Welcome to the Vine Energy First Quarter 2021 Earnings Conference Call. I would now like to hand the conference over to your speaker today, David Hutman, Director of Investor Relations. Please go ahead. Good morning, everyone. I'd first like to introduce myself as the Director of Investor Relations. I'm enthused at the opportunity to cultivate a 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 vineenergy.com. Feel free to reach out to me by phone or email if needed. I strive to respond to both within a few hours if I'm 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, David Elkin, Chief Operating Officer, and Wayne Stoltenberg, Chief Financial Officer. Each will deliver brief prepared remarks, and then we'll get to your questions. 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. Actual 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 and IPO as if the transactions occurred on January 1st, 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. I'll now 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 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 and 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 basin by acquiring leases in sections that complemented our existing inventory. From that, Brix Oil and 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. Today, that vision is a reality. Along with a small royalty company we call Harvest, the entities are now joined, and a new company emerged, Vine Energy, the namesake of the company that started it all. Our corporate logo was redesigned to honor our past while 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, our identity 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. Vine 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 were critical components to this plan, our top-tier asset is ultimately the fulcrum that will drive our longevity and sustainability. Following the combination, Vine holds approximately 25 years of future drilling inventory across 227,000 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, where we realize high netback pricing. It's situated in the highest pressure area where the Haynesville and the Mid-Bossier are equally productive, so we are truly a stacked play. The Haynesville's productivity is widely understood, having been developed since 2008. At that time, the Mid-Bossier was thought to be inferior, and so it was frequently bypassed as producers targeted the deeper Haynesville formation. We saw it quite differently. Back 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. We saw sufficient vertical separation between the Haynesville and Mid-Bossier to allow for effective stimulations of each zone. Seven years ago, at the company's inception, the Mid-Bossier was an intriguing play. Today, it's a core asset to Vine, 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-Bossier, more than any other operator combined, and well results unequivocally support our original thesis. 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 9,000 psi is common, enabling wells to produce at their initial production rate for eight months on average before entering 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 well's 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 7,500-foot Haynesville lateral, we typically recover more than 7 Bcf in the first 12 months, a level 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 a $2.50 NYMEX gas price and payback periods of 14 months, allowing us to recycle cash much faster than our peers. At a $2.75 NYMEX gas price, 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 is a feature somewhat unique to Vine, though acreage towards the western edge of the basin exhibits favorable geologic characteristics, it's shallower and thus is under far less pressure, yielding payout times and cash recycle ratios far in excess of what we realize. 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, and 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 realize 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. 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 above 10 Bcf a day. In fact, on April 18th, exports hit an all-time high at 11.9 Bcf per day. In contrast, exports were about 6.5 Bcf per day this time last year. We estimate an additional 3 Bcf per day in 2022 and another 5 Bcf per day in the next several years. Vine's 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 stand out for a reason many may not appreciate. We are witnessing the advent of a balanced scorecard approach to sourcing LNG and environmental factors that are a prominent component. In an expected shift, the world's LNG consuming nations increasingly desire to source supply from low emissions basins and low emissions cargoes. That's where Vine can differentiate itself through its ESG leadership. Not only in the Haynesville Basin is it ranked among the cleanest in North America, Vine's carbon dioxide equivalent emissions are ranked the lowest among 17 peers, according to a recent study by the EPA Greenhouse Gas Reporting Program. In fact, from 2017 to 2020, we've reduced our CO2 emissions intensity. Additionally, Vine's methane intensity decreased 62% to 0.014% of its production. 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 coincidental, nor is it a response to a trend. Rather, it's the intended consequence of our strategy tracing back to Vine's 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. In a striking example, late last year, the French government terminated an LNG agreement with a U.S.-based exporter, in part due to environmental concerns stemming from its sourcing of natural gas from the Permian, where methane emissions lead all other U.S. gas basins. Given the leading environmental profile of Vine's acreage and our environmentally sensitive practice, we are ready to step in to meet the world's energy needs with natural gas that is 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 eases its grip on the economy. Here's where things get intriguing. The domestic storage levels are on top of the five-year average, and lower 48 gas production is slowing. Seasonal weather alone could push a supply shortage in the domestic U.S. gas market. Furthermore, the chronic delays of the Mountain Valley Pipeline considerably 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 backwardated. 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 Vine can thrive along the way. Management, along with our largest shareholder, Blackstone, profoundly 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 we're 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 Vine 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 in which we have an interest. Our 3P reserves at year-end 2020 were 8 Tcf and $3 billion of PV10 at a 2.55 Mcf price. At 2.75 Mcf price, PV10 at year-end 2020 jumps 10% to $3.3 billion. Second, somewhat related, given the energy investors' proclivity for low risk, Vine's asset is among a few that can deliver consistent and repeatable performance. Our wells exhibit high productivity across our entire acreage footprint for both the Haynesville and the Mid-Bossier intervals. Since 2017, wells we've developed exhibit low variability as defined by a probability ratio of P10 to P90. On that basis, our Haynesville and Mid-Bossier exhibit more repeatability than the Marcellus in the Northeast. While the approach is exceedingly technical, the interpretation of the result is quite simple. Vine's acreage is characterized by top-tier rock qualities. Completion engineering really matters, and we've clearly demonstrated competencies in that discipline, having repeatedly developed the most prolific wells in the basin since the company's inception. As such, we've 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 long term. If you're searching to invest in a company with returns and cash flows underpinned by consistency, reliability, and longevity, you're undoubtedly in the right place this morning. Third and lastly, our commitment to substitute growth for free cash flow generation may be encountering skepticism, sentiment 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. That was never us. Our 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, and they trended higher year after year as we realized enhanced EURs through the evolution of our completion design and our reduced cycle times. I want to be clear. Vine's 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 seize 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, David Elkin will cover first quarter operational milestones and our progress toward 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 Winter Storm Uri. 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 pull that back later in the year, as David Elkin 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 and IPO a success. Bar none, 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 genuinely believe our best days are ahead. To our investors, again, thank you for your support of Vine Energy. With that, I'll turn the call over to David Elkin. 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, they 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 continued to drill during the storm, and our completion operations were only paused for about three and a half 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 3.8 Bcf of gross production or 28 million a day net for the quarter. Now on to my first quarter update. Vine's 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 efficiency stands out. Throughout our acreage, the Mid-Bossier and Haynesville reservoirs are deep and overpressured. We often contend with bottomhole 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 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 270,000 gross ft of lateral in 2020, of which 80% were long laterals. We achieved a 24% reduction in drilling days for 7,500-foot laterals and a 17% reduction in days at 10,000 ft when comparing against 2019 results. To be exact, we averaged 29 drilling days on our 7,500-foot laterals compared to 38 days in 2019, and 39 days on our 10,000-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 ft of lateral per rig. In 2020, that ratio jumped to 77,000 ft 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 G 23-14-11 H. It's the longest lateral Vine has drilled to date, with a total measured depth of 23,300 ft. It will have a lateral length of over 10,500 ft when it is completed later this month, and it took just over 35 days to drill the well. Its sister well at H-3 was 700 ft 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 ft per day on 160 foot stages. We're about 21% higher than 2019, when we averaged 619 ft 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 ft 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 for 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. 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 multi-year trend of targeted emission reductions following step changes to our operational approach. Specifically, we've converted all contracted rigs to bi-fuel 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 valves 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. At a cadence of just over three rigs, the 2021 capital program will target the development of 250,000 to 260,000 net ft 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 but 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 overreliance 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 ft per day to 1.05 Bcf per day. Second quarter production is estimated at 1.05 billion cubic ft per day-1.06 billion cubic ft 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 one-time 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 ft per day, driven by a 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 this 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 that we fully expect to drive down full-year per unit cost in the range of $0.19-$0.26 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-$0.30 per Mcf due to the development plan we've laid out for later in the year. That completes my remarks. I'll hand it off to Wayne for a financial update. Wayne? 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 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 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 1.8x 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 call expires on June 30, 2022. In the interim, we expect to build a cash balance in an amount sufficient to retire the loan on or about this date. At that time, our leverage ratio would approach the point at which we could consider instituting a dividend sometime in later 2022, early 2023. Though we have not yet been prescriptive on a policy, we like the model of 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 David Elkin covered previously, general 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 April extinguishment of the legacy Vine Oil and Gas unsecured notes and the associated acceleration of deferred financing fees. Thereafter, non-cash interest expense should be approximately $2 million to two and a half 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. Be aware the $63 million call premium we paid to retire the legacy Vine Oil and Gas notes will be recorded as interest expense in the second quarter. With the RBL paydown, 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 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 Up-C structure. The prior owners also agreed to defer their rights to the sharing agreement through December of 2025. Our cash tax exposure in the interim will be substantially lower than it would have otherwise been without such an agreement. 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 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 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 this same pattern. 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. 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 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. Our first question comes from Phillips Johnston with Capital One. Your line is open. Hey, guys. Thanks. We look at your production guidance, it implies a fairly large uptick in the second quarter versus the first quarter, and then 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. 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. 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 is for the third and fourth quarters as well. Yeah. 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. Okay, great. Perfect. 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? 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. Just a question maybe following up a little bit on that production cadence, and it sounds like you all provided a pretty good bullet 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? Theoretically peaking into late this year, early next year could be certainly more financially beneficial. Yeah, Scott, this is Eric. Good question. What Dave described is that second and third quarters will be higher production times. You're right, we drop off a bit in the fourth quarter. It's really about just managing it, trying to keep it around a Bcf a day. 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. It's going to happen. The thing I think what you probably should note is that we're still hedged in 2021 in December. We're upwards of 90% hedged for the quarter. We agree it would be great to have it peak perfectly. This is the way the program kind of got laid out even before the IPO. That's what's happened. 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. Hopefully that helps answer it. Yeah, it'd be perfect to do it that way, 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 then 40% in the second half, and so that the production on average will be strong in the middle of the year. Yeah. I guess 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 the gas production of the commodity. Is that a fair way to look at it at this point? 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. In hitting our numbers, that means our capital needs to come in at the range that we've talked about, $340-$350. 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 we will. We've done it every year for seven years, so we'll do it. Got it. Okay. My follow-up, you kind of discussed your positioning on the Gulf Coast market and potentially accessing the LNG markets. Can you talk about where you guys are at, and is this something that could happen sooner than later, or is it going to take some time? And just give us a sense of potential implications and timing of that. 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 differentials are less. I think last quarter they averaged around $0.18. We have approximately 55% of our production pre-sold on fixed sales, of which some of that is to the LNG facility. Today, that's a reality. We do that on a regular basis. 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. We manage that both on a NYMEX and a mainline basis. We're constantly in the market looking at fixed sales. 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. If you look at first quarter of 2021, you also notice that our differential was down a bit more than normal. Normally, it's been around $0.18, and this quarter it was $0.13, and that's just a reflection of how we've managed it. Okay. I guess the point you're making, you look at LNG opportunities. That's obviously just within that market. You wouldn't look to an end user selling it across the water anywhere. Is that right? You just utilize existing facilities and contracts directly with them. Is that right? Yeah, 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. For today, no, we just sell to the LNG at inlet of their plant and do a contract with them. Thank you. You bet. Our next question comes from John Abbott 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 Uri. You've also made commentary on produced water being higher. You did address water in your opening remarks. Just thinking about the higher water in the first quarter and how that translates to the rest of the year, and then thinking beyond that, how do you think about a normalized LOE run rate post 2021 going into 2022? Yeah. We had two fracs running in the first quarter. We turned some additional wells online that certainly contributed to the increase in water production. Certainly there were some, I'll say, additional costs related to the movement of water during the storm. I think that's really the main explanation. We had a little bit of additional expense in repair and maintenance as well, just due to some of the surface facilities being impacted by the storm. 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-$0.20 that we guided for the rest of the year. I think as we continue to expand the water gathering system, and continue to develop our own SWDs, that is the number one component for our LOE. 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. I think moving forward, that'll be how we continue to bring those costs down. Appreciate it. 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 a way possibly to reduce that interest? Is that a viable strategy? Yeah, John, good question. We just continue to say that we have 25 years of growing 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. 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. That's not something that is top of our priority. We like the idea of something, if we were to do that, would it bulk up to our acreage? And could we do it with a balance sheet type transaction as opposed to taking on significant debt? 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 marks and be able to establish that track record, before we even start to think very hardly on M&A. Again, to be really clear, we don't need to do any additional acquisition. We have an inventory that is deep in quality and locations, and we just need to just go out and continue to execute on our plan. The tuck-in type to us, and that's about it. As far as BX goes, the Blackstone guys, they've been good partners. They're very patient investors. They saw this as an opportunity to invest additional monies, as did management. I think it's important to know that we all believe in what we're about to do. We invested additional monies in it. We think there will be a time, as Blackstone has always demonstrated, when they invest in a public company, that they will exit. It's not in our minds imminently. They've been a good partner, very active at the board level. We have a great relationship, and they see this company as 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. My first one is just following up on one of the comments in your 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. As you think about the 2021 guidance, can you just comment on what you're assuming for that services and supply chain side of things? To 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? 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 oilfield service inflation. We have done a number of things to try and help offset that and ensure our costs 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 least through 2022, and most of our contracts actually run into 2023. 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. 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. We're doing what we can to limit the diesel fuel gallons that we're burning every day. All of our rigs are also bi-fuel, so again, we are substituting as much diesel fuel for natural gas as we can. Great. Very helpful. My second question is on cash flow. 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, those other numbers at some point late 2022, and that puts you in a position 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 looking at more of a maintenance type capital spending scenario here over that time horizon. The yield seems like it'd be very impressive and competitive versus peers, including the peers you listed in the slides, given the strong cost structure and cash generation you all have. Devin, Wayne Stoltenberg here. I'll take that one. You look at our guidance of your cash flow at $150 is sort of the midpoint. If we get the timing right, towards the end of this year, we'd certainly be, from a leverage perspective, where we would consider that. I look at it again, we haven't been prescriptive. I'm not going to get out in front of our board. If you look at a model that's half of your free cash flow going back to shareholders, half of it being used to reduce debt. Part of that half that would go back to shareholders, part of it is fixed, as we like the idea of a fixed dividend, make the other part variable. I think that gives you a pretty good yield even from the fixed component, and then the variable one, depending on how things go, could be pretty meaningful while you also continue to reduce leverage. Again, we think that reducing leverage is a form of return of value to shareholders. Yeah. Makes a lot of sense. Thanks so much. You're welcome. One last question comes from Jeanine Wai with Barclays. Your line is open. Hi. Good morning, everyone. Thanks for taking our questions. You bet. Sure. Hi, Jeanine. Hi. Good morning. This is exciting, my first call. It is. Maybe just following up on Devin's question there on the return of capital. We noticed on your slides that you cited both a potential for a special and a variable dividend. How are you thinking about the difference between the two of those? It seems like the market really capitalizes them very differently. 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. Obviously a variable component on top of that. I'll do some paint by numbers here. We talked about kind of $150 million free cash flow. That's our guidance for this year. If half of that were distributed, that's $75 million, and obviously a component of that's fixed, a component of that is variable with a market cap of roughly $1 billion, call it $30 million to $35 million would be a 3%-3.5% yield. The rest of that sort of $75 million would obviously get you closer, again, if that were a variable component, would get you closer to 7.5% 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 Wai, I also think that as Wayne Stoltenberg indicated, once you get to that one and a half times lever, which is after we've paid off that second lien, the other component of the capital that Wayne Stoltenberg's referring to could be used to continue to reduce the leverage down. Because we do believe that continuing to lower the leverage below that one and a half 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 one and a half times. Okay, great. Very helpful. Maybe just sticking on the cumulative free cash flow estimate of $800 million, can you just talk about what other assumptions go into that, such as annual CapEx, any inflation or cash taxes? Also, can you just confirm that we should be thinking about that slide as the plan versus just a maintenance scenario that you're throwing out there? I think when you had adjusted with Scott's question, it sounded more like you were committing to just 2021. I just wanted to confirm that this kind of slated 1 Bcf a day through 2025 is the actual plan. I think that's fair. We've talked about a BCF a day of production, not just this year, but 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. From a CapEx perspective, again, that's the maintenance number, maintaining that BCF a day of production. We will always look to further optimize LOE over time. We're not promising massive LOE decreases, but we're always looking to, again, optimize all of our costs, and we'll continue to do that. When we're paying down debt, we've got interest expense going down as that happens, so that certainly helps us there. We'll continue to, again, work on those things, but again, prioritize return of free cash flow to shareholders over time. Okay, thank you very much. You're 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.