EQT Corporation

Ladies and gentlemen, thank you for standing by and welcome to today's EQT Q1 quarterly results 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 this time, you will need to press star 1 on your telephone. If you require further assistance, please press star 0. I'd like to hand the conference call over to Andrew Brees, Director of Investor Relations. Please go ahead.

Good morning, and thank you for joining today's conference call. With me today are Toby Rice, President and Chief Executive Officer, and David Connie, Chief Financial Officer. The replay for today's call will be available on our website for a seven-day period beginning this evening. The telephone number for the replay is 1-800-585-7000. 8367 with a confirmation code of 2066546. In a moment, Toby and David will provide the prepared remarks with a question and answer session to follow. During these prepared remarks, Toby and David will reference certain slides that have been published in a new investor presentation, which is available on the investor relations portion of our website. I'd like to remind you that today's call may contain forward-looking statements. Actual results and future events could materially differ from these forward-looking statements because of factors described in today's earnings release and in the risk factor section of our Form 10-K for the year ended December 31, 2019, and in subsequent filings we make with the SEC. We do not undertake any duty to update any forward-looking statements. Today's call may also contain certain non-GAAP financial measures. Please refer to this morning's earning release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. And with that, I'll turn it over to Toby.

Thanks, Andrew, and good morning, everyone. Today I will give a brief review of the quarter and provide an update on the business. I will then pass it today to review the details of the quarter and talk about the recent actions we have taken to improve the financial standing of this business. Afterwards, we will open up the call for Q&A. This management team, since being elected, has been unrelenting in our quest to deliver on campaign promises. Our operational results validate the promises that we made to our shareholders and prove our thesis that a well-planned business, combined with leading technology, creates a differentiated, durable, and sustainable business. The equity and debt markets have taken notice. Since the beginning of the year, we have accessed the capital markets twice. Once in January, with our $1.75 billion senior note offering, and again in April, with our $500 million convertible debt deal. Both offerings strengthened our strategic flexibility, de-risked our near-term maturities, and were met with overwhelming market participation. Additionally, we have seen significant strengthening in both our equity and debt performance supporting these strategic actions. ETT is in a unique position to capitalize on the improving natural gas macro, as the vast majority of our production is natural gas, and less than 5% of our production is tied to deteriorating liquids and oil prices. Even more so, our acreage sits in the southwestern core of the Marcellus and has over 15 years of inventory. Our financial and operational results over the last several quarters have proven that our approach to developing this world-class asset is working, and this company is well on its way to becoming the clear operator of choice. Moving forward, we will continue to push our technological boundaries and be at the forefront of innovation to drive incremental efficiencies and create value for our shareholders. This commitment is reflected in our first quarter results. Our acute focus on cost reduction, schedule optimization well-designed, and operational uptime drove our strong performance during the period. We were able to deliver volumes well above the high end of our guidance range for less capital and developed our Pennsylvania Marcellus asset at a well cost of $745 per lateral foot, an accomplishment that is approaching our target of $730 per lateral foot faster than anticipated. Our operational costs are trending down, and we will continue to focus on driving these down throughout the year. EQT and its employees continue to work hard to safely generate value during the COVID-19 pandemic. As exhibited by this quarter's results, our business has been able to thrive as we seamlessly transitioned all of our office personnel to a remote work environment. This success is principally a result of our digital work environment that we implemented during our 100-day plan, coupled with the heart, dedication, and teamwork of our employees. EQT remains committed to our safety culture. We have had regular conversations with state and local officials, and the safety of all of our employees and contractors have been our primary focus. We have gone beyond the minimum safety standards in our response and have intensified our focus on data collection and technology to create an insight that allows us to contact, trace employees and contractor partners that enter our active sites. This insight has allowed us to contact hundreds of contractors and employees shortly after learning of potential exposure cases and provide them with the names of all individuals to be monitored. The greatest risk to operators like EQT is the potential for increased exposure as a result of missed contacts and response delays, and our contact tracing technology is just one example of how we are looking at managing the impact of this pandemic differently. To our employees in the field, our contracted partners, our peers, and the healthcare and frontline responders, we thank you for your continued dedication during these times. We are working passionately to support the communities in which we operate, including recently donating $360,000 to local community funds. will keep doing our part to make EQT and its community as safe as possible. The energy industry has also been impacted by deteriorating oil prices as a result of unprecedented demand destruction due to the COVID-19 pandemic. While oil prices sit at historic lows and have forced reductions to rig counts and frack crews, well shut-ins, slashing of capital budgets and production, and bankruptcies, EQT has not only been resilient, but has been effectuating positive change while other EMPs are challenged. While we are just one quarter into the year, we are trending at the high end of our production guidance and the low end of our capital and operating expense guidance, a standing that presents us with the ability to make strategic decisions on the remainder of our 2020 program as we continue to monitor the improving macro setup in 2021. While we believe there is upside to our plan, we have maintained our previous 2020 guidance and intend to update that guidance as well as provide more commentary on our 2021 program as we move throughout the year. On a macro front, we continue to see weakness in demand impacting 2020 prices and expect prices to strengthen in 2021 and beyond. For 2020, demand has declined between 4 to 6 BCF per day with weakened power, industrial, and RESCOM consumption. Furthermore, LNG exports are facing more and more cancellations as the ARB to export gas has gone negative for the next three months. On the supply side, we are now beginning to see the impact of declining oil and liquids prices reducing associated gas output and building condensate and liquids inventory, resulting in associated gas supply being shut in. The estimates for the supply impact range from 3 to 8 BCF a day, and this can balance the market fairly quickly and sets up for a strong fourth quarter 2020 in calendar year 21 and beyond. In addition, the last several years of declining natural gas prices have caused natural gas rates to decline over 50%. from 200 back in January to currently under 90 today. As a result, near-term natural gas supply response will be very delayed until balance sheets are repaired. The challenge will be trying to balance the timing of demand recovery and to anticipate the new normal for demand. We can see prices having the potential to spike in certain peak demand periods that could result in some demand destruction or fuel switching. The 2014 and 2018 winter periods are somewhat test cases for how gas could be rationed for the highest and best use. We believe the forward curve is underestimating the move in prices, and this is especially noticeable in the 2022 and 2023 curve. As the largest natural gas producer in the country, EQT is doing its part with a disciplined approach to capital allocation, focusing on maximizing free cash flow versus production growth, despite a rising natural gas price environment. Now, I'll turn it over to David County to discuss some of our financial accomplishments, dig into the first quarter results a little more closely, and then discuss our balance sheet management strategy.

Thanks, Toby. Before we get into the detailed quarterly results, I'd like to quickly review the financial accomplishments that we've made through the first four months of the year. Coming into 2020, we faced approximately $3.8 billion of debt maturities coming due through 2022. Subsequently, we have refinanced or paid down approximately $2.4 billion and plan to retire the remaining $1.4 billion over the next 19 months. We've thoughtfully managed our liquidity, and although our current position is more than adequate, we fully expect to improve it going forward. We've developed a more robust hedge process to be able to capture rising prices over time while at the same time be risking the volatility in our revenues. We've accelerated the timing of our tax refunds which increased our first quarter free cash flow and helped us better rationalize our asset sale program. We've lowered our CapEx forecasts for 2023 times and squeezed out more out of our G&A expenses. And last, we are reiterating our 2020 guidance while many in the S&P 500 have pulled their guidance. In addition to these accomplishments, we've also had a great first quarter from an operational and financial performance perspective. The earnings release published today and the 10Q that will be filed later this afternoon contain all the details, but I will review some of the highlights. Overall, we outperformed in many areas. First, we achieved sales volumes of 385 BCF for the quarter, which exceeded the midpoint of our guidance range by 20 BCFE. This outperformance was really a culmination of various efficiencies realized across the organization, the larger of which was improved base production uptime. Adjusted operating revenues were $957 million, down 21% compared to the first quarter of 2019, as the average realized price was $2.49, or 67 cents below last year, while sales volumes remained relatively flat year over year. Our first quarter 2020 production-related operating costs reflected a per-unit basis where $1.33 per MCFE, five cents lower than the first quarter of 2019, and below the low end of our full year 2020 guidance range of $1.34 to $1.46 per MCFE. Capital expenditures were $262 million or $214 million lower than the first quarter of last year and lower than our expectations. As Toby mentioned, our Pennsylvania Marcellus well costs averaged $745 per foot, accelerating our path towards achieving our target well costs and driving our outperformance for the period. Our adjusted operating cash flow for the quarter was $513 million as compared to $647 million in the first quarter of 2019, while free cash flow was $251 million as compared to $171 million in the year-ago period. Free cash flow was positively impacted by reduced capital expenditures as well as $95 million in accrued cash income taxes from the CARES Act, which accelerate our ability to claim federal refunds of alternative minimum tax credits. For the first quarter, there were also a few other items I want to point out which impacted our competitive results versus last year. First, as previously disclosed, we completed the exchange of 50% of our equity stake in E-Train for gathering rate relief in conjunction with the execution of a new gas gathering agreement with EQM and $52 million of cash proceeds. As a result of this transaction, we recorded a contract asset of $410 million representing the present value of the expected rate relief and a gain of $187 million. We will amortize the contract asset over a period of approximately four years, beginning at MVP and service date. This non-cash amortization expense will be reported as a part of the gathering expenses in our GAAP reporting, but will be separately identified and excluded from our adjusted EBITDA and free cash flow non-GAAP metrics. Second, during the first quarter, we also reclassified certain in-basin transportation expenses to gathering expense in our financial statement and disclosures and guidance. This aims to provide additional clarity into costs associated with transporting our gas outside the Appalachian Basin. There's no net change to our 2020 guidance, but approximately 14 cents has been moved from the transmission to the gathering bucket. Overall, the first quarter was another successful quarter under the new leadership. During the second quarter of 2020, we expect sales volumes of between 360 to 380 BCFE, average differentials of negative 45 cents to negative 25 cents per MCF. We're also expecting an uptick in capital expenditures to approximately 300 million, driven by increased activity, better weather, and more daylight, all of which we expect to drive roughly break-even free cash flow during the period. I started off my prepared remarks by discussing the financial accomplishments we've achieved thus far in 2020, and now I'd like to spend a little time talking about the details related to a maturity management strategy. I'd like to refer you to slide 15 in our analyst presentation, which clearly lays out our plan. After applying all the proceeds from the recent convertible debt offering to the 2021 term loan, we now sit with about $620 million of debt maturing in 2021. When you take into consideration the 2020 expected free cash flow of $275 million at the midpoint, over $300 million of additional tax refunds and other small receivables, approximately $125 million in proceeds expected from E&P sales in advanced stages, and the remaining E-Train stake, which has a current market value of approximately $200 million, you can see we have a clear line of sight in handling the 2021 maturities and adequate carryover funds to be applied against the 2022 maturities. Then we turn to 2022 maturity of $750 million, which I remind you isn't due until the end of 2022. As I just mentioned, we plan to have several hundred million of that paid off by the end of 2020, leaving us with significant flexibility in our approach to managing that debt stack. Improving natural gas macro and commodity setup could support our ability to pay down this debt with cash flow generation if we choose. We also have several selective asset divestiture opportunities we can pursue to accelerate, supplement, and or enhance debt retirement. Touching on the selective asset investors quickly. We are taking a measured approach to selling assets. The market is still there, particularly the minerals market, but we're being very selective and deliberate in our decision on whether to continue pursuing this at this time. We expect that by the end of 2021, we'll have reduced debt by more than the original contemplated 1.5 billion, but in a more methodical way that should improve our cost of capital. This substantial debt reduction in conjunction with the improving natural gas macro should X by R pursue back to investment grade metrics, creating a more strategic differentiation for E3T. As the fundamental drivers of natural gas macro continue to play out, we are carefully studying the commodity market to assure we are making highly informed strategic hedging decisions. When we created our updated hedge program in February, winter weather disappointed, sending the strip down about $0.30 to the $2.20 to $2.30 level. We added about 300 BCF to our 2021 hedges during the February and March time period, the latest capturing pricing between $2.50 to $2.70. At the heart of our strategic approach is appropriately balancing upside while protecting the downside risk. As we move through the year, we will look to opportunistically layer on hedges. Expect to enter 2021 with a substantial percentage of our production head over the next several years. The pace of our hedging activity has slowed post the full emergence of COVID-19 and the OPEC price war for a couple reasons. First, as the supply-demand impact of the current environment become clearer, we're becoming more and more bullish on the natural gas pricing setup. Secondly, the broader impact group has been forced to layer on hedges to protect borrowing bases that are subject to redeterminations, creating pricing pressure in the market to abate. I'd like to also remind that we have roughly 90% of our 2020 gas production hedge at a weighted average floor price of above $2.70 per decatherm, which has and will insulate us from commodity price volatility as we move through 2020. It sits at $1.6 billion which consists of $2.5 billion unsecured revolver, which is essentially undrawn, $2.5 million of letters of credit posted stemming from the ratings downgrades that occurred earlier this year. Based on discussions with counterparties and maximum we believe we are largely through. I want to reiterate that unlike many EMPs, our revolver is unsecured and not subject to borrowing-based redeterminations. This is a strategic differentiator as it removes one of the biggest liquidity is nicely above our minimum steps to add back liquidity. Progress we have made in removing risk, improving the balance sheet, we have received that we've taken and look forward to continuing to create value for all our stakeholders. I'll call back to Toby.

Thanks, Dave.

This team has established both the track record of execution and we will continue to find ways to lower our costs, become more efficient, and extract more asset base. We've made improvements from top to bottom, across the board, and scalable business that is able to withstand external pressures. Our heavy exposure to natural gas will be on the horizon and will drive strong free cash flow yield and will create ample strategic flexibility. Our double path back to an investment-grade differentiation for all our stakeholders. And lastly, EGT is committed to operating the right way, with an intensifying focus on our to thank all of our EQT employees who have displayed the heart, trust, and teamwork which are driving the evolution of this business.

Operator for Q&A.

At this time, star one on your telephone keypad. Again, that would be star one on your telephone keypad. The first question comes from Josh Silverstein.

You've made a lot of headway in getting towards the $1.5 billion. The reason why you would stop there, given the growing free cash flow position, and if you did hit the $1.5 billion after that, additional debt reduction, or even starting that by a little bit of growth spending.

Yeah. I think you'll see by the time we're all done, we'll be probably between $8 billion of debt retirement down below two times. So I think those are really key thresholds for us. The convert that we did can obviously be converted into equity as well. But I think once we get below them, then that gives us the flexibility to do all I call it shareholder-friendly things such as dividends, buybacks, and other things.

That's helpful. And then can you just get an update on the asset sales thoughts a little bit just to help get some better valuations into a rising price environment? What changed in terms of the priorities and what you wanted to sell relative to before? Is there less of a pressing need to do the royalty transaction? So any thoughts there would be great.

Toby.

Yeah, on our asset sales program, we're going to continue to sort of trim the rosebush and be willing to divest of properties that are non-core to our operating footprint. I think the progress we've made on a non-core asset sale that we've mentioned here, $125 million is sort of representative of that. We call it non-core fields. That some of the larger assets that we've to, you know, keep in mind these assets are largely PDP. We think the value of these assets will just continue to appreciate in a rising commodity price environment. And so part of this is making sure that we maximize value creation and catch up to sort of where our fundamental view before we continue to sell those larger assets.

Like I said, this is a continued focus for us.

We have our core plan. We know where we want to develop, and we've got a goal of deleveraging this business and generating free cash flow, but we'll continue to play a part of that.

Everybody is well over a billion dollars, so there's a lot of firepower.

Your next question will come from Wells Fitzpatrick from SunTrust.

Hey, good morning.

Good morning.

So it looks like the $390 million of tax refundability to be more selective in the divestitures, and so maybe you're focusing more on the overrides, if I'm hearing it correctly. But on the other side of that equation, can we get an update on the strategy vis-a-vis to offset those overrides or for your own book that you guys have talked about in the past?

I think there's an opportunity set in front of us to purchase minerals, and that was something that we were looking at.

We've maybe pushed pause on selling minerals.

I think that opportunity set still remains. And we have a land budget that was set that we would be able to capture those opportunities without having to to increase our purchasing minerals ahead of the drill bit is part of our strategy, and it's budgeted for, and we're looking forward to executing that.

Okay, makes sense. And can you talk to the GOR moving forward? Obviously, you guys are pretty gassy relative to your peers, which is great right now. see gas as a portion of production to increase? I mean, are you planning on, I guess, shifting those rigs a little bit further east to maybe take advantage of the positive gas curve?

Yeah, I mean, sitting at 95% production of dry gas is probably going to stay consistent and consistently allocating capital to dry gas. So there wasn't really a big amount of wet development to shift from. So we anticipate continuing to have a 95% production mix of dry gas.

Okay, perfect. And then just one last one from me. It looks like on page 23, the gathering rates for 2024 plus went from a little bit under 50 cents to a little bit over. Is that the price escalators, or is that part of the reclassification you guys have talked about?

Are you talking about in 23, you said? Yeah, that's part of the reclassification.

Okay, makes sense. Thank you, guys.

You're welcome.

Your next question will come from Chris Dandrinos from RBC Capital Markets. Your line is open.

Thank you. Good morning. Just going back to the February commentary around the Equitrans sale targeted for mid-year, has that timing changed at all in light of the recent kind of share price performance there or kind of any impact to your all-projected free cash flows?

Yeah. Yeah, you know, for us, we were always looking at trying to make sure that the value of E-Train was more fairly valued, and it's been very volatile. And I think now that – I think the merger between E-Train and EQM coming, you know, MVP in-service state was kind of another key catalyst. And I think now that you're seeing improvement in natural gas fundamentals, all those things I think play very well into why E-Train stock has kind of moved back up. And so I think for us, we're not going to hold on to it, you know, by the end of the year. At some point we'll sell it before then, and we're just going to make sure that we maximize value

Great. Okay. And then just on the guidance, you mentioned this non-core asset sale in the press release. Does the current guidance include the impact of that asset sale? And if not, kind of, you know, what's maybe the production associated with that?

Thanks. Yeah. It's a very small amount of production. And so, you know, right now we're running ahead of expectations. So when we strip it out, it will have very minimal impact to our guidance, if anything at all. All right. Thank you.

Your next question comes from Holly Stewart from Scotia Howard. Your line is open.

Good morning, gentlemen.

Good morning, Holly. Good morning.

Maybe just a... A couple quick ones here. First, recognizing that NGLs and condensate are not a huge part of your business, but, you know, the guidance does move down for volume for the year. So I guess the first question would be, what are you doing with your own portfolio right now, just given pricing, and then what are you seeing in the basin in terms of, you know, curtailments?

Sure. Yeah, so, you know, just given our exposure to liquids, We're not seeing any material differences in the way that we operate, but I think what you mentioned is a dynamic that's very important to understand is what's happening to other operators in the basin. We have seen people having to shut in wells because of not being able to get rid of their condensate. If I had to quantify what we've seen from the amount of dry gas that would be shut in as a result of these shut-ins, it would be probably in the order of 500 to 800 million cubic feet of gas a day. And so that's a pretty important dynamic that we'll continue to track. And again, these things would be favorable to, you know, the natural gas outlook that we see.

Okay, that's interesting. That's a big number. And then, Dave, maybe just some perspective on, you know, the longer-term goal for sub-two times leverage. You know, I guess just thinking about the timing there according to your plan? Do you see that being feasible by the end of 2022?

Well, I think from an absolute debt perspective, we'll get our absolute debt down to where we want to or better by the end of 21. So that'll be things I'd say probably in our control. And then the next thing will really be the commodity price environment. And so if the commodity price you know, gets up, you know, closer to that three times level, $3 level, that's where that'll be a nice trigger for us to get our leverage right into that zone. And so I think those are really to be the two variables to think about.

Okay. And then maybe just a housekeeping item. Any impact from this Texas Eastern explosion?

Yeah. So that was an event that occurred a couple days ago. We have no major impacts as a result of that. You know, just to give some background on that incident, about 10 p.m., we were notified. By 2 p.m., we had to shut back some gas. But working with our partners, E-Train was very helpful in allowing us to get our gas back to flowing. But by 2 p.m. the next day, we had all of our gas scheduled, and the commercial team had found markets for that gas, and we were able to put it to sale. So, You know, there will be some differences on the pricing that we'll get for that selling in Basin versus on the TECO line, but, you know, we expect that to be rather insignificant, and we'll be able to quantify that now.

Okay, great. Thanks, guys.

You're welcome.

The next question will come from Jane Trasenko from Stiefel. Your line is open.

Good morning, and thanks for taking my questions. The first question is on $500 million in convertible debt that you guys issued in April. Maybe you guys can talk about the rationale for doing this type of debt instead of plain vanilla senior notes.

Sure. This is Dave Connie. So if you look at the setup heading into doing a convert, Our debt traded up very close to par, so that created a really good dynamic from a fixed income perspective. And then the volatility, as our stock rallied very sharply, good volatility really creates a second component of a convert, which is really a combination of debt and an equity option. And so when you put those two together, it created a very, very good dynamic to do a convert. And so... We hired a consultant who was very skilled in that, and if you notice how we executed that, we were able to get a very low coupon at 1.75%, and we were able to get a call spread that was very differential versus our peers that did convert. So it helped us actually save about $20 million when you looked at kind of the cost differential between other converts and what we did. So it's just a really good setup for a convert.

Okay, okay, got it. And then I wanted to ask you something on Ohio Utica. So when you guys announced the CapEx cut back in March, it seems like it should have impacted capital allocations to Ohio Utica. Maybe you guys can talk about how you think about this asset, and obviously it's for sale. How do we be kind of thinking about production outlook and maybe well costs, where they stand currently?

Sure. So I'll take this sort of just at a higher level, just looking at the capital efficiency of our program and how the Utica fits into that. I think looking at the capital efficiency at EQT, I break it down into sort of two categories, the capital efficiency of our entire program and the efficiency of our execution of specific well costs. When we look at the capital efficiency of our entire program, Couple things that are happening that allow us to lower costs. I mean, first, starting with capital allocation decision activity levels. You know, we have a mentality that we're going to continue to stay in maintenance mode, and so not adding any new activity or production. I think the other aspect of capital allocation comes to the types of wells that we're actually developing. You'll see us start to shift more activity into our Marcellas first and shift away from Ohio Utica development. That will give us the ability to execute Pennsylvania Marcellus wells at, call it, $7.30 a foot versus our Ohio Utica that's north of $1,000 a foot. So it will be a more efficient application of our dollars there. And so I think you may see Ohio maintain production, but in the future that asset may decline a little bit as we shift activity into Pennsylvania Marcellus.

That's very helpful. The last question, if I may, on cash costs. So, obviously, strong outperformance on cash costs in 1Q20. And just curious if there were, like, some one-off items or if this is something that you guys can sustain through the remainder of the year.

Yeah, you know, we maintain our guidance, but I think I'd say we have a bias that if you sit and wait and stay tuned, we're going to think about what we do with the upside that we've created in our plan.

Got it. Thanks a lot.

Thank you.

And your next question will come from Samir Padwani from Tudor Pickering Holtz. Your line is open.

Hey, guys. Good morning. You've done a great job of getting the well costs down, and it would seem service costs have provided somewhat of an unexpected benefit in the current environment. Does you think about heading into 2021? Do you see potential line of sight to get that 730 per foot target even lower, maybe with a six handle?

Yeah, sure. So this is Toby. I would say, you know, 730 foot was always our target, but it was not our floor. And so when we look at some of the things that we're doing now in present day and the sustainability of that into the future, we look at the quality of our well execution. I think there's really four parts. One is operation schedule. You know, that's largely driven by, you know, what percentage of our development is going to be set for combo development. And in the future, we have a rising percentage of activity that's going to be part of combo development. So that's going to strengthen and allow us to lower costs. From a well-designed perspective, another key aspect with our standardized well designs, we know that we're going to be generating, putting the same design in the ground with some simple tweaks, but expect that will really set us up to make sure that from the oil field service side, which is another cost driver, that our teams are able to procure the services they need for a stable schedule, activity schedule. And while it is true, I think service costs have come down and I think that largely has allowed us to accelerate hitting our well-cost targets. The teams have been really focused on making the costs that we're benefiting from right now sustainable into the future, and so we've been able to sign into long-term contracts. I mean, specifically just looking at some of the biggest spend services on our frack equipment, we've been able to execute two long-term pricing agreements, one with U.S. Well Services and another one with Evolution, both some really great technology that allows us to really take our operational efficiencies to the next level. And that really leads us into the fourth aspect of cost sustainability, talking about our operational efficiencies. And with good combos, with the right well-designed, good service contracts, we're really getting high-quality crews and equipment. Our operational efficiencies will continue to improve. You know, we showed on our slides the fact that we've, continue to show gains in our drilling performance. That will continue to improve as we get through our legacy well boards that we inherited. You know, we had a lot of wells that were drilled with short top holes, so we've had to spend a little bit more time drilling vertical section with our horizontal rigs. Those will be sort of flush through the system towards the back half of this year. So we see performance improvements on the horizontal section on the completion side of things. getting access to this new technology and the team's continued execution, we see an opportunity for us to increase the operational efficiency from a stages-per-day perspective there as well. So, I mean, all these things to say, they all come together and, you know, lead us to have great confidence in hitting our 730 afoot, extending that performance into the future, and setting the table for lower costs going forward.

Yeah, that's great, Collin. I really appreciate that. And then just wanted to clarify some of your earlier comments. I think you mentioned there's some optionality heading into 2021, but also, you know, focus on free cash flow towards addressing debt. Those could be somewhat mutually exclusive. So just looking for some clarity there.

Yeah. So, you know, you've seen some other peers talk about the opportunity that's in front of Appalachian producers and all natural gas producers, frankly. Right. To defer some production in 2020 and push that production into 2021, which is a much higher gas price environment, that opportunity is something that we're looking at at EQT. Our operational uptime that we've had has allowed us to be ahead of schedule from a production standpoint, and that efficiency is going to give us the flexibility to be able to capture that opportunity. So you may see us shift a little bit of production into 2021, you know, but the decisions that we would make would not cause us to change our guidance.

Okay, okay. So even if you were to curtail, it would still be within the guidance range, maybe just towards the lower end or something?

Yeah, probably more towards midpoint, midpoint to high. Okay.

Okay, got it. Thank you.

And your next question will come from Jeffrey Campbell from Two Way Brothers. Your line is open. Good morning.

Thinking about your Ohio Utica remarks at a high level over time, is acres that cost more than $730 per foot to produce an eventual candidate for asset sale?

Yeah, I mean, I think we think about we want to make sure we're spending our dollars in the highest return assets. And right now, you know, combo development, Pennsylvania Marcellus is the most efficient use of development right now. And so we've shifted our operations schedule to prioritize, you know, the best rate of return type of projects. And when we look at that, the Ohio Utica sort of falls behind our Pennsylvania Marcellus and our West Virginia Marcellus assets.

Okay, great. Thank you. Could you add any color on the 2020 land budget? I was just wondering if there's anything unique happening now because of the conditions this year versus a better macro year like we're hoping for in 2021?

Yeah, you know, our land budget was largely driven by a maintenance program, leasehold maintenance. About two-thirds of our $150 million budget was set towards renewing leases and another $50 million was for filling in the holes. So, you know, we've done some things working with our landowner partners to sort of spread some of those costs over time. So, you know, there is an opportunity for us to come in a little bit lighter. You know, looking forward in future years, 2021 going forward, you know, there's an opportunity for us to take the amount of that we have budgeted for land and walk that down from the 150 to something that is lower. You know, I think one of your points you referenced, you know, with a stronger 2021 outlook for gas, you know, has that impacted land? I'm reading through into thinking about competition. And I would just say that, you know, with such a dominant foothold and along with just the mature aspect of this basin, you know, we really haven't seen a lot of competition here. Really, in any part of the play, there's only one operator that can give landowners the confidence to get a wellbore drilled and get royalties, which is a big prize. They are definitely educated and understand that and willing to work with EQT. That's the dynamics of land right now.

That was a great answer. I appreciate that. If I could ask one last one, just getting off the script of a lot of the questions here. I was just wondering, what features of the hybrid drilling rig that you show on slide A do you find superior to what most operators are using?

Yeah, sure. I mean, I think it really just, I mean, keep in mind, a lot of these rigs, we burn diesel to generate power. I mean, we're burning diesel to generate electricity, and that electricity powers the rigs. These battery packs really just sort of normalize power. the power loads that the rig is using.

So that's really what's taking place.

Thank you.

Thank you. Yep.

Thank you.

I have no further questions. Over to Toby Rice for closing remarks.

On behalf of the EQT's directors, the management team, and our workforce, thank you for your support and interest in EQT. and all of us momentum and working hard to deliver the results that our shareholders deserve. Thank you.

Thank you, everyone, for joining. This will conclude today's conference call.