Ron Hagood - Director of Investor Relations Randy Foutch - Chairman and Chief Executive Officer Rick Buterbaugh - Executive Vice President and Chief Financial Officer Dan Schooley - Senior Vice President, Operations Karen Chandler - Vice President of Operations.
Brian Singer - Goldman Sachs Kashy Harrison - Simmons and Company Joe Allman - FBR Capital Markets Derrick Whitfield - Stifel Financial John Herrlin - Societe Generale Blaise Angelico - Iberia Capital Cindy Treska - Goldman Sachs Philip Stuart - Scotia Howard Weil.
Good day, ladies and gentlemen, and welcome to the Laredo Petroleum Inc. Second Quarter 2017 Earnings Conference Call. My name is Jonathan, and I will be your operator today. [Operator Instructions] As a reminder, this conference call is being recorded for replay purposes. It is now my pleasure to introduce Ron Hagood, Director of Investor Relations.
You may proceed sir..
Thank you, and good morning. Joining me today are Randy Foutch, Chairman and Chief Executive Officer; Rick Buterbaugh, Executive Vice President and Chief Financial Officer; Dan Schooley, Senior Vice President, Operations; Karen Chandler, Vice President of Operations, as well as additional members of our management team.
Before we begin this morning, let me remind you that during today's call, we'll be making forward-looking statements. These statements, including those describing our beliefs, goals, expectations, forecasts and assumptions are intended to be covered by the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995.
The Company's actual results may differ from these forward-looking statements for a variety of reasons, many of which are beyond our control. In addition, we'll 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 yesterday's news release.
On July 19, 2017, the company issued a press release confirming that Medallion Gathering & Processing, the sole owner of Medallion-Midland Basin pipeline system had initiated a process to potentially sell 100% of the ownership in Medallion Gathering & Processing in which Laredo Midstream Services owns 49%.
At this time, there can be no assurance that such potential sale will ultimately be consummated or if consummated, the specific terms of such sales. Laredo will have no further comments on this potential transaction on this call.
Yesterday afternoon, the company issued a news release and presentation detailing its financial and operating results for Second Quarter 2017. If you do not have a copy of this news release or presentation, you may access it on the company's website at www.laredopetro.com.
I would now turn the call over to Randy Foutch, Chairman and Chief Executive Officer..
Thanks, Ron, and good morning. Thank you for joining Laredo's Second Quarter 2017 Earnings Conference Call. The company's record second quarter is a reflection of how we have managed Laredo since inception. As with my past 3 E&P companies, we have invested in data and infrastructure to drive capital efficient operations and create value.
These investments, by nature, are long-term. And over the past 2 years the benefits have been evident in increased well productivity and lower capital and operating costs.
Our efforts to increase well productivity utilizing our proprietary workflows continued to pay off as total production grew 12% in the second quarter of 2017, compared to the previous quarter. Oil production grew 16% and represented 47% of total production, and including NGLs, liquids represented 73% of total production.
Additionally, we are increasing our anticipated production growth for full year 2017 from greater than 15% to a range of 16% to 19%, with no change to our capital budget. Our oil cut has displayed technically supported consistency over the last nine quarters, staying within a range of 45% to 48%.
As we have explained previously, our oil cut is driven by our reservoir engineering parameters and activity levels. The slight variation in oil cut reflects timing of well completions during the quarter, which varies to some degree as we drill packages of wells to maximize the efficiencies and minimize parent-child issues.
Over those nine quarters, we have consistently operated three to four rigs, it makes sense that a stable operating cadence would result in a consistent oil cut, if your long-term models accurately reflect your data.
At the beginning of 2017, we adjusted our Upper and Middle Wolfcamp type curves to incorporate both increased oil and gas production from better well results and additional gas and NGL volumes as long-term production history demonstrated a flatter gas curve in the later years of the curve.
In my 40 years or so in the industry, it has always been a reservoir engineering characteristic that key ore can change over time and you have to be aware of these reservoir parameters. Laredo has always modeled this concept into our type curves and other reservoir engineering work.
We slightly adjusted oil cut up in the early years of ore curves and flattened out the gas curve in the later years. But our adherence to the data we are seeing is reflected in our production modeling. It is reflected in the consistency of our oil cut and the accuracy from which we modeled it for guidance.
Recently, there has been increased discussion in the industry regarding water issues in the Permian Basin. Laredo has always believed that properly managing water needs is important and we believe it will become even more important for businesses in general. Beginning in 2013, we began implementing a plan for water handling throughout our leasehold.
Our contiguous acreage holdings facilitated the building of a centralized water infrastructure to handle water recycling, transportation and storage.
Our water infrastructure has provided a significant economic benefit by lowering capital and operating costs, provides operational flexibility and ultimately, it's the right thing to do in operating responsibly.
Very early in our field development we recognized that injecting produced water into the shallow San Andres formation could cause significant drilling problems. In fact, we first protested a San Andres saltwater disposal well in November 2014 and have protested a total of five wells.
Our water treatment facility has been a key alternative to injecting produced water into the San Andres. We are recycling approximately 35% of our produced water, drastically reducing the need to dispose of produced water and have plans to expand our water recycling infrastructure.
Essentially, all water that we do inject into salt water wells is being disposed of in the much deeper Ellenburger formation.
Turning to our investments in data, we are leveraging our massive amounts of data and proprietary workflows to build out robust development plan models that enable the simulation of a large number of development scenarios to maximize NAV.
The hydrated scenarios can then be implemented in the field, resulting in a substantial reduction in the time you need to move from concept to implementation in the most cost efficient manner to accelerate value creation.
This is driving our testing efforts that if successful, will materially increase our premium inventory in the Upper and Middle Wolfcamp zones.
Additionally, we are applying these workflows to other formations, such as the Lower Wolfcamp in Cline with the goal of consistently increasing well productivity in these formations and maximizing total oil recovery per section. Field infrastructure investments are a key component of our long-term value creation.
In addition to the water handling infrastructure mentioned earlier, our production corridors include oil and gas gathering and centralized compression facilities. The benefit of these prior investments increase as more wells are drilled near and utilize our corridors.
In the second quarter, our field infrastructure provided $7 million in total benefits to the company and is expected to generate more than $28 million in total benefits during the full year 2017. In summary, Laredo is consistently building value because of the way it's operated since its inception.
Investments in infrastructure are driving operational excellence and some of the most efficient capital productivity and lowest unit operating costs in the basin. Long-term investments in data & technology that take time to come to fruition and add value for years are enhancing our well productivity, driving higher production growth.
Our data driven workflows enabled a rapid implementation of new ideas in the field and we expect to build value through the addition of premium drilling inventory. All of this adds up to building value for shareholders. I would now like to turn the call over to Dan for an operational review..
Thank you, Randy. The second quarter was another impressive operational quarter for Laredo. We executed our development program with no issues, achieved company record production and continued to demonstrate the value of implementing technology driven workflows to enhance well productivity.
We have now completed 80 wells using our proprietary workflows to model variables such as proppant loading, perf cluster spacing and precise landing point selection and have implemented them in the field. As a group, these wells are performing 37% above the company's relevant type curves.
We expect to continue testing various spacing and completion configurations in all our well packages through the end of 2017. The testing will be determined by our modeling recommendations and implemented in the field based on operational considerations.
Determination of the effectiveness of the test will be driven by economics, and modifications will be made based on those economics. Production in the quarter was positively impacted by a couple of larger well packages.
The 9 well Middle Wolfcamp JL McMaster-Bodine package was completed late in the first quarter and 6 of the 9 wells in the Sugg-Graham package were completed at the beginning of the second quarter. The JL McMaster-Bodine package is currently performing 45% above our upper-middle Wolfcamp type curves.
Various combinations of perf cluster spacing and proppant densities were tested in this package, including 4 wells that were completed with 2,400 pounds of proppant per lateral foot, and 1 completed with 3,300 pounds. The 4 2,400-pound wells are currently outperforming our relevant type curves by 50% and the 3,300-pound well is outperforming by 83%.
As always, we will continue to monitor longer-term data and relevant economics. The Sugg-Graham package is currently performing 24% above our upper-middle Wolfcamp type curve and is continuing to improve, as it is still relatively early in its production history and is on managed flowback.
Also, during the second quarter, we completed four cluster wells that have limited production history but are above expectations and continuing to improve. Subsequent to the end of the quarter, we completed three wells, two Middle Wolfcamp and one Upper Wolfcamp with lateral lengths greater than 15,000 feet.
Both drilling and completion operations went smoothly on all three wells, and we did not experience any issues due to the length of the wells. These wells have been on flowback for less than a month. As we advance these proprietary models and workflows, we are able to accelerate the process of implementing NAV-accretive ideas in actual field tests.
Without the proper models, the time from testing conceptual ideas of dense well spacing and hydraulic fracturing designs to have sufficient data to access production impact can take years.
Laredo's proprietary hydraulic fracturing and well spacing workflows enable the acceleration of learning through testing of multiple iterations of spacing configurations and completion designs prior to actual field tests. One example of this is the completion designs being tested in concert with higher sand concentrations.
Early 2016 modeling predicted an uplift of approximately 50%, when utilizing completion designs with 2,400 pounds of proppant per lateral foot. Our production data from field tests for the 13 wells utilizing this model demonstrates an uplift of 46%, and is still showing improvement.
We continue to pursue numerous initiatives to further enhance our knowledge of spacing and completion design that are value accretive to Laredo. Hydraulic fracture modeling and associating it with well spacing continues to be a key focus area where numerous NAV-accretive field tests are under consideration for full implementation.
Our Big Data analytics program is focused on identifying the meaningful variable from hundreds of variables that can either positively or negatively impact production. Continued focus within the analytics domain continues to identify primary and secondary production drivers that can be implemented to improve production.
The Gas Technology Institute hydraulic fracturing test site project that we operated on [RA accretion] late 2015, is capturing fundamental data on hydraulic fracturing process to use in modeling fracture creation and proppant distribution.
Our microseismic program is acquiring the data needed to further refine our models that predict fracture geometry during the completion process.
These data acquisition and modeling efforts are key to advancing our development plan, as we work to codevelop multiple landing points in both the Upper and Middle Wolfcamp formations and add to our premium inventory. In the second quarter, Laredo recorded LOE of $3.77 per BOE, the fourth consecutive quarter below $4 per BOE.
A key driver of our success in reducing operating expense is our prior investments in field infrastructure and our production corridors with water handling infrastructure providing significant benefits. Randy and the Laredo management team have always been a proponent of our industry to be good stewards of the land and water resources.
We began planning our water handling infrastructure in 2013, and made initial investments in 2014. Our systems, which include pipes for delivery and take away of water, a treatment plant and storage were designed to minimize fresh water needs, reduce costs and maximize operational efficiency.
In the second quarter, Laredo gathered 73% of produced water by pipe and recycled 35% of total produced water. In total, the company's water infrastructure assets reduced Second Quarter 2017 operating and capital costs by $3.7 million. Operating cost savings associated with water infrastructure reduced LOE by $0.56 per BOE in the second quarter.
Crude oil gathering infrastructure was also a significant component of our production corridors. In the second quarter of 2017, we gathered 82% of our total gross operated production on pipe.
This generated a benefit of $3.1 million to Laredo through realized price uplift on our oil sales and operating income paid by crude oil purchasers who utilize the crude oil gathering system. I will now pass it over to Karen to give you additional details on what steps our operations team has taken to address drilling through the San Andres..
Thank you, Dan. As Randy noted earlier, and as you all are aware, injection of produced water into the shallow San Andres formation can cause substantial drilling issues. Laredo has long been aware of this potential issue and has taken steps to minimize the impact on our leasehold.
We think this protects not only our leasehold but the entire surrounding basin. Because our acreage was not as heavily drilled in the past as some other parts of the basin, it does not have as many salt water disposal wells.
However, despite this, we had experienced a very few high-pressure shallow water flow zones in parts of our acreage and have proactively taken operational steps to minimize the costs associated with this issue.
Two of the benefits of our centralized water infrastructure are to maximize produced water recycling and allow direct transportation to deeper Ellenburger disposable wells, which have enabled us to eliminate San Andres disposal from Laredo wells.
Essentially, all of our produced water that is not recycled is now disposed in seven Ellenburger disposal wells. As part of our centralized water handling infrastructure, we have produced water pipelines, with connection to six of these Ellenburger SWDs.
We also trucked one additional Ellenburger disposal well, and have contracts in place to directly pay the SWD companies rather than the trucking companies, which enables us to determine exactly where our produced water is being disposed.
In addition to eliminating our disposal into the San Andres, we actively monitor all existing SWD wells and protest all proposed San Andres SWD wells near our leasehold. As we begin planning operations for each well package, we review detailed map overlays of the drilling area with relevant SWD information.
This information is sourced from Texas Railroad Commission data and other external websites and includes information such as cumulative injection volumes, completed intervals and injection pressures.
We evaluate potential impacts from all San Andres injection wells within approximately three miles of our surface locations, including contacting the operator of the SWD to confirm the current status of the injection well.
This process enables us to make risk based decisions about the potential impact of shallow over-pressure zones for all of our wells, which enables us to use a standard three-stream casing design across all of our acreage, with operational contingencies in place if needed.
Our risk based planning process has been highly effective and since identifying the issue in early 2014, we've been able to manage our drilling program using a three-stream casing design in all but six of our horizontal wells, which is less than 3% of our drilling program during that time.
For these six wells, which require significant increases in mud weight to manage the San Andres overpressure, we successfully implemented our contingency plan of running an expandable liner, basically converting our standard 3-stream casing design to a 4-stream casing design.
The contingency liners only run if it is determined after drilling the San Andres formation that a 4-stream casing design is required for that specific well. This significantly minimizes the overall cost impact to our drilling program. To conclude, we do not inject produced water into the shallow San Andres formation.
Our centralized water infrastructure helps maximize produced water recycling injection in the deeper Ellenburger disposable wells. Through our risk based contingency planning, we have successfully managed over-pressure San Andres zones, while maintaining a standard 3-stream casing design across all of our acreage.
I would now like to hand the call over to Rick for our financial update..
Thank you, Karen and good morning. As announced in last night's earnings release, Laredo's Second Quarter 2017 production volumes were at the top end of our guidance and a company record, exceeding 58,600 BOE per day.
We had indicated that well completions that occurred late in the first quarter would and did have a positive impact on production during the second quarter.
As a reminder, Laredo tends to drill larger packages of wells, which we believe enables us to take advantage of operating efficiencies and to enhance hydrocarbon recoveries within a volume of acreage.
Keep in mind, that the development of these larger well packages often cross over the quarterly reporting periods and the timing of when these packages come online within a quarter may impact results in the 90-day reporting period.
Due to our plan in 2017 to increase the number of these larger well packages, you will recall that Laredo gave production guidance at the beginning of the year for the first 6 months and from the actual production results for the first half of 2017, we are outperforming the midpoint of that guidance.
Production has also benefited from prior investments in data and infrastructure. As both our base production and new drilling volumes are outperforming initial expectations.
As a result, we have increased our production guidance for full-year 2017 growth and now expect annual production growth to be in the range of 16% to 19%, an increase from 2016 volumes.
Crude volumes as a percent of total production came in at 47% for the quarter, at top end of our guidance, and product realizations were in line with our guidance, relative to their benchmark pricing.
Total units cash costs for LOE, production and ad valorem taxes, midstream and G&A, continued to decline and were down to $8.03 per barrel of oil equivalent for the second quarter, which was below the midpoint of guidance for these costs.
As a result of the company's continued focus on cost control, and capital efficient investments for the long term, the $8.03 per BOE rate is a 19% reduction from the second quarter of last year and a 12% reduction sequentially from the first quarter of this year.
Unit noncash costs for G&A and DE&A also declined sequentially from the first quarter and were below the guidance midpoint. As a result, we reported net income for the second quarter of 2017 of $61.1 million or $0.25 per diluted share and adjusted net income, which is a non-GAAP financial measure, of $25.2 million or $0.10 per adjusted diluted share.
The non-GAAP financial measure for adjusted EBITDA for the second quarter of 2017 increased to $114 million, from $107 million in the first quarter of this year. The increase was driven by record production volumes and cash costs that were 12% below those in the first quarter of 2017.
This cost improvement is meaningful as it overcame weaker commodity prices in all three streams, that lowered our average realized price per BOE by about 10%. Reconciliations of these non-GAAP financial measures are posted on our website and included in the earnings release that was issued last night.
Laredo has exhibited remarkable consistency in its adjusted EBITDA over the last 2.5 years, even as oil prices dropped by approximately 50%. The company's hedging program has worked exactly as it was intended. It protected our cash flow as commodity prices fell and activity levels slowed.
In 2015, as our average realized price per BOE fell 58%, our adjusted EBITDA decreased only 20%. In 2016, as our average realized price per BOE fell 11%, our adjusted EBITDA decreased by just 3%. Over that time period, we have realized $472 million in cash settlements for matured derivatives.
Through the first half of 2017, we have received $92 million less in cash settlements for mature derivatives than we did in the first half of 2016, yet adjusted EBITDA in the first half of 2017 grew to $222 million, increasing from $208 million in the first half of 2016.
Our hedges protected our cash flow as the company adjusted to the current price environment, cutting costs and improving well productivity. The company continues to maintain an active and disciplined hedging program.
We currently have approximately 65% of our expected oil production for the second half of 2017 hedged, at a weighted average floor price of nearly $56 per barrel. In 2018, we have hedged 6.7 million barrels at a weighted average floor price of approximately $46 per barrel. Importantly, these hedges are not swaps.
They are puts and collars that retain significant upside to an increase in the price of oil. Puts on 2.6 million barrels have no ceiling and the collars on 4.1 million barrels have a $60 ceiling price.
Capital expenditures of $139 million for the second quarter brings our total for the first 6-months of 2017 to $268 million, which is in line with our total capital budget of $530 million for the year. Several factors could impact our budget assumptions for the remainder of this year.
We are experiencing some cost pressure on service related to well completions, however, we are not certain of the sustainability of these cost increases. Should they persist through the second half of the year, it could result in a slight increase in our full-year budget.
Additionally, we will likely continue to test multiple completion designs to further enhance the productivity of our wells. If these designs were to be fully implemented, in the remainder development program for 2017, budget expenditures may need to be adjusted.
In summary, we are very pleased with the results achieved from our operations, the progress we have made towards advancing a flexible cost efficient development plan and the opportunities that we see to further create value for all of our stakeholders.
Operator, at this time, would you please open the lines for any questions?.
[Operator Instructions] Our first question comes from the line of Brian Singer of Goldman Sachs..
You talked to a number of the technological improvements that are leading to substantial better than expected performance versus your type curve and wondered if you could just step back and give us a sense as to where you see recovery rates in the Permian on your acreage and how that's evolving and if there's any differences in the mix as -- relative to the extent of the outperformance versus type curve?.
I'll take first -- this is Randy, I'll take first crack at that and let Jason add something if he wants to. We know that oil recovery factors in oil shales are poor.
We also know that any kind of improvement on recovery factors could be very, very meaningful, so our approach has been to, we haven't always drilled the best rate of return wells, what we've really tried to do is get the data and understand what we need to do to maximize the NAV of this cubic volume of shale that we have that's got a lot of oil in it.
So if we can figure out the right optimization, which we're still obviously, from the results, still improving on, I think that has a positive impact on the oil factor. As we talk about multiple landing points, also think that in the sense of the volume of rock we're intersecting, with our simulations, it has a positive impact on factors.
Recovery factors.
Jason, do you want to?.
Sure, I'll add a little bit. Hello, this is Jason Greenwald Vice President of Reservoir Engineering.
And I'll just underline 1 part of what Randy was talking about there, is that we do feel that recovery factors are still quite low for the resource as a total, which just underlines why we're investing so much in the technology, the infrastructure and all these continuing optimizations that we are pursuing with..
Great, thanks.
And then, if we think ahead to -- from a CapEx and cash flow perspective, maybe give us an update on the Medallion sale and then if and when that's complete, how if at all does that change your tolerance for outspending cash flow and how should we think about that in the years to come?.
This is Randy. I think we stated about all we're going to say about Medallion, which is, refers back to both the press release that came out earlier this month and what's in our Q.
So we'll defer anything on Medallion, Ron?.
And I just reiterate that we're not going to have any comments on Medallion or potential transaction on this call..
Can you speak to the CapEx cash flow strategy and tolerance for outspending cash flow to the degree your balance sheet is significantly improved by an asset sale? Would that make you more willing to outspend cash flow, or how should we think about that in the years to come?.
Brian, for 2017, we did pick up a fourth rig and as a result of that, we increased our capital program.
That fourth rig is only, since it started up right at the end of 2016, you're not getting a full benefit of the production growth and therefore, the cash flow that, that fourth rig is going to generate, in 2017, so a little bit of mismatch between the capital spend associated with it and the production and cash flow that it will generate.
Maintaining a 4-rig program going forward, we would expect to be a little better matched between the capital and the cash flow. We're not going to speculate on any type of transaction or the proceeds from that or the use of that.
2017, do anticipate to have about $150 million to $170 million outspend of which we did prefund a portion of that outspend through the small divestiture that we completed in the first quarter of this year, for about $60 million.
We think that level of outspend, given the leverage position that we have, the liquidity that's available on our credit facility, which is over $900 million, and the fact that none of our debt is due until 2022, although a significant portion of it, $950 million of it is callable today, the remaining $350 million of the long-term notes is callable in March of next year, so we do believe that, that gives us a lot of flexibility and most importantly, the fact that we continue to have a very strong hedge position that protects our cash flow..
Our next question comes from the line of Kashy Harrison from Simmons. Your question please..
Good morning everyone and thanks for taking my question. So just making sure I heard this correctly.
In the prepared remarks, did you mention that wells employing 3,300 pounds per foot are outperforming the type curve by greater than 80%? If so, can you give us an idea what the incremental costs on those completions looks like relative to the 1800-pound completions? And then finally, was this just, was that just a really good rock or is this something that could be repeated on other wells employing 3,300 pounds per foot?.
You know, we think we have a really good rock across our acreage.
And I think, the messaging is that we think the effort that we're going through, which is kind of core to how we think about the business and goes back all the way to -- back to Colt Resources and Pat and I were at Lariat, in terms of you really need to get the data to understand what's going on and part of that data takes time to get, it takes some production history.
So while I'm pretty excited about what we're seeing in terms of optimization in generally, we need to keep it in framework of we're not all about just having one great well, we want to make sure that we are maximizing the NAV across all of our acreage.
So with that as a framework, Karen, do you want the additional? Rick?.
Yes, we've had given guidance previously that our kind of base well of a 10,000-foot lateral with 1,800 pounds of sand per foot would be about $6.4 million.
Going up to 2,400 pounds, would probably add somewhere around $1 million to that, going to the 3,300 pounds on this well, probably added close to $1.7 million, $1.8 million above that base -- base level..
And then maybe just switching gears to the, hopefully I'm pronouncing this well, the Sugg-Graham package.
So this package with the wells employing tighter vertical spacing, how does that compare to other -- to wells with similar completion designs but spaced at your standard vertical well spacing at this point in their production history, basically what I'm trying to understand is, how is that 24% performing relative to other wells that were spaced maybe a little bit wider vertically at this point in their life?.
I think what we're trying to do, and I'll let Jason -- we've said now for some time that we have multiple landing points in the upper and the middle.
And we've seen a fair amount of performance across our entire portfolio that exceeds our type curve and so I think for us, what we're really messaging and trying to figure out is that hey, this is -- if we can continue to see that type of improvement and add additional landing zones, then we've really increased what's a premium kind of premier acreage base by adding substantial inventory to it..
The part that I would add to that, is for similarly completed wells, which I think I was your question, we're not really seeing any interference at this point in time with those completions. It's still pretty early in the production life and they're on managed flowback, but we're fairly encouraged with those results so far..
Thank you. Our next question comes from the line of Joe Allman from FBR. Your question please..
On the drilling problems that you've encountered in less than 3% of your horizontal wells, is there a commonality among those wells? And are there variables that increase the risk of the drilling problems? And are you able to identify the high-risk before you drill the wells?.
We recognized early on Joe, that the, that our acreage had a pretty -- it just really wasn't densely drilled and so there wasn't a lot of dense salt water disposal issues, and that's one of the advantage of our acreage is that, the spacing on the vertical wells was really pretty broad.
We started mapping salt water disposal well areas a number of years ago, this isn't a new problem, we've known for a long time that if you drill through areas where there's been a lot of saltwater injection, whether it be disposal or water flood, or whatever, then you've got to handle pressured zones.
So I think the messaging that we wanted to convey was that it's a pretty localized event on our acreage, we're just not having problems, when we've encountered it, which is very rare, we've set up to deal with it, and we've been doing it for several years.
And I think we believe in what we're doing, and we've been protesting a few other operators that attempted to inject in shallow zones on the peripheral of our acreage, but for us it's routine, the way we're going about handling it..
Okay, that's very helpful.
On the GOR issue, what drilling completion and/or production techniques enable you to influence the GOR?.
I think we've kind of indicated that the GOR is, is a predominantly a function of reservoir parameters and what you've got.
We do think that we were never excited about the attention being paid to 24 hour IPs, you heard me say that a lot, and we think one of the reasons was that a managed flow back and a little more prudent process on completing the wells does help you in terms of making sure that you don't move and change the gas relative to permeability, but I think basically, you've got what the formation will give you..
Got it.
And just a follow-up there, if you're targeting, say, better quality rock within the formation, wouldn't that optimize the GOR, or minimize the GOR, as opposed to drilling in a lower quality rock within the same formation?.
Well there's lots of reasons why we would drill into the best possible rock we have and not just -- I'm not sure why you would drill into the low quality rock.
James, do you want to make a comment?.
Yes, so the fluids that we have in our rock, this is James Courtier, Vice President of Exploration, the fluids that we have in our rock are really a result of the regional processes that have occurred over geologic times, so they're pretty ubiquitous throughout the formations that we drill and complete..
Is it safe to say, I completely understand, so when you're doing your precision targeting, you're just trying to hit the best rock to have the most productivity, but one of the benefits of that if I'm -- and it's really a question, is that in better quality rock, because you got better porosity and permeability, the oil can flow better, right.
So your GOR, all else being equal, would be lower than if you were drilling into a zone that was just less productive, and had a lower permeability and porosity..
There's a long conversation probably needs to take place there, but what -- we've not always drilled for the best productivity. What we've done is really try to drill and make sure we can understand the value creation from drilling for the best NAV, Joe.
So if the reservoir fluids that your -- and this is what James was trying to say, is the same up and down the section are basically the same or a lot alike, then anywhere you penetrate that and successfully complete any kind of stimulation, you're going to have about the same fluid content..
Your next question comes up from the line of Derrick Whitfield from Stifel Financial..
Thanks for your comments regarding saltwater disposal, certainly appreciate the detailed discussion on a topic that's very important for the industry.
Specific to Laredo, do you think there's adequate Ellenburger capacity across your position to manage longer-term water disposal needs?.
Yes. We've done, early, several years ago, we did a fair amount of looking at the entire water issue.
And in a perfect world we would continue to recycle more and more water, reuse it, but as part of that process, literally I think starting in '13, when we were first modeling our water, built our recycling plant in '14 and tried to get as much of it in pipe as we could, we wanted to make sure that we had adequate disposal.
You're always going to have some. And we think the Ellenburger doesn't require as much pump pressure, it's a pretty good place to put the fluid that you can't reuse.
Obviously it costs more to drill an Ellenburger disposal well but we're pretty comfortable that the things we did, three or four years ago, as far as handling water, is the right way to go..
Thanks Randy.
And maybe one more comment if I could, in light of what you guys know today, on the 2,400 pound per foot and 3,300 per foot designs, are you confident that 3,300 pound per foot is the upper boundary?.
I think we're, in Laredo's view, we've drilled 300, over 300 horizontal wells, and we're still -- the next one we drill we hope we optimize it and it's a little more custom well than the last one we just drilled.
So I think our view is that while we're excited about seeing, obviously, 80%-plus over our type curve is meaningful, but what we need to do is put that back in context of what it does economically, what it does to the NAV, how it adds to well spacing.
We're still early, I think, in a game of understanding what's the right spacing, cluster spacing, what's the right amount of sand, so I'm not prepared to say much more than, I don't want to call out a max, I want to call it -- it may be way too much, it may not be enough.
We're early in the optimization and a lot of things we're seeing are very, very exciting to us..
Our next question comes up from the line of John Herrlin of Societe Generale. Your question please..
Randy, when you were discussing modeling versus actual implementation of your well designs, when you start getting to the say the middle and upper Wolfcamp, are your frack designs pretty much universal or are they formation specific? And then aerially, do you find, within the same formation or zone that you can apply the same frack or are their differences within your production corridors?.
That's a good question John. I think the way we're viewing this is that, we're not going to go do 10 wells identical unless we think there's modeling backup and so far what we've done is pretty much customized, we're not changing all the parameters on every completion but we predict what we're going to find before we drill it.
We use that to help us select the right landing zone.
We drill it, we look at what we've got and then we do take the time between moving the rig off and getting in line for the completion to really look at how we want to customize that exact completion and if we're looking at a lot of variables, that we've kind of narrowed down we think to what matters, so I don't think you should anticipate us, even within a corridor, not having some variance perhaps, on the completion.
Certainly this early, in the optimization process.
James, do you want to add something to that?.
I think from my perspective, it's really a couple of things. The first thing, the goal of the modeling is really just to try and predict the outcome. So as we model, we can model many different types of completions and well spacing to see what we believe the optimum economic outcome is and that's what we're trying to do in the field.
What we also try to do in our well packages is really, like Randy mentioned, is to test 1 or 2 different things, so we can observe that specific change, whether that relates to specific targeting, whether that relates to specific completion designs in terms of proppant loading or cluster spacing or fluid type or whatever.
So really that's what we're trying to achieve overall..
Next one for me is simple.
I assume the Ellenburger's casted, so its easy to dispose of the water as you said, Randy, but no issues with seismicity, adding the water, like in, say Oklahoma?.
We're in an area that's one, geologically pretty stable, with our Permian. And the pump pressures are pretty low. The wells, or our disposables wells are spaced out very broadly.
I think on our acreage, we're less than 2 barrels of produced water for every barrel of oil and in Oklahoma at some places they were 15 barrels plus of water for every barrel of oil, so I just don't think there's a good correlation, we're very aware, we monitor the water, we monitor the pressures that it takes, but you're right, the Ellenburger is pretty good disposal zone..
And our next question comes from the line of Blaise Angelico of Iberia Capital..
Just curious on that 6-well package testing the co-development on the upper Wolfcamp, how are you thinking about the completion design on those wells?.
I'd let Karen or Jason answer specific, but again, I think what the messaging is, we're still early in trying to optimize those completions. And in fact, depending on how the spacing works, we might use more, we might use less sand.
Cluster spacing is still something that we're seeing in terms of our optimization, things that we want to pay attention to. So I don't want to say that, that's the completions that we're going to use everywhere, with that spacing quite yet.
Dan, You want to say something?.
This is Dan Schooley, on that close well package, we're going to test several different things, we're going to test different cluster spacings, we're going to use 1800-pound of sand and run different cluster spacings around that to see if we can keep the frack, obviously, as close to that bore hole as we can, that would support this co-development idea that we're testing as well..
Got you, appreciate that. And just as you're looking down the road, how many other additional codevelopment tests are planned for the remainder of the year? And....
I think we're the -- the messaging is that we're going to design our program based on what we see both from a completion point of view and the spacing point of view. We're giving -- we're seeing good reason to continue the spacing test.
We're seeing good data that makes us think we still have a lot of room on optimization, so we're kind of letting the -- this may not be the answer that you're looking for specifically, but we're kind of letting data drive those kind of decisions.
James?.
So, I think we have about three large packages that we have coming up on the schedule for the rest of the year..
Thank you. Our next question comes from the line of Cindy Treska from Goldman Sachs. Your question please..
Good morning, thanks for taking my question.
On service costs, can you speak to what you're seeing in terms of pressure in the Midland so far in the third quarter? And have you locked in any portion of your service costs through the rest of the year?.
This is interesting to me, service costs over time, in my experience kind of always go up. And we want the service providers to be -- to bring us a good crew, you heard me say this before, a crew that has had some sleep and is safe.
We want them to bring us good maintenance on the equipment that we got, there is nothing worse than getting out there and then having to wait a day or two for a part to arrive, but thirdly, we want to see the service providers to continue to bring us new technology, which we hopefully, allows us to be more economically efficient and I think, I'll let Rick address budget in terms of what we're seeing as service costs but we didn't adjust our budget down, as far as service costs got for a while, we didn't think that long-term that was a good service costs plateau to have, so yes we're seeing some pressure on cost.
I think we would have been surprised if there hadn't been at some point..
When we put our budget together initially for 2017, we did include some level of escalation for service costs, and certainly for some of the testing activities that we're doing and expect to continue to do, with that -- with the $530 million capital program as you saw through the first half of this year, even with some of those service costs already reflected, those increases in service costs reflected in our second quarter, we're running about right on track with what we would anticipate for the first half of this year.
We are watching that very closely, we're looking at the results of the wells, what the costs associated with some of these tests are, and anticipate that we will be able to stay relatively close to that $530 million capital program, and that excludes any Medallion investments, through the rest of this year.
We are seeing a little bit of pressure, some of that was already built in and we will balance the type of testing in the programs that we do, relative to the performance that we're receiving from those tests to ensure that our outspend is reasonable..
And one follow-up if I could, I wanted to know how uniform your results have been in Reagan County, so how far south in the Midland Basin do you think you could go before economics get significantly worse?.
Well, as you know, Cindy, we bought our acreage early. We started buying well before horizontal -- people were still talking about drilling the cheapest vertical wells out there when we were drilling horizontal wells. So we bought our acreage in a buy out line that we thought at the time was pretty much the same acreage.
And it turns out that we were grossly correct, it all kind of looks the same.
So we expect our acreage, while it will have differences literally well by well, and certainly as you run up, what is it, 80 miles north to south? There'll be some differences but in general, we expect our acreage to have that volume of rock, has a lot of oil and gas in it that we need to go get..
Thank you. Our final question comes from the line of Philip Stuart from Scotia Howard Weil. Your question please..
Most of them have been asked. I guess kind of one quick one.
One of your peers to the west of your Reagan County acreage has recently completed a couple very prolific Wolfcamp C wells, I was just wondering if you all have learned anything from those wells that maybe change your view on your lower Wolfcamp zone at all? Or perhaps, if those wells have persuaded you all to look at drilling more lower Wolfcamp wells on your Reagan County acreage going forward?.
Laredo has historically drilled somewhere around 30 plus or minus lower Wolfcamp wells, we haven't drilled any in three or four years, the ones that we drilled, I would certainly like to go back over and do with what we now know with the earth model and everything else, and I'm confident that we're going to drill Lower Wolfcamp wells this year.
It's a pretty high -- we like what we see, we do have a Lower Wolfcamp well coming up in a six-well test. I think it's another indication to us and we've seen this now in a lot of our surrounding acreage is other operators are now helping us prove up the quality of our acreage.
We know the Lower Wolfcamp is going to produce on our acreage, we're excited to do it with the Big Data model and our optimized completions..
And are you going to test that kind of on 2,400 pound per lateral foot or 3,300 pounds per lateral foot? I'm sure the wells that were drilled three or four years ago were using a very basic completion design?.
Yes, the wells that we, a lot of those Lower Wolfcamp wells we drilled were pretty short laterals and not a lot of sand, I think we're kind of in a position to where we'll decide exactly how we want to complete that well as we get closer to it and see the data from it. I'm not comfortable with today saying it's going to be 18 or 22 or whatever.
So what I will say is that we know it's going to produce. A lot of our earlier wells aren't that exciting but then again, we had pretty small amounts of sand and not a lot of lateral length. So we're excited..
And this does conclude the question-and-answer session of today's program. I'd like to hand the program back to Ron Hagood for any further remarks..
Thank you for joining us for our second quarter earnings conference call. This concludes our call, and have a good morning..
Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program. You may now disconnect. Good day..