Vital Energy Inc (VTLE) 2021 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to Laredo Petroleum First Quarter 2021 Earnings Conference Call. My name is Carol, and I will be your operator for today. (Operator Instructions) As a reminder, this conference is being recorded for replaying 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 Bryan Lemmerman, 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, forecast and assumptions, are intended to be covered by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Our 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 references to non-GAAP financial measures. Reconciliations to GAAP financial measures are included in yesterday's news release.

Yesterday afternoon, we released a news release and presentation detailing our financial and operating results for the first quarter of 2021. We will refer to the presentation during today's call. If you do not have a copy of this news release or presentation, you may access it on our 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 our first quarter of 2021 earnings call. Our results for the first quarter are a demonstration of the solid financial management and operational execution that underpins our strategic transformation. We generated $22 million in free cash flow in the quarter as we continued to reduce well cost, which entirely reduced capital expenditures. We sold shares under the ATM program for about $27 million in net proceeds and reduced borrowings under our revolver by $35 million. Our long-term trend of drilling and completion efficiency improvements and innovations, such as our company-owned sand mine, are indicative of our drive for continuous improvement.

Capital efficiency improvements from our transition to Howard County came to fruition this quarter. Production from our first package of wells in Howard County had a substantial impact on our production during the quarter despite downtime due to February's winter storms. Oil production grew 11% sequentially versus the fourth quarter of 2020, and we expect sequential oil growth of 9% to 13% in the second quarter as our second package of wells reaches peak production.

We continue to do well on our ESG metrics flaring or venting only 0.22% of produced natural gas during the quarter. The company has put forward an ambitious plan to reduce greenhouse gas emissions and reducing and, ultimately, eliminating routine flaring as a key component of the plant.

To conclude, I would like to recognize the efforts of our operational team to quickly and, more importantly, safely restore production after the winter storms in February.

With that, Karen will provide more details on our operations.

Thank you, Jason. I'd like to begin by seconding Jason's comments on the efforts of the entire operations team to get us back up and running after the severe weather that occurred in February. It was all hands on deck, and it took a lot of focus and discipline by all of the teams to work as quickly and safely as we did to minimize the impact.

Results in the first quarter continued to reflect our successful transition of activity to Howard County. We continue to make significant progress on reducing well cost, with our first 2 packages in Howard County being delivered at $525 per foot. One of the main drivers of this success has been our company-owned sand mine. We are now consistently realizing savings of $90,000 per well, with the mine supplying over 85% of the sand we used in the first quarter. We were also able to successfully source the other 15% of our sand volumes with third-party sand right after the winter storm as we were getting operations up and going again at the mine, with no increase to our well cost. Additionally, we continued our long-term trend of increasing operational efficiency, increasing drill feet per day per rig in the first quarter even as we were working with the new rig we added at the beginning of the year.

Cost incurred in the first quarter came in lower than anticipated. This was driven by the decreased well cost just mentioned as well as some infrastructure projects that were delayed until later in the year.

Based on the first quarter cost, we believe that we were on track to spend less than our $360 million capital budget, but also planned to fully evaluate the potential for continued improvements in drilling and completion efficiencies, which could positively pull some activity forward in the 2021 from first quarter 2022, as we keep activity levels steady at our current 2 rigs and one frac (inaudible)

In addition to delivering capital cost, we've also been pleased with our LOE trends in Howard County. While we still expect LOE to rise as we bring on more production in Howard County and still forecast about $4 per BOE for the life of a well in Howard County, so far our operating costs have been lower than we originally anticipated.

We have been testing the application of high-rate, high-pressure gas lifts on a few wells to evaluate the impact on both production and operating costs. We also continue to optimize our water forecast as we gain more production data. And we've transitioned the majority of our facilities and wells to purchase power, all of which could positively impact our operating costs going forward.

We expect to deliver steady oil production growth throughout 2021, as we bring on one well package per quarter in Howard County, running one continuous frac (inaudible). While there can be some lumpiness to production based on timing of the large 12 and 13 well packages in our development plan, we expect sequential oil production growth throughout 2021 as well as an increase in our oil cut.

The early production results to date in Howard County are within the range of our expectations. As we showed in last quarter's release, the first package, the 15-well Gilbert/Passow package started out in line with our average performance expectations. This package has begun to tail off a bit over the past couple of months, but overall, it's still performing within a range of expectations, particularly given the tighter well spacing in this package.

Our second package, the 12-well Trentino/Whitmire package is well ahead of the average performance expectations early in its history. Both packages were developed on the tighter 12-well per DSU spacing in the Wolfcamp.

Subsequent packages will be up spaced to approximately 8 wells per DSU in the Wolfcamp. We believe this will deliver more consistent performance and maximize value per DSU.

We continue to make good progress building our Howard County leasehold. Subsequent to the end of the first quarter, we acquired a full section contiguous to the section that we acquired in October 2020. This formed up in 2 section DSU, which now sets us up to develop the DSU with 10,000 foot laterals.

I will now hand the call to Bryan for financial updates.

Thank you, Karen. Like our operational execution, we also executed on the financial side of our strategy. We maintained our capital discipline and our focus on expense control, which combined with the capital efficiency of the Howard County development program drove free cash flow of $22 million for the first quarter.

In February, we initiated our at-the-market equity program. Authorized for $75 million, the ATM program allows us to opportunistically sell equity from time to time. We put the program in place with the intention of using the proceeds to pay down a portion of our credit facility that had been used in the fourth quarter of 2020 to repurchase $61 million of notes at 62.5% at par and to finance a bolt-on transaction at Howard County where we bought acreage at a little over $2,000 per undeveloped acre. These opportunistic, very accretive transactions totaled about $50 million. When we announced the ATM program, our stock was in the mid-30s. Subsequently, we were able to sell 723,000 shares at an average price of approximately $38.75 for net proceeds of $26.9 million. These proceeds combined with the free cash flow enabled us to pay down our credit facility by $35 million during the quarter while also making an interest payment on our notes of approximately $46 million.

Going forward, our goal is to continue to pay down debt and strengthen our balance sheet. Recent commodity price increases have enhanced the free cash flow generation profile of the company. During the first quarter, we added to our 2022 oil hedges, and we intend to add more as the year progresses, further increasing our confidence in our 2021 and '22 free cash flow profile and debt-reduction capabilities.

With that, I will ask the operator to please open the line for questions.

(Operator Instructions) And your first question comes from the line of Derrick Whitfield with Stifel.

Well, my first question, perhaps for Karen. I'd like to focus on your chart on Page 8 to understand the differences between the first 2 sets of wells. Other than the winter storm Uri impact to the first set, were there other noticeable or notable differences in the D&C design or [flow] back approach between these 2 sets?

So at a high level, the answer is no. There's no real difference between those first few well packages. They were really designed on the same spacing, even really looking at landing points. They basically had the same basic design. So overall, both of these packages are still relatively early in the flow back. We continue to evaluate performance of the different landing points between the Spraberry and the Wolfcamp formations. But really no design differences in these first 2 packages.

That's just again, statistically, we just see packages that are a little better, a little worse. So it's just something that's not unusual to oil and gas when you're kind of putting these first few wells -- packages and wells now.

That makes sense. For my follow-up, I wanted to focus on the A&D market, perhaps for you, Jason. In your view, did the recent larger midland transaction in the basin tilt the A&D environment from a buyer's market to a seller's market? Or do you sense sellers can see that it was somewhat of an anomaly?

Most of the folks that we've talked to and all the analysts that looked at it think that that's an anomalous transaction. Again, good fit for the purchaser there, but I don't think that the expectations have been raised by that level across the basin. I mean there's lots of things that are on the market, so again, it's a good time. I think the bid-ask is narrowing, especially, again, as prices have risen a little bit, it was difficult to do things in a much lower price environment, but I do think we're in a price environment today where we can be successful with transactions.

Fantastic. Congrats on your success today.

(Operator Instructions) Your next question comes from the line of Noel Parks with Tuohy Brothers.

I just wondered, could you just sort of review a little bit the spacing history of what you've been doing since your Howard County acquisition. [Initial one I think was about] going on 23 years ago, if memory serves me. And just sort of what the spacing assumptions were under the legacy operator, what you started out at, where you are now. And also, could you just kind of review the geological characteristics that helped determine what spacing works where? Geological or, I guess, the completion choices.

This is Karen. Yes, I would be happy to kind of step back and talk a little bit about the history of the acreage. So we acquired the acreage and kind of closed on the Howard County acreage that we're developing right now in late 2019, right at the end of 2019. One of the reasons that this position was very attractive to us was it really had not been developed. So there were really no parent wells. So it was a good location for us to go in and go into kind of full development in this area. So no real spacing kind of outlined prior to that.

We actually transitioned very quickly in 2020 to active operations in Howard County, but then delayed completions in Howard County just given the environment that we were in, in early 2020 with COVID and other things. So we actually started completion operations in September of 2020. So we've only been actually operating with active completions going back since really the very end of 2020. So 4 to 5 months on the first package. So that's why we kind of referred to the early well performance. We were really getting the first look at the well results coming back from Howard County. And the first 2 packages, which is what we are showing on Slide 8 in the earnings release.

So as we began development in Howard County, this spacing design that we've talked about was 4 wells in the Spraberry, 12 wells in the Wolfcamp. That was the development plan that we went in from the first two well packages, the Passow/Gilbert and the Trentino/Whitmire as we refer to them. And that's what the 2 packages that are plotted up for the Howard County wells on Slide 8 are.

As we kind of got into that development, continued to look at all the work that was being done by us, the offset operators, just really a lot of technical work in completions. (inaudible) the drilling rigs as well out in front of the completions crew. So we decided to really up space a little bit in Howard County in front of even getting any of these well results back. And that's what we've been doing on the next packages that we'll be pulling back in subsequent quarters.

So what we're -- the up spacing design is still 4 wells in the Spraberry, 8 wells in the Wolfcamp is currently what we're doing. Overall, looking at the well results on Slide 8, overall these are strong packages. It's early in their history. We're happy with their performance. These wells that are pulling back right now are supporting our overall company strategy, which is capital efficient wells, high rates returns, high rates returns really supporting our strategy of free cash flow generation and paying down debt. So these first 2 packages are clearly supporting that. And as we continue to bring on the up space packages, which will be the packages that we bring on in the next couple of quarters, we just think that they will help support more consistent results and continue to support that strategy. So that's kind of the history that we've been on since acquiring the Howard County acreage.

Great. This is helpful. And could you just talk a minute about what you're thinking of going forward on steel cost. I was wondering if you have been thinking about building up your inventory or maybe already had or what are your thoughts -- maybe this was kind of a temporary blip upwards for steel and we might be in a better shape turning into future quarters.

Overall, so we have a supply chain team that really works every aspect of our business. And steel's an interesting one which is impacted by the broader global market at times. So we do see some fluctuations up and down. Overall, we're not really seeing impact on our well cost currently. We do have contracts in place that we work out in time to make sure that we're managing both the cost and inventory on all of our key [dealers] and everything. So really not seeing any significant impacts currently to our business.

And your next question comes from the line of Richard Tullis with Capital One Securities.

Question for maybe Jason or Bryan. Given the recent uptick in commodity prices, that certainly helps the cash flow for the quarter. Does this present an opportunity to potentially look at monetizing some of the less core acreage, the 100,000 plus acres that you hold in the legacy properties outside of the current focus area in Howard? We've seen a couple of other E&P sell sort of noncore acreage over the past couple of months in the recent announcements. So I just want to see if maybe it heightens your interest at all in maybe look into part with some of the legacy acreage.

Yes. It's a great question. I think that it is something that's on our radar. Again, as everyone knows on the call, we are looking to continue to bring in higher-quality inventory. Today, the core position provides the cash flow that funds that. But depending on how much PDP might come in with a transaction, selling down, selling a non-op interest or carving out a portion of the field is something that we would consider to, again, just help strengthen the balance sheet and not just bring on straight debts. Those are things that we think about. A lot of it will just depend on kind of the M&A work in the future.

Okay. Question for Karen. Obviously, really nice well cost average with the packages in Howard County online year to date. How sustainable do you think the $525 per lateral foot is as we go forward? And I mean, is there potential to even lower that more?

Yes. We've talked about prior that we were expecting to come in a little bit below where we were, so $540 a foot. But really, again, with the first package coming through, we wanted to have actual clear performance as we're going in and really starting the completions operations in Howard County. So, with the first 2 well packages behind us at this point, really felt comfortable coming out with actual well cost at the $525.

So as we all talk about are there potential pressures on service cost, that dialogue continues. We are not seeing any really significant upward pressure there. As far as continuing to optimize our designs and look for performance improvements, yes, I think there is opportunities. So it will be really just kind of balancing how to continue to drive performance improvements into drilling and completions, operations, and make sure that we're managing any type of cost pressure that we're getting on the service side of the business.

We've talked about our sand, our own mine that we have. We are -- just from our frack service provider's external company is hearing that there is pressure on the sand side, both trucking and sand. So right now we're really insulated from that, which is a good position to be in with the sand that we're providing off of our own locations.

So overall, I think we're set up pretty well. We shared again the performance of both drilling completions. We've been doing that on a quarterly basis. Even with the severe winter storm that impacted us for a few days in February, we're seeing really good performance and continued performance improvement. So I do think there's opportunity for that to continue.

And ladies and gentlemen, we've come to the conclusions of our Q&A session for today. And I'll turn the call back over to Mr. Ron Hagood for the closing comments.

Thank you for joining us for our call this morning. We appreciate your interest in Laredo. This concludes our call, and have a great morning.

Ladies and gentlemen, this concludes today's conference. Thank you for participating. You have a wonderful day. You may now all disconnect.