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Laredo Petroleum (NYSE:LPI)
Q1 2019 Earnings Call
May. 02, 2019, 8:30 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:


Operator

Good day, ladies and gentlemen, and welcome to the first-quarter 2019 Laredo Petroleum, Inc., earnings conference call. [Operator instructions] As a 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.

Ron Hagood -- Vice President of Investor Relations

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'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. Yesterday afternoon the company issued a news release and presentation detailing its financial and operating results for the 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.

Randy Foutch -- Chairman and Chief Executive Officer

Thanks, Ron. Good morning everyone, and thank you for joining Laredo's first-quarter 2019 earnings conference call. As we discussed previously on our fourth-quarter 2018 earnings call, we anticipated that 2019 would be a transitional year for Laredo. We've put forth an operating plan that facilitated the transition from a development strategy focused on net asset value creation and increasing inventory to a plan focused on measured 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 tight-spacing development packages that we have been drilling since early 2017, to wide-spaced packages, with the expectation that the wide spacing would improve capital efficiency and moderate the oil decline seen 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 cadence and pledging to align personnel expenses with our reduced operating cadence. In the first quarter, we exceeded our expectations for our plan. We continued to excel operationally, completing wells ahead of schedule and finishing completion operations on our last 20 tight-spaced wells, enabling completion operations to begin on wide-spaced packages earlier than anticipated.

Additionally, we surpassed both our 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, through a 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 or well productivity. We have made strategic and tactical decisions 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 remained approximately 90% hedged on our anticipated oil production.

But by closing out 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 we retain unlimited upside to rising oil prices on approximately 25% of our anticipated production. Raising the weighted average floor price on our oil 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 and sand.

This is in addition to savings secured at the start of 2019 that were already included in our 2019 capital plan. The new savings are expected to reduce well cost by approximately $500,000 from original budgeted cost for the balance of 2019. Lastly, we settled a previously disclosed lawsuit resulting in a substantial cash payment to Laredo. We have decided to allocate this additional secured cash flow to drilling and completion activities.

This will have a dramatic impact on Laredo's expected production profile in 2019 to 2021, and should significantly accelerate the timing of when we are able to generate free cash flow while growing oil 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 our improved cash flow position occurs in the second half of 2019, and we now expect to operate two rigs and one completion crew through 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 four.

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 level in both drilling and completions operation will help us to retain the operational efficiencies that we achieved over the past years, and now do not expect to build a DUC inventory beyond wells that are in the process of being completed. The updated operational plan has a positive impact on 2019 oil production and dramatically improves 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, an 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 a weighted average floor price of almost $59 per barrel, while retaining unlimited 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 swaps 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 a 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 at 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.

Karen Chandler -- Senior Vice President and Chief Operations Officer

Thank you, Randy. In the first quarter of 2019, we continued to demonstrate the outstanding efficiency of operations. We brought online five more wells than previously forecasted, and both of the 10-well packages completed during the quarter flowed to sales earlier than anticipated. Laredo exceeded 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 wells, including managing frac impacts 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 have 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 to end in July, resulting in a substantial DUC inventory by the end of the year. Under the updated plan, wells are expected to be completed on a regular schedule, eliminating the time in 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 in completion services and fairly substantial reductions in pricing for in-basin sand. These combined savings total approximately $500,000 per well, further reducing expected cost for a 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 the balance of 2019.

In the second quarter of 2019, we expect to complete 12 horizontal wells. Importantly, in the first quarter, we finished completing and put on production the last of our planned tight-spacing wells, meaning all completions in the second quarter will be wells developed with wide spacing. The first package is the eight-well Yellow Rose package. This is a wide-space codevelopment package in the Upper Wolfcamp formation, meaning that the wells are spaced 13 20 feet apart in zone, and two zones are being developed simultaneously within the formation.

The second package is the four-well Holsher package, also being developed in the Upper Wolfcamp formation on wide spacing, but as a single-zone development. As a reminder, wide-space codevelopment 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 improvements as we execute our updated operating plan. I will now handle the call to Michael for a financial discussion.

Michael Beyer -- Senior Vice President and Chief Financial Officer

Karen, thank you, and good morning. There are a few items contained in our first-quarter 2019 earnings release issued yesterday afternoon that will 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 it to 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 Platts in their first-of-the-month edition of Platts Insider 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 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 mark were already set, so we used those actual prices and incorporated futures prices for March delivery month. At the time we issued guidance for the first-quarter 2019 realizations, we expected the Henry Hub benchmark to be $3.05 per MMBtu for the quarter and the WAHA Index price was expected to be $1.45, resulting in our estimate of the 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 $2.92 for the Henry Hub benchmark and $1.45 for the WAHA Index. This resulted in a WAHA Index being 50% of the Henry Hub benchmark for the quarter, or 2% less than our expectations at the time of guidance. This fully accounts for our actual first-quarter gas price realizations being less than guidance set in February. Guidance for our pre-hedge gas realizations for the second quarter of 2019 is at 0% in 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 on 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 expectation for Henry Hub pricing for the second quarter is an average of $2.62 per MMBtu and a WAHA Index price of approximately $0.10 per MMBtu. Traditionally, we allocate the gathering and processing fees charged for our gas purchases 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 the 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 and the WAHA result in 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 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 these 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 approximately $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 at $1.1 billion, with $270 million currently drawn. This line provides the company with significant liquidity, and we expect to resume oil reserve growth in 2019, further increasing the value of our reserves back in this facility. As previously mentioned, our updated 2019 operating plan underpinned by our hedges in place combined with our commitment to operate within cash flow for 2019 and 2020, sets Laredo up to grow oil production and to be able to generate free cash flow in 2021. Operator, please open the line for questions.

Questions & Answers:


Operator

[Operator instructions] Ladies and gentlemen, our first question comes from the line of Derrick Whitfield with Stifel. Your line is open. Please go ahead.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Thanks. Good morning, all. 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.

Randy Foutch -- Chairman and Chief Executive Officer

Thank you.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

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 is most appropriate? Or is the geology relatively unique for each batch?

Randy Foutch -- Chairman and Chief Executive Officer

This is Randy. I'll let Karen address that in a little more detail. But in our presentation filed, we do have one slide on Page 8, in 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.

We have a lot of wells that have been drilled. And now of course, we're starting to get some pretty significant production history. So I think we're comfortable with the tighter spacing, degraded oil added inventory. We've got plenty of inventory on the wider spacing.

So I think we're pretty comfortable. Karen, do you want to say anything else?

Karen Chandler -- Senior Vice President and Chief Operations Officer

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 through the rest of the year that really fit that four to eight DSU based on what we think is the best development for that particular area.

Randy Foutch -- Chairman and Chief Executive Officer

And I 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 has some pretty good returns, some of our better wells.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Very 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?

Randy Foutch -- Chairman and Chief Executive Officer

We work 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 about every quarter. And I keep saying we can't continue to always be getting this more efficient.

But we are getting more efficient and just learning more about how to do this better. Now sand has obviously been a big cost improvement for us. Karen, do you want to? Thanks, Derrick.

Operator

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

Brian Singer -- Goldman Sachs -- Analyst

Thank you. Good morning.

Randy Foutch -- Chairman and Chief Executive Officer

Good morning, Brian.

Brian Singer -- Goldman Sachs -- Analyst

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?

Randy Foutch -- Chairman and Chief Executive Officer

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

Brian Singer -- Goldman Sachs -- Analyst

And my second question is 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 -- or fall?

Michael Beyer -- Senior Vice President and Chief Financial Officer

Yeah. Derrick, this is Michael. First quarter was right at 37%. Our guidance for the second quarter was down a percent, about 36%.

And just kind of given that cadence of completions during the next three quarters at that 10 to 12 mark per quarter, I think we would expect the oil mix to stay relatively flat for the year.

Brian Singer -- Goldman Sachs -- Analyst

Great. Thank you.

Randy Foutch -- Chairman and Chief Executive Officer

Thank you, Brian.

Operator

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

Richard Tullis -- Capitol One Securities -- Analyst

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

Will the main target be the Upper Wolfcamp? Or will there be some Middle Wolfcamps mixed in?

Karen Chandler -- Senior Vice President and Chief Operations Officer

Yes. So for the remaining of the year, we're completing both Upper and Middle Wolfcamp packages, both single-zone and codevelopment.

Richard Tullis -- Capitol One Securities -- Analyst

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

Ron Hagood -- Vice President of Investor Relations

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, Lower and Cline.

About half of those are in the Upper and Middle Wolfcamp.

Richard Tullis -- Capitol One Securities -- Analyst

OK. 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 living within cash flow for 2019 on the increased budget?

Michael Beyer -- Senior Vice President and Chief Financial Officer

Yeah, this is Michael. That is included in that number that we're allocating to the $465 million of capital expenditures in the year.

Richard Tullis -- Capitol One Securities -- Analyst

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

Randy Foutch -- Chairman and Chief Executive Officer

Thank you.

Operator

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

Sameer Panjwani -- Tudor, Pickering, Holt and Company -- Analyst

Hey, guys. Good morning. 

Randy Foutch -- Chairman and Chief Executive Officer

Good morning.

Michael Beyer -- Senior Vice President and Chief Financial Officer

Good morning.

Sameer Panjwani -- Tudor, Pickering, Holt and Company -- Analyst

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

Michael Beyer -- Senior Vice President and Chief Financial Officer

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 sets us up to start growing oil as we go through 2020 and especially into 2021, with flat for '19 and 2020.

Sameer Panjwani -- Tudor, Pickering, Holt and Company -- Analyst

OK. OK, that makes sense. And then I also wanted to get your thoughts on how the oil PDP decline rate should shallow 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?

Ron Hagood -- Vice President of Investor Relations

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.

Sameer Panjwani -- Tudor, Pickering, Holt and Company -- Analyst

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

Michael Beyer -- Senior Vice President and Chief Financial Officer

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

Sameer Panjwani -- Tudor, Pickering, Holt and Company -- Analyst

OK. Thank you.[Audio gap]

Duration: 32 minutes

Call participants:

Ron Hagood -- Vice President of Investor Relations

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

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Brian Singer -- Goldman Sachs -- Analyst

Richard Tullis -- Capitol One Securities -- Analyst

Sameer Panjwani -- Tudor, Pickering, Holt and Company -- Analyst

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