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 Patrick J. Curth - Senior Vice President of Exploration & Land.

Gilbert K. Yang - DISCERN Investment Analytics, Inc Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division Brian Singer - Goldman Sachs Group Inc., Research Division Jason Smith - BofA Merrill Lynch, Research Division John P. Herrlin - Societe Generale Cross Asset Research Brian D.

Gamble - Simmons & Company International, Research Division Joseph Bachmann - Howard Weil Incorporated, Research Division Jeffrey Connolly - Mizuho Securities USA Inc., Research Division.

Good morning, ladies and gentlemen, and welcome to the Laredo Petroleum's First Quarter 2014 Earnings Call. My name is Ryan. I'll be your operator for today. [Operator Instructions] And as a reminder, this conference is being recorded for replay. Now it's my pleasure to introduce Mr. Ron Hagood, Director, Investor Relations. Please 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 additional members of our management team.

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

The company's actual results may differ from those forward-looking statements for a variety of reasons, many of which are beyond our control. In addition, we will be making reference to adjusted net income, 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 a combination -- in a combined liquids total.

If reported on a 3-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 the -- with -- to companies that report on a 3-stream basis.

Also, Laredo's unit cost metrics will appear higher when compared to companies that report on a 3-stream basis. However, the true economic value is the same. Earlier this morning, the company issued a news release detailing its financial and operating results for the first 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'd now like to turn the call over to Randy Foutch, Chairman and Chief Executive Officer..

Thanks, Ron, and good morning, everyone, and I do thank you for joining Laredo's First Quarter 2014 Earnings Conference Call. In the first quarter, Laredo continued to execute its long-term plan for the efficient multi-zone development of our Permian-Garden City asset.

Data demonstrates that stacked laterals are the most economic method to recover the resource identified in our 4 proven zones. By the end of the quarter, 5 of our 7 horizontal rigs were drilling stacked laterals from multi-well pads with the capacity to add additional wells in the zone.

We also made substantial progress in the build-out of the first of several production corridors. We are constructing that when fully operational. We'll facilitate the efficient movement of oil, gas and water.

This first quarter was designed to, over time, handle approximately 450 horizontal wells and can accommodate even more should additional zones be proven. Our long-term well results continue to substantiate the quality of our acreage and our identified resource potential of more than 1.6 billion barrels of oil equivalent on just our de-risked acreage.

In fact, of the more than 100 horizontal wells we have drilled, 68 have 1 year or more of production history, of which 24 are long laterals of at least 6,000 feet and at least 25 frac stages. Our extensive database, including production data, has proven to be very helpful as we plan for the long-term development of this resource play.

Laredo is well positioned, both operationally and financially, to execute its long-term development plan for its Permian asset. We're now at an inflection point that has positioned the company for many years of efficient development of the more than 3,500 de-risked horizontal wells to be drilled on our acreage.

Now I'll turn the call over to Jay for an operational update..

Thank you, Randy. First quarter Permian production achieved company record levels as the benefits of that 15 horizontal wells completed in the fourth quarter of 2013 was realized for the entire quarter.

We completed 7 horizontal wells in the first quarter, including our second-best Cline horizontal to date, which achieved a 2-stream 30-day average IP rate of 900 barrel of oil equivalent per day at 67% oil or 1,162 BOE per day, calculated on a 3-stream basis.

With over 60 days of production, this well continues to perform at a 119% of the company's Cline type curve. This makes the top 20 list of our best wells. The 7 wells averaged an initial 30-day IP of 706 barrel of oil equivalent per day on a 2-stream basis with 75% average oil cut or 827 BOE per day on a 3-stream basis.

We're currently operating 7 horizontal rigs. We added our sixth and seventh horizontal rig at the end of the quarter, 2 to 3 months later than anticipated. This was caused by construction delays and a new-built rig, another operator delaying release of the other rig as planned.

We had expected the sixth rig prior to the end of the 2013 and the seventh early in the first quarter of 2014.

Because of the continuous acreage position and abundance of drilling locations, we have been able to alter our development program to minimize the production impact for this year and still expect annual production to be within our original guidance range. At the end of the first quarter, we had 13 wells drilled and uncompleted.

The majority of these wells were waiting on drilling operations to conclude on our multi-well pad prior to completion. Upon conclusion of drilling operations, all wells on the pad will be completed concurrently, which drives our lumpy production growth profile.

Most of the wells being drilled in the second quarter are on multi-well pads and are expected to be completed in the third and fourth quarters. In our press release this morning, we gave guidance ranges for production and completions by quarter.

The guidance ranges for production are necessarily wide to accommodate for fluctuations and completion schedule for multi-well pads and the potential for large pads to begin production earlier or later in a quarter than we anticipated.

As we had previously stated, the guidance is biased to the second half of the year, as multi-well pads bud late in the first quarter and second quarter or completed and will be -- and will provide the full benefit of their production to the following quarters. We drilled our first exploratory horizontal Spraberry well in the first quarter.

Because our single-zone Spraberry test and offset vertical well showed water production above and below our landing point, we only completed 1/3 of the 8,500-foot lateral with a 10-stage redesigned fracture stimulation. This stimulation was pumped at low rates in an attempt to keep the frac height within zone.

Only 7 of the 10 stages were effective due to poor behind-pipe cement. Although, we do not feel 24-hour rates are indicative of long-term economics, we are encouraged with the initial test results of a normalized peak 24-hour rate as 628 barrel of oil equivalent per day. We do not yet have a 30-day average flow rate.

We will complete the rest of the lateral in the future once we get better data on production and have time to study our stimulation procedures.

Although these exploration tests are important, we will continue to focus the majority of our efforts on developing 3,500 de-risked horizontal locations, and we'll expand our exploration efforts at a measured pace.

As we transition into manufacturing mode, we've been very successful in increasing our technical and operational stack to sufficient levels ahead of the execution to efficiently manage our capital program.

We're still on target to reduce our drilling and completion cost by 10% by the end of the year through pad development and other efficient CI improvements. However, we will be investing more in completion optimization efforts on a portion of our wells through upsized fracs, profit material and engineered frac designs.

I will now turn it over to Dan to discuss the infrastructure build-out..

Thank you, Jay. I'll provide some background on Laredo Midstream Services, also known as LMS. Since Laredo's inception, timely marketing of its production has been an integral part of our overall business plan.

Core philosophy has been to maximize the flexibility of our marketing infrastructure to ensure that we have access to adequate and economic takeaway capacity. Historically, this meant building and getting ahead of gathering infrastructure as oil production was trucked from the lease.

As Laredo has grown and is moving into full-scale development of a resource base that has 40 to 50 years of drilling inventory, additional infrastructure is necessary for the efficient implementation of our development plan.

With Laredo's large, contiguous acreage position and the attendant resource base, LMS now has the responsibility of getting our crude oil and natural gas to market timely and economically and also with developing a sustainable water system for our completion operations, including recycle and non-potable water supplies and both with high- and low-pressure gas needed for gas lift and rig fuel.

To accomplish this in the most capital-efficient manner and the greatest long-term economic benefit, LMS has designed and is billing production corridors to centralize all the necessary infrastructure.

Contained within a corridor are the pipelines and facilities necessary for oil and gas takeaway, gas compression for artificial lift, low-pressure gas lines for rig fuel, water production, water recycling and the movement of freshwater.

Our first water recycling plant, which is one of the largest investments in the production corridor, should be operational in the fourth quarter and is designed to service multiple corridors.

The centralization of the production corridors makes it possible to maximize the number of wells our facilities can service, enhances the capital efficiency and economic return of our infrastructure investments.

Our first production corridor in Reagan County, which we expect will be fully operational in the fourth quarter, will accommodate all horizontal wells in a 21-square-mile area or approximately 450 wells at current spacing for our 4 currently proven zones, as well as additional zones that may be developed over time.

We are in various stages of construction for 3 other production corridors to support our development plans over the next several years. We've also constructed crude oil truck stations in both Glasscock and Reagan Counties. The station in Glasscock County takes in oil from Laredo leasehold and delivers it to third-party pipelines.

The Laredo crude oil truck station at Reagan County that we expect to be fully operational in the second quarter is also connected to our production corridor oil gathering lines in addition to receiving trucked oil.

These stations provide an oil price uplift by shortening the distance trucks travel to gather our oil or in the case of the Reagan station gathering facility, eliminates the need for trucks altogether.

Developing these production corridors across our Garden City acreage will enable Laredo to enhance our capital efficiency, economics and operational flexibility while also reducing our overall cost of operations across our oil, gas, water activities in the Permian Basin.

Several of these major facilities projects are specifically designed to enhance our wellhead realizations and flow assurance on crude oil.

By building these crude oil gathering systems that we've discussed above, Laredo will be able to deliver our crude oil into multiple pipelines, including the Medallion-Wolfcamp Connector pipeline, in which we are anchor shipper with firm transportation.

The Wolfcamp Connector will connect to both our Glasscock and Reagan County stations and deliver our production to Colorado City, thereby, avoiding the congested Midland Colorado City corridor.

With our current exposure to LLS pricing under our Shell contract, our firm service on the Wolfcamp Connector into Colorado City, our firm service on BridgeTex and our existing basis hedge for the Midland Cushing differential, Laredo was well positioned on both takeaway capacity and enhanced pricing for the next several years.

With that, I'll turn it over to Rick for our financial update..

Thank you, Dan. As stated in this morning's news release, Laredo reported first quarter 2014 adjusted net income of $69 million or $0.49 per diluted share. This includes an approximate $77 million benefit from the cash settlement associated with the unwinding in February of the Brent-based derivatives that we had discussed on our year-end call.

Had this contract remained in place through its initial term, any gain or loss at settlement would have been included in our quarterly adjusted net income over that term due to the ongoing nature of our derivative program. If you exclude this approximate $77 million benefit, the adjusted net income would have been $19.2 million or $0.14 per share.

Adjusted EBITDA for the first quarter of 2014 was about $187 million. Excluding the $77 million of proceeds from unwinding the Brent-based derivative, adjusted EBITDA was approximately $111 million, which is comparable to the 2013 period, which, as a reminder, included EBITDA from our Anadarko Basin properties, which we divested of in August of 2013.

As Jay discussed, total average daily production was a record 27,000 barrels of oil equivalent per day from the Permian Basin in the first quarter of this year despite the challenging winter storm season.

These volumes resulted in total oil and gas sales of approximately $173 million, which is up 6% from the prior year quarter, and up approximately 13% sequentially from the fourth quarter of 2013.

Total oil and gas sales benefited from increased oil volumes as a percent of total production volumes compared to the first quarter of 2013, along with higher realized prices for both oil and our high-BTU natural gas. Total lease operating expense for the first quarter of 2014 of $21.8 million was down slightly from the prior year quarter.

The 2014 quarter included some onetime costs related to the difficult winter storm season associated with items such as reestablishing power and generator rentals. In addition, we experienced increased costs for lease personnel as we continue to hire in advance of our production ramp-up.

General and administrative costs of $23.3 million for the first quarter of 2014 included a onetime charge of $3 million related to a charitable contribution. This contribution will actually be paid over 10 years, and our actual cash outlay is only $200,000 in 2014.

Without this charge, G&A, excluding stock-based compensation, increased about 24% from the prior year period, primarily due to our growing workforce, which has grown above 23% during the past year. The increase in stock-based compensation was primarily driven by the 40% increase in the Laredo stock price over the past year.

Depletion, depreciation and amortization expense of $20.38 per barrel of oil equivalent decreased $0.26 per BOE from the first quarter of 2013 and decreased $0.64 per BOE sequentially from the fourth quarter.

The decreases were primarily related to lower depletion charges that benefited from our growing reserve base as we continue to develop our vast inventory of drilling opportunities. This morning, we also issued production and cost guidance for the second quarter of 2014, as well as quarterly production guidance for the remainder of this year.

As Jay described, in the out quarters, we have presented slightly broader ranges for production, which reflects the impact of start-up timing on the larger multi-well pads.

As we have discussed previously, our transition to full-scale development using multi-well pads of 2, 3 and 4 stacked wells on a single pad has caused the cycle time from spud to first production to lengthen. As we continue to implement this program, our production growth will certainly be weighted toward the second half of 2014.

As a result of this growth, we expect our unit costs will continue to trend down throughout the year. Following the recent semi-annual review of our reserves, our bank group has increased the borrowing base on our credit facility to $1 billion. However, Laredo has elected a commitment of just $825 million.

This commitment, coupled with our existing cash and equivalents, provides the company with approximately $1.3 billion of liquidity today.

We believe that our anticipated growing cash flow and existing liquidity is more than sufficient to meet our projected capital needs for at least the next 24 months and provides the company with significant financial flexibility in the future. At this time, Ryan, we would like to open the call for any questions..

[Operator Instructions] And our first question comes through from Gil Yang with DISCERN..

You mentioned that you have, I think, 6 wells drilled on stacked laterals.

Can you comment on the relative performance of the stacked lateral wells versus, otherwise, similar wells that are not stacked? Are you seeing any differences?.

I'll let Jay answer that. I'll just make the point that we view that type data as something that takes some time to really rely on and get comfortable with..

Yes, Gil, the stacked laterals, especially the Upper Wolfcamp and Middle, where they're closer together, we've seen a difference in the initial production of the wells. The Upper takes longer to dewater. It appears it is taking a lot of the load off the Middle.

The Middle, when they're drilled in a stacked position, has been coming on immediately with oil production, which is uncharacteristic of the middle wells that we've drilled standalone.

In total, we're -- of the data that we have to date, it appears we're getting about the same total production from that -- the section of Upper and Middle from wells that we've drilled standalone Upper and Middle.

So we're currently within our type curve and pretty encouraged by what we've seen from the stacks of the Lower and the Cline in a stacked position, really, have been right on target..

Okay, great. Then related to that, as you drill these wells on the pads, I think, you mentioned that you'll be hooking the rigs up to fuel supply, presumably of the natural gas.

Will that -- how will that change produce volumes and your costs going forward?.

We see about 2,000 to 2,500 day of fuel cost savings. We take the natural gas right off of our producing infrastructure. We take it through a JT skid to remove the liquids, so it's dry gas. It really has no impact to our gas production in revenues. That wet gas is metered right off the pad, and that's what is -- we -- the sales point..

And just to be clear on that, we do pay all the royalties and everything else on that gas..

Next question comes through from Ryan Oatman with SunTrust..

A large Permian operator was discussing the potential for cost inflation of about 10% seemingly across the board, whether it be for labor rigs or completions.

Are you seeing that type of upward pressure in costs? And can you just comment on the broader service environment on which you're operating?.

Yes, we really don't see a lot of pressure on rig costs in frac services and other across the board. We will have pressure on personnel cost, not a huge impact to the total LOE. But we're seeing -- we're signing up rigs essentially within the range of what we're currently paying. Some of the commitments on rigs are a little longer.

But I don't see us -- we don't see in our operations a large inflationary impact..

That's helpful.

And can you discuss kind of the nature of your contracts? Any upcoming redeterminations or negotiations that we need to think about there?.

Are you talking about our service cost contract?.

Yes, kind of the drilling and pressure pumping contracts..

We've historically at this company, we've stated a lot of times that we tended, all things being equal, to not sign long-term contracts. And as we -- to get the best rigs and the best crews, both in terms of drilling and pressure pumping, we've had to sign 1-year contracts, and going forward, that may grow to 2.

But we've done that in a very methodical and staggered way. Most of our operations are well less than a year on contract. We'll see how that works going forward. But I think our job is to make sure that we have flexibility to decrease or increase those service providers in terms of number of rigs and pumping and so and so forth..

That's great. And then one final one from me before I hop back in the queue. You spend a fair amount of time in your prepared remarks talking about production corridors.

Looking out to next year, do you anticipate sort of the capital spend rate on facilities, land, seismic, other to be sort of in this year's range of about $160 million? Or could they go up or down?.

There'll certainly be some flexibility to it, but we do believe that this year's capital spend rate will probably see something fairly similar to that in 2015. But keep in mind that these expenditures, as Dan discussed, are helping to build the infrastructure that is going to support drilling activities for many, many years to come..

Next we have Brian Singer with Goldman Sachs..

Just wanted to follow up on 2 related cost points. The first was with regards to operating costs. Looked like operating cost per BOE ticked up during the quarter. You talked about the potential for some savings with regards to maybe doing less trucking or more manageable trucking costs.

But could you just talk about the operating cost trajectory going forward and how that incorporates some of the production corridors and facilities and benefits that you've been talking about?.

Yes, from a unit standpoint, you keep in mind that 2013 quarter included the Anadarko Basin properties, which is primarily dry gas, which have an inherently lower unit operating cost. As far as -- so our oil volumes now represent 58% or so of our total volumes.

As I mentioned in the first quarter of 2014, we did have some more onetime cost related to some of the winter storms that we had at the end of 2014, as well as carryover from a pretty rough winter season in January and February.

So as we were doing our normal activities, as well as restoring some of the power lines and bringing in generators to ensure that we could keep production volumes up or up to their normal levels that we did have some higher cost.

Acceleration of the hiring to make sure that we had field personnel in place, trained consistent with Laredo's operating practices to make sure that they understand our safety emphasis and just our overall working environment. We have hired well in advance of having the actual production coming online.

So as the volumes continue to tick up in the second half of the year from a unit standpoint, we expect to see substantial decrease over the year..

Got it. So that would put you back to about where you were in Q4, which I think was a quarter free of -- free and clear of the Granite Wash properties..

Q4 was -- did not have any Granite Wash properties in, but it did have very low actual operating cost because of the downtime associated with that severe winter storm that hit, really, in the Thanksgiving or early December time frame..

And then looking more on the capital side, you spent 1/5 of your budget during the quarter.

Is there any cost-savings benefits here? Or is this just normal course given the timing of when your wells and activities is just coming as that ramps up? Is there any potential to come in under budget for the year that you see now? Or was this just very much in line with the program?.

It was pretty much in line with the program, however, as Jay mentioned, keep in mind that the sixth and seventh rigs did not really come in until really right at the beginning of the second quarter.

So as those rigs now are operating and drilling for us, I would anticipate seeing a little bit higher ramp-up in capital expenditures over the rest of the year. It's still somewhere pretty much with inline with our original $1 billion capital program. But keep in mind that, that capital program excludes any acquisitions..

Our next question comes through from Jason Smith with Bank of America..

Just on delineation, obviously, your peers have started to have some success up further north in Howard County.

Can you just remind us how much acreage you have up there? And any plans to drill in that area? And also just any additional Spraberry tests you guys have planned as well?.

I think I'll let Pat kind of address that..

We have our acreage position to the north. We have in the extreme southern, southwest corridor of Howard County. 3% to 4% of our acreage is up there. Our main acreage block is to the south in Central, Southern Glasscock County and Northern Reagan County. We continue to do exploration out there.

As Jay noted, a majority of our interest expenses will be on our development program. The Spraberry well is our first well out there. We still have to do a lot more work on it. Other zones, so we continue -- we've talked about the Strawn and the Canyon. We do what we've always done culturally.

We've taken cores in both those zones, whole cores and sidewall cores. We're analyzing that data, correlating them with our 3D seismic data, doing petrophysical analysis. Where possible, we're taking production log from individual zones and the vertical wells.

So we continue to move forward very methodically on our exploration efforts, including in the Lower Spraberry and some of these other zones we've mentioned before. As a point of reference, I'll remind people that it was almost 2 years before we took -- we drove our first Cline well after we took our first whole core in that section though.

So the effort continues..

And then, I guess, just on the Cline, I mean, last quarter, you guys talked about historical wells performing under your type curve. You had 2 wells that were 125% above after 180 days, and you've always had a fairly strong well this quarter as well.

So can you update us on how those 2 wells -- are they still trending above the type curve? And can you talk about -- did you guys doing anything different in terms of completion or anything on the Curry-Glass [ph] well?.

We have been trying to optimize completions all alone, but we effectively didn't do much different on those completions. And I think, our message was geared to be that we were showing data that showed the Cline at that point was below the curve. We said that we had additional data coming and that once we see a need, we'll adjust the curve.

But so far, we haven't seen a need to adjust that curve up or down. We're slow to push out type curves, and we need data to adjust them. So we're -- we'll adjust those when we see data that suggests we should. But so far, we're kind of on the Cline curve..

Next we have John Herrlin with Societe Generale..

Regarding well designs or completion designs, many companies have been talking about either greater stages in terms of density or more sand loads for proppant.

Are you contemplating any completion design changes in your wells?.

Yes, John. We stated before as we move into development phase and we concentrate our effort in one geographic area drilling the same type wells, it's a lot easier to get better understanding changes of your frac designs, how impactful they are versus the change in geology if you're delineating a few.

This year, we've started altering our frac program and our designs to upsize the frac, including more sand, different type of proppants, trying some ceramics in an effort to optimize our frac design. Of course, that is a long process.

After you change something, you need meaningful data to understand that the change that we made did have positive impact. Usually, if you're spending more money on it, it has an incremental return on those additional dollars that you spent.

We're spending more time engineering our fracs, trying to group like rock types together, so we have more consistent stimulations across the stage, not where stages one perf cluster takes all of the frac.

We're running more production logs to understand what parts of the well are productive, trying to tie that with our seismic, so we can see those rock type before we stimulate a well.

And we'll also be running some fiber optics towards the end of year, so we can get a long-term understanding along the wellbore of how effective our fracture stimulations have gone compared to the rocks that we frac-ed..

With the ceramics, are you putting it in at the end or throughout? Or what are you doing versus sand?.

We're designing that throughout the frac. We -- early on, we frac-ed some Cline wells with ceramics. And they're actually some of the best wells that we've drilled. Not sure if that's geologically driven or because of the proppant type.

Of course, ceramics are a lot most expensive, so it's -- we've got to have a pretty good uplift in the well results to justify that expense.

But it is something we're looking at, and though a lot of other operators just use brown sand and white sand, but long -- in ceramics, somewhat a little different that you really have to look at the long-term impact of the improvement in that well because of the proppant strength ceramics provide.

So that will take some time to understand if that is really a positive benefit..

Great. One other one from me.

In terms of the production corridors, overall, when you had one up and running and servicing area, what kind of blended savings do think you'd be able to achieve?.

We've got, obviously, in-house models and numbers and economics on that. And I think, John, those are meaningful numbers, but I think our view, as always, and I know this isn't the answer you're looking for, we'll get proof on those savings and then talk about them.

Dan, do you want to add anything to that?.

No, I think that's right, Randy. The -- it'll be the fourth -- or the corridor. Our first corridor is up and running at full throttle with water, oil and gas takeaways. So we have all this modeled, and we think we understand what the savings will be, but we don't have any data yet..

We got a lot of the models but not data, John.

And I think -- I will say that, I think, when you look at the benefit of a production corridor, in which all the floods are able to be moved up and down, north, southeast and west on that corridor in pipe with compression on the gas or you've eliminated literally dozens of compressors at well sites and centralize all that.

It doesn't take much to imagine that the savings could be meaningful. And that's why we're doing them. And we'll get -- we're very, very definitely wanting to answer that question on what the savings really is..

Great. Well, I figured it'll be substantial. I was just hoping I could get you to lift the veil so to speak..

Next, we have Brian Gamble with Simmons & Company..

I was thinking about the -- when the sixth and the seventh rig came on. Actually, wanted to take a follow on the -- an earlier question about the spending rate.

Because those rigs did come on a little later than you planned, could you actually bring on another rig sooner and still may maintain your capital budget for the year? I know that you've talked previously about bringing 1 on every 9 months or so, but is that being contemplated to, I guess, spend your budget?.

Well, we still believe that we will spend the $1 billion program. You'll see a little bit higher tick-up in the capital spend as we start to do some of the completions to some of the well inventory that had been drilled but yet to be completed, as well as the full impact of operating 7 horizontal rigs.

We have been able to use a spudder rig to drill a portion of the vertical section. I'll let Jay kind of go through some of the details on that. That has allowed us to modify our drilling program, where we still believe that we will be in the range of our overall guidance for the year despite the fact that we're delayed 3 months on those 2 rigs..

I agree, Rick. We've been able to -- as I mentioned, we have been able to do some things to accelerate that. Of course, the spud production time, cycle time is very important to the production profile. We have utilized some smaller rigs to do some free drilling to accelerate those laterals and the rigs that were delayed.

We just bought on the 2 rigs, and we're pretty patient to understand, to digest the pace that we operate to make sure we're not getting rigs ahead of infrastructure and material, personnel to operate those rigs.

So we're going to get comfortable with the 2 rigs that we're operating before we start adding additional rigs and being less capital efficient..

And then just to pry a little bit, if I may, on the exploratory wells, you talked about the Spraberry horizontal and obviously, still working through that well itself.

But are there any more like that or in other step-out locations that are currently drilling or soon to come on the drilling schedule?.

I think our capital budget, as we talked about it, you can see where our focus is with most of our money is going into the development plans within the de-risked acreage. But I think the point is that we've shown in the past we have a number of other zones to look at, at some point.

And those zones, in many cases, like as Pat said, we've have got cores. In many cases, well, we've tested them vertically in single-zone completions. We kind of know that some of them are going to produce at least -- to some degrees, the question is how well do they produce horizontally.

So I think, our view is that we really want to get on with the development plan, where we think we can deploy capital most efficiently and methodically add to that with exploratory. And we're actually pretty methodical about our exploratory as we've shown you over the last couple of years. So there's lots of other zones out there to go explore for..

Next we have Jeb Bachmann with Howard Weil..

Just a couple of quick ones for me. Going back to the question on differentials. Just wondering if the for the deduct for the API gravity of your accrued, if that's something that could be eliminated or lessened with this new infrastructure build-out..

Yes, Jeb. The API gravity of our crude oil is all 40 to 43 degrees, so we don't anticipate seeing any gravity deducts being applied against ours. We don't have any condensate and little or no sour that I'm aware of. So we have WTI sweet barrel.

In our discussions with the JPMorgan folks on the -- bringing our crude oil down BridgeTex, we had long discussions about that symptom assays [ph] to make sure that we were getting the kind of product that the refineries want to see in the U.S. Gulf Coast, and that was confirmed.

So we feel pretty confident, we're not going to have any differentials around gravity. Now one of the things that I will emphasize here is that part of our plan to get as much crude oil as we could into Colorado City was to lessen our exposure to the Midland/Cushing differential, which right now for July or June is averaging $7.45.

At Colorado City, we expect to get U.S. Gulf Coast-related pricing less the cost to get it there obviously, but that's -- we think that's going to be a very preferred place to be for years to come until we get the Midland/Colorado City corridor uncongested.

And that's really going to be whenever basins looped [ph] , which will be at least a couple of years out. So we really feel like differential wise, we're in the sweet spot, both from an API gravity standpoint and where our barrels are going to be located..

Okay. Great. And then last one for me. Looking at the stacked laterals and the comments on the Upper versus the Middle, just wondering if -- where you're landing the stacked or the lateral in the Upper, if it's different from the standalone or it's a similar design to what you're doing with the stacked..

Yes, the -- in the Upper, it's pretty much in the same area across the field. It's a smaller interval in the Upper. The Middle, however, is much thicker package we have several landing places in the Middle that we have landed our Middle completions, all of them performing about the same.

So at some point, we may even have 2 middle horizontals stacked because of the thickness of that package..

[Operator Instructions] The next question is from Jeffrey Connolly with Mizuho Securities..

Last quarter, you told us about a Wolfcamp Well up on your northern acreage where you saw a phase east [ph] change.

After another quarter of watching it, can you guys update us on what you've learned from that well?.

Yes. I think -- I don't know that we've reached any different conclusion than we had, Pat or Jay. I think we're -- we said we were kind of, I think, disappointed in it, but we weren't sure how to think about it yet with more -- we needed more production data. And at some point, we've got to decide on other zones.

Pat, do you want to add anything to that?.

No. We continue to watch the production, and we're going back and look at the petrophysics and continue to look at..

Okay.

And then just where was the Spraberry well on your acreage?.

It is in Reagan County..

It looks we have some follow-up coming back from Ryan Oatman of SunTrust..

One very quick one for me here. I have received from investors a couple of questions on the guide kind of marrying the annual figure reiterated of the 12.2 million to 12.7 million versus the quarterly figures.

Can you help us just kind of reconcile those 2 figures and to sort of think about being at the high end of those quarterly guidances on average to kind of meet the annual guidance?.

Yes, Ryan, as Jay discussed, I tried to clarify, the quarterly ranges for the second, third and fourth quarter, you should not expect -- it's fairly unlikely that you're going to be able to add the upper end of all those ranges per year.

If the second quarter comes in at the upper end of the range, it is likely that the following quarter will come in at a little bit lower. It all has to do with the timing of these stacked laterals and the pads.

If it's a 4-well pad that's coming online, when that comes online within the quarter, can have a very meaningful impact on that quarter's production. And so if it's comes on a week or 2 early with the amount of volume coming from 4 wells, it can have -- it can move the needle.

That's why, as we move out throughout the year, we have given broader ranges around that. We will true that up as we continue out through the year..

Okay, that's helpful. And kind of along those same guidelines here, I mean, probably too early but figured I'll try it.

In terms of an exit rate, have you guys kind of thought about the ranges there as well?.

That's really driven by the same issues, Ryan..

And it looks we have no other questions, so I will turn it back to you, Ron, for any closing remarks..

Thank you, Ryan. I'd like to thank everybody for joining us [ph] for our first quarter earnings call. We'll release our second quarter financial and operation results the morning of Thursday, August 7, and we'll host our earnings call at 9:00 a.m. Central Time that morning. We appreciate your interest in Laredo..

Thanks everybody..

Thanks, everyone, for your time and your participation. You may disconnect. Enjoy your week [ph]..