Vital Energy Inc (VTLE) 2018 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to Laredo Petroleum, Inc.'s Third Quarter 2018 Earnings Conference Call.

My name is Imani, and I will be your operator for today. (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. You may proceed, sir.

Thank you, and good morning.

Joining me today are Randy Foutch, Chairman and Chief Executive Officer; Rick Buterbaugh, Executive Vice President and Chief Financial Officer; Karen Chandler, Senior Vice President and Chief Operations Officer; and Dan Schooley, Senior Vice President, Midstream Marketing and Subsurface; 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'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 third quarter 2018. 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, and thank you for joining Laredo's Third Quarter 2018 Earnings Conference Call.

As Ron mentioned, last night we provided a third quarter 2018 earnings presentation that we will refer to throughout the call this morning.

As you can see on Slide 3, Laredo's history of improving operational efficiencies carried into the third quarter, driving slightly higher-than-anticipated total production growth in the quarter. We are also raising the number of expected completions for 2018 to 71 net wells and total production growth to approximately 17% while still expecting to stay around our $630 million capital program. We grew adjusted EBITDA 5% from the previous quarter, keeping our debt-to-EBITDA ratio at 1.4x even as we continue to repurchase shares under our stock repurchase program.

Turning to Slide 4. Our cash costs on a unit basis were below guidance for every category. Coupled with our focus on controlling capital costs, this helped to align CapEx and cash flow from operations for the third quarter as we had guided with our original 2018 budget announcement.

On Slide 5. As I mentioned previously, we have raised our total production growth guidance for 2018 by 2% to approximately 17%, although lowering our oil production growth guidance for the year by 2.5% to approximately 7.5%. In a few minutes, Dan will discuss some of the drivers we believe are impacting our oil production. Looking into 2019, we expect to operate closer to cash flow from operations for full year 2019 than in full year 2018. A small outspend would result in oil production growth similar to 2018. Aligning CapEx and cash flow from operation would result in an oil production growth below that of 2018.

As shown on Slide 6, in the first 3 quarters of 2018, we've utilized approximately $495 million of our capital budget. We anticipate capital costs incurred in the fourth quarter to come down from third quarter costs incurred, as we are dropping a completion rig in mid November. Although our completions for full year 2018 are expected to increase from previous estimates, we anticipate staying around our $630 million full year 2018 capital program, excluding non-budgeted acquisitions.

Turning to Slide 7, I would like to make some comments about how we are evaluating our development plan.

For the past 1.5 years, we've been focused on the high-density development of our Upper and Middle Wolfcamp formations. This has been an intensive process to determining the complex interaction of landing point selection, horizontal and vertical spacing, parent-child impact, completion design and lateral length on well productivity and long-term production decline rates. We believe the results of the 4 high-density packages for which we have production data confirm our thesis that developing the Upper and Middle Wolfcamp formations with 24 to 32 wells per DSU adds to the overall value proposition of our acreage. We had 2 additional high-density packages that have just been completed and another 3 that will be completed through the first half of 2019.

As I mentioned a moment ago, moving into 2019, we are focused on balancing capital expenditures with cash flow from operations. To accomplish this goal, we anticipate running at a slightly reduced rig and completion crew cadence and therefore have begun shifting our development to focus on improving our rate of return and [in] capital efficiency. As illustrated on this slide, this will be driven by lower-density development packages. Lower-density packages are expected to be brought on production around the end of the second quarter of 2019, impacting results in the second half of 2019.

I would now like to hand the call off to Dan to further discuss well results.

Thank you, Randy. And good morning.

Still on Slide 7, one additional comment as it relates to our inventory. Low-density development that focuses on capital efficiency and rate of return still results in extensive running room for the company. In total across all formations, we think we have approximately 1,600 locations at rate-of-return focused lower-density development. Obviously, we have significantly more locations at higher-density development, but now that we have defined what we -- can be accomplished at the higher-density development, we are moving to improve our rate of return and capital efficiency to minimize our outspend.

Slide 8 shows the results of the 4 high-density development packages that have a wide range of production history and other data. A trend we are observing in these results is influencing our thinking on near-term future development. High-density wells are seeing steeper-than-forecast oil decline rates, much more so than the gas curve. If this trend holds, it does not significantly change a well's expected first-year oil productivity or expected rate of return, but has an impact beginning in year 2 which influences the company's base production volumes. This concept has capital efficiency implications as it would take more capital to grow oil production in the future at higher-density development. Multiple factors are present that influence the oil productivity of these high-density packages, including landing point selection, completion design, parent-child interactions, lateral lengths and horizontal and vertical spacing. We have extensive data on well performance relative to these factors and will be applying these learnings in development planning and budgeting going forward.

Moving to Slides 9 and 10. These charts show performance of wells completed by year since 2015 relative to type curves at that time and adjusted for formation and lateral length for total production on Slide 9 and oil production on Slide 10.

Total production is generally exceeding expectations and maintaining its performance relative to our expectations. We see evidence of steeper oil decline rates than expected, resulting in lower anticipated oil production. Oil production tends to peak within the first year, and then performance versus expectations begins to diminish. This trend is even more pronounced at higher-density development, which we believe is the primary driver of both the difference between total production growth as compared to oil growth and the recent lower oil cut trend. We believe the implication is the converse for future development at wider spacing. Lower-density development in future drilling programs should positively impact both oil productivity and capital efficiency for individual well packages and on an annual program basis.

I will now hand the call over to Karen Chandler, whom we recently named Senior Vice President and Chief Operating Officer.

Thank you, Dan.

During the third quarter, we continued to see efficiency improvements as a result of outstanding work of our operations teams. Our original 2018 budget was built on completing approximately 62.5 net wells. Driven by efficiency gains in both drilling and completions operations, we now expect to complete 71 net wells. This is a 14% increase without increasing the originally budgeted rig or completion crew count.

Turning to Slide 11, we show the improvements in drilling efficiency we've accomplished since the beginning of 2017. The data represents the average days to drill a normalized 10,000-foot horizontal well from rig accept to rig release, which includes the time to drill both the vertical and horizontal sections of the wellbore. These improvements are the culmination of ongoing implementation of performance initiatives that engage our contractors in all areas, from the basic to the most complex, to identify best practices and drive continuous improvement.

Internally, we are better integrating our drilling and subsurface teams to fully utilize our geomechanics modeling in our well-planning processes. This has greatly optimized our intermediate casing setting-downs and reduced nonproductive time related to fighting either mud losses or hole stability while drilling the production laterals. On Slide 12, you see even more substantial improvements in our completions efficiencies. These improvements are a result of completions design optimization and reduction in nonproductive time across our completion crews. We have also achieved significant improvement in our drill outperformance through optimization of bit and BHA designs. We continue to work towards consolidating our operations with service providers who can deliver on both improved efficiency and safety performance.

As shown on Slide 13, these improvements have culminated in an expected 50% increase in gross completed lateral feet per rig in 2018, as compared to 2017. Just as impressive is the approximately 200% gain since 2014, which has enabled us to accomplish as much activity with 3 to 4 rigs as with the 8 horizontal rigs we were operating in 2014. Reduced cycle times driven by continued improvements and operational efficiencies are expected to enable the early completion of our budgeted 2018 drilling and completions program. And we anticipate dropping 1 completion crew this month and operating with a single completion crew for the remainder of the year.

We have maintained the same focus on continuous improvement to control operating costs. On Slide 14, we show unit LOE since the beginning of 2015. Since the third quarter of 2016, we have maintained unit LOE below $4 per BOE on a quarterly basis. Like the other aspects of our operations, we have implemented extensive analysis of cost drivers and are constantly looking for ways to optimize operations and drive down costs. One of the main drivers of our low unit LOEs is our prior investments in field infrastructure, primarily our integrated water systems and field gas compression. We believe this will provide ongoing benefits as we continue to focus drilling and completion activities in areas to further utilize and capitalize on our existing infrastructure.

I will now hand the call to Rick for a financial overview.

Thank you, Karen. And good morning.

The company's financial performance continues to improve as we grow production and control cash cost. In the third quarter of 2018, we balanced capital expenditures with operating cash flows and grew adjusted EBITDA, a non-GAAP financial measure that is reconciled in the appendix to this presentation, by 5% from the previous quarter to a total of $160.6 million. You can see on Slide 15 the growth in adjusted EBITDA on a net-debt-adjusted per share basis. Since the beginning of 2017, we have grown adjusted EBITDA per net-debt-adjusted share by approximately 50%, substantially faster than the increase in the price of oil over the same period despite recent basis headwinds. Our focus on cost control throughout our operations and goal of strengthening our balance sheet are reflected in this metric's continued improvement.

As shown on Slide 16, at September 30, our net debt was approximately $920 million or just 1.4x the annualized amount of third quarter 2018 adjusted EBITDA. This debt includes $800 million of senior notes, which are not due for at least 3 years. However, each tranche is callable today, with call premiums declining during the first quarter of 2019. The remaining net debt is on the company's reserve-based credit facility. The company's borrowing base of $1.3 billion and our elected commitment of $1.2 billion on this facility was recently reaffirmed by our bank group. As a result, we have total liquidity of more than $1 billion, which provides significant flexibility for future investment.

In this vein, as illustrated on Slide 17, during the third quarter, the company executed approximately $10 million of share repurchases under its authorized $200 million share repurchase program. Since the inception of this program, we have utilized approximately half of the program to repurchase approximately 11 million shares at an average price of $8.78 per share, around $0.20 per share less than the weighted average price over that same time frame.

The key to maintaining our investment options is protecting our anticipated cash flows. On Slide 18, we show the company's commodity and basis hedges for each product by year. For 2019, we have approximately 8.7 million barrels of oil hedged, primarily using puts which protect the downside while retaining all of the upside in a volatile commodity environment. We consistently review opportunities to add protection, including financial commodity and basis derivatives, in addition to physical firm transportation to underpin our future cash flows and assist in general development planning. Details of these derivatives and physical deliveries are shown in the appendix of this presentation on Pages 22 and 24.

In summary, we believe we have concluded significant performance testing across our acreage, including multiple landing points, a variety of vertical and horizontal spacing, completion design, parent-child relationships and lateral lengths. Although long-term production data will continue to be analyzed, we are moving to wider spacing, which we believe best balances our goal of growth within operating cash flow while recognizing the highest value of our asset for stakeholders.

Operator, please open the lines for any questions.

(Operator Instructions) Our first question comes from Derrick Whitfield with Stifel.

Perhaps for Randy or Dan. Referencing Page 10, is there a vintage-type-curve year that will be most representative of 4- to 8-well spacing?

You're on Page 10. I think the messaging that we wanted to convey is that, as we -- we know a lot about our acreage. We've learned a lot about our acreage. We've done a variety of spacing and vertical testing and lateral lengths and completion design. And so I think what we -- what I would tell you, and then I'll let Dan respond, is that each one of these years has got a mixed testing program within it to some degree. I don't know that one is representative.

I think yes, Randy. Adding on to what Randy said, I think that's exactly right. 2016 performance was driven not just by wider spacing. That outperformance was also driven by drilling in what you would consider virgin rock. We weren't drilling around other wells. We weren't having to worry about infill, parent-child. We had very few parent-childs in 2016. So 2016 does reflect wider spacing, but it also has a lot of other things that -- challenges that we're not -- we're going to have to face going forward. We're going to have to drill in areas that have existing wells. We're going to have to drill infilled wells around that. So we don't anticipate as good a performance as 2016 even though we're going out to the wider spacing.

That makes sense. And then as my follow-up, referencing Page 7, what variables drive the lower and higher end of your 4- to 8-well per-section range for the Upper and Middle Wolfcamp? I assume location and price are 2 of the variables, but I'd love to hear your feedback on that.

Yes, I think there's several things. And again, I'll let Dan -- this is Randy. I'll let Dan follow up [it]. Part of that is what's already been drilled. Part of that is exactly what landing we're going to use. Part of that is what lateral length we're talking about, and so it's -- I think it's a variety of factors that give us that range on how many wells per drilling space you get.

And just as a follow-on to that, Derrick. The -- one of the drivers also is co-development. We had -- in previous years, we were drilling at 3 to -- actually, we had 4 total landing zones in the Upper Wolfcamp alone and 4 in the Middle Wolfcamp. So what we're going to migrate to now is away from co-development and looking more at single-zone wider spacing. So that's what's driving the counts primarily in -- on the rate of return in low-density drilling on Slide 7.

Our next question comes from Kashy Harrison with Simmons Energy.

So just a first one for me, the commentary on inventory. I was just wondering. How many of these 1,600 locations are in the Upper Wolfcamp and then Middle Wolfcamp?

Kashy, thanks. This is Dan Schooley. It's about 50%, so almost 900 of them, a little bit better than 50%.

Okay, got it. And then just a second quick one for me. I was seeking some clarification on the 2019 guidance. So it sounds like the 2019 CapEx budget is going to be held -- sorry. The 2019 CapEx budget is going to be held flat year-on-year at $630 million. And is that the oil production case, or is that the oil decline case? Just wanted to get some clarification on that.

Yes, Kashy. This is Rick. We have not come out with our 2019 budget yet. Would expect to have final approval of that sometime in January, early 2019. So as we're formatting that or forming that 2019 program, the primary driver from a cash standpoint is to operate within our operating cash flows. So that will drive the amount of activity, but we'll also look at various investment opportunities for that, as far as what is the right cadence to operate to be drilling, completing at, meeting our requirements. As you know, our acreage position is primarily held by production and that we have a lot of flexibility on how we go about the development of that acreage. So it's a balance of at what level we would spend. Now keep in mind that the $630 million that we're anticipating spending and committing to for 2018 did create an outspend, so I think using a $630 million program in 2019 is going to be above what you should be expecting.

And our next question comes from Asit Sen with Bank of America Merrill Lynch.

I understand these are early days in this, but as it relates to the wider and tighter spacing test, could you provide any thoughts on resource per section or cost per section, any early thoughts?

Yes, Asit. This is Dan Schooley. I don't think we think the resource, obviously, has changed. The rock hasn't changed, and we still have the same amount of oil in place. It's obviously a matter of how much of that we can get out at the different spacing densities that [we've] been on. And I'm -- let me go at this a different way too and then have Jason jump in here if I -- if we need some more technical help, but this rock that we're talking about is 4,000 feet thick. We've tested 17, I think, discrete landing points in this rock, 8 of which were in the Upper and the Middle Wolfcamp. So these -- all of these landing points have -- they drill different. They complete different. They produce differently, not just in within a DSU but across our acreage position as a whole. So I think what we're seeing in the data right now, like I said in my discussion, is the primary drivers that we're seeing in these higher-density development is landing zone; completion design; parent-child; as Randy said, lateral lengths; and spacing. Jason, did I leave anything out?

Yes. This is Jason Greenwald, Vice President of Reservoir Engineering. I think the only thing I would also add emphasis to is our understanding of the resource in place hasn't changed. We still think it's a huge amount of oil in place. This is a world-class basin. When we're talking about NPV and higher-density development, that is a higher-recovery development scheme. And by shift -- but the shift to lower density and rate of return, it's focused on the rate of return of those wells and the capital efficiency of those wells, but then that also comes with a slightly lower recovery at the end place.

Okay, all right, I'll take it offline -- or any early thoughts again? You were doing some work on lower concentration of fluids in some cluster tests. Any early thoughts on that? And have you talked about completion designs?

Yes. This is Karen Chandler. The -- so we're continuing to test multiple completion designs. I think that across the completion design we're going to optimize as we work our different spacing. So I think that will be impacted. And I think going to the lower-density development will actually give us an opportunity to look to continue to optimize the completions design, meaning from an operations standpoint driving down costs, improving our cycle times. So I think those really go hand-in-hand with continuing to help us improve the capital as we make this transition in our program. So we're testing a lot of different things, like we mentioned, and -- or have. And we'll just continue to optimize that with our spacing program.

(Operator Instructions) Our next question comes from Sameer Panjwani with Tudor, Pickering, Holt.

With your equity trading where it is, our view at TPH is that the market is only paying you for PDP value and not giving you any credit for undeveloped locations, so in that context and with the coming inflection in capital efficiency, how do you think about accelerating buybacks instead of pursuing production growth?

This is Randy. We consider lots of different ways of reinvesting capital, including just that. We've got acreages held by production, so -- for the most part, so we have a lot of flexibility on where we put capital. And I think going forward, we'll have decisions to make about what that looks like. We've been careful in our investment decisions in terms of how we actually expend those dollars, but yes, we understand the math pretty well, Sameer.

Okay, that's helpful. And then on 2019, I understand you're still in the budgeting process, but is Q4 a good approximation of how you're thinking about at least the first half of 2019 from both an activity and production standpoint? So about 15 wells a quarter and flattish oil production.

Yes, as you're aware, I mean, the cycle time from planning to drilling and completion is rather lengthy. We do expect to bring our activities in-line fairly well on a quarterly basis with our cash flows. You will see some ups and downs with it. And our primary focus, as I stated earlier, was that we would live within cash flow for the entire year. The amount of completions and the timing of that is still yet to be determined. You're seeing that we have reduced our -- or are in process of reducing the amount of completion crews that we have running. We want to balance those activities to make sure that we're still operating as efficiently as possible but staying with our -- within our commitments. It also, as we just talked about and Randy talked a little bit more about, is the investment decision of where are we going to put that cash to work if it's not being rewarded with the drilling activities. And the value of the equity is that what we believe is a discounted value. You may see more of the capital and the cash flow being directed in that direction. So we will come out, as I mentioned, early in '19 with a little more definitive plan, but those are the types of things that are being looked at now.

Our next question comes from Richard Tullis with Capital One Securities.

Randy, I apologize if you've touched on this already. So with the planned lower-density development going forward, will you be retaining the 1.3 million-barrel type curve with the 1.45 B-factor?

We look at that pretty often quarterly. And I think what we've seen and we've kind of mentioned is that the higher-density drilling impacted production. And we're really trying to understand what that ultimately does for reserves over time. We've expressed in the past that on base production that's been out there for a while the gas-oil ratio will continue to increase. We've not yet talked about 2019 in terms of what reserves look like, but I think clearly we've indicated that that's a stress factor.

Okay. And then just lastly, the $7.4 million well costs referenced in the earnings release. Any impact on cost expectations moving from the higher density to lower density going forward?

So again, this is Karen. Yes, so right now, the $7.4 million, we talk about for an average 10,000-foot lateral. So as we move forward, and back to the prior question, I think there's an opportunity for us to continue to optimize the completion design, particularly at the wider spacing, to really focus more on increased stage length, cycle times, things that really suit that wider spacing some. Those are things we've been working on and really trying to understand fully, and then we'll continue to push that way. So I think there is some opportunity there, and we'll balance that in with just other price pressures and other things. So yes, it's additional opportunity there.

Our next question comes from Dan McSpirit with BMO Capital Markets.

What is the decline rate on oil PDPs today? And what's the estimate 12 months out? Asking in an effort to get a better sense of how the capital intensity of your operation is expected to change over time.

Dan, I think we're -- I think that's something that we're still very aggressively trying to answer ourselves and work on going forward, so that may be something that we should address at some point in the future as we start talking about 2019.

Thank you. This concludes today's Q&A session. I would now like to turn the call back over to Ron Hagood for closing remarks.

We'd like to say thanks for joining us for our third quarter update. 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. You may all disconnect. Everyone have a great day.