Good day ladies and gentlemen, and welcome to First Quarter 2019 Laredo Petroleum Inc., Earnings Conference Call. At this time, all participants are in a listen-only mode, later we will conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions] As reminder this conference is being recorded.

I would like to introduce your host for today's conference. Mr. Ron Hagood, Vice President Investor Relations. Sir, please go ahead..

Thank you and good morning. Joining me today are Randy Foutch, Chairman and Chief Executive Officer; Karen Chandler, Senior Vice President and Chief Operations Officer; 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 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 2019. We will refer to this 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 Randy Foutch, Chairman and Chief Executive Officer..

Thanks, Ron. Good morning, everyone, and thank you for joining the Laredo’s first quarter 2019 earnings conference call. As we discussed previously our fourth quarter 2018 earnings call, we anticipated that 2019 will be a transitional year for Laredo.

We put forth an operating plan that facilitated the transition from a development strategy focused on net asset value creation and increasing inventory. To the plan focused on [ph] middle growth improved returns and living within cash flow.

In late 2018 we laid the groundwork for this transition by announcing that we were moving away from the NAV accretion focused type spacing development packages that we've been drillings into early 2017 to wide spaced packages with the expectation that the wide spacing will improve capital efficiency and moderate the all the oil declines scene in tight spacing development.

Additionally, in mid-February 2019 we announced our plans to operate within cash flow for full year 2019 moderating our operational gains and pledging to the land personnel expenses with our reduced operating cadence. In the first quarter, we exceeded our expectations for our plan.

We continue to excel operationally completing wells ahead of schedule and facing completion operation on our last 20 tightly-spaced wells enabling completion operations to begin on wide based packages earlier than anticipated. Additionally, we surpassed both out total production and oil production guidance for the quarter.

We were able to further reduce per well capital cost below our previously announced plan and continue to drive down controllable cash costs on a unit basis. Capital expenditures were in line with budgeted expectations. Furthering our confidence in delivering on our goal to align cash flow and capital expenditures for full year 2019.

Subsequent to the end of the first quarter, we delivered on our promise to right size our employee base relative to our operations to the reduction in force. We took a hard look at all positions and made some difficult choices. In the end we cut total headcount by approximately 20%, reduced positions at the officer level and above by more than 40%.

This action is expected to reduce cash, non-cash and capitalized personnel cost by approximately 25% on an annualized basis or approximately $30 million. When we released our 2019 operating plan in mid-February, we made clear our target was to align cash flows and capital expenditures.

We also made note of factors that could drive changes to our cash flow assumptions. Specifically, commodity prices, service cost per well productivity. We have made strategic and tactical decision since the end of the first quarter to take advantage of factors that will drive higher 2019 cash flow for the company.

First, we restructured oil hedges for the balance of 2019. We remain approximately 90% hedged on our anticipated oil production but by closing our – most of our put contracts and entering into WTI swap contracts at an average price of approximately $62 per barrel.

We increased our weighted average floor price from approximately $47 per barrel to approximately $60 per barrel.

This dramatically reduces the company's risk should oil prices fall and secure significant cash flows above original budget assumptions, while you retain unlimited upside to rising oil prices on approximately 25% of our anticipated production.

Raising the weighted average floor price on our whole hedges from $47 per barrel to $60 per barrel secures approximately $100 million in cash flow. Second, we were able to negotiate price reductions for completion services in sand. This is in addition to saving secured at the start of 2019 that we're already included in our 2019 capital plan.

The new savings are expected to reduce well cost by approximately $500,000 from original budgeted calls for the balance of 2019. Lastly we settled a previously disclosed lawsuit resulting in a substantial cash payment to the Laredo. We have decided to allocate this additional secured cash flow to drilling and completion activities.

This will have a dramatic impact on the Laredo’s expected production profile in 2019 to 2021 and should significantly exhilarate the timing of when we are able to generate free cash flow, while growing at a measured rate.

Our updated operational plan is relatively unchanged in the first half of 2019, as our capital expenditures were heavily weighted to the first half of the year. The additional activity enabled by improved cash flow position occurs in the second half of 2019 and we now expect to operate two rigs and one completion crews to the balance of 2019.

We are adding 16 completions in the second half of the year, increasing our expected completion count in the second half to 20 wells from 4 wells. With the updated operational plan, we are now conducting completion operations through the entire second half of 2019 rather than stopping completions in July, as we would have under our original plan.

This continuous activity globally in both drilling and completion offers will help us to retain the operational efficiencies that we achieved over the past years. And now did I expect to build a documentary beyond whales that are in the process of being completed.

The updated operational plan has a positive impact on 2019 oil production and dramatically improved oil production in 2020 while staying within cash flow.

Previous guidance for 2020 oil production was an average of approximately 23,000 barrels per day while under the updated 2019 operating plan, we now expect oil production to average more than 27,000 barrels per day at approximate 19% increase versus previous expectations.

Additionally to further underpin operational activity in 2020, we increased our oil hedges to approximately 75% of anticipated 2020 oil production with the weighted-average floor price of almost $59 per barrel, while retaining limited upside to oil price increases on approximately 25% of anticipated 2020 oil production.

Again, this supports our ability to maintain our plan to operate within cash flow and importantly puts the company in a position to be able to generate free cash flow and grow oil at a measured rate in 2021.

We believe our updated 2019 operating plan improves the future financial performance of the company, in addition to the beneficial oil production increases in 2019, 2020 and 2021, locking-in pricing with Schwab's combined with lower well cost improve our expected well level rate of return by approximately 10%.

Finally as you saw in our press release dated April 24, we are excited to welcome new member to the company's leadership team, Jason Pigott will join us in late May as our new President. I will be working closely with Jason as he takes the reins in Laredo and transitions to the CEO role during the fourth quarter of 2019.

Both the Board and I could not be happier to have hired a leader of Jason's caliber. I will now turn the call over to Karen for an operational update..

Thank you, Randy. In the first quarter of 2019 we continue to demonstrate outstanding efficiency of our operations. We brought online five more wells than previously forecasted and both of the 10 well packages completed during the quarter sales earlier than anticipated.

Laredo's both oil production and total production guidance for first quarter 2019, driven by these earlier completions and better base production.

The better than anticipated base production was a result of continued focus at an individual well level by the production engineering and operations teams to fully optimize our producing oils, including managing [indiscernible] as we continue to develop new well packages in and around our existing wells.

We operated three drilling rigs and two completion crews through the first quarter of 2019 and had now dropped to two drilling rigs and one completion crew. As indicated in our updated operating plan, we expect to operate at this level through the end of 2019.

With our updated operating plan, we now expect to complete approximately 52 wells in 2019 while still staying within cash flow. Completing wells consistently throughout the year is expected to drive a couple of significant benefits. First, capital will be used more effectively than what we planned in the original budget.

In the original plan, completion operations were scheduled ending July, resulting in a substantial dark inventory by the end of the year. Under the updated plan wells are expected to be completed on a regular schedule eliminating the time on which drilling capital is unproductive.

Secondly, continuous operations will allow us to better retain the operational efficiencies that we've achieved over the past several years. Continuous operations by definition are more efficient than those that are starting and stopping throughout the year. We continue to drive down well cost below 2018 levels.

Our original budget included completion service cost reductions that reduced anticipated well cost to approximately $7.5 million for a 10,000 foot horizontal well. This was a reduction from approximately $7.7 million in 2018.

Around the end of the first quarter we began to realize additional cost reductions and completion services and fairly substantial reductions in pricing for in-basin sand. These combined savings totaled approximately $500,000 per well further reducing the expected cost for 10,000 foot horizontal well to approximately $7 million.

We’ve incorporated this lower well cost into our updated operating plan as we expect to continue to realize these reductions throughout at least balance of 2019. In the second quarter of 2019, we expect roughly 12 horizontal wells.

Importantly, in the first quarter, we finished completing and prudent production the last of our planned tight spacing wells. Meaning all completions in the second quarter will be well developed with wide-spacing. The first package is the eight-well yellow rose package.

This is a wide-space co-development package in the Upper Wolfcamp formation meaning that the wells are space 1,320 feet apart in zone and two zones are being developed simultaneously within the formation.

The second package is the four-well kosher package also being developed in the Upper Wolfcamp formation of wide-spacing, but as a single zone development. As a reminder, wide-space co-development packages equate to eight-wells per formation per DSU. And wide-space single zone packages equate to four-wells per formation per DSU.

I would like to conclude by recognizing our operations teams once again on another outstanding quarter. They have consistently surpassed performance expectations and we look forward to delivering additional performance improvement as we execute our updated operating plan. I will now hand the call to Michael for financial discussion..

Karen, thank you, and good morning. There are a few items contained in our first quarter 2019 earnings release issued yesterday afternoon that we’ll benefit from some additional clarification. First is our realized pricing in general and for natural gas in particular.

Our guidance for realized pricing is based on a formula and does not include realized hedge settlements. When we issue guidance for any product, we take three items into account; the product price, the basis differential to the benchmark price for the market in which we sell our product, and our cost to process or get into the market.

For example, let's look at our natural gas realized pricing. To begin with, Laredo sells approximately 80% of our natural gas production at the West Texas WAHA index price.

As published by [indiscernible] in their first of the month addition of inside our FERC gas market report, the remaining 20% of our natural gas production is typically sold at the WAHA related daily spot price. For the first quarter of 2019, we got to a 34% of Henry Hub benchmark price as published by the EIA, and we actually realized 31.8%.

When we gave guidance in mid-February, the West Texas WAHA index price for January and February delivery month were already set. So we use those natural prices and incorporated futures prices for March delivery month.

At the time we issued guidance for the first quarter 2019 realizations, we expect that the Henry Hub benchmark to be $3.05 per Btu for the quarter. And the WAHA index price was expected to be $1.45, resulting in our estimated WAHA index as a percent of the Henry Hub benchmark being 52%, adjusting for the fees charged by our processors.

We expected our net realizations at the wellhead to be 34% of Henry Hub. The daily average March Henry Hub spot price and the WAHA index produced actual prices for the quarter of $2.90 for the Henry Hub benchmark and $1.45 for the WAHA index.

This resulted in the WAHA index being 50% of the Henry Hub benchmark for the quarter or 2% less than our expectation at the time of guidance. This fully accounts for our actual first quarter gas price realizations being less in guidance set in February. Guidance for our pre-hedged gas realizations for the second quarter of 2019 is at 0% Henry Hub.

I will stress that this does not mean we are flaring gas. Our wet gas is still being processed. The residue gas is being sold into downstream pipes by our gas purchasers, and we are still realizing the value of our NGL components.

Guidance for the second quarter is based off of the actual Henry Hub to date spot price, WAHA index prices for April and May, and the futures prices for the balance of the second quarter. Our current expectations for Henry Hub pricing for the second quarter is at an average of $2.62 per MMBtu and WAHA index price of approximately $0.10 per MMBtu.

Traditionally, we allocate the gathering and processing fees charged for our gas purchasers between the gas and NGL realized prices, based on the relative revenue of those two streams.

For the second quarter, we plan to allocate almost all of the gathering and processing fees to our NGL revenue stream as revenue from the residue gas sales will be minimal.

This full allocation to our NGL revenue stream of our incurred gathering and processing fees is considered in our second quarter NGL price guidance of 20% of the WTI benchmark price. To minimize the impact of pricing volatility on the company we have a robust hedging program in place.

We have discussed the extensive oil hedging activity we executed in April, but we also have hedged majority of our anticipated natural gas and NGL volumes for 2019. Details of our current hedges are on page 26 of our current corporate presentation posted on our website.

Natural gas product and basis hedges in 2019 represent approximately 70% of our anticipated production. And offer substantial protection relative to current pricing. Second quarter expectations for Henry Hub in the Waha resulting a realized price before fees of $0.09 per MMBtu.

This $0.09 combined with our hedges yield a hedge realized price before fees of $1.58 cents per MMBtu. A second item for clarification is our G&A guidance, as we previously announced the company implemented a reduction in force in early April to better align our personnel costs with our operational cadence.

These reductions are expected to result in annualized savings of approximately $30 million in combined cash and non-cash G&A expenses and capitalized savings. Second quarter cash G&A guidance of $2 per BOE partially reflects its reductions, but also reflects one-time items associated with the recent hiring of our new president.

We expect cash G&A to further decline to approximate $1.75 per BOE as it normalizes in the third quarter of 2019. Also in April our banking group set our reserve base facility borrowing base of $1.1 billion with $270 million currently drawn. This line provides the company with significant liquidity and we expect to resume more reserve growth in 2019.

Further increasing the value of our reserves back in this facility. As previously mentioned our updated 2019 operating finance underpinned by our hedges in place, combined with our commitment to operate within cash flow for 2019 and 2020. That's what Laredo love to grow oil production, and to be able to generate free cash flow in 2021.

Operator, please open the line for questions..

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

Thanks. Good morning all. I want to first congratulate your team on the strategic and tactical steps taken to change the production and free cash flow profile of your company..

Thank you..

Perhaps for Randy or Karen. Could you speak to the objectives of your first and second batch of low density development wells? Is it to some degree a test on whether four or eight years is most appropriate.

Or is the geology relatively unique for each batch?.

We some of let is ready. I’ll let Karen to address kind of more detail, but in our presentation we do have one slide on page 8 and which we kind of show what we're thinking in terms of completions going forward.

And as you know, we've got a lot of data and a lot of wells being that have been drilled and now off course we’re starting to gets pretty significant production history. So I think we're comfortable with the tighter spacing [indiscernible] added inventory, we’ve got plenty of inventory on the wider spacing.

So I think we're pretty comfortable, Randy you want to add anything else?.

And the only thing I'll add is we mentioned the two packages that are coming up at the wider spacing.

All the remaining packages for the rest of the year fit the same profile and all are in the same range we're doing a mix of packages to the rest of the year that really fit that four to eight the issue based on what we think is the best development for that particular area..

And I’ll just point out we've said for some time that we have other zones that are productive and in some places the client has been pretty economic. So I don't know when we get back to that but it's still out there and actually that's a pretty good return some of our better wells..

Helpful and as my follow-up regarding the $500,000 improvement in completed well cost.

How much of that improvement is market versus self-help or D&C optimization?.

As we've – we worked that hard and I think it's – I kind of feel like I'm a little bit of a broken record. We keep talking about how much more efficient we've gotten just better every quarter and I keep saying we can't continue to always be getting more efficient, but we are getting more efficient and just learning more about how to do this better.

Now sand is obviously been a big cost improvement for us..

Thanks, Dan..

Thank you. And our next question comes from the line of Brian Singer with Goldman Sachs. Your line is open. Please go ahead..

Thank you. Good morning..

Good morning, Brian..

As you were considering the options on use of both the proceeds from litigation and then as well as the lower risk profile from the better hedges, how did you weigh the direction that you're taking now reinvesting in the business to mitigate the decline versus other options such as pay down debt or lower net debt as well as, or return capital to shareholders?.

Obviously, all of those options were on the table and considered. You know, we're still, in 2019 drilling well within cash flow – cash flow neutral. And we think this is substantively put us in a very good position going forward of having more free cash flow and actually more ore growth..

And my second question is on the oil – on the production mix side, given the greater activity levels, is there any impact that that has on production mix you've highlighted where you see oil and relative to what it would have been, should we expect that oil as a percent of the total mix would go up or stay flat or continue to – or fall?.

Yeah. This is – and Eric [ph] this is Michael, first quarter was right at 37%. Our guidance for the second quarter was down 1%, about 36%. And just kind of given that cadence of completions during the next three quarters at that10 to 12 or more per quarter, I think we would expect the oil mix to stay relatively flat for the year..

Great. Thank you..

Thank you, Brian..

Thank you. And our next question comes from the line of Richard Tullis with Capital One Securities. Your line is open. Please go ahead..

Hey, thanks. Good morning and Randy, congratulations on the planned retirement. I guess my first question is regarding the increased drilling plants for the second half of the year.

Will the main target be the Upper Wolfcamp or will there be some Middle Wolfcamp mixed in?.

Yes, for the remaining of the year, we are completing both upper and Middle Wolfcamp packages, both single zone and co-developed..

Okay.

And then just looking at the drilling inventory, going forward how many Tier 1s Upper and Middle Wolfcamp locations do you – do you have any inventory say, 10% or plus greater rate of return at say $50 or $55 oil?.

Hey, Richard. This is Ron. Yeah, we wouldn't – in our inventory if it's not economic, if it's not meeting our cost of capital, it's not going to be in the inventory anyway. But we've got approximately 1,600 locations if you include Upper, Middle and Lower incline, about half of those are in the Upper and Middle Wolfcamp..

Okay. Thanks, Ron. And then just lastly, just to verify is the settlement with Shell trading I think it was around a little over $40 million.

Is that included in the capital as being allocated toward meeting the free – live within cash flow for 2019 on the increased budget?.

Yeah, this is Michael. That is included in that number that were allocated into the $465 million of capital expenditures in the year..

Okay. All right. Well that's all for me. Thank you..

Thank you..

Thank you. And our next question comes from the line of Sameer Panjwani with Tudor, Pickering. Your line is open. Please go ahead..

Hey guys, good morning..

Good morning..

Since you've highlighted the progression of free cash flow on production through 2021, can you also talk about the expected capital program for the next few years? Kind of feel like it should be relatively flat to 2019, but just wanted to confirm that..

Yeah. This is Michael. So kind of the way we're looking at that today is, kind of our expectation is the capital would be relatively flat in 2020 compared to 2019, and about flat again for 2021. So really what we're doing today is set this up to start growing oil as we go through 2020 and especially in the 2021 with flat for 2019 and 2020..

Okay, that makes sense. And then I also wanted to get your thoughts on how the oil PDP decline rates should sell out over the next several years.

So how do you expect that 44% decline rate at the end of 2018 to look at the end of 2019 and 2020?.

Hey, Sameer. This is Ron. We’ll update that. I mean, you can expect us to update that on a yearly basis, but as far as projections going forward, there's a lot of data that's going to go into the analysis of that especially as we close out reserves at the end of each year, so we'll just update the PDP on a yearly basis..

Okay. And then last one if I can squeeze – squeeze one more in. Wanted to see if you guys could quantify kind of the level of free cash flow you guys are thinking about in 2021 to accompany the low to – the mid-single-digit growth you're expecting on the production side..

Yeah. So, in the end, it's still going to be based on commodity prices and then where commodity costs and where our CapEx costs are, but it's still probably a little bit too early to hit that number in 2021. I think once we get through 2020, we'd be in a much better position to get a real number for that..

Okay. Thank you..

Thank you. And I'm showing no further questions at this time. And I would like to turn the conference back over to Mr. Ron Hagood for any closing remarks..

I just want to say thanks for joining us for our first quarter call. We appreciate your interest in Laredo and have a great morning..

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