Q1 2021 Vine Energy Inc Earnings Call
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 to ask a question. During the session you will need to press star one on your telephone.
If you require any further assistance please press star zero.
I would now like to hand, the conference over to your speaker today, David Erdman.
Director of Investor Relations. Please go ahead.
Good morning, everyone I'd first like to introduce myself as the director of Investor Relations.
The opportunity to cultivate on long term working relationship with you My contact information was included at the end of the earnings release, we issued this morning and on our website at Vine energy Dot com feel free to reach out to me by phone or E mail if needed.
Strive to respond to both within a few hours if im on available I'd also highlight management is planning to participate in several virtual investor events over the next several months refer to our website for a complete list to arrange a one on one meeting please contact the conference coordinator.
Today's speakers will be Eric Marsh, Chairman, President and Chief Executive Officer, Dave <unk>, Chief operating Officer, and Wayne Stoltenberg, Chief Financial Officer.
Each will deliver brief prepared remarks, and then we'll get to your questions, but first let me quickly cover the customary safe Harbor provisions. During this call we will be making forward looking statements, which are subject to risks and uncertainties.
<unk> results may differ materially from those predicted in these forward looking statements additional information concerning risk factors, which could cause such differences are outlined in the press release. We issued this morning. If you don't have a copy of that release, it's available on the Investor Relations page of our website, along with an updated investor presentation.
Unless otherwise noted all metrics discussed this morning are presented pro forma for the combination in IPO as if the transactions occurred on January one 2020.
Alternatively, a GAAP presentation of our first quarter financial statements are disclosed in the appendix of the press release and will be included in our 10-Q, which will be filed later today. So now I'll yield the floor to Eric to begin his comments Eric.
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 buying energy.
We look forward to working with you over the coming years.
Seven years ago, I partnered with the Blackstone group to invest in our highest return on natural gas asset in North America.
At the time, we targeted a haynesville basin for its potential to drive superior economics.
Short time later vine oil <unk> 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 the opportunity to expand our undeveloped acreage within the base on by acquiring leases and sections that complemented our existing inventory.
From that breaks oil and gas was born.
Although a separate entity. It was managed by the same operating team with a vision that the two with one day merged to create a world class natural gas company.
The day that vision is a reality.
Along with a small royalty company, we called harvest.
The entities are now joined in a new company emerged buying energy the.
The namesake of the company that started at all.
Our corporate logo was redesigned to honor our past.
Personifying the role we play in the world's transition towards cleaner energy and our longstanding commitment to be stewards of our ecosystem.
While many things have changed.
Alright entity and purpose have not.
The newly combined company retains the same exceptional operational qualities of its predecessor company, but with the size scale and balance sheet to drive industry, leading levered free cash flow over the long term.
Buying energy stands to be one of the few gas focused upstream companies with a viable plan to return capital to shareholders through debt reduction and a dividend policy.
While the IPO and high yield transactions, where critical components to this plan our top tier asset is ultimately the fulcrum that will drive our longevity and sustainability.
Following the combination volume holds approximately 25 years of future drilling inventory.
<unk> 227000, net effective acres in the core of the Haynesville basin.
Our acreage is located near LNG and industrial demand centers, along the U S Gulf Coast.
We realized high net back pricing.
Is situated in the highest pressure area, where the haynesville in the mid Bossier are equally productive. So we are truly a stack play.
The Haynesville is productivity is widely understood having been developed since 2008. However at that time, the mid Bossier was thought to be inferior and so it was frequently bypass as producer to targeted the deeper Haynesville formation.
We saw quite differently.
In 2014, our technical analysis concluded the mid Bossier resembles analogous reservoir properties to the haynesville across the vast majority of our acreage with respect to pressure gradient porosity permeability and thickness.
Further we saw sufficient vertical separation between the Haynesville and the mid <unk> to allow for effective stimulations of each design.
Seven years ago at the Companys inception, the mid Bossier was an intriguing play today.
Today, it's a core asset to volume net.
No different than the Haynesville and we are uniquely qualified to commercially develop this prolific shale.
In fact since 2015, we've drilled 64 gross wells to the mid <unk> more than any other operator, combined and well results unequivocally support our original thesis well.
Wells drilled in 2020 under our modern completion vintage have demonstrated exceptional productivity and economics, yielding an average rate of return of 70% at a flat $2 50, Nymex gas price.
Similar to our Haynesville wells, we are able to realize these industry leading returns in large part due to the high formation pressures, we encounter specifically pressures of 9000 Psi comment enabling wells to produce at their initial production rate for eight months on average.
<unk> energy hyperbolic decline.
In fact, many of our wells have produced flat for up to 24 months.
Accordingly through our proprietary pressure management strategy, we recover about 45% of our wells EUR in the first 12 months of production and about 80% in the first five years of production.
To put this in perspective on a 7500 foot haynesville lateral we typically recover more than seven Bcf in the first 12 months or less.
<unk> unmatched by virtually any other shale play in North America.
It's a leading reason this well can generate a rate of return of 83% at $2 50, Nymex gas price and payback periods of 14 months, allowing us to recycle cash much faster than our peers.
On a $2 75, Nymex gas price, which which more closely aligns with our fundamental view.
It's even more remarkable rate of return of 110% and payback periods of 12 months.
This flat time performance as a feature somewhat unique to vine.
Though acreage towards the western edge of the basin exhibits favorable geologic characteristics.
Shallower and thus is under far less pressure, yielding payout times and cash recycle ratios far in excess of what we realized.
We are compared favorably in this regard to other plays across North America, whether oil or gas further as we target relatively stable production over the long term our flat time production profile translates into a capital reinvestment rate similar to peers, who have a lower.
PDP decline.
We're also drilling and completing wells at a faster pace than we have in our history and this is a significant factor in our ability to drive superior well economics.
Compared to 2019 average drilling days in 2020 were 20% lower than on average completion days were 21% lower.
Dave will expand on this and other operational milestones during his prepared remarks.
Along the way natural gas fundamentals are improving as expected building a tailwind that will supplement the returns we currently realized from our exceptional well productivity.
Last year natural gas prices touched four year lows amid a tariff war and a pandemic that crippled global energy demand building a considerable backlog of natural gas supply in the U S. Today. However, we are entering a far more sustainable environment supported by capital discipline.
And rapid growth in natural gas demand.
The latter is unsurprising bolstered by the long anticipated surge in LNG exports. Thanks in part due to favorable weather across the northern hemisphere.
April marks the second consecutive month of LNG exports above 11 Bcf per day.
And omitting February five consecutive months of about 10 Bcf a day.
In fact on April 18th exports hit an all time high at 11 nine Bcf per day.
In contrast exports were about $6 five Bcf per day. This time last year, we estimate an additional three bcf per day in 2022, and another five Bcf per day in the next several years.
<unk> acreage is optimally located to deliver the lowest cost natural gas feedstock to the LNG facilities, along the U S. Gulf Coast, but we also standout for a reason many may not appreciate.
We are witnessing the advent of the balance scorecard approach to sourcing LNG and environmental factors that are prominent component.
An expected shift the world's LNG consuming nations increasingly desire to source supply from low emissions basins and low emissions cargos.
That's where volume can differentiate itself through its ESG leadership.
Only in the Haynesville basin is it ranked among the cleanest in North America volume carbon dioxide equivalent emissions are ranked the lowest amongst 17 peers. According to a recent study by the EPA greenhouse gas reporting program and.
In fact from 2017 to 2020, we've reduced our cotwo emissions intensity.
Additionally, volume methane intensity decreased 62%, 2.014% of its production.
And I believe we can lower it even further.
Given the low emissions nature of our natural gas production and the additional active mitigation measures. We are implementing I believe we have one of the lowest emissions levels per bcf of production of most domestic oil and gas companies.
None of this is coincident nor is it a response to a trend.
Rather it's the intended consequence of our strategy tracing back to volume inception in 2014.
We are committed to do our part to significantly reduce greenhouse gas because simply put it's the right thing to do.
The evolution to clean LNG is quite remarkable and a striking example, late last year. The French government terminated in LNG agreement with a U S based exporter in part due to environmental concerns stemming from a sourcing of natural gas from the Permian for methane emissions lead all other U S.
Gas basins.
However, given the leading environmental profile of <unk> acreage and on environmentally sensitive practice, we are ready to step in to meet the world's energy needs with natural gas as responsibly produced.
The growth in LNG export is expected to continue in conjunction with a broad recovery in global markets and industrial demand, particularly as COVID-19 eases its grip on the economy.
Here's where things get intriguing the.
The domestic storage levels on the are on top of the five year average and lower 48 gas production is slowing seasonal weather alone could pushed a supply shortage in the domestic U S gas market.
Furthermore, the chronic delays of the mountain Valley pipeline.
<unk> elevate the risk at a time when favorable weather has re entered the equation.
This should raise an interesting backdrop for natural gas prices in the near term.
And it supports my thesis of an undervalued forward curve that remains backward dated.
While while we are largely hedged in 2021, we have considerable exposure next year and we have significant unhedged volumes in 2023 and beyond.
Hedging is in our DNA. So despite our bullish views, we plan to add hedges, but with instruments that preserve upside exposure, while protecting downside risk.
I've never been more enthusiastic about this setup for natural gas nor have I been more optimistic on how volume can thrive along the way.
Management, along with our largest shareholder Blackstone Pro family share. This view as we clearly demonstrated in the IPO.
Together, we purchased approximately 20% of the IPO shares because in our opinion, we recognize the company has considerable upside at the transaction price.
Even though were substantially above the lows, we tested last month, our stock performance since the transaction has been disappointing.
As I contemplated what the market may be overlooking even at today's price three key factors come to mind.
First what's unique about line is that the vast majority of our probable and possible reserves are geologically technically proven because of our asset is largely de risked by virtue of a wellbore in nearly every section, which we have an interest.
Our three P reserves at year end 2020 were eight Tcf.
And $3 billion of PV 10 at a $2 $55 Nymex price.
At $2 75, Nymex price PV 10 at year end, 2020, chumps, 10% to $3 3 billion.
Second and somewhat related given the energy investors proclivity for low risk volume asset is among a few that can deliver consistent and repeatable performance.
Our wells exhibit high productivity across our entire acreage footprint from both the Haynesville and the mid Bossier intervals.
Since 2017 wells, we've developed exhibit low variability is defined by a probability ratio of <unk> to <unk> 90 on that basis, our haynesville and Bossier exhibit more repeat ability than the Marcellus and the northeast.
While the approach is exceedingly technical interpretation of the results quite simple.
The acreage is characterized by top tier rock qualities.
However, completion engineering really matters.
We've clearly demonstrated competencies and that discipline, having repeatedly developed the most prolific wells in the basin since the company's inception.
As such we have largely mitigated operational risk and we can generate predictable outcomes, particularly when evaluated alongside with our hedges. We have approximately 25 years of core inventory that I firmly believe will allow us to generate an industry, leading free cash flow profile for the <unk>.
Long term.
So if you are searching to invest in a company with returns and cash flows underpinned by consistency reliability and longevity.
<unk> in the right place this morning.
Third and lastly, our commitment to substitute growth for free cash flow generation may be encountering skepticism sediment common across the entire upstream sector.
In defense of those investors I understand that concern for years producers outspent cash flow to build a sizable wedge of production growth.
Often at rates of return below cost of capital despite claims otherwise.
Was never us on.
<unk> historical growth rate was by design to build a production base that created a company of investable size and scale.
During that time, we deployed capital at rates of returns that led the industry in the trended higher year after year as we realize enhanced <unk> through the evolution of our completion design and our reduced cycle times.
So I want to be clear volume core mission is to invest capital in a manner that prioritizes free cash flow and return of capital to shareholders and we believe this is achieved through a relatively flat production profile for the foreseeable future.
Even if gas prices rise as I fully believe they will we do not expect to deviate from this plan and will instead seized the opportunity to accelerate debt reduction and the return of capital to our shareholders.
To that end I've tasked the organization to maintain aggressive cost management, both on the capital and LOE fronts and build on development efficiencies I am confident this team harbors the technical knowledge and determination to meet these objectives and push the bar even higher.
In a moment, Dave Elkann will cover first quarter operational milestones and our progress towards achieving the goals we set forth this year.
As a preview we had an outstanding quarter and we're on track to deliver full year guidance. Despite challenges imposed by the winter storm in February.
Fortunately, we were able to fully recover our operations earlier than expected following the crippling ice storm.
With that we're a bit ahead of the pace, we expected per the development plan, we amended in the midst of the storm, but we have viable options to call that back later in the year as Dave will cover.
Before yielding I'd like to take a moment to recognize every vine employee for their commitment and determination to make the combination an IPO a success or not I believe we have the most dedicated team of professionals in the business and I'm honored to have made this journey with them.
I generally believe our best days are ahead.
To our investors again, thank you for your support Vine energy.
With that I'll turn the call over to Dave.
Thank you, Eric and good morning, everyone.
I would like to start out with a quick summary of the impact of winter storm here.
The buying team did a tremendous job under difficult conditions, and most importantly, a stage Dave.
Fortunately there was enough warning before the storm that we could develop and execute our plan to either keep operations going on a return to normal operations quickly.
All of our rigs continued to drill during the storm and our completion operations were only pause for about three five days.
Our production team did a great job keeping production up.
However, mainly due to power issues at our third party gathering and processing facilities, we were forced to shut certain wells in for about six days and thus we lost about three eight bcf of gross production or 28 million a day net for the quarter.
Now onto my first quarter update.
Volume 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 set fresh milestones in 2021.
Among our achievements the realization of incremental drilling and completion efficiencies stands out.
Throughout our acreage the mid Bossier and Haynesville reservoirs are deep and over pressure, we often contend with bottom hole temperatures above 320 degrees and extreme pressures.
The development of long laterals and 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, where at times, a struggle as we slowly and sometimes painfully made our way along that learning curve and.
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 our rig fleet.
Improved performance in the intermediate section of the hole and reduced curve drill times.
The outcome was impressive.
As 2020 was the most efficient year for the vine drilling team.
Specifically, we drilled 270000 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 10000 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.
39 days on our 10000 foot laterals compared to 47 days in 2019. This.
This saved us over $650000 per well.
However, my favorite statistic from the drilling team relates to rig efficiency.
In 2019, we average about 62000 feet of lateral per rig.
In 2020 net ratio jumped to 77000 feet of lateral per rig a 25% improvement led to real per well savings put.
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 line wells, including the rocking G 23, 2014, 11 H one.
It's the longest lateral vine has drilled to date with a total measured depth of 23300 feet.
It will have a lateral length of over 10500 feet. When it is completed later this month.
And it took just over 35 days to drill the well.
Its sister well to age three 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 averaged 619 feet per day on mostly 140 foot stages.
Additionally, we achieved an average pumping hours per day of $14, six or 14% higher when compared to 2019.
The increase the 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 $1470 per lateral foot in the second half of 2019.
Two one on $187 per lateral foot in the fourth quarter of 2020.
While lower service cost 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 and.
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 disposal water, while also reducing our impact on the community through less traffic reduce risk of vehicle accident or spill and lower emissions.
Last year, we injected 80% of our water volume into our own SWT facilities, and we moved 324000 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.
On 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 124 million barrels through our gathering systems in 2021, eliminating 9500 truck trips while over 90% of our water will be disposed in our own SWT facilities.
Together, our water costs are projected to declined 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 incidents 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 200000 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 GHT 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% or.
Our progress in 2020 March on multi year trend of targeted emission reductions following step changes to our operational approach.
Specifically, we have converted all contracted rigs to biofuel engines, we've implemented managed pressure drilling systems to address fugitive emissions during drilling and installed solar panels at every well location for onsite power generation.
Further although we are an early adopter of intermittent bleed control valves, we kicked off the process last year to convert these styles to zero bleed configurations.
Now, let's talk about the 2021 plan.
The collective savings realized from 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.
And it came from just over three rigs the 2021 capital program will target the development of 250.
To 260000 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 180 to $210 per lateral foot.
With the opportunity to outperform with further D&C optimization strategies, we are currently implementing.
The development program will be balance between Haynesville and mid <unk> and all but three wells are expected to be completed with long laterals.
Approximately 60% of the capital budget will be gear Mark to the first half of the year.
So I would caution against an overreliance on quarterly delineations, which are highly dependent upon the timing of our pad drilling program.
And we have 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 and pad development programs.
Annual production should average 985 million cubic feet per day to one five Bcf per day second.
Second quarter production is estimated at $1 5 billion cubic feet per day to one 6 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 2000 Twenty's capital program.
I designed that program was intended to attain a one time step up to a long term base production objective of approximately one bcf per day.
Apart from the disruptions caused by winter storm Yuri 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 downtime.
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 as 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 optimized 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 22 per Mcf most.
Most of this variance was related to winter storm here and its impact on production in 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 costs in the range of 19% to 20 per Mcf with additional build out of our water disposal infrastructure.
Gathering expense was 31 per Mcf modestly higher than expected due to the mix of wells turned in line during the quarter, some of which carry contractual gathering rates slightly above the field average.
We're confident our full year expense will land in the range of 29 to <unk> 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 wane from a financial update thank.
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 RVO 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 everywhere just months ago. Moreover, within our guest focus peer group. We're one of the few non 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 hours to retiring RBS debt as if the only obligation that can be repaid today at April 30, we had $73 million outstanding Rvs borrowings following the refinance of the unsecured notes, which settled in early April we will knock that down quite substantially in the second quarter. Just last week, we made a $13 million repayment.
We expect to remit a second payment in June in the range of 15% to $25 million.
We expect to pay off the remaining <unk> balance outstanding by the end of the third quarter afterwards debt outstanding would be $1 1 billion comprised of $150 million second lien term loan and $950 million of the unsecured notes.
Net leverage would then be approximately one eight times based on our 2021 EBITDAX projections.
Once the <unk> paydown, our attention will shift to the $150 million second lien term loan once the make whole expires on June 30 of 2022.
In the interim we expect to build the cash balance and in about sufficient to retire the loan on or about the stake.
At that time, our leverage ratio would approach the point on which we could consider instituting a dividend sometime in later 'twenty two early 'twenty three.
So we have not yet been prescriptive on a policy wed like to model the base dividend augmented by a variable component that looks to gas prices and the service cost environment to determine the appropriate level. We believe will be one of the few natural gas companies that can institute a meaningful dividend in the relatively near term and it is 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 EBITDA from the first quarter was $145 million, which was slightly ahead of our forecast.
Largest contributor with 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 it is expected to increase to approximately $10 million in the second quarter to account for the April extinguishment of the legacy Vine oil <unk> gas unsecured notes and the associated acceleration of deferred financing fees thereafter noncash interest expense should be approximately two to $2 5 million per quarter.
<unk> and remain there for at least the next five quarters. Likewise, the run rate per 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 and gas notes will be recorded as interest expense.
From the second quarter.
With the <unk> Paydown cash interest expense thereafter should trend through about $21 million per quarter through the middle of 'twenty two.
Turning to adjusted free cash flow, we generated approximately $20 million on 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 ladder on 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 to 155 million from.
Principal drivers our 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 to 24 million per full year, 'twenty, one or approximately 15% of post combination pretax adjusted free cash flow.
The combination of an IPO created some unique tax features so it's likely beneficial to provide a brief overview.
As disclosed on our S. One filing buying energy entered into a tax receivable agreement with the volume predecessor entities at the closing of the IPO, most notably that agreement provides for the sharing of any net cash savings we realized if any in federal and state income taxes pursuant to the new up sea 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 and 21.
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 disbursed. According to the a and b share splits and will be reflected on our financial statements somewhat Unconventionally. 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 <unk>.
<unk> in the computation of net income enhance will effectively be an outflow appearing in the operating section of the cash flow statement, the remaining $10 million or 45%. However, we 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 payments.
Payment timing will occur according to regulations as such we expect to remit estimated taxes for the first half of 'twenty. One 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% to $24 million of estimated cash taxes for calendar year 'twenty one in calendar year 'twenty, one 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 <unk> availability and cash on hand.
We really appreciate your attention as we showcase 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.
Ladies and gentlemen, if you would like to ask a question. Please press Star then the number one on your telephone keypad.
Our first question comes from Phillips Johnston with capital line.
Your line is open.
Hey, guys. Thanks, if we look at your production guidance it implies a fairly large uptick in the second quarter versus the first versus the first quarter and then sort of production falls off a bit in the second half of the year from the second.
Second quarter run rate I think you guys sort of touched on that 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 am wondering how many wells youre expecting to.
Turning into sales in the second quarter and also whats your expectation is for the third and fourth quarters as well.
Go ahead, yes.
Youre 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.
Okay, great perfect and then.
Just a housekeeping question for Wayne.
Credit facility balance as you mentioned increased to $73 million net at the end of April from around $28 million at the end of March is that mainly just a function on the call premiums and I guess, the other fees associated with the <unk>.
Refinancing.
That's correct.
Okay perfect. Thanks, guys.
Our next question comes from Scott Hanold with RBC capital markets.
Your line is open.
Thank you all.
The question, maybe following up a little bit on that production cadence and it sounds like you all provided a pretty good the bullets that are per gas that you see coming through.
Can you just describe your perspective on on obviously being disciplined with your capital, but you 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 towards the end of the year because of more of a strained activity.
How do you think about that.
In terms of just the timing of production because theoretically Peking Union to early late this year early next year could be certainly more financially beneficial.
Yeah, Scott This Eric and good question, what Dave described as that second and third quarters will be higher production times, and then Youre right, we drop off a bit in the fourth quarter, it's really about just managing and trying to keep it around a bcf a day. So we're going to see these over the years.
You'll see that production kind of 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.
<unk>.
We're upwards of 90% hedged for the quarter. So we.
We agree it would be great to have.
At peak perfectly, but this is the way the program kind of got laid out even before the IPO. So so that's that's what's happened, but then I would tell you that in 2022, we have less hedges in place and overall.
If the if the gas prices, which we truly believe will stay reasonably strong will capture a lot of that value in 2022.
So hopefully hopefully that helps answer it yes, it would be it would be perfect to do it that way by.
The way we've laid this program out we're going to spend about 60% of our capital on the first half of the year and 40% in the second half and so that the production kind of on average will be will be strong in the middle of the year. So it disappointed the question on asking and I think you've answered it.
Your.
Certainly looking to be more disciplined and more opportunistic with the guests.
Kind of production on the commodity that is that a fair way to look at it.
We're definitely going to be disciplined on it we're going on we're going to.
We always try to do we're going to hit our numbers and hitting our numbers that means our capital needs to come in at that the range that we've talked about $3 40 to $3 50.
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 right, which which which we will we've done it every year for seven years. So we'll do it got it Okay and then as my follow up you kind of discuss.
Your positioning on the Gulf coast market and potentially accessing LNG.
LNG markets can you talk about like where you guys are at and is this something that could have been give you. Then later or is it going to take some time and just give us a sense of the potential implications of the timing of that.
Yes.
I think 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.
With fixed sales and Thats, why typically our basis differentials and less I think last quarter. They average around 18.
And we have approximately 55% of our production.
<unk> 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 manage the basis differentials through these fixed sales.
There, we have a portfolio of contracts typically not going out much more than about three years and.
We manage that both on on IMAX centre, and a mainline basis. So.
We're constantly in the market looking at at fixed sales.
And always with credit worthy Counterparties I think that's another important point is that.
Not only is that LNG sales, but it's big utilities, it's big.
Petro Chems and so people with really good credit ratings, we think it's super important to be able to do.
It paid when you when you do sell your gas and then if you if you kind of look at 2001st quarter of 'twenty. One you'll also notice that our differential was down a bit more than normal normally had been around 18.
And this year this quarter. It was 13 and that's just a reflection of how we've managed it.
Okay. Okay. So I guess the point you're making.
You will continue to look at LNG opportunities.
But thats, obviously, just within that market I mean, you would look to and end users on it.
Across across the water anymore is that right you're just utilize existing.
The existing facilities and contracts directly with them is that right. Yes, that's correct at the interesting concept in one we have thought about but but it's not 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 will we'll entertain that one it's a <unk>.
More of a packaged commodity.
But for today no we just sell to the to the LNG.
In light of their plant and do a fuel contract with them.
Thank you.
You bet.
Our next question comes from John Murphy with Bank of America. Your line is open.
Good morning.
Thank you for taking our questions.
Our first question is on LOE expense for the quarter, we understand the impact from storm Yuri.
But you've also made commentary or produced water being higher.
You did address water in your opening remarks, but just sort of thinking about.
The higher water in the 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 low run rates post 2021 going into 2022.
Yeah.
We had two frac crews running in the first quarter and so we turned some additional wells on 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 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.
Don't have any doubt we're going to make the 19% to 20 that we guided for for the rest of the year and I think as we continue to expand the <unk>.
Water gathering system.
Continued to develop our own <unk> and that is the number one component for our low.
And so I think we will we'll be able to bring that rate down moving forward into 2022.
Fourth wells online already we will be bringing on our third gathering system. We are targeting August for that system to be on line. So I think moving forward that will be how we continue to bring those costs down.
Appreciate it and then our second question is on on M&A, what are your latest thoughts on M&A.
Your partner still retained a relatively significant interest in the firm.
His potential M&A away also due to particularly the way constantly to reduce net interest is that a viable strategy.
Right.
Yes, John Good question.
Continue to say that we have.
We have 25 years of drilling inventory.
The returns that you can you can go out and take a look at in our investor presentation on our website.
Clearly indicate the very very economic wells.
We have.
We have plenty of inventory.
From the 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 that's not something that is top of our priority. We liked 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 our balance sheet type transaction as opposed.
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 into some quarters here hitting.
Hitting the marks and be able to to establish that track record.
Before we even start to think very very hardly on M&A, but again to be really clear.
We don't we don't need to do any additional acquisition we have in inventory.
His deep and quality locations and we just need to just go out and continue to execute on our plan.
On the Tac in.
On the Tac in.
Tuck in type.
Acquisition got some interest to us.
And that's about it as far as far as Bx goes the Blackstone guys they've been good partners.
They've they're very patient investors day.
Saw this as an opportunity to to invest additional monies asking management and so I think it's important to know that we all believe.
And what we're about to do and so we invested additional monies on it. So we think we think there will be a time.
As is 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 they've been a good partner.
Very active at the board level and so we.
We have a great relationship.
They see this company has an opportunity to create more value.
Appreciate it thank you for taking our questions.
Our next question comes from Devin Mcdermott with Morgan Stanley. Your line is open.
Hey, good morning, Thanks for taking my question.
So my first one is just following up on one of the comments on the prepared remarks, I think you noted that.
The efficiency gains that were realized through 2020, 60% more structural in nature, and then 40% services supply chain deflation you think about the 2021 guidance can you just comment on what youre assuming for that.
Services and supply chain side of things in that day.
There were to be inflation over the next few years any offsetting mechanisms, but there might be too.
Retaining some of the gains that you've seen on the D&C side over the past year.
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.
Start of we'll call it we'll field service inflation.
And we have done a number of things to try and help offset that and ensure our cost per the year.
We have extended our pressure pumping contract we use Liberty oilfield services is on 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 least through 2022 on 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 have agreed to a tier four bi fuel fleet, which allows us to significantly increase the amount of diesel fuel that we can substitute natural gas and it also helps us with our emissions profile. So.
We're doing what we can.
To limit.
Sure.
Diesel fuel gallons that we're burning every day all of our rigs are also biofuel. So again, we are substituting as much diesel fuel for natural gas as we can.
Great.
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.
$800 million, it's almost the market cap and free cash flow over the next five years leverage targets should be achievable on our numbers at some point late 2022 would that forgiveness should start returning more cash back to investors and I know, it's still early and structuring what that ultimate payout might look like but I wonder if you can just talk at a.
High level about how you think about the cash.
Cash that can be turned to investors versus Mccain given we're kind of looking at more of a maintenance type capital spending scenario here over that time price Neil It seems like it would be very impressive and competitive versus versus peers.
You listed in the slides I, just given the strong cost structure on cash generation you on that.
Yes, Devin Wingstop over here I'll take that one if you look at sort of our guidance of kind of cash 150 is sort of the midpoint.
Yes, I think you hit the timing right towards the end of this year, we'd certainly be from a leverage perspective, where we would consider that and I look at again NIM did prescriptive I'm not going to get out in front of our board, but if you look on 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 happened to go back to shareholders part of it is fixed as we took a we like the idea of a fixed dividend Nic. The other variable I think that gives you a pretty good yield even from a fixed component and then the variable one depending on how things go it could be pretty meaningful. While you also continue to reduce leverage and we think that reducing leverage is a form of return.
On the value to shareholders.
Yes makes a lot of sense. Thanks, so much.
Okay.
From last question comes from Tahira.
<unk> with Barclays. Your line is open.
Hi, good morning, everyone. Thanks for taking our questions.
Hi, Jenny Hi, good morning.
And your first call.
No.
Maybe just following up on Kevin's question there on the return of capital we noticed on your slides that you cited.
Our special a potential for a special.
Variable dividend.
How are you thinking about the difference between the two of those because it seems like the market really capitalize on some very differently.
I don't disagree with that in fact, I agree with that I think we would want to have a fixed component.
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 by numbers here, we talked about you kind of a $150 million free cash flow that's our guidance for this year.
On a half of that were distributed.
75 million Bucks on obviously a component of that is fixed component of that is variable with a.
Market cap of roughly $1 billion call. It 30 to 35 view would be a three to three 5% yield and the rest of that sort of 75 million, but obviously gets you closer again net were variable component.
Through seven 5% again yield from a distribution perspective free cash flow yield obviously be twice that because you're retaining the rest of that to further reduce debt.
Okay got it.
Jeanine I also think that as Wayne indicated once you get kind of to that one five times lever.
After we paid off that second lien.
The other component of the capital that that wanes, referring to could be used to continue to reduce net leverage down because we do believe that.
Continuing to lower the leverage below that one on a half is certainly on 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 one five times.
Okay, Great very helpful. And then maybe just sticking on the cumulative free cash flow estimate to $800 million can you just talk about what other assumptions go into that this is Daniel Capex, Amy inflation, our cash taxes and then also can you just confirm that we should be thinking about that plan that.
Slide as the plan versus just on maintenance scenario that you're throwing out there I think when you had addressed this with Scotts question. It sounded more like you were committing to just 2021. So I just wanted to confirm that that is kind of flattish billion a bcf per day through 2025 is the actual plan yes.
Yes.
That's fair, we've talked about a bcf a day of production Youre not just this year, but sort of going out and net prioritizes again, the generation of free cash flow and returning it to shareholders in various forms again that we just talked about so from a capex perspective again, that's sort of the maintenance number maintaining net bcf per day of production.
We will always look to further optimize LOE.
Over time, we can we're not promising massive LOV decreases, but we're always looking to optimize all of our costs and we will continue to do that obviously when we're paying down debt. We've got interest expense going down as that happens and that certainly helps us there.
So we will continue to begin work on those things, but again prioritize returning free cash flow to shareholders over time.
Okay. Thank you very much.
Youre welcome.
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.
Okay.
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