Vine Energy Inc.
Q1 2021 Earnings Call Transcript

Published: 17 May 2021

Operator:

Good day and thank you for standing by. Welcome to the Vine Energy First Quarter 2021 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker’s presentation, there will be a question-and-answer session. I would now like to hand the conference over to your speaker today, David Erdman, Direct of Investor Relations. Please go ahead.
David Erdman:

Good morning, everyone. I'd first like to introduce myself as the Director of Investor Relations. I'm enthused of the opportunity to cultivate a long-term working relationship with you. My contact information was included at the end of the earnings release we released this morning and on our website at VineEnergy.com.
Eric Marsh:

Thank you, David and good morning, everyone. I'd like to first extend a warm welcome to our new and existing stakeholders, and reiterate to each of you that we are grateful for your firm's investment and confidence in Vine Energy. We look forward to working with you over the coming years. Seven years ago, I partnered with the Blackstone Group to invest in the highest return natural gas asset in North America. At the time, we targeted the Haynesville Basin for its potential to drive superior economics. A short time later, Vine Oil & Gas was created following the acquisition of the most distinguished natural gas acreage in the Haynesville Basin and quite possibly in all of North America. Not long thereafter, we saw opportunity to expand our undeveloped acreage within the basin by acquiring leases in sections that complemented our existing inventory. From that Brix Oil & Gas was born. Although a separate entity, it was managed by the same operating team, with a vision that the two would one day merge to create a world-class natural gas company.
Dave Elkins:

Thank you, Eric and good morning everyone. I would like to start out with a quick summary of the impact of winter storm Uri. The Vine team did a tremendous job under difficult conditions and most importantly, we stayed safe. Fortunately, there was enough warning before the storm that we could develop and execute a plan to either keep operations going or return to normal operations quickly. All of our rigs continue to drill during the storm and our completion operations were only paused for about 3.5 days. Our production team did a great job keeping production up. However, mainly due to power issues and our third-party gathering and processing facilities, we were forced to shut certain wells in for about six days. And thus we lost about 3.8 Bcf of gross production or 28 million a day net for the quarter. Now to my first quarter update. Vine is coming off our best operational year in 2020. We achieved a transformational uplift in drilling, speed and completion efficiency. The year was defined by operational excellence, technological advancement, exceptional safety performance and environmental gains and it lays the foundation for us to fresh milestones in 2021. Among our achievements, the realization of incremental drilling and completion efficiency stands out. Throughout our acreage Mid-Bossier and Haynesville reservoirs are deep and over-pressured. We often contend with bottom hole temperatures above 320 degrees and extreme pressures. The development of long laterals in our part of the basin has only been a reality in the last few years due to these conditions. Candidly, the first few years of development were at times a struggle as we slowly and sometimes painfully made our way along that learning curve. In 2019, we began to make real progress. And as I mentioned previously, 2020 was truly transformational. Among other factors, we focused on improving the performance of downhole tools, consistency of drilling parameters and tools across the rig fleet, improved performance in the intermediate section of the whole and reduced curve drill times. The outcome was impressive. As 2020 was the most efficient year for the Vine drilling team. Specifically, we drilled 270,000 gross feet of lateral in 2020 of which 80% were long laterals. We achieved a 24% reduction in drilling days for 7500-foot laterals and a 17% reduction in days at 10,000 feet when comparing against 2019 results. To be exact, we averaged 29 drilling days on our 7500-foot laterals compared to 38 days in 2019 and 39 days under 10000-foot laterals compared to 47 days in 2019. This saved us over $650,000 per well. However, my favorite statistic from the drilling team relates to rig efficiency. In 2019 we averaged about 62,000 feet of lateral per rig. In 2020 that ratio jumped to 77,000 feet of lateral per rig, a 25% improvement that led to real per well savings. Put another way, we were able to drill 5% more lateral with 256 fewer rig days. The team has continued its success in the first quarter of the year. We reached total depth on seven wells, three of which were best-in-class among all Vine wells including the rocking G231411H1 . It's the longest lateral Vine has drilled to date with a total measured depth of 23,300 feet. It will have a lateral length of over 10,500 feet when it is completed later this month and it took just over 35 days to drill the well. At sister well, the H3, was 700 feet shorter, but only took 30 days to drill, two really impressive wells delivered by the team. 2020 was also our most efficient year for the completions team. We averaged 746 feet per day on 160-foot stages or about 21% higher than 2019, when we average 619 feet per day on mostly 140-foot stages. Additionally, we achieved an average pumping hours per day of 14.6% or 14% higher when compared to 2019. The increase to stage length and cluster spacing helped provide a reduced cost per stage, but most importantly, did not have a negative impact on EUR. The completions team continued to perform at a record pace in Q1, completing an average of 858 feet per day, our best quarterly performance in the company's history. Average well costs fell 19% from $1,470 per lateral foot in the second half of 2019 to $1,187 per lateral foot in the fourth quarter of 2020. While lower service costs contributed, improved drilling performance and completion efficiencies comprised more than 60% of that savings. That trend continued in the first quarter and we are on track to deliver the 2021 program within the guidance range provided in this morning's release. On the LOE front, we continue to realize the benefits from our comprehensive multi-year water management plan, which has effectively reduced our largest cost element. In 2020 we expanded our disposal infrastructure with our third company-owned and operated saltwater disposal facility. And we developed two produced water gathering systems that deliver water directly from our well pads to those disposal facilities. These systems eliminate the need for water trucks on the road, significantly reducing our cost per barrel to dispose of water, while also reducing our impact on the community through less traffic, reduced risk of vehicle accident or spill and lower emissions. Last year we injected 80% of our water volume into our own SWD facilities and we moved 324,000 barrels through the two new gathering systems. As I'll cover momentarily, our capital program this year provided for the development of a fourth saltwater disposal well, which today is complete. And a third produced water gathering system which is on track to be completed in August of this year. Once complete, this additional asset will allow us to move 1.24 million barrels through our gathering systems in 2021, eliminating 9,500 truck trips, while over 90% of our water will be disposed in our own SWD facilities. Altogether, our water costs are projected to decline 14% year-over-year to $1.45 per barrel. These operational milestones would be meaningless, had they not been accomplished in a safe manner. Fortunately, Vine employees have not incurred an OSHA recordable incident since 2015 and our contracted drilling rigs have not incurred a lost time incident for a combined 13 years. Our total recordable incident rate last year was a remarkable 0.09 per 200,000 man-hours across 4.4 million hours logged. This is an 81% improvement compared to 2019 and the lowest rate ever in the company's history. And it clearly demonstrates our pledge to operate with a safety-first mindset and only work with vendor partners that share that mindset. On the emissions front, we continued our relentless focus on reducing emissions from operations and achieved a 7% decline in greenhouse gas intensity for 2020. Since 2017 we have reduced GHG intensity by 35%. Key to this reduction has been our ability to reduce methane intensity as well. Last year was no exception, as we reduced methane intensity by 8%, bringing our four-year total reduction to 62%. Our progress in 2020 marks a multiyear trend of targeted emission reductions following step changes to our operational approach. Specifically, we have converted all contracted rigs to buy fuel engines. We've implemented managed pressure drilling systems to address fugitive emissions during drilling and installed solar panels at every well location for on-site power generation. Further, although we are an early adopter of intermittent-bleed control valves, we kicked off the process last year to convert these valves to zero bleed configurations. Now let's talk about the 2021 plan. The collective savings realized for cycle time efficiencies, service cost reductions and lower LOE is the formula, which sets the opportunity to drive down capital intensity and maximize free cash flow. As Eric highlighted earlier, our 2021 development plan was designed to meet these two objectives. At a cadence of just over three rigs, the 2021 capital program will target the development of 250,000 to 260,000 net feet of pay. Total capital is expected to be in the range of $340 million to $350 million, while well costs are expected in the range of $1,180 to $1,210 per lateral foot with the opportunity to outperform with further D&C optimization strategies, we are currently implementing. The development program will be balanced between Haynesville and Mid-Bossier and all the three wells are expected to be completed with long laterals. Approximately, 60% of the capital budget will be earmarked to the first half of the year though I would caution against an over-reliance on quarterly delineations which are highly dependent upon the timing of our pad drilling program. A mere five-day acceleration or delay in completing a four-well pad can alone upset the timing by $3 million to $5 million on capital spending. Such an anomaly is quite common in pad development programs. Annual production should average 985 million cubic feet per day to 1.05 Bcf per day. Second quarter production is estimated at 1.05 billion cubic feet per day to 1.06 billion cubic feet per day. Compared to actual first quarter production, the growth in the second quarter is a consequence of wells turned in line late in the fourth quarter and during the first quarter and are largely related to 2020's capital program. By design that program was intended to attain a onetime step-up to our long-term base production objective of approximately one Bcf per day. Apart from the disruptions caused by winter storm Uri, that step-up would have largely occurred in the first quarter as originally planned. Before concluding, I'll quickly walk through the key operational results of the first quarter, bearing in mind all metrics are pro forma. Production was ahead of expectations at 945 million cubic feet per day, driven by shorter curtailment period than anticipated during the February winter storm. As Eric disclosed earlier, we revisited our 2021 forecast during the storm and reset several operational metrics to account for the risk of extended downtimes. However, as I mentioned earlier, due to our team's efforts and the cooperation from our business partners, we were able to resume full production quickly. The early recovery time also accounts for a portion of the higher capital spend in the quarter compared to our forecast. However, some of the overspend is related to the accelerated pace in which we are drilling and completing wells per my earlier remarks. To counter this impact, we plan to coordinate holiday periods with our vendors to remain within full year capital guidance. Our ability to slow operations later this year is a result of the relationships we have built with our major service providers and I want to thank them for their continued support as we optimize capital spending for the year. Our full year production guidance already reflects the slowdown. Turning to lease operating expense, costs were higher than expected at $0.22 per Mcf. Most of this variance was related to winter storm Uri and its impact on production and our facilities in the field. Our full year guidance includes the impact of this event, but we fully expect to drive down full year per unit cost in the range of $0.19 to $0.20 per Mcf with additional build-out of our water disposal infrastructure. Gathering expense was $0.31 per Mcf, modestly higher than expected due to the mix of wells turned in line during the quarter, some of which carried contractual gathering rates slightly above the field average. However, we're confident our full year expense will land in the range of $0.29 to $0.30 per Mcf due to the development plan we've laid out for later in the year. That completes my remarks. So, I'll hand it off to Wayne for a financial update. Wayne?
Wayne Stoltenberg:

Thank you, Dave and good morning everyone. As everyone is aware we were quite busy in the first quarter with the combination, IPO, and refinance of our RBL and unsecured notes. It was a sprint to the finish line, but it was unquestionably a worthy effort. Today, the combined company has a leverage ratio among the lowest of our natural gas peers which is quite a contrast from where we were just months ago. Moreover, within our gas focused peer group, we're one of the few investment grade issuers with leverage near two times. Based on our forecast, we have a clear path to generating substantial free cash flow this year. We will logically appropriate the first dollars to retiring RBL debt as it's the only obligation that can be repaid today. At April 30, we had $73 million of outstanding RBL borrowings following the refinance of the unsecured notes which settled in early April. We'll knock that down quite substantially in the second quarter. Just last week we made a $13 million repayment and we expect to remit a second payment in June in the range of $15 million to $25 million. We expect to pay off the remaining RBL balance outstanding by the end of the third quarter. Afterwards debt outstanding would be $1.1 billion comprised of the $150 million second lien term loan and $950 million of the unsecured notes. Net leverage would then be approximately 1.8 times based on our 2021 EBITDAX projection. Once the RBL is paid down, our attention will shift to the $150 million second lien term loan once the make-whole expires on June 30th, 2022. In the interim, we expect to build a cash balance in an amount sufficient to retire the loan on or up the state. At that time, our leverage ratio would approach the point at which we could consider instituting a dividend sometime in later 2022 or early 2023. So, we have not yet been prescriptive on a policy We like the model a base dividend augmented by a variable component that looks to gas prices and the service cost environment to determine the appropriate level. We believe we'll be one of the few natural gas companies that can institute a meaningful dividend in the relatively near-term and it's going to be a primary focus of the management team and our Board. Now, let me quickly review some of the key financial highlights in the first quarter which I would remind you are all on a pro forma basis unless otherwise noted. Adjusted EBITDAX in the first quarter was $145 million which was slightly ahead of our forecast. The largest contributor was the revenue generated from higher production volume as disclosed earlier. Notwithstanding the cost elements Dave covered previously, general and administrative expense broadly was also a positive factor. While G&A was in line with expectations, the monitoring fee was eliminated when the company completed its IPO. Interest expense presented on an actual non-pro forma basis was $35 million. Of this amount, non-cash interest was $8 million, but is expected to increase to approximately $10 million in the second quarter to account for the extinguishment of the legacy Vine Oil & Gas unsecured notes and the associated acceleration of deferred financing fees. Thereafter non-cash interest expense should be approximately $2 million to $2.5 million per quarter and remain there for at least the next five quarters. Likewise the run rate for cash interest will decline approximately $5 million in the second quarter related to the refinance of the unsecured notes. However, be aware the $63 million call premium we paid to retire the legacy Vine Oil & Gas notes will be recorded as interest expense in the second quarter. With the RBL pay down, cash interest expense thereafter, should trend to about $21 million per quarter through the middle of 2022. Turning to adjusted free cash flow, we generated approximately $20 million in the first quarter, in line with our forecast. As a reminder, we compute adjusted free cash flow as adjusted EBITDAX less the sum of cash interest capital incurred and tax payments and distributions. I'll expand on the latter in just a moment. We expect to generate substantially higher adjusted free cash flow in the subsequent quarters such that adjusted free cash flow for full year 2021 should fit inside the range of $145 million to $155 million. The principal drivers are interest savings, lower capital incurred in the second half of the year, and higher production. Cash taxes will partially undercut these gains, which we estimate in the range of $22 million to $24 million for full year 2021 or approximately 15% of post-combination pre-tax adjusted free cash flow. The combination and IPO created some unique tax features, so it's likely beneficial to provide a brief overview. As disclosed in our S-1 filing, Vine Energy entered into a tax receivable agreement with the Vine predecessor entities at the closing of the IPO. Most notably, that agreement provides for the sharing of any net cash savings we realize if any, in federal and state income taxes pursuant to the new UFS structure. However, the prior owners also agreed to defer their rights to the sharing agreement, through December of 2025. With that, our cash tax exposure in the interim will be substantially lower, than it would have otherwise been without such an agreement. But nevertheless, we estimate approximately 15% of our pre-tax adjusted free cash flow will be paid in tax, in 2021. Several factors beyond our control can impact this rate, including changes in NYMEX prices and the timing and size of future sell-downs from the legacy owners, to name a few of these things. We will update tax guidance, as material events unfold. Our tax liability will be dispersed according to the A and B share splits. And will be reflected on our financial statement somewhat unconventional. For example, if our full year tax guidance proves accurate, we will remit approximately $13 million to the internal revenue service or 55% of the estimated obligation. That amount will be included in the computation of net income and hence, will effectively be an outflow appearing in the operating section of the cash flow statement. The remaining $10 million or 45% however, will be remitted to the original owners and will be treated as a distribution in the financing section of the cash flow statement. Our full year adjusted free cash flow guidance, accounts for these distributions and payments. Payment timing will occur according to regulations. As such, we expect to remit estimated taxes for the first half of 2021 in June, in the normal course, while subsequent quarters' estimated tax payments, will be remitted, within each respective quarter. We expect the distributions to original owners will follow the same pattern. So, put simply, we would expect to pay the entire $22 million to $24 million of estimated cash taxes, for calendar year 2021, in calendar year 2021. Before closing, I'm happy to report one of our Surety underwriters released 50% of a $26 million letter of credit earlier this month. So pro forma for that event, liquidity at April 30 was $347 million. This includes RBL availability and cash on hand. We really appreciate your attention, as we've showcased the transformational milestones of the past year and how it sets the stage for future success. Without further delay, let's get to the Q&A segment.
Operator:

Our first question comes from Phillips Johnston with Capital One. Your line is open.
Phillips Johnston:

Hey guys. Thanks. If we look at your production guidance, it implies a fairly large uptick in the second quarter versus the first quarter. And then, sort of production falls off a bit in the second half of the year, from the second quarter run-rate. I think you guys sort of touched on some of the drivers in the prepared remarks. It seems like, there's a little bit of a slowdown in the back half of the year, which is sort of by design I guess. So maybe just to help us with the modeling, I'm wondering, how many wells, you're expecting to turn into sales in the second quarter, and also what your expectation as for the third and fourth quarters as well?
Wayne Stoltenberg:

Go ahead.
Dave Elkins:

Yeah. The -- you're right. There will be a little bit of a slowdown, as we mentioned in the call script there, we will be slowing our completions, really probably in the third quarter which will really have an impact on the fourth quarter run-rate for production. For the year, we should turn in somewhere between, 30 and 32 net wells, during the year.
Phillips Johnston:

Okay. Great. Perfect. And then, maybe just a housekeeping question for Wayne. The credit facility balance as you mentioned increased to $73 million, at the end of April from around $28 million at the end of March. Is that mainly just a function of the call premiums? And I guess the other fees associated with the refinancing.
Wayne Stoltenberg:

That's correct.
Phillips Johnston:

Okay. Perfect. Thanks guys.
Operator:

Our next question comes from Scott Hanold with RBC Capital Markets. Your line is open.
Scott Hanold:

Thank you all. Just a question maybe following up a little bit on that production cadence. And it sounds like you all provided a pretty good bolus setup for gas that you see coming through. Can you just describe your perspective on, obviously, being disciplined with your capital but if inventories are tight now, obviously, going into this winter things could get really tight, but you've got the cadence of production obviously falling toward the end of the year because of the more restrained activity. How do you think about that in terms of just the timing of production? Because theoretically peaking in the early -- late this year early next year could be certainly more financially beneficial.
Eric Marsh:

Yeah. Scott this is Eric. And good question. What Dave described is that second and third quarters will be higher production times. And then you're right we dropped off a bit in the fourth quarter. It's really about just managing and trying to keep it around Bcf a day. So we're going to see these over the years, you'll see that production ebb and flow a little bit around that number. And so it's going to happen. The thing -- I think what you probably should note is, is that we're still hedged in 2021 in December. And we're upwards of 90% hedged for the quarter. So we agree it would be great to have it peaked perfectly, but this is the way the program got laid out even before the IPO. So that's what's happened. But then I would tell you that in 2022, we have less hedges in place. And overall if the gas prices, which we truly believe will stay reasonably strong, we'll capture a lot of that value in 2022, so hopefully that helps answer. Yeah, it'd be perfect to do it that way. But the way we've laid this program out, we're going to spend about 60% of our capital in the first half of the year and 40% in the second half. And so the production on average will be strong in the middle of the year.
Scott Hanold:

Yeah, yeah. So I guess the point is the question I was asking and I think you've answered it, but you're certainly looking to be more disciplined and more opportunistic with I guess, kind of, production in the commodity. Is that a fair way to look at it?
Eric Marsh:

Yeah. We're definitely going to be disciplined on it. We're going to -- like we always try to do, we're going to hit our numbers and then in hitting our numbers that means our capital needs to come in at the range that we've talked about, the $340 million to $350 million. And so we're going to have to moderate our pace a little bit as Dave mentioned in the third quarter to make that all work out just trying, which we will. We've done it every year for seven years. So we'll do it.
Scott Hanold:

Got it. Okay. And as my follow-up you discussed your positioning on the Gulf Coast market and potentially accessing LNG markets. Can you talk about like where you guys are at? And is this something that could happen sooner than later? Is it going to take some time? And just give us a sense of potential implications and timing of that?
Eric Marsh:

Yeah. I think the answer to the question is we've been a seller to the LNG facilities for some time. As you know we actually sell a lot of our production forward with fixed sales. And that's why typically our basis differential's less. I think last quarter they averaged around $0.18. And we have approximately 55% of our production pre-sold on fixed sales, of which some of that is to the LNG facility. So today that's a reality. And so we do that on a regular basis. But we have -- the way we've managed the basis differential is through these fixed sales where we have a portfolio of contracts typically not going out much more than about three years. And we manage that both on a NYMEX and a mainline basis. And so we're constantly in the market looking at fixed sales. And always with creditworthy counterparties, I think that's another important point is that not only is it LNG sales, but it's big utilities, it's big petrochems. And so people with really good credit ratings, we think it's super important to be able to get paid when you do sell your gas. And then if you look at -- first quarter of 2021, you also noticed that our differential was down a bit more than normal. Normally it's been around $0.18, and this year, this quarter it was $0.13 and that's just a reflection of how we've managed it.
Scott Hanold:

Okay, okay. So I guess the point you're making, you will continue to look at LNG opportunities, but that's obviously just within that market, I mean, you would look to end users selling it across the water anywhere. Is that right? You just utilize existing facilities and contracts directly with them, is that right?
Eric Marsh:

Yes. That's correct. It's an interesting concept and one we have thought about, but it's not really mature enough to be able to do something like that yet. There's a few companies doing that, but we think we'll entertain that when it's a little more of a packaged commodity. But for today, no, that's -- we just sell to the LNG in light of their plant and do a contract with them.
Scott Hanold:

Thank you.
Eric Marsh:

You bet.
Operator:

Our next question comes from John Abbott with Bank of America. Your line is open.
John Abbott:

Good morning. Thank you for taking our question. Our first question is on LOE expense for the quarter. We understand the impact from Storm Uri, but you've also made commentary or produced water being higher. Yes, you did address water in your opening remarks, but just sort of thinking about the higher water in the first quarter and how that translates to the rest of the year? And then sort of thinking beyond that how do you think about a normalized LOE run rate post-2021 going into 2022?
Eric Marsh:

Yes. We had two fractures running in the first quarter, and so we turned some additional wells in line. That certainly contributed to the increase in water production. And then certainly there were some I'll say additional costs related to the movement of water during the storm. So I think that's really the main explanation. We had a little bit of additional expense and repair and maintenance as well just due to some of the surface facilities being impacted by the storm. So I think that really explains the majority of the difference for Q1. I don't have any doubt, we're going to make the $0.19 to $0.20 that we've guided for the rest of the year. And I think as we continue to expand the water gathering system and continue to develop our own SWDs and that is the number one component for our LOE. And so I think we'll be able to bring that rate down moving forward into 2022. The fourth well is online already. We'll be bringing on our third gathering system. We're targeting August for that system to be online. So I think moving forward that will be how we continue to bring those costs down.
John Abbott:

Appreciate it. And then our second question is on M&A. What are your latest thoughts on M&A? Your partner still retains a relatively significant interest in the firm, is potential M&A away also to way possibly to reduce that interest? Is that a viable strategy?
Eric Marsh:

Yes, John good question. We just continue to say that we have 25 years of drilling inventory. The returns that you can go out and take a look at in our investor presentation on our website clearly indicate very economic wells that we have plenty of inventory to work from to start with. So we think executing on the plan we've laid out today and previously during the IPO is the most important. Could we participate in M&A? Sure. We could. But that's not something that is top of our priority. We like the idea of something if we were to do that would it bolt up to our acreage. And could we do it with our -- with a balance sheet type transaction as opposed to taking on significant debt. So those are the things that we think about when we think about M&A, but we really just feel that what's best for the company is to turn in some quarters here hitting the marks. and be able to establish that track record before we even start to think very, very hardly on M&A. But again to be really clear, it's -- we don't need to do any additional acquisition. We have an inventory that is deep in quality in locations and we just need to just go out and continue to execute on our plan. The tuck-in type acquisition got some interest to us, and that's about it. As far as BX goes, the Blackstone guys, they've been good partners. They've -- they're very patient investors. They saw this as an opportunity to invest additional monies as did management. And so, I think it's important to know that we all believe in what we're about to do. And so we invested additional monies in it. So, we think there will be a time as Blackstone has always demonstrated when they invest in a public company that they will exit, but it's not in our minds imminently. So, they've been a good partner, very active at the board level. And so, we have a great relationship and they see this company as an opportunity to create more value.
John Abbott:

Appreciate it. Thank you for taking our questions.
Operator:

Our next question comes from Devin McDermott with Morgan Stanley. Your line is open.
Devin McDermott:

Hey. Good morning, and thanks for taking my question. So, my first one is just following up on one of the comments in the prepared remarks. I think you noted that of the efficiency gains that were realized through 2020, 60% were more structural in nature and then 40% were services and supply chain deflation. You think about the 2021 guidance, can you just comment on what you're assuming for that services and supply chain side of things and that the extent that there were to be inflation over the next few years, any offsetting mechanisms that there might be to help retain some of the gains that you've seen on the D&C side over the past year.
Eric Marsh:

Sure. We're targeting a number similar to what we quoted as our Q4 number for 2020, for the remainder of the year. I think from an efficiency standpoint, we will continue to improve. We're all aware of the -- at least start of, we'll call it oil field service inflation. And we have done a number of things to try and help offset that and ensure our cost for the year. We have extended our pressure pumping contract. We use Liberty Oilfield Services as our pressure pumping company. We just recently extended that contract with them out through 2023. On the drilling rig side, we have extended our drilling rig contracts at lease through 2022, and most of our contracts actually run into 2023. So, those are really the main cost drivers that we have. Where are we seeing inflation currently? Certainly in fuel, diesel prices are up about 60% from where we were last year. So, we're doing what we can to mitigate that along with the Liberty contract extension, we've agreed to a Tier 4 bi-fuel fleet, which allows us to significantly increase the amount of diesel fuel that we can substitute with natural gas and it also helps us with our emissions profile. So, we're doing what we can to limit the diesel fuel gallons that we're burning every day. All of our rigs are also by fuel. So again, we are substituting as much diesel fuel for natural gas as we can.
Devin McDermott:

Great, very helpful. And then, my second question is on cash flow. And you all have done a great job quantifying the strong free cash flow over the next few years for this business $800 million is almost the market cap in free cash flow over the next five years. Leverage target should be achieved. Is that our numbers at some point in late 2022 and that potentiation to start returning more cash back to investors? I know it's still early in structuring what that ultimate payout might look like. But I was wondering if you could just talk at a high level about how you think about the cash that could be returned to investors versus retained given. We're kind of looking at more of a maintenance-type capital spending scenario here over that time pricing the yield, seems like it'd be very impressive and competitive versus peers. I think including the peers you listed in the slides just given the strong cost structure and cash generation you all have.
Wayne Stoltenberg:

Yes. Devin, Wayne Stoltenberg here. I'll take that one. If you look at sort of our guidance of kind of your cash flow $150 million is sort of the midpoint. And if we get -- I think you hit the timing right kind of towards the end of this year, we'd certainly be from a leverage perspective where we would consider that. And I look at -- again, we haven't been prescriptive. I'm not going to get out in front of our Board but, if you look at a model that's kind of half of your free cash flow going back to shareholders, half of it being used to reduce debt. Again, part of that half we go back to shareholders, part of it is fixed as we like the idea of a fixed dividend make the other park varies. I think that gives you a pretty good yield even from a fixed component and then the variable one depending on how things go could be pretty meaningful while you also continue to reduce leverage, because again, we think that reducing leverage is a form of return to value to shareholders.
Devin McDermott:

Yes. Makes a lot of sense. Thanks so much.
Eric Marsh:

You’re welcome.
Operator:

And last question comes from Jeanine Wai with Barclays. Your line is open.
Jeanine Wai:

Hi. Good morning, everyone. Thanks for taking our questions.
Wayne Stoltenberg:

You bet for. Hi, Jeanine.
Jeanine Wai:

Hi. Good morning. This is exciting your first call. So maybe just following up on Devin's question there on the return of capital. We noticed on your slides that you cited both a special -- a potential for a special and a variable dividend. How are you thinking about the difference between the two of those? Because it seems like the market really capitalizes them very differently?
Wayne Stoltenberg:

I don't disagree with that. In fact, I agree with that. I think, we would want to have a, again, a fixed component. That's one that we felt could withstand certainly cycles and commodity prices and the like, and then obviously a variable component sort of on top of that. And again I'll do some sort of paint line numbers here. We talked about kind of $150 million of free cash flow. That's our guidance for this year. If sort of half of that were distributed that's $75 million and obviously a component of that is fixed, component of that is variable with market capital of roughly $1 billion call it $30 million to $35 million would be a 3% to 3.5% yield. And the rest of that sort of $75 million would obviously get you closer again if that were a variable component we'll get closer to 7.5%. Again yield from a distribution perspective free cash flow you'll obviously be slice that because you're retaining the rest of that to further reduce debt.
Jeanine Wai:

Okay. Got it.
Eric Marsh:

And Jeanine I also think that as Wayne indicated once you get kind of to that 1.5 times lever, which is after we've paid off that second lien. The other component of the capital that Wayne is referring to could be used to continue to reduce the leverage down because we do believe that continuing to lower the leverage below that 1.5 is certainly an objective that we all have. We just have been a little bit more prescriptive on when do we start to consider a dividend and it's when we get down to a leverage ratio of about 1.5 times.
Jeanine Wai:

Okay. Great. Very helpful. And then maybe just sticking on the cumulative free cash flow estimate the $800 million. Can you just talk about what other assumptions go into that such as the annual CapEx, any inflation or cash taxes? And then also can you just confirm that we should be thinking about that plan that slide is the plan versus just a maintenance scenario that you're throwing out there. I think when you had a justice with Scott's question it sounded more like you were committing to just 2021. So I just wanted to confirm that this kind of flattish billion or Bcf today through 2025 is the actual plan?
Eric Marsh:

Yes. Look I think that's fair. We've talked about a Bcf a day of production not just this year but, sort of, going out and that prioritizes. Again the generation of free cash flow and the return of it to shareholders in the various forms again that we just talked about. So from a CapEx perspective again that's, sort of, the maintenance number maintaining that BCF a day of production. We will always look to further optimize LOE over time. Again we're not promising massive LOE decreases, but we're always looking to again to optimize all of our costs and we'll continue to do that. Obviously, when we're paying down debt we've got interest expense going down as that happens so that certainly helps us there. So we'll continue to again work on those things but again prioritize return of free cash flow to shareholders over time.
Jeanine Wai:

Okay. Thank you very much.
Eric Marsh:

You’re welcome.
Operator:

There are no further questions in queue at this time. This concludes today's conference call. Thank you for your participation. You may now disconnect.

Vine Energy Inc. Q1 2021 Earnings Call Transcript

Vine Energy Inc.
Q1 2021 Earnings Call Transcript