the reservoir engineering parameters -- Our acreage position -- we can -- we're 60%-plus held by production. I don't have the exact numbers here.

And we can hold our acreage position by just running four or five, six vertical wells for another couple of years. 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 lengthen the wells better if you've got basically the same earth model, you can land those four wells and you've got a pretty good view of the geology?

Exactly.

Okay.

Keep in mind, we've got great 3D, which we use a lot. We also have pretty -- 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.

For example, if you saw a fault on one of those laterals, you could update your geo-steering from the other three to 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.

Great. Thank you.

Thank you.

Ipsit Mohanty, JPM Security.

Hi. It's actually GMP Securities. Good morning, guys.

Good morning.

I wanted to get your longer lat look. I'm just curious to know how you're going to -- and I apologize if I missed this -- but if you can give a specific guidance of the percentage, the portion of long laterals you plan on doing in 2015? And then in your position with that, I'm curious to see how you're going to apply the [cross year] in that stacked concept in terms of your two-, three-, and four-well stacks as you go ahead in 2015.

Yes. We've been -- we started drilling our horizontals to go back in 2008 and 2009 or over 2010, and we were drilling very -- 4000 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 completions, 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 two, roughly 10,000-foot laterals. The early indications were that that's something we need to very carefully look at.

The one thing that I'll say is that on most of our acreage, we're set up and blocked up, we're building our production corridors and we have the capacity to drill longer than 7500-foot laterals, if we think that's the best economic length 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 or the 7500.

Okay. And then my follow-up is basically more of a strategy question. Trying to decide that, it seems to me like you're drilling completion program is (inaudible) your production corridors.

I'm just wondering, then, what's the motivation to go out and delineate northern part of your acreage or even going (inaudible) zones versus that you're cording up and developing around the production corridor system. Would you go ahead with those programs, or would you reduce some of that acquisitions that you just did?

I think, if I understood all of the question I'm trying to answer -- we've allocated about 10% of our budget to other zones and to additional acreage outside of the area that we've called de-risk. With in the area that we've 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 kinds 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, anything you want to add?

If you at those -- up in the presentation, you can see how it really fills in the gap, and it allows us to drill 7500-foot or 10,000-foot laterals, as we choose, as compared to single sections we've been doing 4000-foot lateral.

Got you. But back in the small block at Irion have to come as a package, or are there any plans should have [loved that]

That came as a package. We also see that area as a perspective area that we will be evaluating.

Thank you.

Brian Gamble, Simmons and Company.

Good morning, everybody.

Good morning, Brian.

A couple of questions. One, you're trying to alleviate the pressure from your delays by signing the agreement. Obviously, a good step moving forward. The length of that agreement that you signed, and how much of your pressure pumping needs on a quarterly basis does that cover?

The length of -- what we've done with the Company is pretty much put in a evergreen-type of contract that 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. Having consistent crews on a long-term basis really improve the cycle times, just from producing and becoming more efficient with each job.

The other benefit of that is that they've got engineers in our office, sub-funded to the Company, that we can plan out further in advance, the next two to three months of work from the rig schedule, and plan on additional crews, as needed, when, say we have two, three, or four well pads finish drilling at the same time, you're going to need two crews instead of one. And we can better plan for that. So all of that, we think, can greatly reduce cycle times.

Great. And then does that -- my question originally was going to be, 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?

Our vertical wells are drilled primarily to hold the acreage position again. We've got about two more years running four, five vertical rigs, then 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 position together/

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

It's just the question -- do you delay the production, or do you salvage the money. That's going to be a tightness in the market going forward.

And then, on the acquisition -- just looking at the slide, there's a few acres over in Irion. Does that -- were those acres part of something you bought in Reagan, or was that Irion 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.

Thanks, Randy. Appreciate it.

Mike Kelly, Global Hunter Securities.

Hey, guys. Good morning.

Good morning.

On the cycle times, since -- looking at your slide deck right now, and you've got, on page 31, you've got where you budgeted, in terms of (technical difficulty) days. I think you've got 15 days budgeted from rig release to the start of completions, and 18 days to frac.

Maybe you could just quantify some of these delays that you've seen, what your actual times were? And then, with this new long-term service contract, how quickly do you think you could get back to these budgeted times? Thanks.

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

You want to talk about cycles?

Yes. I can tell you -- here's the data from our four-well stacked pad, as compared to what you see on this page. In actuality, our first four wells took 15 days longer than what is laid out in this chart.

That 15 days was due to delay in frac company getting on location a couple days. We got a couple of days downtown with wellhead issues, getting four wellheads rigged up and manifolded for a combination zipper frac. We fracked all of those wells, essentially, simultaneously. And then getting those -- everything moved off.

That comes from -- this is the first time we ever did a four-stacked lateral -- four-stacked well and missed it 15 days. I think -- that's the importance of having consistency of completion crews, is that they learned, along with us, of how to become more efficiency, reduce non-productive time, and therefore, reduce the total cycle time.

Got it. Thank you.

Just on the longer laterals, just maybe 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 on $90 oil for a four -- a stacked pad with four wells on it. What do you think that ultimately could be? I'm trying to get at -- is this potentially a meaningful, game-changing type deal if we go to all longer laterals, because those 30-day rates look really good.

Yes. 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 the 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 kinds of answers.

All right. Fair enough. Thanks, guys.

David Heikkinen, Heikkinen Energy.

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

But wanted to talk about how your borrowing base grows, and really how your cash flows grow, given you're outspending a lot this year. Just really trying to think about how you think about the multi-year financing of the Company, either Rick or Randy.

Yes, David. On the -- we do have the significant cash on hand. We've got our credit facility -- we have actually elected to limit that at $825 million today.

It actually has a full borrowing base and a borrowing capacity based upon our December 31, 2013 reserves of $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 the $825 million.

We have a semiannual redetermination to our credit facility, which takes into account and updates our borrowing base based upon drilling activities that have taken place since last redetermination. We do have are redetermination that's coming up in October. That will include, then, the drilling activities that have taken place in the first half of 2014.

Would 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 supports any outspend that we would have in 2014 and anticipated in 2015. So, we're covered, at least over the next 18 months.

We're obviously going to make sure that we maintain significant liquidity at the Company. We make sure -- 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 pre-funded 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 and we're working through our 2015 budget and looking at things, such as what type of wells, and the lateral lengths that were 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 of benefit our overall acreage position.

Thanks, Rick.

Richard Tullis, Capital One.

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

The way we -- Rick, the way we went about that internally, we 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're expecting now for the third quarter. Is the fourth quarter still matching up with what you had at the last update, 20 to 25 wells in the fourth?

Yes. It'll 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 we'll really be able to add noticeable volumes in that quarter.

Okay.

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 two that were mentioned in the release?

They were right at $9 million.

Okay. That's all for me. Thanks a bunch.

Thank you.

John Herrlin, Societe Generale.

Yes. Hi. Thank you. 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 the split?

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

Okay. That's fine. With respect to the production corridors, as you start up and build gas lift systems and all that, these things generally just don't start immediately. At the beginning, did that slow some of your output growth, too, as you were bringing these pads on, because you're bringing on the systems, as well? Can you address that?

John, this is Dan Schooley. No. 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 frack-density approach that we're hearing so much about from many of your peers? Are you looking at that as well as also doing XLs?

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

The nature of the beast -- it takes a while to really understand the results -- incremental results of the investment on the return. we really need six to nine 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 just with white sand or mixed with brown sand, you lose connectivity -- conductivity through time, pretty substantially. And we've done a couple wells with ceramic or resin-coated sand.

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

Great. Thank you.

Matt Portillo, TPH.

Good morning, guys. Just one quick question for me. You mentioned, and I know you guys have done a great job of getting in front of the 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 a second question, as the industry continues to accelerate the use of proppant, how you guys are thinking about the logistics of potentially getting in in front of any bottlenecks that may occur on that front.

On the rig front, we -- hitting the market right now for spot rig or horizontal bulking rig is pretty much zero. We have arrangements next year to bring in additional rigs as a newbuild rigs. We're in queue for those deliveries. That's how we're looking at playing our rig business, is you got to be a year out ahead of that.

As far as proppant -- that's one of the reasons we signed a long-term agreement earlier -- the evergreen agreement with a large completion pumping service company. It has the logistics strength to minimize the delay or shortage in proppants that we would see working directly with this proppant supplier to secure that proppant well in advance. All of those kinds of things we're trying to take those risks -- execution risks off the table.

Thank you very much.

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 two upcoming conferences, the EnerCom's Oil and Gas Conference on Monday, August 18 at 3:10 PM Mountain time. And Barclays CEO Energy-Power Conference on Tuesday, September 2 at 1:05 PM Eastern time.

Also we'll release our third-quarter 2014 earnings on the morning of November 6 and host a conference call that morning at 9:00 AM 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.