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EQT Corp
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Ladies and gentlemen, thank you for standing by. And welcome to today's EQT Q1 Quarterly Results Conference Call. [Operator Instructions].
I would I'd like to hand the conference call over to Andrew Breese, 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 Khani, Chief Financial Officer. The replay for today's call will be available on our website for a 7-day period beginning this evening. The telephone number for the replay is 1-800-585-8367 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 Factors 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 earnings 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 to Dave 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 our campaign promises. Our operational results validate the promises that we made to our shareholders and prove our thesis that our 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 access 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, derisked 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. EQT 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 design 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 transition 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 traces, employees and contractor partners that enter our active sites. This insight has allowed us to contact hundreds of contractors, employees surely 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 an 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. For our employees in the field, our contracted partners, our peers and the health care 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. We'll 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 disruption due to the COVID-19 pandemic. While oil prices sit at historic lows and have forced reductions to rig counts and frac 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 E&Ps are challenged.
While we are just 1 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 RES com consumption. Furthermore, LNG exports are facing more and more cancellations as the arc to export gas has gone negative for the next 3 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 bounce the market fairly quickly and sets up for a strong fourth quarter 2020 and 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 Khani 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 have made through the first 4 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 have developed a more robust hedge process to be able to capture rising prices over time while at the same time, derisking the volatility in our revenues. We've accelerated the timing of our tax refunds, which increased our first quarter free cash flow and helps us better rationalize our asset sale program. We've lowered our CapEx forecast for 2020 3x 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 10-Q 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 combination of various efficiencies realized across the organization, the largest 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 $0.67 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 or $1.33 per Mcfe, $0.05 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.
Outlook synergies 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 our 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 release and a gain of $187 million.
We will amortize the contract asset over a period of approximately 4 years beginning at MVP and service date. This noncash amortization expense will be recorded 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 is no net change to our 2020 guidance, but approximately $0.14 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 2020, we expect sales volumes of between 360 to 380 Bcfe, average differentials of negative $0.45 to negative $0.25 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 breakeven free cash flow during the period.
I started off my prepared remarks by discussing the financing accomplishments we've achieved thus far in 2020. And now I'd like to spend a little time talking about the details related to our 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 in 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 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 retirements.
Touching on the selective asset divestitures quickly. We are taking a measured approach to selling assets. The market is still there, particularly the minerals market, but we are 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 exploit our pursuit back to investment-grade metrics, creating a more strategic differentiation for EQT. 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, setting 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 the ability to capture 2021 pricing upside while protecting the downside risk. As we move through the year, we will look to opportunistically layer on hedges at favorable prices. We will expect to enter 2021 with a substantial percentage of our production hedged with additional hedges 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 of reasons. First, as the supply/demand impact of the current environment become clear, we're becoming more and more bullish on the natural gas pricing set up for 2021 and beyond. Secondly, the broader E&P group has been forced to layer on hedges to protect borrowing bases that are subject to redeterminations, creating pricing pressure in the market, and we want to wait for this dynamic to abate.
I'd like to also remind that we have the 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. Our current liquidity sits at $1.6 billion, which consists of $2.5 billion unsecured revolver, which is essentially undrawn, offset by approximately $900 million of letters of credit posted, stemming from the ratings downgrades that occurred earlier this year.
Based on discussions with counterparties and maximum collateral exposure levels, we believe we are largely through to collateral cycle. I want to reiterate that unlike many E&Ps and Appalachian peers, our revolver is unsecured and not subject to borrowing base redeterminations. This is a strategic differentiator as it removes one of the biggest variables of the liquidity equation. Although our current liquidity is nicely above our minimal liquidity needs, we continue to pursue steps to add back liquidity. I'm encouraged by the progress we have made in removing risk, improving the balance sheet, getting this business up to prosper.
We have received positive feedback from the steps that we've taken and look forward to continuing to create value for our stakeholders. I'd now pass the call back to Toby.
Thanks, Dave. The setup for EQT is compelling. This team has established both the track record of execution and keeping promises made to its shareholders. We will continue to find ways to lower our costs, become more efficient and extract maximum value from our premiere asset base. We have made improvements from top to bottom across the organization and have created a durable and scalable business that is able to withstand external pressures.
Our heavy exposure to natural gas will allow us to capture the bullish macro setup on the horizon and will drive strong free cash flow yield and will create ample strategic flexibility. Our debt and maturity management plan will create a viable path back to an investment-grade balance sheet, which will create clear differentiation for all our stakeholders.
And lastly, EQT is committed to operating the right way with an intensifying focus on our ESG program. Before I turn the call over for Q&A, I'd like to thank all of our EQT employees who have displayed the heart, trust and teamwork, which are driving the evolution of this business.
With that, I'll turn it over to the operator for Q&A.
[Operator Instructions]. Your first question comes from Josh Silverstein.
You've made a lot of headway in getting towards the $1.5 billion debt target. Any reason why you would stop there given the growing free cash flow position? And if you did hit the $1.5 billion target, what would be prioritized after that? Additional debt reduction, return of capital to shareholders or even starting that by a little bit of growth spending?
Yes. So I think our goal is -- I think you'll see, by the time we're all done, we'll be probably between -- my guess is between $1.6 billion and $1.8 billion of debt retirement. Our goal is to get our leverage down below 2x. So those -- I think those are really key thresholds for us. The convert that we did can obviously be converted into equity as well. That could be a further deleveraging event. But I think once we get below them, then that gives us the flexibility to do other, 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? It seemed like you guys were pushing those out a little bit just to help get some better valuations into a rising price environment. But has your thoughts 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 versus just straight to production? So any thoughts there would be great.
Yes. Josh, this is Toby. Yes, on our asset sales program, I think we're going to stay -- we're going to continue to sort of trim the Rosebush and be willing to divest properties that are non-core to our operating footprint. I think the progress we made on a noncore asset sale that we mentioned $125 million is sort of representative of that. We have some more of those, call it, noncore fields that would be on the table. I think some of the larger assets that we've -- we're holding on to, keep in mind, these assets are largely PDP weighted, and we think the value of these assets will just continue to appreciate in a rising commodity price environment. So part of this is making sure that we maximize value creation and waiting for the macro to catch up to sort of where our fundamental view is before we before we continue to sell those larger assets. But like I said, these are -- 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 for shareholders. So asset sales, will continue to play a part of that.
Yes. Just that bucket, just to remind everybody, is well over $1 billion. So there's a lot of firepower in there. It's just finding the right timing.
Next question will come from Welles Fitzpatrick from SunTrust.
So it looks like the $390 million of tax refunds really gives you the ability 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-à-vis mineral buys, either to offset those overrides or for your own book that you guys have talked about in the past?
Sure. I think there's an opportunity set in front of us to purchase minerals. And that was something that we were looking at doing to offset any mineral sales that we did. Even if 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 you'd be able to capture those opportunities without having to increase our CapEx budget in 2020. So 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. Make sense. And then can you talk to the GOR moving forward? Obviously, you guys are pretty gassy relative to your peers, which is great right now. Do you see gas as a percent 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?
Yes. I mean, sitting at 95% production of dry gas is probably going to stay consistent. So yes, for us, I mean we've been 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 for me. It looks like on Page 23, the gathering rates for 2024 plus went from a little bit under $0.50 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?
2024.
Yes.
Yes. That was part of the reclassification.
The next question will come from Chris Dendrinos from RBC Capital Markets.
Just going back to the February commentary around the Equitrans sales 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 impacts to your all's projected free cash flows?
Yes. Yes, for us, we're 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 there's the merger between e-Train and EQM, coming MVP in-service date was kind of another key catalyst. And I think now that you're seeing an 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 onto it by the end of the year. At some point, we'll sell before then and we're just going to make sure that we maximize value for us.
Great. Okay. And then just on the guidance, you mentioned this noncore asset sale in the press release. Does the current guidance include the impact of that asset sale? And if not, kind of what's maybe the production associated with that?
Yes. It's a very small amount of production. And so 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.
Your next question comes from Holly Stewart from Scotia Howard.
Maybe just a couple of quick ones here. First, recognizing that NGLs and condensate are not a huge part of your business, but 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 curtailments?
Sure. Yes. So 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 I -- what we've seen from the amount of dry gas that will be shut-in as a result of these shut-ins, it'd be probably in the order of 500 million to 800 million cubic feet of gas a day. And so that's a pretty important dynamic that we're continuing to track. And again, these things would be favorable to the natural gas outlook that we see.
Okay. That's interesting. That's a big number. And then, Dave, maybe just some perspective on the longer term goal for sub 2x leverage, 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 will 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 gets up closer to that 3x level, through that level, that's where that will be a nice trigger for us to get our leverage right into that zone. And so I think those are really to be the 2 variables to think about.
Okay. And then maybe just a housekeeping item. Any impact from this Texas Eastern explosion?
Yes. So that was an event that occurred a couple of days ago. We have no major impacts as a result of that. Just to give some background on that, that incident, about 10:00 p.m., we were notified by 2:00 p.m. And we had to shut back some gas but working with our partner's e-Train was very helpful in allowing us to get our gas back to flowing. By 2:00 p.m., the next day, we had all of our gas scheduled and the commercial team added -- found markets for that gas, and we were able to put it to sales. So there will be some differences on the pricing that we'll get for that selling in-basin versus on the TETCO line. But we're -- we expect that to be rather insignificant, we're -- we won't be able to quantify that now.
The next question will come from Jane Trotsenko from Stifel.
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 Khani. So if you look at the setup that 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 of -- as our stock rallied very sharply created 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 2 together, it created a very, very good dynamic to do a convert. And so we hired a consultant who is 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 high Utica. So when you guys announced the CapEx cut back in March, it seems like it should have impacted the capital allocation to high Utica. Maybe you guys can talk how you think about this asset? And obviously, it's for sale. How 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 at sort of 2 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, there's a couple of things that are happening, that allow us to lower cost. I mean, first, starting with capital allocation decision activity levels. We're having 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 ship more activity into our Marcellus first and shift away from Ohio Utica development. That will give us the ability to execute wells -- Pennsylvania Marcellus wells at, call it, $730 a foot versus our Ohio Utica, that's north of $1,000 a foot. So it will be 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 the Pennsylvania Marcellus.
That's very helpful. The last question, if I may, on cash costs. So obviously, strong outperformance on cash costs in 1Q '20. 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?
Yes. We maintain our guidance. But I think with -- 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.
Our next question will come from Sameer Panjwani from Tudor, Pickering, Holt.
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. As 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 6 handle?
Yes, sure. So this is Toby. I would say $730 a 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 4 parts. One is operation schedule. That's largely driven by 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 design perspective, another key aspect of -- 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 oilfield 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 frac equipment. We've been able to execute 2 long-term pricing agreements, 1 with U.S. Well Services, another 1 with Evolution, both some really great technology that allows us to really take an -- 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 -- with the right well design, good service contracts, we're really getting high-quality crews and equipment. Our operational efficiencies will continue to improve. We showed in 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 wellbores that we inherited. 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 flushed at 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 lead us to have great confidence in hitting our $730 a foot, extending that performance into the future and setting the table for lower costs going forward.
Yes. That's great color. 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 focus on free cash flow towards addressing debt. Those could be somewhat mutually exclusive. So just looking for some clarity there.
Yes. So you've seen some other peers talk about the opportunity that's in front of Appalachian producers and all natural gas producers, frankly. 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. But the decisions that we would make would not cause us to change our guidance.
Okay. So even if you were to curtail, it would still be within the guidance range, maybe just towards the lower end or something?
Yes. Probably more towards the midpoint, midpoint to high.
And your next question will come from Jeffrey Campbell from Tuohy Brothers.
Thinking about your Ohio Utica remarks. At a high level over time is acreage that costs more than $730 per foot to produce an eventual candidate for asset sale?
Yes. I mean, I think we think about -- we want to make sure we're spending our dollars the highest return assets. And right now, combo development, Pennsylvania Marcellus is the most efficient use of development right now. And so we've shifted our operation schedule to prioritize 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. 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?
Yes. Our land budget was largely driven by a maintenance -- leasehold maintenance, about 2/3 of our $150 million budget was set towards renewing leases and another $50 million was for filling in the holes. So we've done some things working with our landowner partners to sort of spread some of those costs over time. So there is an opportunity for us to comment a little bit lighter on the land budget side of things. And then looking forward in future years, 2021 going forward, there's an opportunity for us to take the amount of dollars that we have budgeted land and walk that down from the $150 million to something that is lower. I think one of your points, you referenced with a stronger 2021 outlook for gas, has that impacted land? I'm reading through into thinking about competition. And I would just say that with such a dominant foothold and -- that EQT has, along with just the mature aspect of this basin, we really haven't seen a lot of competition here. And really in any part of the play, there's only 1 operator that can give landowners of confidence to get a wellbore drilled and get royalties, which is the big prize. And landowners are definitely educated and understand that. And they're willing to work with EQT. So that's sort of the dynamics of land right now.
That was a great answer. I appreciate that. And if I could ask one last one, just kind of 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 8, do you find superior to what's become kind of the standard high-spec rig that most operators are using?
Yes, 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 generate electricity and electricity powers the rigs. These battery packs really just sort of normalize the power load that the rig is using and doing it in a more efficient manner. So that's really what's taking place there. It's just a more efficient use of energy.
I have no further questions in queue. I turn the call back 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 look forward in continuing on this 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. You may now disconnect.