Vital Energy Inc (VTLE) 2014 Q1 法說會逐字稿

Good morning ladies and gentlemen and welcome to the Laredo Petroleum's first quarter 2014 earnings call. My name is Ryan and I will be your operator for today. At this time, all participants are in listen-only mode. We will be conducting a Q&A session after the financial and operations report, 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. 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 under the Private Securities Litigation Reform Act of 1995.

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

Also as a reminder, Laredo reports operating and financial results including reserves and production on a two-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 three-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 three-stream basis.

Also, Laredo's unit cost metrics will appear higher when compared to companies that report on a three-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. Now I'd like to turn the call over to Randy Foutch, Chairman and Chief Executive Officer.

Thanks Ron and good morning, everyone. 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 four 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 and zones. We also made substantial progress in the build out with the first of several production corridors we are constructing that, when fully operational, will 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 continued to substantiate the quality of our acreage in our identified resource potential of more than 1.6 billion barrels of oil equivalent on just our derisked acreage. In fact, of the more than 100 horizontal wells we have drilled, 68 have one 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 are now at an inflection point that has positioned the Company for many years of efficient development of the more than 3,500 derisked horizontal wells to be drilled on our acreage. Now I will 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 the 15 horizontal wells completed in the fourth quarter of 2013 was realized for the entire quarter. We completed seven horizontal wells in the first quarter including our second best Cline horizontal to date which achieved a two-stream 30-day average IP rate of per day at 900 barrel of oil equivalent per day at 67% oil, or 11.62 BOE per day, calculated on a three-stream basis.

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

We are currently operating seven horizontal rigs. We added our sixth and seventh horizontal rig at the end of quarter, two to three months later than anticipated. This was caused by construction delays and a new built rig and other operator delaying release of the other rig as planned.

We had expected the sixth rig prior to end of the 2013 and the seventh, early in the first quarter 2014. Because of the continuous acreage position and abundance of drilling locations, we've 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 their multi-well pad prior to completion. Upon conclusion of drilling operations, all the 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 schedules for multi-well pads and a 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 the second half of the year as multi-well pads brought in late in the first quarter and second quarter are completed and will be -- and will provide the full benefit of the production to the following quarters.

We drilled our first exploratory horizontal Sprayberry well in the first quarter. Because our single zone Sprayberry test and an offset vertical well showed water production above and below our landing point, we only completed one-third of the 8,500-foot lateral with a 10-stage redesigned fracture stimulation. The stimulation was pumped at oil rates in an intent 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 of 628-barrel 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 our time-study our stimulation procedures.

Although these exploration tests are important, we will continue to focus the majority of our efforts on developing 3,500 derisked horizontal locations and will expand our exploration efforts at a measured pace. As we transition into manufacturing mode, we have been very successful in increasing our technical and operational staff to sufficient levels of head of the execution to efficiently manage our capital program.

We are still on target to reduce our drilling completion costs by 10% by the end of the year through pad development and other efficiency improvements. However, we will be investing more in completion optimization efforts and a portion of our wells through upsized fracs, proper 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 take-away 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 the 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 nonpotable water supplies and with both 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 building production corridors to centralize all the necessary infrastructure. Contained within a corridor are the pipelines and facilities necessary for oil and gas take-away, 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 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 four currently proven zones as well as additional zones that may be developed over time. We are in various stages of construction for three other production corridors to support our development plans over the next several years.

We have also constructed crude oil truck stations in both Glasscock and Reagan Counties. The station in Glasscock County takes in oil from the Loredo Leasehold and delivers it to third-party pipelines. The Laredo crude oil truck stations in Reagan County, that we expect to be fully operational in the second quarter, is also connected to our production corridor oil and 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 all together. 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 oil 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 an 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 heads for the Midland Cushing differential, Laredo is well-positioned on both take-away capacity and enhanced pricing for the next several years. With that, I'll turn it over to Rick for a 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 high 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 one-time costs related to the difficult winter storm season associated with items such as re-establishing power and generator rentals. In addition, we experienced increased cost 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 one-time 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 about 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 continued 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 two, three, four-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 towards 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.

Certainly. So, folks, the lines are now open.

(Operator Instructions)

Our first question is from Gil Yang with Discern.

Good morning.

Good morning, Gil. How are you?

Fine, Randy. How are you?

Good.

You mentioned that you have, I think, six 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.

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 dewatered. It appears it's taking a lot of the load off the middle. The middle, when they're drilling in a stacked position, have been coming on immediately with oil production which is uncharacteristic of the middle wells that we've drilled stand-alone.

In total, we're -- of the data that we have to date, it appears we're getting about the same total production from that section of Upper and Middle from wells that we've drilled stand-alone 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 the stacked position really 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 that would be the natural gas. How will that change and produce volumes and your costs going forward?

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

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

Okay. Got you. Thank you very much.

Thank you.

Next question comes from Ryan Oatman with SunTrust.

Good morning, Ryan.

Hi. Good morning. 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 you upward pressure in cost and can you just comment on the broader service environment in which you're operating?

Yes. We really don't see a lot of pressure on rig cost and frac services and other across the board. We will have pressure on personnel cost, not a huge impact to 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 the 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. 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 historically, at this Company, we stated a lot of times that we intended, all things being equal, to not sign long-term contracts. As we -- to get the best rigs and the best crews, both in terms of drilling and pressure pumping, we've had to sign one-year contracts and going forward that may grow to two but we have done that in a very methodical and staggered way.

Most of our operations are well less than a year on contracts. 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 on and so forth.

That's great. And then one final one from me before I hop back in the queue. You spent 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, others to be sort of in this year's range of about $160 million or could that go up or down?

There would still certainly be some flexibility to it but we do believe that this year's capital spend rate, we'll 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.

Thank you.

Thanks Ryan.

Next we have Brian Singer with Golden Sachs.

Thank you. Good morning.

Good morning, Brian.

I just wanted to follow up on two related cost points. The first was with regards to operating costs. It looked like operating costs 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 -- can you just talk about the operating costs trajectory going forward and how that incorporates some of the production corridors and facilities and benefits that you have been talking about?

From a unit standpoint, 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 one-time costs 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 costs.

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. As the volumes continue to tick up in the second half of the year from a unit standpoint, we expect to see a 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 costs because of the downtime associated with that severe winter storm that hit really in the Thanksgiving, early December time frame.

Got it. Thanks. And then looking more on the capital side, you spent a fifth of your budget during the quarter. Is there any cost savings benefits here or is this just normal course given the timing and when your wells activity is coming on 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. We're still somewhere pretty much within line with our original billion dollar capital program. Keep in mind that, that capital program excludes any acquisitions.

Great. Thank you.

Your next question comes from Jason Smith with Bank of America.

Hi. Good morning, guys.

Good morning.

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 Sprayberry 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 corner of Howard County, 3% to 4% of our acreage is up there. Our main acreage block is to the South and are Central and Southern Glasscock County and Northern Reagan County.

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

We do what we have always done culturally. We've taken cores in both those zones, whole cores, and sidewall cores. We're analyzing that data, correlating it in with our 3D seismic data doing petrophysical analysis. Where possible, we're taking production logs from individual zones and the vertical wells.

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

Thanks and then I guess just on the Cline, last quarter you guys talked about historical wells performing under your type curve. You had two wells that were 125% above after 180 days and you've obviously had a fairly strong well this quarter as well. So can you update us on how those two wells, are they still trending above the type curve and can you talk about -- did you guys do anything different in terms of completion or anything on the Cray/Glass well?

Yes, we have been trying to optimize completions all along, but we effectively didn't do much different on those completions. I think our message was geared to be that we were showing data that showed Cline at that point was below the curve.

We said we had additional data coming and once we see a need we'll, adjust the curve. So far we haven't seen a need to adjust that curve up or down. We are 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 on the Cline curve.

Okay, thanks. I appreciate it.

Thank you Jason.

John Herrlin with Societe Generale.

Hi. 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 at one geographic area, drilling the same type wells, it's a lot easier to get better understanding in changes of your frac designs, how impactful they are versus the change in geology if you're delineating field.

This year, we started altering our frac program and our designs to upsize the frac, including more sand, different type of proppant, 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, did the change that we make, did it have positive impact?

Usually if you are 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 types before we stimulate a well. And we'll also be running some fiber optics towards the end of the 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 fracked.

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. Early on, we fracked some Cline wells with ceramics, and they're actually some of the best wells that we've drilled. I'm not sure if that's geologically driven or because of the proppant type.

Of course, ceramics are a lot more expensive so 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. I know a lot of other operators just use brown sand and white sand but long -- and ceramics are somewhat a little different that you really have to look at the long-term impact of the improvement in that well because of the proppants during ceramics provide so that will take some time to understand if that is really a positive benefit.

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

We've got obviously in-house models and numbers and economics on that. 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. It will be fourth corridor -- first corridor is up and running at full throttle with water, oil and gas take-away. So we have all this modeled and we think we understand what the savings will be but we don't have any data yet.

Got a lot of mileage but not data, John. I think I will say that I think when you look at the benefit of a production corridor in which all the fluids are able to be moved up and down, north, south, east, and west on that corridor, in pipe with compression on the gas where you eliminated literally dozens of compressors at well sites and centralized all that, it doesn't take much to imagine that the savings could be meaningful. And that's why we're doing them. We'll get -- we're very, very definitely wanting to answer that question, what the savings really is.

Great. Well, I'm sure it will be substantial. I was just hoping I could get you to lift the veil, so to speak. Thanks.

Next we have Brian Gamble with Simmons & Company.

Good morning. I was thinking about the -- when the sixth and seventh rig came on, I actually wanted to take a follow on to an earlier question about the spending rate. Because those rigs did come on a little later than you think, could you actually bring on another rig sooner and still maintain your capital budget for the year? I know that you've talked previously about bringing one on every nine months or so but is that being contemplated to, I guess, spend your budget?

We still believe that we will spend the billion dollar program. You will 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 have been drilled but yet to be completed as well as the full impact of operating seven 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 that we still believe that we will be in the range of our overall guidance for the year despite the fact that we were delayed three months on those two rigs.

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

We just brought on the two 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 two rigs that we're operating before we start adding additional rigs being less capital efficient.

Then just to pry a little bit, if I may, on exploratory wells. You talked about the Sprayberry horizontal and obviously, still working through that well itself but are there any more like that or in other step out locations that you're 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 derisk acreage. But I think the point is that we have 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 got cores. In many cases, well, we tested them vertically in single zone completions.

We kind of know that some of them are going to produce at least, to some degree, 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 exploratory as we've shown you over the last couple of years, so there's lots of other zones out there, that are good to explore for.

Appreciate it, Randy. Have a good one.

Thanks, Brian.

Next we have with Jeb Bachmann with Howard Weil.

Good morning, guys.

Hello Jeb.

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

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 [souths] that I am 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 to make sure that we were getting the kind of product that the refineries want to see in the US Gulf Coast and that was confirmed. So we feel pretty confident we're not going to have 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 US Gulf Coast-related pricing less the cost to get it there, obviously, but that's a -- 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 basin is looped, which will be at least a couple years out. We really feel like differential-wise, we are in the sweet spot both from an API gravity standpoint and where our barrels are going to be located.

Okay, great. Then last one for me, looking at the stacked laterals and the comments on the Upper versus the Middle, just wondering where you're landing the stacked or the lateral, and the Upper if it's different from the stand-alone or if it's a similar design to what you're doing with the stacked?

Yes, and the upper is 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 two Middle horizontals stacked because of the thickness of that package.

Okay. Great. Thanks guys.

(Operator Instructions)

Next question is from Jeffrey Connolly with Mizuho Securities.

Good morning, guys. Last quarter you told us about a Wolfcamp well up on your northern acreage, where you saw -- facies change. After another quarter of watching it, can you guys update us on what you have learned from that well?

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. 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 looking at the petrophysics and continue to look at it.

Okay. Then just where was the Sprayberry well on your acreage?

It was in the Reagan county.

All right. Thanks guys.

Thank you, Jeff.

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

Thanks. One very quick one for me here. I have received from investors a couple questions on the guide, kind of marrying into the annual figure reiterated of the 12.2 to 12.7 versus the quarterly figures. Can you help us just kind of reconcile those two figures and should I think about being at the high end of those quarterly guidances on average to kind of meet the annual guidance?

Ryan, as Jay discussed and as 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 for the 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 four 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 comes on a week or two early with the amount of volume coming from four 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 maybe kind of along those same guidelines here, it's probably too early but I figure I will 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.

Right, right. Okay. Very good. Appreciate it.

Thank you.

Thanks.

It looks like we have no other questions, so we'll turn it back to you, Ron, for any closing remarks.

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

Thanks, everybody.

Thanks everyone for your time and your participation. You may disconnect and enjoy the rest of your week.