Good day ladies and gentlemen, and welcome to the Laredo Petroleum, Inc. Third Quarter 2019 Earnings Conference Call. My name is Sarah and I will 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 call is being recorded for replay purposes. It is 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 Jason Pigott, President and Chief Executive Officer; Karen Chandler, Senior Vice President and Chief Operations Officer; and Michael Beyer, Senior Vice President and Chief Financial Officer, 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 non-GAAP financial measures. Reconciliations to 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 third quarter of 2019. We will refer to the presentation by page during today’s call. 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 Jason Pigott, President and Chief Executive Officer..

Thank you, Ron. Good morning and thank you for joining us for our call today. Beginning in late 2018, Laredo began transition from a development strategy focused on net asset value accretion to one driven by return and free cash flow generation.

To accomplish this, we widened spacing , moderated our pace of development, and made the difficult position to align G&A with the slower development pace. Throughout 2019, we have executed on these initiatives and results have steadily improved throughout the year.

On our website, we have posted an earnings deck that I'll refer to during my prepared comments and encourage you to follow along. On Slide 3, we lay out our updated strategy.

We plan to continue building upon the work we've done in 2019 to further accelerate growth and free cash flow, and oil growth on a debt adjusted per-share basis to increase the value for our stakeholders. The first pillar of this strategy is to continue building on a great work the team has done and optimize our existing operations.

High grading the inventory and optimizing completion designs to maximize oil productivity and maintaining our focus on cost and operational efficiency to further improve our basin [ph] low cost structure is our top priority.

To implement the second pillar of our strategy, further improving our capital efficiency in corporate returns, we intend to opportunistically pursue transactions like the one we will discuss in a moment to target high margin inventory that will move to the front of our development queue.

By applying our cash flow to the acquired high margin development opportunities, we expect to increase corporate returns, improve oil growth, and free cash flow generation. We believe that the current environment is presenting an opportunity to add high quality acreage at multi-year low valuations.

By being very selective on acreage quality and price, we tend to make acquisitions that are quickly accretive and they execute while maintaining a competitive balance sheet and debt associated with the acquisitions that we paid off in a historic amount of time. Additionally, we see opportunities to increase scale through consolidation.

Combining operations to eliminate redundancies and leveraging our basin-leading low cost structure to achieve synergies can drive increased returns to our stakeholders. Any transaction will need to make operational sense be accretive on a debt-adjusted per share metrics and ultimately result in a stronger balance sheet.

Turning to Slide 4, our results in the third quarter illustrate the first pillar of our updated strategy that is optimizing our existing acreage and operations.

For the third quarter in a row, we beat both oil and total production guidance for the quarter, and we continue to reduce controllable cash costs of lease operating expenses and cash G&A, which are far lower than our similarly sized peers on a per-unit basis.

These results combine with disciplined capital expenditures which were about 17% below street estimates, and robust hedging gains generated 49 million of free cash flow during the quarter. On Slide 5 is further confirmation of our success optimizing existing acreage.

On the top graph, we have the results from our four packages of wider spaced wells completed in the second and third quarters of 2019. In total, these 23 wells are outperforming both our initial expectations and our Wolfcamp oil type curve. You can see that two packages are outperforming the type curve and that two are below.

This distribution is what we expected for a range of results when we established our Wolfcamp oil type curve and reinforces our confidence at this type curve is accurate. The bottom graph utilizing data from RSEG, demonstrates the success we have had driving down our drilling and completion cost and enhancing our capital efficiency.

During 2019, we have demonstrated the lowest average cost per lateral foot in the basin amongst this peer group and are moving even lower. We are currently delivering average D&C cost per lateral foot of $660 for a standard completion design.

Slide 6, demonstrates how this success is driving increasing oil production and free cash flow estimates while improving debt levels as we use the free cash flow to pay down our revolver.

From our initial budget expectations in February 2019, oil production estimates for the year have increased 1600 barrels per day, and free cash flow estimates have increased by more than $40 million. We've also delivered on our commitment to pay down the $80 million we drew on our revolver in the first quarter of 2019 by the end of the year.

In fact, we delivered on the commitment by the end of the third quarter and have currently paid down another $10 million more than what we drew on the first quarter, not including the pending acquisition.

These results have been supported by a very robust hedge book in 2019 that has generated $36 million in cash from hedge settlements to the end of the third quarter of 2019. Our 2020 hedges are similarly robust, and on Slide 7 we show the hedge is currently in place for 2020.

We've hedged a significant amount of our expected oil, natural gas, and natural gas liquids production at prices that are currently above 2020 levels. Our 2020 hedges are valued at $99 million at the end of the third quarter of 2019 and helped to drive our confidence in cash flow projections as we finalize our 2020 development plans.

Turning to Slide 8, we have made an acquisition of tier-one high margin acreage in Howard County expected to close in December that represents the first step in Laredo’s strategy to target consistent free cash flow generation and oil growth per net adjusted share.

This acquisition opens up a new operating area for Laredo that transforms our near-term development plan. The acreage is in the area of high oil productivity with offsetting wells indicating first-year production that is 80% oil and first-year oil productivity that is 55% higher than our Wolfcamp oil type curve on our existing acreage.

This is not acreage that is being acquired to languishing our development queue as expect to begin drilling our first package in the first quarter of 2020 and that the majority of our completions will be on this acreage in the 2020 to 2022 timeframe. Development is expected to focus on the lower Spraberry and upper and middle Wolfcamp formations.

We estimate four lower Spraberry locations, six upper Wolfcamp, and six middle Wolfcamp locations per DSU totaling 16 wells per DSU in these primary zones and 120 primary locations on the acreage. This acreage has practically no horizontal drilling and that's limited existing parent/child considerations to work around.

We currently expect to develop the locations in 16 well packages targeting primary zones to limit future parent/child interactions. As we are evaluating this acreage in assessing potential productivity, we had a substantial amount of information from offsetting wells to work with.

The blowout map on Slide 8 shows the locations around the acreage we deemed relevant after an extensive review prior to drilling on this area. The green line on the graph at the bottom of the slide demonstrates the two-year accumulative oil productivity of the relevant offset locations adjusted to a 10,000-foot lateral length.

With this transaction, we believe we have purchased Tier 1 acreage at a conservative multiyear low valuation. We had the advantage of substantial offsetting production with which to judge productivity but without value destroying parent-child issues to work around the actual leasehold.

The transaction is not just for 7,360 net acres, which are 96% operated, but also includes 750 return-enhancing net royalty acres within the operated acreage. Applying our basin-low D&C and operating cost to the development of this acreage, we believe, makes the transaction accretive very quickly and drives improved corporate returns as soon as 2020.

Moving to Slide 9, I'll expand on that statement. The graph in the upper-left hand portion of the slide demonstrates the dramatic positive impact of cash flow generation that results from putting our cash flow to work developing the Howard County acreage versus our existing acreage. Our existing acreage has good economics.

The acquired acreage is superior. The table at the bottom of the slide further demonstrates the higher expected oil productivity over two-year period. Based on these assumptions, we expect to become substantially more capital efficient in the 2020 to 2021 time period.

Versus previous indications for 2020 to 2021, we now expect to be able to generate mid- to high single-digit annual oil growth, increase our oil cut to 40% and generate cumulative free cash flow of $100 million.

We expect to fund the transaction with our credit facility, which based on our net debt-to-adjusted EBITDA at the end of the third quarter of 2019 would move our ratio to only 1.9 times from our current 1.7 times.

Further, we intend to utilize free cash flow to pay the revolver back down to current levels by 2021 and maintain a competitive leverage profile. It's an exciting time for Laredo. The progress we have made over the last 12 months is evident in our financial results.

Our Howard County acquisition positions us for a step change in our capital efficiency, and we've implemented an updated go-forward strategy that is directly correlated to increased stakeholder value. All of us are extremely proud of what we've accomplished thus far and are energized by what lies in front of us.

We look forward to sharing our progress with you in the months to come. Operator, please open the call for questions..

Thank you. [Operator Instructions] Our first question comes from the line of Derrick Whitfield with Stifel. Your line is now open..

Thanks, good morning all and congrats on a third consecutive strong quarter and an accretive acquisition..

Thanks, Derrick..

Perhaps for Jason, regarding your increasing scale through consolidation bullet on Page 3, could you speak to your guiding principles for M&A and the degree of opportunities available in the market?.

Yes. Well, I mean, I think one of the things that we try to emphasize and what we see in the quarter, continuous quarterly improvement is that we've got a great drilling and completion machine, we've got low LOE and low G&A. So these are all things that we think worked to our advantage.

If you're thinking then about consolidations, we should be the company of choice. So we don't have anything that is particularly in the queue today, but it's something that we just -- again, as we think of transforming the company and getting more oily, there should be opportunities for a company like ours to take advantage of..

That makes sense.

And then as my follow-up, perhaps, looking into 2020, how would you frame expected -- your expected activity levels and the allocation and activity across your asset bases assuming the successful close of the Howard County asset?.

Yes. As we mentioned in the prepared comments, I mean this is something that comes to the front of our queue. I'd say, when I talk about the company and the strategy, we spent $7 million a well and deliver roughly 35% oil. So for us, this opportunity is to take that same $6.5 million to $7 million and apply it in an opportunity that makes 80% oil.

So for us, again, we become much more capital efficient by using the same capital spend on these assets. And I'll turn it over to Karen and she can talk to you more about kind of the timing and things like that..

Yes. So, as we plan for the close by the end of the year, as Jason said, we want to move these assets as early as we can in direct schedules. So, we run in three rigs right now. Our expectation would be that we'll transition those rigs in the first quarter over to the new asset and then continue on with completion.

So activity wise, from a completion standpoint, first half would be -- well that we're already in the queue right now on our existing asset base. And then, second half will be full transitioned over to the new Howard County asset base..

Very helpful, thanks for your time guys..

Thanks, Derrick..

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

Thank you, good morning..

Good morning, Brian..

To follow up on the acquisition question, as you look to further enhance your oil mix with opportunities like the one that you announced in Howard County.

Strategically, is there a specific focus to try to gain scale around the Howard County acreage that you've just bought? Or would you look for similar type transactions elsewhere in the Midland Basin, broader Permian Basin or an even wider -- or kept an even wider net?.

Again, we've got this acreage position. It will be a great position to expand on. So, again, that will definitely be a priority for us. But for us, again, it is -- it's high-quality wells that are -- have high oil content. Those are the things to think about close to our core position if we can do those.

So those are the things that can -- as we look at our matrix and how we grade opportunities, those are things that -- at the top and why you see this opportunity here. But we're -- again, we're open to things. We need to achieve scale. This opportunity gives us -- we talk about 120 gross wells, 100 net wells.

So it provides about two years of inventory as hard as we're going to go on this. So we'll need to, we call it, loading the conveyor belt. So we're looking to fill the conveyor belt full of kind of these opportunities that come down. But the key is, we're not going to put a lot of debt on the balance sheet.

So just having a measured growth and considering all those things. We don't want to -- we've done a lot of work to get the balance sheet healthy, and so we don't want to destroy it through acquisition process that is too aggressive. So those are all the things that we look at when we're considering these..

Great. Thanks. And then my follow-up is on some of the free cash flow objective that you have.

Can you just talk a little bit to how you see 2020 sequentially putting out, it seems with the new assets that you're acquiring, the real impact from an oil mix perspective is a little bit more back-half of the year or fourth quarter? But can you just talk to how you see the capital investment relative to the oil production through the year?.

Yes. As we stated, our goal is ultimately to be free cash flow positive to neutral. But as you suggest, the benefit of this comes in the late third quarter and fourth quarter, and that's when you really see the acceleration of cash flow as these wells are starting to come online.

So again, it's over that two-year period, but it's -- you really have to be able to benefit from these wells to apply the majority of the cash flow back to the balance sheet..

Do you have any target for year-end 2020 oil mix exit rate or just some sense as to -- based on how you're thinking about investing? How -- what the magnitude of the oil mix change could be?.

Well, we'll kind of -- we'll start to lay out the budget in the next couple of months, and we'll have more clarity on kind of what those look like. It will be -- we are doing larger packages. So our production profile will be lumpier, and you'll see, I say, a large slug of oil coming on in the late third and -- the third and fourth quarter.

So those are -- again, you're kind of hitting around it, but we'll lay out clear guidance as we get closer to kind of having our budget finalized..

Great, thank you..

Thank you. Our next question comes from the line of Noel Parks with Coker & Palmer. Your line is now open..

Good morning..

Good morning, Noel..

Just a couple of questions. In the new acreage you acquired, is there a lot of cleanup to do on the property before you get out there? I don't know if it was -- had any recent activity out there. You sounded like there hasn't been horizontal activity out there..

Yes. The -- one of the reasons that the acreage position was really attractive to us is that it has had very little operational activity, no horizontal wells and even very limited vertical development. So there's very little, I guess, from your question or the point of activities, but yes, it's pretty much undrilled to date..

Wow. That's -- and just -- was it land issues that sort of kept it out of play for so long or....

Yes. No. Again, opportunity just came to us. So the history is not something we speak to. But for us, it's a great opportunity. There isn't a lot of production on it. So that will -- like, again, a lot of the issues other operators face are these parent-child issues. So for us, we don't have to deal with any of those type of things.

So we'll -- should -- don't have to put a lot of risk on future wells and quantity of wells. So for us, it's just a perfect opportunity that fits the strategy..

Okay. And then just I was wondering, you put a lot energy into your improving the results in the Cline. And I was wondering, much of that work also going to be applicable to what you'll be doing on the acreage. Are the geologies similar enough, etc.

depth and so far?.

Yes. So for the Cline, we've got a couple of Clines in progress on the existing acreage. So we're -- rather we're being able to get that -- those in and get those operations done and get the new completion design on the Clines as we kind of move forward, as you said, from the recent discussions.

So Cline is a potential on the new acquisition, but is assumed to be an upside, so wasn't part of the valuation. So we'll continue to evaluate that. We're really focused in the original -- the initial development plan on the Lower Spraberry, the Upper Wolfcamp, and the Middle Wolfcamp, and the Howard County acreage..

Got it.

So, the location count you're identifying does not include cline potential at this point?.

That's correct..

Great, that's all from me, thanks..

And I'll just follow up. I mean I think alluding to your question, we spent a lot of time as we're working at Cline taking on completions, technology, what sand concentration does to performance. Those are things that we considered in this acreage.

On Slide 8, we've got all the wells that we used, and those are -- completion technology is a factor that kind of elevates the performance that we expect on these wells. So we're excited about it and expecting the results. What works for us here is just, again, all the legacy work we've done to optimize our drilling and completion machine.

We're not moving far away from an area that we're with very familiar with. So I'll expect to be able to hit the ground running there..

Great, thanks..

Thank you. Our next question comes from the line of Richard Tullis with Capital One Securities. Your line is now open..

Hey, thanks. Good morning, Jason. Congratulations on a nice quarter. Two quick questions for you. Laredo has been doing a very good job on keeping opex cost down, G&A cost down.

How do you see those costs trending, say, in 2020 and into 2021 as you move a little bit away from the production corridors already in place and likely a oilier production mix?.

So this is Karen. I'll just answer -- start the discussion here. So, yes, as we move to the Howard County, so the -- there's considerable infrastructure already in place in the area. Obviously, we're entering this area of development in different time than when we entered our heritage acreage position -- existing acreage position.

So from an oil, water, gas gathering, there's a lot of third-party facilities in place, and we tend to fully utilize those to manage our cost and keep everything down. So overall, we feel like we're going to be able to move in, maintain our D&C efficiencies.

This is in a good location for us so we can get oilier, but at the same time, use our resource base from the standpoint of just all the people and everything that we have in place out there. So overall, we think we will be able to transition pretty much at similar cost, both in D&C and opex, as what we're doing on our current acreage position..

All right. Thank you, Karen. That's helpful.

And just lastly, is -- just to fully understand it, do you plan to run the three rigs exclusively on the new acreage until you basically exhaust the drilling inventory that you identified and maybe any additional locations? Or do you see the rigs transitioning somewhat back to the legacy acreage? And does it also open up the opportunity to maybe monetize some of the legacy position?.

This is Jason. I mean we'll be running the three rigs there. Karen gave the update on timing. And a lot of it depends on, I guess, we're looking to execute on our strategy, as we mentioned. This has provided us about two good years of inventory. And for us, we need to, again, load the conveyor belt.

So we look forward for a future discussion like this where we're talking about the next deal or an expansion here in Howard that keeps that conveyor belt loaded. So we'll consider future opportunities as they come, and what -- how we want to operate our existing acreage position.

I mean challenges with the current position are lower gas prices and lower NGL prices. Those return and then our returns will boost up on our legacy position. So we'll kind of work through that as we continue to execute on the strategy..

I'll just say a little bit on the details of the rig schedule. So as we've talked about a lot in the past, I mean one of the causes of our existing acreage position is almost 90% held by production.

We've got six wells that we need in 2020 to meet our obligations there, and we'll knock those out all very early in the year as we're transitioning over to the new acreage position. So we could do that easily in the first quarter and then transition all the rigs.

So that is the plan right now is to transition all three rigs, and we'll be able to run those through to accelerate these higher rate of return wells through 2020 and into 2021..

Thanks a bunch, I appreciate it..

Thank you..

Thank you. Our next question comes from the line of Gregg Brody with Bank of America. Your line is now open..

Good morning, guys..

Hi, Gregg..

Just -- you commented earlier about your comfort level with how you're thinking about funding future acquisitions.

Could you talk about how far are you willing to stretch sort of your target leverage metrics and -- before an acquisition? And then how does equity play into potential funding?.

Yes. I mean what we're working through right now is, if I can bring these in. Again, CIBOR's are probably around that two times debt to EBITDA, we don’t want to go much above that. I'd say we want to keep our balance sheet in healthy shape. So, we're going to see this as, again acquiring properties, paying it down, may go back up to 1.9, pay it down.

So, those are the ways to think about it. We're not going to go too far above at 2.0, but we'll see opportunistic if those come about..

Got it. And then I noticed you're borrowing base came down a smidge there. Did they -- were there any indications of sort of from your -- as you look at what happened with that borrowing base, what does that potentially tell you about the next one in the spring? And you think that there's potential for borrowing base to go up or down? Excuse me..

Yes. We do a spring and fall bank meeting and what we kind of walked in 2019, just couple of comments on reduction of borrowing base. Everyone knows, we've seen about a 10% drop in oil price and that really is the main driver for that reduction.

But with the potential acquisition closing in the fourth quarter, that's going to load up that future growing with some hard oil cost properties, which will just continue to help support that borrowing base going forward..

Got it. And then just last one from me. You mentioned a minimum drilling and your legacy assets to hold acreage.

I'm just curious, are there any commitments associated with Medallion that will require you to keep production at a certain level or to drill in that area and to meet any sort of NBCs or anything like that?.

Yes, this has been cline and we've obviously considering all of our marketing and midstream arrangement and while we do that commitment with certain midstream companies, there is very ancillary concerns or what not in regards to fulfilling our commitments with our existing base production..

Got it. And just last one for me. You mentioned a minimum drilling in your legacy assets to hold acreage.

I'm just curious, are there any commitments associated with Medallion that require you to keep production at a certain level or to drill in that area to meet any sort of MVCs or anything like that?.

Extremely minimal, if any..

Got it. Thanks for the time, guys..

Thank you..

Thank you. Our last question comes from the line of Kashy Harrison with Simmons Energy. Your line is now open..

Good morning and thank you for taking my questions..

Hi, Kashy..

So just a few quick ones from me, can you walk us through the strategy on the net royalty acreage, I'm just wondering whether that could be a candidate for monetization to help accelerate value for shareholders?.

Yes. Initially, when we were, again, working through this acquisition, we disvalued it as a whole with it. But as we move forward, again, that's something that we need to consider. There is a higher value than we would place on it. Again, everything's for sale at the right price.

So for us, we like the incremental royalty in production that comes with it early on, but we can definitely consider that as part of our strategy and what the right next step is..

Got it. And then switching gears a little bit. I know it's certainly not -- it's not coming anytime soon, but I was just wondering if right now, you all have some high-level thoughts on how you might attack the 2022, 2023 debt maturities that are coming..

Yes. This is Michael. The 2022s come in January, and we're actively watching the market kind of the last premium on that front rolls off in January.

So I think where we're at today is kind of where we've been out for the last six or nine months is we're continuing to watch the market, and we're just going to be really tactical about refinancing the 2022s when the time is right.

We don't feel much pressure today, but as you kind of roll into the next year, we're not going to allow them to go current. So we'll just kind of keep watching the market and see what happens..

That sounds good.

And then final one from me, more of a modeling question than anything, I was just wondering if you could remind us how we should be thinking about oil base declines entering 2020 and also how we should be thinking about just maintenance CapEx to hold oil volumes flat over the next several years just giving all the improvements in the cost structure? Thank you..

Yes, this is Jason. I mean, we'll have to get to you when we've got these, again all the maintenance capital just changed with these assets. So, we'll have to kind of run through those numbers are different than anything we've done in the past just because these are so much more productive than the legacy assets that we got..

Got you, thank you..

Thank you..

Thank you. This concludes today's question-and-answer session. I would now like to turn the call back to Mr. Ron Hagood for closing remarks..

We appreciate you joining us this morning for our call and this concludes the call for today. Thank you..

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect..