Ronald L. Hagood - Laredo Petroleum, Inc. Randy A. Foutch - Laredo Petroleum, Inc. Daniel C. Schooley - Laredo Petroleum, Inc. Richard C. Buterbaugh - Laredo Petroleum, Inc. T. Karen Chandler - Laredo Petroleum, Inc..

Derrick Whitfield - Stifel, Nicolaus & Co., Inc. Brian Singer - Goldman Sachs & Co. LLC Sameer Panjwani - Tudor, Pickering, Holt & Co. Securities, Inc..

Good day, ladies and gentlemen, and welcome to the Laredo Petroleum, Incorporated First Quarter 2018 Earnings Conference Call. My name is Sonia, and I'll be your operator for today. At this time, all participants are in a listen-only mode. We will be conducting a question-and-answer session after the financial and operations report.

As a reminder, this conference is being recorded for replay purposes. It's now my pleasure to introduce Mr. Ron Hagood, Vice President, 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; and Ben Klein, 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 these forward-looking statements for a variety of reasons, many of which are beyond our control. In addition, we will be making reference to adjusted net income and adjusted EBITDA, which are non-GAAP financial measures.

Reconciliations of GAAP net income to these non-GAAP financial measures are included in yesterday's news release. Yesterday afternoon, the company issued a news release and presentation, detailing its financial and operating results for first quarter 2018.

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 will now turn the call over to Randy Foutch (00:01:50-00:02:12)..

...we described our progress toward a plan to develop our Upper and Middle Wolfcamp formations based upon 32 wells per drilling spacing unit or DSU. The path to executing this development plan in 2018 consisted of drilling packages of wells in 2017 that could validate what our miles were telling us.

Later in this call, Dan will give an update on the performance of two packages completed in 2017 that are confirming our assumption to a tighter spacing. These packages give us confidence in the productivity of wells developed on both 24 and 32 Upper/Middle Wolfcamp wells per DSU spacing.

We are moving ahead swiftly on our higher-density development plan for our Upper and Middle Wolfcamp formations. For the remainder of the year, 20 to 25 of our scheduled completions have been or will be developed on 32 wells per DSU spacing.

We will be adding a fourth horizontal drilling rig at the beginning of the third quarter, and anticipate adding a fifth rig at the end of 2018 or beginning in 2019.

We are confident we have identified key production drivers in all of our formations and can adjust spacing and completion design based upon the economics generated in various commodity price and service cost environments.

Our goal has always been to maximize the value of our asset through a development strategy that is flexible and sustainable over the long term. The company believes it has a flexible plan that can respond to new data and economic inputs to drive capital-efficient growth.

The company's past infrastructure investments also support capital efficient growth. We have built out five production corridors that can support approximately 2,500 horizontal wells and enable the drilling of large development package that require the movements of large volumes of oil, water and gas on and off lease.

The majority of the capital for these corridors has been invested and the benefits they provide to Laredo build rapidly as more wells are drilled on them. A core tenet of Laredo's business philosophy is owning our own infrastructure and pursuing optionality in the marketing of our production.

This has become a focus for the industry recently as takeaway capacity is tight. Widening basis in the Permian for both oil and natural gas have been swift, but it is something we've seen before and planned for.

Laredo prepared for this by building our own gathering systems, contracting firm capacity out of the basin, and hedging the basis on a significant amount of anticipated production that we expect to sell in the Midland market for oil or in Waha for natural gas.

Based on our confidence in our efficiencies and results, we have increased our expected total production growth for 2018 to greater than 12%. This has been driven by continued outperformance of our natural gas and NGL production.

Our oil production continues to meet our expectations, and we have reiterated our previous oil growth guidance of greater than 10%. I will now turn the call over to Dan for an operational update..

Thank you, Randy. The first quarter was a solid operational quarter for the company. We exceeded our production guidance on both oil and total production, and total cash expenses were in the aggregate in line with the guidance. We completed 20 wells in the quarter, four more than anticipated.

This outperformance was driven by more efficient completion operations and completion design modifications. At the beginning of the year, we rebid our stimulation services contracts and brought on a second full-time dedicated completion crew.

This crew has been more efficient than crews we were utilizing in 2017, from both the stages completed per day and non-productive time perspective. With the goal of reducing capital costs and cycle time and increasing capital efficiency, we made several completion design modifications in the first quarter.

Part of the well cost increases we saw in late 2017 were related to reduced perf cluster spacing from 54-foot clusters to 30-foot to 15-foot clusters. These completion design changes were tested in support of our 32 wells per drilling in the spacing unit development plan.

The results have been positive, and now we are working to maintain the positive well spacing results from tighter cluster spacing, but also reduce cycle time and well cost by increasing the number of clusters per stage. The completion's optimization work was performed at a constant number of clusters per stage to fully evaluate the impact.

However, by keeping the number of clusters per stage constant, this shortened each individual stage, thus increasing the number of stages per well. Now we are working to increase our base well design of 30-foot clusters at five clusters per stage back up to the 8 to 10 clusters per stage range.

This has the potential to reduce well cost by approximately $300,000 per well at 10 perf clusters per stage spaced at 30 feet. We are encouraged by the results thus far and intend to continue phasing in the increased clusters per stage throughout the year. During the first quarter, we also modified completions by reducing fluid concentrations.

By reducing the amount of water used in the completion, both cost and cycle times were reduced, and we achieved a savings of approximately $800,000 per well. These wells were completed as parts of larger packages so performance could be directly compared with traditional completions.

We will continue to monitor the performance of these wells relative to both the offsetting traditional completions and relative to the significant capital savings associated with the reduced fluids.

For now, we do not anticipate completing any additional 2018 wells in this manner, and we have adjusted expectations for the productivity of the wells, utilizing reduced fluid concentrations in our second quarter 2018 and full-year 2018 guidance. Another avenue to reduce cost that we are pursuing is utilizing in-basin sand.

To-date, we have not fully implemented in-basin sand due to third-party delays and opening of mines in close proximity to our acreage that will generate the most savings. Currently, it is anticipated that we will begin receiving sand from these mines via our stimulation services provider in August of this year.

Once fully implemented, we anticipate savings of approximately $400,000 per well. When we released our 2018 budget, we explained that we expect cost savings of $600,000 per well on average throughout the year. These savings were layered in during the year, increasing each quarter.

As we mentioned, the bulk of the expected savings were comprised of completion design modifications in the utilization of in-basin sand. To err on the side of conservatism, a portion of our D&C capital increase is to account for the later start of the in-basin sand.

We do, however, still think we can achieve the targeted per well savings by the end of 2018 with the ultimate implementation of in-basin sand coupled with completion design modifications such as longer stages. As Randy mentioned, we are moving forward with our 32 Upper/Middle Wolfcamp wells per drilling and spacing unit development plan.

The results of two recent packages give us great confidence in our modeling. The SUGG-A 157/158 five-well package in the Upper and Middle Wolfcamp developed on 32 wells per drilling spacing unit spacing is on average at approximately 110% of type curve after nine months of production on a lateral length adjusted basis.

The nine-well Lane Trust package, seven wells of which were drilled in the Upper and Middle Wolfcamp formations, was developed on a 24 well per drilling spacing unit spacing. The seven Upper and Middle Wolfcamp wells are on average at approximately 110% of type curve after more than 50 days of production.

Three of the wells in the SUGG-A package I just mentioned were 15,000-foot wells. As we have discussed previously, these wells were slow to clean up, but they are now in line with their lateral length adjusted type curve. Through the first quarter of 2018, we have completed 19 horizontal wells with lateral lengths of 11,500 feet or longer.

The production history of this group of wells demonstrates there is no performance degradation associated with longer lateral lengths.

We now have more than 500 land ready Upper and Middle Wolfcamp locations of at least 15,000 feet and anticipate drilling more of these extended rates laterals as we increase the average lateral length of our development program. Recently, industry-wide worries have reemerged relative to the ability to move oil out of the Permian Basin.

These worries have been reflected in the Midland-Cushing basis differential, which has gone from Midland trading at a premium in the first quarter of this year to recently trading at a discount of $10 per barrel.

Laredo has always recognized the product takeaway risk associated with operating in a fast-growing basin and the infrastructure-associated dislocations that can arise. For years, we have taken steps to mitigate the impacts of such events. One such step Laredo took was entering to a crude oil purchase contract with Shell Trading (US) Company.

This contract, effective October 1, 2016, was the second of these contracts we had undertaken with Shell Trading dating back to May of 2012. The contract provided a menu of pricing alternatives for Laredo's crew that enabled us at our option to take advantage of Midland market pricing as well as U.S. Gulf market pricing.

The contract covers 19,000 barrels of oil per day of Laredo's gross production as well as a like quantity of crude oil from Shell, and extended through June of 2020.

As we've disclosed previously, Shell Trading filed suit on May 3, 2017 alleging that the contract contained a drafting mistake and did not accurately reflect the compensation to be paid to Shell under one of the menu pricing alternatives. Laredo does not believe there was a drafting mistake. The contract is clear.

We performed our obligations under the contract exactly as the contract was written and agreed to by both parties. As of May 1, 2018, Shell Trading has determined to no longer perform the obligations it has agreed to under the contract and notified Laredo it was terminating the contract.

Again, we believe Shell Trading's claims are without merit, and we intend to pursue our rights under the provisions of the contract and seek all appropriate damages from Shell Trading. We have taken a number of actions to mitigate some of the damage from Shell Trading's breach.

I will discuss the physical marketing details, and later, Rick will discuss the financial implications. We intend to transport 10,000 barrels a day of gross production from our fuel production to Magellan's BridgeTex pipeline under our firm transportation capacity.

Previously, crude oil produced at our lease did not utilize our BridgeTex pipeline transportation capacity. With this change of arrangements in June, 10,000 gross barrels per day will be marketed in the U.S. Gulf Coast that was currently a significant premium relative to the constrained Midland market.

To hedge our basis exposure on this marketing arrangement, we have entered into swaps that lock in the difference between Midland and Houston pricing on 10,000 barrels of oil per day.

The remainder of the barrels Shell Trading had been buying are now contracted to third parties to be marketed at Midland base pricing on a month-to-month basis as Laredo continues to explore various alternatives, including additional long-term exposure to the U.S. Gulf Coast pricing.

To hedge our basis exposure for these barrels, we have swaps that lock in the basis between Midland and Cushing pricing on 10,000 barrels of oil per day.

I would like to stress the tremendous job our crude oil marketing team has done in the face of this improper termination in finding buyers for our May production on very short notice and making longer-term arrangements for our production in future months.

Laredo's investment in field infrastructure and its contractual arrangements with the Medallion for redelivery of its crude to multiple market hubs has provided the company with the ability to not curtail or shut in any of its production as a result of this wrongful termination.

In addition to a widening oil basis, the Permian Basin is also facing a widening basis for its natural gas production that is generally sold at the Waha Hub. The Permian Basin currently has approximately 11 Bcf a day of natural gas takeaway capacity, which is well in excess of the current 7 Bcf a day of production.

The widening basis at Waha is therefore characterized as a lack of demand rather than a lack of capacity, as Permian natural gas supply now exceeds demand, and this deficiency is expected to continue until new infrastructure in Mexico is in place and ready to accept the approximately 3 Bcf a day of export capacity that's currently in place.

In the interim, new pipeline connectivity to the East should provide additional demand for Permian production in the second half of 2019. Laredo sells approximately 90% of its wellhead wet natural gas production to Targa. Our natural gas is transported and sold out of the basin by Targa, who holds firm transportation agreements.

In addition, Laredo has approximately 170 miles of natural gas gathering systems in the field that is connected to and can deliver to multiple other third-party purchasers, for delivery to plants that have access to different residue pipelines.

Laredo also maintains flares in the field that can provide temporary relief for up to 180 days if necessary, to prevent shut in of crude oil production.

We have protection from the Waha basis on approximately 75% of our anticipated natural gas production for the remainder of 2018, through a combination of natural gas puts and collars that are priced at Waha and Henry Hub-Waha basis swaps. The weighted average floor price of our puts and collars is a Waha price of $2.50 per MMBtu.

The basis swaps are priced at Henry Hub less $0.62. I will now turn the call over to Rick for a financial review..

Thank you, Dan, and good morning. Last night, in our first quarter 2018 earnings press release, we reported net income of $86.5 million or $0.36 per diluted share, and adjusted EBITDA, which is non-GAAP financial measure, of $143.4 million.

Adjusted EBITDA increased 33% from the first quarter of 2017, almost double the 18% increase in our realized price per BOE during the same period, while unit cash costs decreased 4%. As Randy mentioned, we increased our expected total production growth for 2018 to greater than 12% and reiterated the previous oil guidance growth of greater than 10%.

This reflects the dynamic demonstrated in our first quarter 2018 results, where we experienced more than anticipated growth in natural gas and NGL volumes while our oil volumes grew as expected. Our guidance anticipates uneven quarter-to-quarter growth throughout 2018.

11 of the 17 expected completions in the second quarter are in the single package that is forecasted to be brought on production at the end of the quarter, leaving just six new completions that are expected to contribute to production during the second quarter.

This, along with a couple of other larger packages, are projected to weight production growth towards the second half of 2018. We have increased the drilling and completion portion of our 2018 capital budget to reflect increases in average working interest and average lateral length for the year.

The increases in wells scheduled to be completed primarily in the third quarter of 2018, and thus the positive impact to production, should occur partially in the fourth quarter of 2018 and into the first quarter of 2019. As anticipated, pressure on service cost, chemicals, and labor are driving some increase to LOE cost.

The Laredo unit LOE remains one of the lowest in the basin. For the first quarter of 2018, unit LOE was $3.85 per barrel of equivalent. This was slightly higher than our guidance primarily due to some extra well work in the quarter that represented approximately $0.15 per barrel of equivalent.

We expect this work to be concluded this quarter and that our unit LOE will trend down slightly over the remainder of the year. In total, our unit cash costs were within guidance and down about 4% versus the prior-year quarter.

As Dan mentioned, beginning May 1, as a result of the Shell termination of our contract with them, we have had to change the way we market 19,000 gross barrels of oil per day or approximately 14,000 net barrels of oil per day. There will be a couple of moving parts in our financials statement resulting from this change.

First, our crude oil price realizations in the second quarter are expected to be approximately 91% of WTI. This is a decrease from our first quarter realized price of 98% of WTI.

I would point out that prior to the Shell breach, we would have guided second quarter crude price realizations to 95% of WTI, reflecting the widening Midland basis for our oil not sold to Shell. Second, beginning in June, we no longer expect to buy oil in Colorado City to meet our BridgeTex commitment.

Instead, we plan to utilize our field production for this purpose. This will mean that sales of oil transported on BridgeTex and marketed in the U.S. Gulf Coast will now be reflected in our crude oil realized price.

We expect the revenue and cost items related to purchased oil will reflect two months of activity in the second quarter and no longer appear in our income statement beginning in the third quarter.

Additionally, although not a change resulting from the Shell termination but related to the discussion, we entered into a basis hedge to lock in the positive difference between Midland and Houston pricing on 10,000 barrels of oil per day.

The economics of this transaction will be reflected in the derivatives line items in our income statement and statement of cash flow. As a reminder, as of January 1, the company adopted new revenue recognition guidelines issued by the FASB and Topic 606.

As I discussed last quarter, this means that the $141 million deferred gain from the sale of our interest in the Medallion pipeline system has been recognized in the beginning balance of our retained earnings. This accounting treatment is detailed in Note 3 of our Form 10-Q that is expected to be filed later this afternoon.

You will recall that mid-February, our board of directors approved the $200 million share repurchase program good for two years, which allows the company to repurchase stock, if any, from time to time.

We have initiated share repurchases under this program, and through March 31, we have invested over $58 million to repurchase approximately 6.7 million shares at a weighted average price of $8.69 per share.

Last month, in connection with the semiannual redetermination of our senior secured credit facility, our lenders increased our borrowing base to $1.3 billion. Additionally, our pricing grid for the credit facility was reduced by 75 basis points.

The upsized borrowing base reflects the increasing value of Laredo's PDP reserves, and the lower pricing grid reflects Laredo's solid financial structure. At the company's option, we increased our elected commitment on this facility to $1.2 billion.

This solid financial position including nearly $1.2 billion of liquidity provides added flexibility to accommodate multiple actions at our discretion. We will continue to evaluate all activities on their merits of growing value to our existing shareholders.

Thanks to the dedicated efforts of Laredo's technical, operational, and corporate staff, the company is moving its development plan forward and accelerating the recognition of the value of our asset in the Midland Basin as evidenced by our increasing rig activity. Operator, at this time, I would like you to open the lines for any questions..

Thank you. Our first question comes from Derrick Whitfield of Stifel Financial. Your line is now open..

Good morning all, and congrats on a strong start to 2018..

Good morning, Derrick. Thank you..

Randy, in your press release, you indicated that Laredo will likely add a fifth rig later this year.

Outside of commodity prices, are there any other checklist items that need to be addressed prior to adding the rig?.

I think we look at a lot of things. We have inventory. We have infrastructure. We have a lot of data that would support that. So, Derrick, I think in our view, we're financially secure enough that we could accelerate activity at that level and still do the share repurchase program or have a lot of optionality.

So, I think we indicated some time ago that we were thinking about some methodical acceleration, and that's how we view that. We'll be careful in that, but we certainly have the structure, the inventory, the infrastructure to add rigs..

Thanks.

And then as my follow-up, given the positive results that you've experienced from your first three 15,000-foot laterals, could you comment on how you see the lateral progression lengths into 2019 and 2020?.

We've indicated that we think our average lateral length will increase. We've indicated that we have a number of 15,000-foot locations in our inventory, given the acreage. We've indicated some that we're still blocking and tackling in terms of trying to increase that inventory.

So I think that we'll probably increase lateral length as part of our CapEx increase. If you – about two-thirds of our capital increase was related to lateral length and increased working interest. So I think that's kind of where we're headed on that. We'll increase lateral length as we go out in the year..

Thanks for taking my questions..

Thank you..

Thank you. Our next question comes from Brian Singer of Goldman Sachs. Your line is now open..

Good morning..

Good morning, Brian..

Can you talk to the production mix and the implications of the guidance change, the guidance increase, which would imply better than expected natural gas and NGLs? Is that driven by decline rates being a little bit lower for those parts of the mix, or is it more on new well performance?.

Hey, Brian. This is Dan Schooley. I think that ultimately, we think it's a lower decline rate for the mix of production that we have. We also have a little bit less activity, new wells coming online. But generally, we think it's related to the lower decline rates that we're seeing on our PDP..

Can I switch things up on you? I want to have you take Laredo from here, the balance of the call, and I'm going to hop over to (29:45)..

Hi.

Can you guys hear me okay?.

Yes..

Okay. Thanks. My follow-up question is with regards to the Shell contract, and this one might be a tough one. But any sense on timing of resolution? And appreciate how quickly you've tried to solve some of the issues with regards to the 2018.

But at what point do you start needing to kind of think about filling gaps on 2019?.

Well, the way our infrastructure was built, the way we view this, I think, it somewhat addresses the robust nature of that, by what we've been able to do so far. But I don't have any anticipation or any schedule for when we'll get resolution..

Yeah. And, Brian, I'd just add to that, I think that Randy is exactly right. Our investment in infrastructure and our investment in Medallion and our ability to move crude oil around in the basin was demonstrated pretty dramatically with this termination. This happened after nominations for May were already in place to move the barrels to Shell.

And so, we had literally 48 hours to move our crude oil around, and we were able to do that without a single barrel being shut in. So, that kind of demonstrates our ability and our flexibility to move things around. But we have no indication of how long this litigation may take. We are taking additional steps.

As we described in my remarks earlier, effective June 1, we think we're going to be able to place 10,000 barrels a day of the 19,000 barrels into our BridgeTex transportation and move that crude oil to the Gulf Coast, and enjoy the current spread between Midland and Houston. The other 9,000 barrels a day will take longer.

We do have some things that we're working on. And hopefully, we'll have that optionality for all of those barrels back in our portfolio quickly..

Thank you very much..

And our next question comes from Sameer Panjwani of Tudor, Pickering, Holt. Your line is now open..

Hey, guys. Good morning..

Good morning..

Good morning..

Appreciate all the color you provided on the potential improvement and capital efficiency.

But can you clarify what exactly is baked into your target well cost and what could be incremental upside? And then also, how does the perf extra completion design compare to your base design on a capital efficiency perspective?.

Karen, do you want to take that?.

Sure. This is Karen Chandler, VP of Operations. So, our base design right now, as we talked about, the original design was set up with the expectation of about $600,000 per well cost savings for the year. Other than the delay of the in-basin sand that we discussed in the call, we're still on track to achieve that cost savings.

So, we're continuing to work in-basin sand. Our expectations now are early third quarter working with the frac service company. We're also continuing to work the design efficiencies. So, again, we're on track other than the discussion that we had previously with just the delays in the in-basin sand..

Yes. Sameer, I think in the first quarter, we did have savings of approximately $600,000 per well by the utilization of the decreased fluids and the increased stage length.

So, we do know that we're certainly in range of being able to achieve the savings that we have indicated earlier, and we demonstrated that with what we did in the first quarter, I think..

Okay. That's helpful.

And then going back to the conversation of, I guess, just how the increased lateral lengths are just taking some additional time to clean up and I guess the commentary on the lower decline on the PDP impacting the hydrocarbon mix in the near term, I guess, is there any need to adjust the type curves to account for either of those issues especially as you continue to expand your lateral lengths going forward?.

At this point, we don't think so. As you know, we've been slow to adjust the type curves even though we have substantial history of some doing most of our wells doing better than the type curve. We think we like the type curve. We look at it. And we're careful to make sure we communicated to you what we're actually seeing.

But I think at this point, we're pretty comfortable with the type curves.

Part of the issue is that we're still doing some optimization work above with sand and lower fluid concentrations and stage, everything else, but I think the important thing for us is that we've been drilling packages of wells based on 24 wells per spacing unit and 32 wells per drilling spacing unit.

And the early indications you heard me say how long we like to have that before we change things. But those wells are drilling – they are currently producing above type curves. So, that's something we're very interested in but no need to adjust today..

Okay. Thank you..

Thank you..

Thank you. And this does conclude our question-and-answer session. I would now like to turn the call back over to Ron Hagood for any closing remarks..

Thank you for your interest in Laredo. This concludes this morning's call and have a good day. Thank you..

Ladies and gentlemen, thank you for participating in today's conference. This concludes today's program. You may all disconnect. Everyone, have a great day..