Laredo Petroleum, Inc. (LPI) CEO Jason Pigott on Q1 2020 Results - Earnings Call Transcript
Laredo Petroleum, Inc. (LPI) Q1 2020 Results Conference Call May 7, 2020 8:30 AM ET
Ron Hagood - VP, IR
Jason Pigott - President and CEO
Karen Chandler - SVP and COO
Michael Beyer - SVP and CFO
Conference Call Participants
Derrick Whitfield - Stifel
Kashy Harrison - Simmons Energy
Brian Singer - Goldman Sachs
Noel Parks - Coker & Palmer
Richard Tullis - Capital One
Good day, ladies and gentlemen, and welcome to the Laredo Petroleum, Incorporation's First Quarter 2020 Earnings Conference Call. My name is Tawanda and I will be your operator for today. At this time, all participants are in a listen-only mode. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes.
It is now my pleasure to introduce Mr. Ron Hagood, Vice President, Investor Relations. Sir, you may proceed.
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; 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, forecast 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 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 first quarter 2020. 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.
Good morning and thank you for joining us on our call today. I hope you and your families are healthy and safe during these trying times. As you read in our press release issued yesterday, Laredo continues to improve in nearly every aspect of our business despite the challenging circumstances we are facing.
In November 2019, we put forward our strategy for increasing stakeholder value which we outline on Slide 3. Although this strategy was formulated in a very different commodity price environment, we believe it is still actionable in the current environment. Results in the first quarter 2020 demonstrate our success optimizing the value of our established acreage position.
We reduced LOE from $3.34 per BOE in the first quarter of 2019 to $2.80 per BOE this quarter. We reduced D&C costs from $700 a foot in the first quarter of 2019 to $630 per foot in this quarter. Our wider-spaced wells continue to outperform our type curve on our core acreage footprint as well. Additionally, we continue to expand our footprint in Howard County adding 1,300 acres so far this year, continuing to bolster our position at a significantly reduced cost compared to prior transactions in the area.
In this tough operating environment, we believe there will be opportunities to scale up our operational advantages using our financial position to make capital accretive acquisitions which improve our capital efficiency and enhance margins. While the current environment is very different from what we saw for most of the first quarter, it was our operational capabilities and risk management that drove our results during the quarter.
Turning to Slide 4, you see we surpassed the expectations for production and controllable cash cost. And very importantly, in this environment our strong financial management was demonstrated as we executed $1 billion notes issuance in a very narrow open window and our commodity derivative settlements resulted in a 34% increase versus our un-hedged average sales price. As demand instruction from efforts to mitigate the spread of COVID-19 virus became apparent combined with the actions of OPEC+, commodity prices dropped rapidly. And we responded quickly and decisively.
On Slide 5, we illustrate our substantial activity cut for the final nine months of 2020 as we reduced our anticipated capital expenditures to $265 million, our original guidance of $450 million. This rapid reduction in capital expenditures drives free cash flow generation in 2020 and delays the completion of our recently acquired Howard County locations into the future when commodity prices should stabilize at a higher level.
Turning to Slide 6, since November 2019 we have executed three acquisitions in areas of higher oil productivity compared to our established acreage position, adding 175 operated locations in these areas. These locations paired with our established Cline locations position Laredo with 10 plus years of high margin inventory at current activity levels that can benefit from improvement in both oil and natural gas prices.
On Slide 7, we demonstrate the leverage of our Howard County acreage to higher oil prices. Additionally, we have recently seen well cost decrease dramatically. At current efficiency levels and received vendor pricing, we estimate well cost at Howard County at $5.5 million per well. This 20% reduction from year-end 2019 cost almost doubles the expected returns and dramatically impacts value at a higher oil price.
We expect to continue operating one drilling rig in Howard County through the end of 2020 and to exit the year with 40 DUCs, positioning us to quickly resume completions activity and drive further capital efficient development.
Last year, as we drove well cost lower, we began to refocus on the client formation on our established acreage position. At deeper formation, the Cline was more expensive than our traditional Wolfcamp development on our established acreage position. As well cost decline, the higher initial productivity of the Cline made its returns competitive with the Wolfcamp.
In the first quarter, we completed two Cline wells, the first in approximately two years. Our operations group performed exceptionally, delivering the well cost for $7.4 million per well, 8% below expectations. At current service costs, we believe we could drill Cline wells for $6.2 million per well.
On Slide 8, we show that at these costs, the Cline well returns start to be competitive with those in Howard County. We continue to see improvement in gas prices resulting from the drop in associated gas as total oil volume declines in the Permian. There are material benefits to our established acreage position. We demonstrate this using our Cline-type curve where we observe returns approaching those in Howard County as gas prices rise.
I would like to turn the call over to Michael now for a more in-depth financial update.
Thank you, Jason. In the first four months of 2020, we have taken significant actions that have had a positive impact on the Company's financial position. In January, we strategically targeted what became a small window of opportunity to refinance our $800 million of notes maturing in 2022 and 2023.
On Slide 9, we show our current capital structure. We issued $1 billion of notes, pushing our maturities out to 2025 and 2028, and repaid $100 million on our RBL facility. Throughout April and finalized last Thursday, we worked with the 15 banks in our reserve based credit facility during our spring borrowing base redetermination, which resulted in a new borrowing base of $725 million.
Our approximate 25% reduction from our previous borrowing base of $950 million compares favorably to the more severe decline in oil prices over that same period. Moreover, our main financial covenants governing the revolver remain unchanged, those being our current ratio requirement of 1:1 and our debt-to-EBITDA ratio of 4.25x. And as of yesterday, May 5, our liquidity position remains comfortable at more than $400 million.
I would like to give a brief comment regarding how the financial ratios that govern our RBL facility and the financial ratios we use for managing the Company and for reporting are different. Among other items, the RBL current ratio covenant calculation gives credit for the undrawn portion of the borrowing base as an addition to current assets and the mark-to-market value of derivatives is removed from both current assets and current liabilities.
Similar to the current ratio, the RBL debt-to-EBITDA covenant also differs from our internal and external calculations with one of the main differences is the treatment of premiums. In our definition of adjusted EBITDA found on Page 26 of today's presentation and in our reported hedge prices reflected in MD&A, we defer recognizing derivative premiums paid at contract execution until the period of settlement of the underlying contract.
Looking forward, when we file our Form 10-Q for the first quarter, you will see in MD&A that we have updated our potential future full cost impairment calculation with current commodity prices. As a reminder, this disclosure is designed to isolate only the impacted commodity prices. Other impacts of lower pricing that we are now currently seeing such as lower surface costs driving lower capital costs are not included in the first quarter disclosure.
In addition to the debt refinancing and RBL redetermination, we significantly increased our commodity derivative position for 2021. We added an additional 8,750 barrels per day at Brent hedges, comprised of 6,750 barrels per day of puts and 2,000 barrels per day of swaps. Utilizing approximately $50 million of expected free cash flow for 2020, we bought our force on the puts resulting in a total 2021 Brent hedge position of 15,350 barrels per day at a weighted average floor price of approximately $53.
Execution of this program secures significant cash flows in 2021, supporting a potential capital program that could keep average daily oil production in 2021 flat with the fourth quarter of 2020 exit rate while generating free cash flow at a WTI price of $30 to $35 per barrel.
I will now pass the call to Karen for a discussion of operations.
Thank you, Michael. As Jason mentioned to open the call, a key component of the Company's strategy is optimizing our existing acreage. Throughout the Company's history, we've done a lot of work around optimal development spacing and parent-child impacts. These learnings drive our current wider-spaced development at our strategy of developing wells in larger packages rather than in single targets or single pads. Since we modified our development spacing in late 2018, we've completed 11 packages with wider-spaced wells. Nine of these packages currently have over 60 days of production history.
On Slide 11, we show that these 9 packages have exceeded our Upper and Middle Wolfcamp oil type curve by 12%, helping drive 5 consecutive quarters of the Company exceeding oil guidance. Another significant part of the optimization story is superior operational performance. On Slide 12, the top chart shows our drilled feet per day per rig and our completed feet per day per crew. As you can see from the chart, the operations team has delivered a 3-year positive performance trend for both drilling and completions. In fact, the Company set yet another record for completions performance in the first quarter and our drilling performance remain near our all-time high set last quarter, even with all of our rigs transitioning to our newly acquired areas in Western Glasscock and Howard Counties.
In 2019, we reduced well costs by over $1 million per well to $680 per foot for a 2,400 pound per foot completion. As shown on the bottom chart on Slide 12, in the first quarter of 2020, we have further reduced our average well cost by 7% to $630 per foot and had among the lowest cost in the Midland Basin. In second quarter of 2020, in this difficult time of demand destruction and price volatility related to COVID-19 and the actions of OPEC+, we have continued to work with all of our service providers to look for additional cost reduction opportunities.
At our current received vendor pricing, the Company expects to be able to deliver wells at or below $550 per foot or a total reduction of approximately 20% from our year-end 2019 well cost. Just as importantly, Laredo also maintains a competitive advantage in our operating cost structure. Turning to Slide 13, we show that since 2015, we have reduced our unit LOE by 58% and have what we believe are the lowest unit operating cost in the basin among our peers. A key driver is the savings we achieved from our company-owned water infrastructure.
Slide 14 shows the extent of the system we've built. In 2019, our system recycled more than 10 million barrels of our produced water and we used more than 11.5 million barrels of recycled water in our completions. This helped drive unit LOE savings of more than $0.50 per BOE and reduce well cost by almost $175,000 per well.
In the current commodity price environment, shutting in production either due to economics driven by operating costs or loan prices resulting from storage issues is a consideration for all operators. For Laredo, we've established a normal ongoing evaluation process to assist the economics of all of our wells. Since 2014, we've shut in 205 older vertical wells as part of this process.
We expect this process to continue in this price environment, but I want to stress that we do not have an inventory of uneconomic vertical wells that have continued to produce uneconomically that we now need to look at harder in response to the oil price decline. But rather we will continue to evaluate wells through our ongoing evaluation process.
The second part of shut-in evaluation revolves around the structures of how we transport and market our oil. On Slide 15, we summarize how we maximize our delivery and sales point performance. We have in place inter-basin firm transportation with Medallion which then gets us to delivery points for our inter-basin firm transportation on Bridgetex and Gray Oak. Upon delivery to the Gulf Coast, we have contracts with large international logistics providers and receive WTI-Houston or Brent-based pricing. Our conversations with all counterparties in this process had been encouraging and we currently believe that we will not have to shut in volumes due to third party constraints.
On Slide 16, we highlight another important advantage of our historical investment in infrastructure. Our 210 miles of oil and gas gathering infrastructure make our operation safer and reduce environmental releases. As you can see, we are among the best performers in the Permian Basin and flare less than half of the peer weighted average.
I'll now pass the call back over to Jason for a few closing comments.
During the quarter, the team continued to perform and improve upon the high standards we set for ourselves, improving our cost structure across all aspect of our business. These achievements were made while our workforce adapted to new working situations as we maintained our focus on keeping all Laredo employees and service providers safe.
Our prior commitments to keeping our cost structure low, protecting our cash flows with hedges, and appropriately timing the refinancing of our debt places us in a position to be proactive rather than reactive as we strive to create differential value for our stakeholders.
Operator, we will now open the line for questions.
[Operator Instructions] Our first question comes from the line of Derrick Whitfield with Stifel.
Perhaps for Jason, with the understanding that you will provide a formal 2021 guidance a few quarters from now, would it be fair to assume that 2021 maintenance scenario of drilling and completing of 30 Howard County wells is an actionable plan at strip prices of approximately $35 or would that outlook require a higher price scenario?
No, I think what we've, again, we've outlaid a plan that would be maintenance again as we've highlighted on the call just a moment ago. Again, we've put in, placed some hedges for next year to protect those cash flows and those activity levels. So we should be able to stay, again, free cash flow positive with prices as low as $30 to $35.
And with my follow-up, I wanted to address the statement near the end of your comments in the press release regarding the potential use of free cash flow to pay down senior notes in the open market or through privately negotiated transaction. Given the potential value this could create with the notes trading and material discounts to par, I wanted to understand how aggressively you could be inclined to pursue this and if there are any conditions or covenants within your debt capital structure that will limit your ability to pursue this action.
Yes, I'll just talk about the ability to do it and turn it over to Michael on the covenant side of it. But it's something that we look at it, it's a good return for us, it's hard. There's not a lot of liquidity out there in those, but something that we're looking at and would ultimately add value to us as a company. To that, I'll turn it over to Michael on the covenant.
Yes, I think from our standpoint, maybe a couple of governors. I think one is we're always going to manage to at a minimum being free cash flow positive. So I think that is a governor. And then there is a restricted payment basket, maximum threshold in our RBL and currently that is set at $100 million of cash.
Our next question comes from the line of Kashy Harrison with Simmons Energy.
My first one for Jason. You've been pretty clear about wanting to aggregate an oilier position and it seems like $20 WTI may be a good time as any to do so if you have the capability. And so I was just wondering if you could just share your thoughts on what you're seeing in terms of consolidation opportunities and how you think about financing set opportunities without impairing the balance sheet.
For us, again, we're, it is a big pillar of our plan. Again, we've been able to add acreage in Howard County again. So far this year we've added 1,300 acres. So, again, there's kind of multiple ways that we can pursue this. The acreage, I think out there you'll get it at all time, well, not all time lows, but lows for the longest period of time we've seen. So opportunity is to purchase land organically in both, again if we can get those at low rates.
I think all the things that we've done as a corporation to protect our balance sheet, push out our debt maturities into the future, to put hedges to protect our cash flows, all of those things work in our favor for larger type deals, again our LOE and when we talk about being at $2.80, again lowest in the basin.
Our G&A cash structure corporately is also very low. So we, it's hard to say exactly what that looks like in this environment. But where we see ourselves is really set up to be successful in a low price environment because of the low cost structure we've had for such a long period of time.
And then maybe a question for Karen. It sounds like leading edge well costs are tracking around $550 a foot. Can you share some thoughts on if you think that there might be more deflation to be had when you get back to work within that $30 to $35 work environment that Jason talked about? Or if you think you hit the limit on service cost deflation?
Yes, I think service costs are always a topic of discussion. And obviously we've seen some really significant impacts just over the last 2 months as we've moved into kind of this current environment with COVID-19 and other impacts. So the forecast for us, we're using current service cost. So those are, the $550 per foot is based on what we could drill well for right now at current performance with our current service providers at our current received pricing. So is there potential for movement up or down potentially, but that's what we wanted to based our forecast on.
Our next question comes from the line of Brian Singer.
Just a couple of questions. First, can you talk to the price points at which you would consider bringing back on the DUCs and then also price points for bringing back rigs? And probably the initial thought would be to consider the oil price. But could you also talk about how gas plays a role in that decision as well?
This is Jason again. We've got a DUC out there that just kind of shows the new economics. Again, on Slide 7 and Slide 8, we show sensitivities to different prices. So you can see with the great work Karen and her team have done, again we've been able to drive down the oil price that we need to get positive rate of returns at Howard County. So, again, there's turning on a DUC, I mean you do have some cost. It could be lower than we show here, but we show all-in well cost. You're getting into good rate of returns as low as $35.
And then the gas prices, again it's, for us it's something that as we rolled out the strategy, we're looking to get more oily as a company. That's still kind of our primary driver. But our core position that we've got is, again we're about a third gas, oil, and NGL. This is where it becomes interesting for wells like the Cline. Again, they are oilier, but they also have a high gas rate. So we can see as gas prices rise, you get in that $300 to $350 range and those Cline wells have just as stronger economics as we do with our wells in Howard County.
So there is a lot of options for us. If you think about companies in the Permian that potentially have exposure to gas, we're one of those few names. While our strategy has been to pivot to the oilier growth, we're more efficient with our capital structure. Our position and exposure to gas could also be a strength just as the associated gas comes down in the Permian with oil as shut-ins and things like that occur.
And then my follow-up is, you talked in response to the earlier question about some of the optionality on buying back debt. And wondered with free cash flow and your capital flexibility in this kind of higher cost to capital environment, how you think about the choices between building cash on the balance sheet versus reinvesting in the business versus the buying back of debt versus the acquisition market and how you see your priorities?
Yes. I'll do my best and then Michael can chime in if he has got some comments. But when we rolled out our strategy events, we're really trying to do all those things and they all change daily as oil price changes. Again, with the bonds trade out, we think through those things. But as a company, we want to try to get our debt-to-EBITDA down, which is something we were working on doing especially as we went to the oilier assets. Again, you can get that debt-to-EBITDA down by multiple methods, growing your EBITDA or getting the debt down that we purchased at a discount today when it was just issued in January.
So that's something that, again, we think a lot about, but it's really trying to do all of those things. Again, we're trying to balance on this free cash flow positive -- sorry, debt-to-EBITDA over time, but also continue to build inventory and be able to grow organically at higher rates as we -- prior to the shutdowns, we saw -- we are experiencing now are the lower price environment. I mean, we were able to create good solid growth out of the Howard County asset. So, again, we're trying to manage all of those things and it's a daily conversation. As prices change, again, cost of debt changes, et cetera.
Yes, I won't add too much. I think the only thing that I would add is kind of our hedge position for 2020 really allows us to evaluate each of those and really make the best strategic decision that needs to be made. And from -- that's from reducing borrowings on revolver to bond buybacks to using some of that free cash flow to restart completions earlier than January under our current plan. So it's just a lot of options out there as we all navigate through a really choppy time to where, really we're trying to get to a little bit of a point where there's some stability out there and those makes those decisions a little easier to make. We are not trying to make a call on pricing or something like that. So time to do it with our hedges and I think each of those things obviously get evaluated on a daily basis.
I'll just add to that. Again, under the liquidity under our RBL, again, gives us option value as well to act on some of the good work by the team with that getting into the $725 million.
Our next question comes from the line of Noel Parks.
Just a couple of things. I was -- I don't know if you touched on this earlier, sorry if it did come up. But at least sequentially it looked like transportation costs went up a bit. And I just wanted to check in on that.
Yes, this is Ben Klein. Couple of movements there. We, for the quarter, had the commissioning of the Gray Oak pipeline going into full service. Yes, in doing so, there was just a little bit of movement coming out of the -- what we call early service when we were shipping under their early service period to today. But kind of what we're guiding for, for this quarter, is going to be reflective of what you should expect in the future.
And speaking of infrastructure, I was wondering, in this period where there are industry shut-ins and lower activity, I was wondering are there any infrastructure projects that you might be able to get done at a particularly attractive price that you might consider moving a little sooner onto the calendar instead of things maybe you are thinking of for next year?
Not right now. I think one of the things we've really stressed over the last couple of quarters is that a lot of the heavy spend is behind us. A lot of our build-outs have been done early on in our development program and we're really capturing the benefit of that in these years. Our in-field infrastructure build-outs have been quite minimal this last couple of years and we don't expect that to change.
And really up in Howard, what we're anticipating doing is leveraging third parties that are already in place. It's a little bit of a different landscape up there with us entering into a more mature area that has already been built out by third parties. So our plan there is to really leverage that and not deploy as much in-field capital in that area.
So just the overall industry capacity, just not as much capacity or competition over the capacity up there now?
Certainly not having any issues being able to find a home for the oil, gas, and water.
And then just the last one. Looking back on what seems a lifetime ago into January, Laredo managed to do that debt offering at sort of that window where the markets were receptive. So just, with that under your belt and looking at how things have all transpired since, I just want to get some sense of what you thought about the debt markets. You mentioned possibility of buying in more of your own. And I wondered if you can, that's something you have to be like really opportunistic on the timing of, you anticipating more volatility? Or you think it's something you can just kind of plug away at throughout the year.
Yes, I think it's just going to be kind of what we talked about a little earlier. It's just another use of cash that we have today. So, I mean, those uses are pay down revolver. If we want to do some open market purchases, go ahead and invest and bring a rig back. But I think it's going to be pretty opportunistic and we're going to be just kind of watching the market. It's not something we need to do today. Obviously, we have a lot of options in '20. We have a, we've started to build a pretty decent hedge position in '21, which just starts to lock in the cash flows necessary to really run the efficient operations that we want to do.
And I think that's one of our keys, is that you see across all of our cost structure from the D&C, the LOE. Utilizing that cash flow, we're always going to try to make the best business decision we can to put it to work to basically generate the best return we can. And I think all 3 of those buckets are out there.
And when you're looking at where, if you just take the bonds specifically, where they're trading today, where oil prices are, it can be an attractive return. But I think we also have to kind of weigh do you want to use that cash flow and complete some additional, the Howard County wells a little earlier. So I think it's just something that as the team and Jason kind of work through this over the next couple of months and hopefully we see some stability that we'll work through those decisions and just see how it evolves over the next couple of months.
Our next question comes from the line of Richard Tullis with Capital One.
Probably for Jason or Karen, regarding the continued success driving down cost, in general terms, what is the split between internally generated efficiencies versus lower service cost for both well cost and LOE? Just trying to gauge the level of significant savings that could be retained in say a $35, $40 or even higher oil environment, I guess I'm optimistic there.
Yes. So, in general, we've had really significant cost savings for really all of 2019 and now obviously through first quarter of 2020. So as we worked through 2019, we were really seeing significant performance improvement and that's continued, which is impressive given that kind of trend forward. And through 2019, we were kind of talking about that we were seeing, in that cost reduction, roughly about half and half performance versus service cost impacts on, particularly on the completions which is where we were seeing most of the cost reduction.
Since we've moved into this year, as we went through our first quarter cost which we've talked about the delivery there, moving down from an expected about $618 per foot to $630, a lot of that is service cost related. And then our forecast forward is all service cost related with the current commodity price environment. So a lot of performance impacts moving through 2019 and then what we're seeing on the LOE side too. But really this year is more service cost performance, just with everything going on in the market.
And then just lastly from me. It looks like you're able to acquire the Howard County acreage at some very attractive prices. What's the typical associated royalty with that? Has it bumped up any because of lower cost or is it still pretty standard?
Say that's pretty standard for right now. But again the world is changing a little bit. So we'll see going forward, we'll see what happens going forward. But again the cost has come down materially. That's something that we're excited about.
Thank you. I'm showing no further questions in the queue. I would like to turn the call back over to Ron Hagood for closing remarks.
We appreciate you joining us for our call this morning. This concludes our call and have a great day.
Ladies and gentlemen, this concludes today's conference. Thank you for your participation. You may now disconnect. Everyone, have a wonderful day.
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