EQT Corp (EQT) 2020 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the EQT Q2 2020 Quarter Results Conference Call. (Operator Instructions) Please be advised that today's conference is being recorded. (Operator Instructions) I would now like to turn the call over to your speaker today, Andrew Breese, Director of Investor Relations. Thank you. 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 6066685.

In a moment, Toby and David will present their prepared remarks with a question-and-answer session to follow. During these prepared remarks, they may refer to 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'm particularly excited as we have recently eclipsed our 1-year anniversary at the company. I plan to provide an update on the business and our strategic initiatives as well as provide a brief review of the quarter.

But first, I would like to quickly reflect on the previous year and what it means for the future of our company. We were called into service by the shareholders last July with a mandate to transform the way that EQT operated while at the same time, addressing legacy governors on the business that were preventing EQT from realizing the full potential of its world-class asset.

Today, I am proud to say that EQT stands firmly on stable ground, and we are primed to take this company to the next level as we unlock the full potential of our premier assets. We've leveraged our experience with these assets to fast-track operational results. We've leveraged technology and maximized the value of our human capital to retool EQT into a modern, digitally enabled organization with vision and purpose.

This was accomplished not only by doing what we said we were going to do by hitting our cost targets, streamlining the organization, implementing our digital work environment but also going above and beyond our promises. We have significantly improved EQT's financial position by creating a clear path to maturity management and absolute debt reduction; enhancing our future cash margins and free cash flow through the renegotiation of our long-term gathering contracts, coupled with substantial near-term fee relief; rebalancing our hedge portfolio to protect our business against a volatile 2020 commodity landscape while positioning for an improved forward curve; rationalizing our FT portfolio, which looks even more promising with the cancellation of ACP.

All of these actions prove that we can be nimble and creative while at the same time, providing strategic flexibility. These decisions were only able to be accomplished from a position of strength unique to this company. EQT is truly a rate of change story being written by an aligned, highly motivated management team and executed by an equally motivated workforce and network of stakeholders.

As evident in the second quarter results announced earlier today, our efforts have translated into a step change in operational performance at a faster pace than originally projected. Our operational improvements have come organically and not by sacrificing long-term efficiencies for short-term benefits. As such and in alignment with our corporate mission, every day, we are getting closer to being the natural gas leader that we all hope for and achieving our mission to realize the full potential of EQT and becoming the operator of choice for all stakeholders.

Our company mission is inclusive of all stakeholders. We believe that it's not just about producing great results for shareholders, it's also about how you produce those results. Recognizing the needs of all stakeholders emphasizes the critical role that natural gas plays in our future energy mix. How we operate is shaped by our commitment to ESG. We believe that performance on ESG issues is a critical component for long-term sustainable value creation.

Today, Appalachia provides the power source for 1 out of every 8 households in America, 1 out of every 60 for EQT alone. The ability of the shale revolution to meet the growing energy demand of the United States while simultaneously replacing coal power generation not only reduced the cost of power for Americans, it also resulted in drastic declines in CO2 emissions. With respect to methane emissions, the primary focal area for oil and gas producers, Appalachia has the lowest intensity of any basin in the United States, representing 16% of the energy supply while generating only 4% of the methane emissions.

As we look to the future of the natural gas industry, we believe that companies like EQT will lead the way. Aside from being purpose-driven, we believe we have an opportunity in front of us that is unique in the industry. Our extensive combo development inventory, coupled with the technological and human capital needed to execute on it, has led to a step change in operational performance with well costs declining by over 30% in just 1 year.

The outputs of combo development are not just financial but are also beneficial to emission levels, water recycling rates and diesel usage, among other ESG-related metrics. To that end, we expect to see similar favorable step changes in environmental impacts as we continue to execute EQT's unique combo development strategy.

This transitions nicely to some operational highlights that were achieved during the quarter. I'd like to direct you to Slide 10 in the investor presentation that we published this morning for reference.

We continue to push the operational, technological and engineering boundaries to drive value creation. And in June, EQT reached an industry first in the basin by horizontally drilling 10,566 feet or more than 2 miles in a 24-hour period. We continue to see improvements in efficiencies. Year-over-year, our horizontal drilling speed has increased by 63% while our horizontal days per 1,000 feet drilled has decreased by 36%. What this means for EQT is we were able to achieve our target drilling costs with higher confidence at an accelerated pace.

Our utilization of electric frac crews and hybrid drilling rigs exemplifies our commitment to improved operational and environmental performance. As highlighted on Slide 11 in our presentation, the use of next-generation frac technology has driven a 20% improvement to both pumping time and frac stages per crew since July of 2019 while lowering our carbon footprint by eliminating over 9 million gallons of diesel consumption. These drilling and completion efficiencies are very encouraging but only represent a subset of the operational efficiencies being realized across the organization, which drove a 10% decrease in our well costs quarter-over-quarter.

During the quarter, we developed our PA Marcellus wells at a cost of $680 per foot, well below our first quarter execution of $745 per foot and our target well costs of $730 per foot. While we will be patient in establishing a new well cost target, our confidence is growing and we are excited about the opportunities in front of us.

Consistent well execution is driven by a strong schedule design proven in consistent well design and efficient drilling and completion operations in the field, all of which translate into sustainable and consistent cost performance. Our entire organization is acutely focused on these measures and the pursuit of optimal operational execution.

Shifting gears, I'd now like to provide an update on the production curtailment we announced in May. We ended the quarter will all our previously announced volume curtailment shut-in. Earlier this month, we began a moderated approach to bring in these volumes back online and have seen no degradation to well performance. As of today, all curtailed production has return to sales.

Having executed this curtailment strategy, we now have a highly informed data-driven analytical understanding of how these actions impacted all aspects of our business and can say with confidence that these actions were value accretive. Moving forward, we will continue to monitor the market and look for opportunities where economics may justify further curtailments.

On the macro front, the effect of COVID-19 has created near-term uncertainty in the U.S. natural gas markets. Already battling excess supply from a warm winter, we saw about 4 Bcf a day of demand destruction from COVID-19 in the industrial, LNG and residential commercial markets.

Power, on the other hand, was a bright spot even with lower electricity usage as natural gas has taken market share away from coal. We are fortunate to be protected from these short-term pricing pressures through our robust hedge portfolio in 2020. Looking forward, we believe the market will be much more supportive as the rapid decline in oil-directed activity and uncertainty around future oil pricing reduces a material amount of associated gas from the market. Additionally, with Appalachia rig counts dropping from 52 to 33 and Haynesville rig counts dropping from 49 to 32 since the beginning of 2020, both premier gas basins sit well below maintenance production activity levels.

We anticipate that these factors, combined with normal winter weather and rising industrial and LNG demand, will cause gas supplies to be short heading into 2021. And as a result, we believe the natural gas strip is undervalued. Because of this view, we have been patient hedgers leaving upside in 2021 and have reduced exposure to the Equitrans Henry Hub price escalator embedded in our previously executed gas gathering agreement which Dave will talk to in a moment.

While undervalued, we base our business plan on strip pricing rather than our more bullish internal pricing view. Based on the current price environment, we expect to run this business at a maintenance level for the next several years. If our upside commodity thesis plays out for 2021, all incremental free cash flow generation would be utilized to further reduce our debt profile and enhance our leverage position.

There are a lot of great things happening at EQT. We're excited about another strong quarter. And I'll now turn the call over to Dave.

Thanks, Toby, and good morning, everyone. Before we get into the detailed quarterly results, I want to highlight the steps that have been taken during the quarter to strengthen our financial position and balance sheet. I'll start with our near-term debt maturities and net debt position, which we detailed on Slide 16 through 19 in our investor presentation.

As you remember, we ended the first quarter with approximately $630 million in debt maturing through 2021 pro forma for the convertible debt offering. During the second quarter, we retired approximately $350 million in conjunction with the execution of our $125 million asset divestiture and the receipt of approximately $190 million or half of our tax refunds we anticipate receiving in 2020.

At the end of the quarter, we have completely retired our 2021 term loan, which stood at $1 billion at the start of the year. Our remaining 2021 debt maturity sits at approximately $280 million, which we plan to retire at or before the end of 2020. Since the beginning of the year, we paid off or termed out $2.6 billion of the $3.8 billion of maturities due from 2020 through 2022.

EQT's net debt position has improved by approximately $400 million during the quarter, going from $5 billion to $4.6 billion, which was augmented by the fair value treatment associated with our convertible debt offering. With our expected free cash flow generation and the second half of our tax refund, we see our net debt declining to $4.3 billion, paying off another $300 million before year-end. The use of our remaining Equitrans stake at today's value nets us closer to $4.1 billion of net debt.

Additionally, assuming 100% equity treatment of our convertible issue, net debt would be reduced by a further $300 million to $3.8 billion. One of the major benefits of issuing [accord] is having the flexibility to deem debt or equity. As we stated in the past, we firmly believe that the best way to increase EQT's equity value and market position is to reduce debt and improve our leverage profile. We've continued to target leverage of below 2x and planned to retire between $1.6 billion and $1.8 billion of debt in the aggregate by the end of year 2021. If we ultimately make decision to execute certain asset sales, our debt reduction level could be meaningfully better.

During the second quarter, we were also successful in issuing approximately $100 million in surety bonds, replacing previously posted letters of credit. This increases available liquidity and saves us about 1% in costs. Our current liquidity sits at $1.7 billion comprised of our $2.5 billion unsecured revolver and offset by approximately $800 million outstanding letters of credit. As a result of successfully following our maturity and liquidity management plan, Fitch has flipped our ratings outlook to positive.

Now getting into some of our second quarter results. First, we achieved sales volumes of 346 Bcfe for the quarter with oil production curtailments remaining in effect through the duration of the quarter. We exceeded the high end of our guidance by 11 Bcfe, driven by production uplifts realized due to lower line pressures associated with the curtailment.

Adjusted operating revenues were $816 million, around 15% compared to the second quarter of 2019 results, driven by a 9% lower realized price and 7% lower sales volumes. Our second quarter 2020 production-related unit operating costs were $1.42 per Mcfe. I remind you that the volume curtailment program increased our unit costs. We expect production-related operating costs to improve throughout the remainder of 2020 as we return production to normal levels.

Capital expenditures of $303 million were aligned with our expectations and $163 million lower than the second quarter of 2019. Pennsylvania Marcellus well cost of $680 per foot during the quarter set the stage for improved capital deployment moving forward.

Our adjusted operating cash flow for the quarter was $221 million, while free cash flow was negative $82 million. This quarter, we had several items negatively impact our free cash flow for a total of approximately $90 million. First, we used a weakening forward curve this quarter to spend approximately $54 million to restructure our 2021 to 2023 hedge book to meaningfully reduce exposure to the 3-year Henry Hub bonus payment embedded in our new gas gathering agreement with Equitrans. As a reminder, these payments have a $60 million per year limit where it could reach $180 million under certain price scenarios.

And second, our decision to shut in production during the quarter deferred approximately $36 million into future periods. On the strategic side, we continue to pursue paths to rationalize our FT portfolio. During the second quarter, we were able to execute several small FT trades and will realize a small premium over the remaining contract duration. Although these transactions were small, the market is open and we're excited about the opportunities available to further execute on this strategy.

One of the more meaningful rationalizations will be our ability to sell down some or all of our MVP capacity. This continues to present the biggest potential for long-term cost reduction improvement, which will drive significant NAV and free cash flow enhancement. We believe the viability of execution has been significantly improved through: one, a favorable Supreme Court ruling approving the crossing of the Appalachian trail; second, the cancellation of the ACP pipeline project, which will send those gas users seeking supply replacement; and three, a favorable Nationwide 12 Water Permit ruling, which should accelerate MVP construction completion. These actions increase the value of the current MVP capacity while also creating incremental value upside through the increased probability of MVP expansion and extension into the growing Southeast demand market. We are having discussions with multiple parties at the moment.

We continue to monitor the value of our equity stake in Equitrans. And although there has been positive news related to MVP as of late, we continue to believe that the equity remains undervalued. The cancellation of the ACP pipeline has increased the value of MVP on multiple measures, and we believe much of that capacity will trade hands in the near term, further enhancing its embedded valuation. Additionally, our high confidence in managing our future maturities allows us to be patient in our approach to monetizing this stake. As such, we will be systematic with our ultimate liquidation of our interest in Equitrans, which we may monetize in 2021, if necessary.

The supply/demand impact of COVID-19 continued to work its way through both domestic and global natural gas fundamentals that Toby highlighted earlier, and we're closely monitoring these market drivers as we make informed decisions about forward hedging. We continue to believe the forward curve is significantly underestimating the price required to incentivize ample production to fulfill future demand. We currently have approximately 40% of our expected 2021 production hedge, and we will continue to pursue a hedging strategy that balances our ability to capture 2021 pricing upside while protecting downside risk. Our goal remains to be majority hedged for 2021 as well as hedging out for multiple years.

I'll now turn the call back to Toby for some closing remarks.

Thanks, Dave. It is abundantly clear that shareholders desire a new approach in shale, one in which oil production growth is muted and efficiencies are amplified. Our approach is aligned with our shareholders and also aligned with all stakeholders who desire a better world now and for future generations. While our near-term accomplishments continue to secure our footing as the operator of choice, we look forward to further enhancing our position as the sustainable natural gas leader.

As part of this, we will continue to strive to have best-in-class ESG metrics and transparency. Our revamped environmental, social and governance report for the calendar year 2019 is set for publication later this year, which will include more details on EQT's long-term ESG strategy as well as to provide insights into our ESG metrics.

Lastly, I'd like to give a shout-out to our employees. For the last year, they've been relentless in transforming the way we work to deliver superior results. Your hard work and dedication is the force driving transformational value creation at this company, and for that, I thank you and look forward to continuing on our mission together.

With that, I'll turn the call over to the operator for Q&A.

(Operator Instructions) Your first question comes from Arun Jayaram from JPMorgan Chase.

I was wondering if you could elaborate a little bit more on the potential implications to EQT from the ACP cancellation. You have noted that multiple counterparties have expressed interest in the pipe. I was wondering if you could talk about perhaps the prospects to offload the bulk of your transportation at par or even your premium and perhaps discuss some potential time lines on this.

Sure. So with ACP being canceled, that was about 1.5 Bcf a day of capacity that was going down into the Southeastern market, which is competing with MVP capacity that was going to deliver gas there. So not having that project online makes MVP more desirable. I think the customers that signed up for that project are still looking for that gas and MVP is going to be a good outlet for that. So those are the parties that we're having conversations with.

And as far as like the likelihood of being able to lay out capacity, it could be up to all of our capacity. I think one of the things that we're looking at that's going to frame up the size that we end up laying off is really going to be getting a better grip on the -- just basis realizations down in that market now.

So that's obviously been a little bit of a dynamic situation when you take off 1.5 Bcf a day of supply coming into the area. I know Williams has announced a project to deliver, I think, up to 0.5 Bcf a day into that area. So we're framing that up, and I think that's going to ultimately dictate the amount that we're willing to lay off.

I think as far as the impact to EQT, if you look at Slide 20 where we show our FT portfolio, you look at the change in our net realization from '20 to '21, you're seeing about almost $0.10 of pricing realization difference in those years. I mean that's largely due to the effect of MVP. So I mean that's sort of the prize that we're looking at if we could be successful in laying off for NVP capacity.

Lastly, on timing, I think this is something that we're working on now. Just given the size of the catalyst for this to our company, it's a priority for us and we're working on this now. And hopefully, we'll have some updates through the end of the year.

That's helpful. Toby, I also wanted to follow up. You guys did hold a special shareholder meeting where you doubled the shares of authorized share cap, pardon me, from 320 million to 640 million. I know it was ratified by, I think, 95% of your shareholders. But we are getting some inquiries on the need to do a special vote here. Thoughts on M&A and just broadly could discuss that move, which I think was earlier last week.

Sure. So EQT hasn't authorized any shares since, I think it was 2005. So this just sort of allowed -- just gives us more flexibility. We don't have any uses for these shares right now, but the landscape up here in Appalachia, there are -- it is a buyer's market. There are some opportunities on the horizon but nothing specifically targeted for use of that equity.

Great. And could you just discuss your broader thoughts around M&A in Appalachia? I think there's, what, 20 management teams, you mentioned mid-30s rigs. It does feel like a market that is ripe for further consolidation. I was wondering if you could maybe highlight your views.

Yes. I think that consolidation will be a part of the value creation story for our shareholders in Appalachia and I think across the industry, the E&P industry as a whole. That being said, what has EQT done to position ourselves to consolidate it? It largely starts with having a great operating model that allows us to scale efficiently. I think the operational results we put out sort of represent the fact that our operating model is sort of in a really good place right now.

And so I think that there are opportunities here. But just as a reminder, the status quo story for EQT is pretty compelling, and we'll continue to be disciplined in our approach with any M&A opportunity that presents itself.

Your next question comes from Josh Silverstein with Wolfe Research.

Just following up on the ACP discussion. Can you talk about how a deal may be structured? Is there any cash that can come from a potential monetization of the stake? Or would it most likely be related to margin improvement? And how would liabilities transfer from those as well?

Yes. This is Dave Khani. So yes, we're in the middle of discussions with a bunch of parties. So I think we'll be very -- we'll just be very quiet on the details. I'd just say our goal would be to really sell it so that there's no -- at least no out-of-pocket costs for us. And if we can structure where we actually can make money, we'll see if we can do that. But right now, there's lots of discussions going on and -- which we'll be very quiet on while we're in the middle of negotiations.

Got it. And then just a quick follow-up to that. ACP was slated to be in service about a year later than MVP. Is this -- would the shippers actually want this for 2021 or would they more likely want it for 2022?

Yes, I think there's -- different parties want it for different time periods. And -- but recognize the need for gas is growing down in that Southeast region over multi years. One entity is building -- there's a bunch of gas-fired generation being built down there. And so -- as well as some of the LDC needs as well. And so their needs are for many, many years. So I think that's probably the biggest important thing.

Got it. And then Toby, just on the 2021 outlook, thanks for the flat year-over-year volumes there, the comments there. Can this be done on a similar 90 to 100 wells? Or do you need to step up activity or kind of actually be a little bit lower?

Yes. So activity levels in 2020, around 1.1 million horizontal feet. To hold production flat, we're probably going to be maybe 5% to 8% lower footage in '21. So -- but it's going to be around 1 million horizontal feet.

Your next question comes from Welles Fitzpatrick with SunTrust.

So on Page 14, it looks like you guys are dropping from 3 to 4 horizontal rigs to 2 to 3. Is that -- are you guys seeing that, that's presumably via drilling efficiencies and you're drilling longer laterals so you're getting more done per day per rig? Is that a fair way to frame that?

Yes. I mean you look at what our horizontal efficiencies have done. I mean we're talking about dropping our drilling times by 30%, so dropping 1 horizontal rig is approximately 30%. So you're seeing just parity with our operational efficiencies, timing up with the resources that we need to execute our program and a similar story with the completion crews as well.

Okay. And then the -- also the drop to -- was it $680 on a per foot basis? I don't know. We're -- we seem like we're a long way from OFS prices going up. But do you have any breakout on that as to how much of that is pricing improvement and how much of that might be efficiency?

Yes. I'd say just looking from this quarter to the past quarter, the service pricing environment hasn't changed. So I mean what you're seeing now is purely sustainable operational efficiencies in the field. I think for us, a couple of things that -- as we shift from setting the bar, now it's locking and making sure that we can operate at this level in the future. Operational efficiencies will continue to climb. What you're seeing is the average we put out. Obviously, we're exiting at higher efficiencies than what the average we report during the quarter.

Our schedule is getting better. We're getting more and more combo development over time and also, our lateral lengths are improving as well. So these are the really 3 core parts of sustainability in your cost performance. And all of these things are -- give us confidence that we'll be able to perform at these levels in the future.

And as you mentioned, service cost pricing, yes, I think you look at the utilization rates that people have in the industry dropping 70% of rig activity and completion crews, certainly leaves a very low utilization rate, and that's obviously going to be a force keeping service pricing low where they're at.

But some of the other things we're doing on the service pricing side is, when you think about operating efficiently, using less rigs to drill the same number of footage -- same amount of footage, that is certainly helpful in being able to lock in these rigs and frac crews with longer-term price contracts is another way to lock in the sustainability and -- or sorry, the pricing for sustainability. And we've done that with 2 out of our -- 2 of our frac crews right now. So we feel pretty good about setting the table for sustainable cost performance.

Okay. That makes sense. I mean 2 really strong updates, fewer rigs, cheaper per foot. And I guess that would bring us to you all keeping the CapEx guide flat. Should we see these flowing through more in '21? Or should we maybe be a little bit biased below that current guide?

Yes, 2 things. One, the ability to drill more and this year is really setting the table for '21. So we are getting ahead of some activity here in the back half of this year that will set up '21 favorably. The other thing I would say is that we have not revised our well cost estimates in our model, and so that hasn't floated to guidance. So that's something that we're working on now and we'll update that with our '21 guidance that we put out.

Your next question comes from Brian Singer with Goldman Sachs.

Wanted to actually follow up on just the point that you were making with regards to the CapEx and how that -- how the lower cost flows into CapEx. It seemed like what you're saying is you're going to get a few more wells that are going to be drilled this year for the same capital budget. And I wondered if you could clarify what the implications are from an exit rate perspective or for 2021 maintenance capital to keep production flat at your exit rate for this year.

Yes. Brian, yes, this is Dave. It effectively means we're setting ourselves up for a little bit better CapEx number for next year. And I think we want to keep the equipment running the way it is. It's running really well and so we are getting ourselves in a better shape. Our goal would not be to increase production. Our goal would be to just take this and effectively improve our 2021 CapEx guidance when we put it out.

Got it. And then my follow-up -- go ahead, sorry.

No, I said, does that help?

Yes, it does. And then my follow-up is a little bit more on color on the decision to bring your shut-in production back online and why -- to do that now at what seems to be similar prices as what was experienced in the second quarter? Or was it that you expected that the second quarter could be potentially even worse than it was?

Yes. So Brian, we -- the goal for us was to really take the extra production and really move it out into future periods. I think if you remember, we were running nicely ahead in the first quarter. And so our goal was really to just to take the excess production, keep our production relatively flat with 2019 and get the benefit of, in future periods, of shutting in production.

So we are very, very hedged. And so even bringing it back, we're very well hedged and not impacted from bringing it back. Having said that though, you're right, the economics still like shutting in production could be worthwhile, and that's something we'll look at and see if we decide we want to shut in more production that -- in sort of, call it, the late either summer or in the fall.

Your next question comes from Scott Hanold with RBC Capital Markets.

So it looks like you guys had some pretty strong production performance this quarter, especially when taking a look at the number of wells put online. Could you give a little bit of color on that? I know -- I think, David, you had mentioned that having some production curtailed, reduced the line pressure. Was that the majority of it or is there stuff organically helping on -- or improving on new wells coming online?

No. I mean I would say, it's nice when your wells meet your type curve. And so I mean that's happening, but that's no surprise to us. Yes, I mean, part of it was having lower line pressures, increasing the productivity of wells that are still flowing. And then again, the 98% production uptime is something that was increased to what our plans were. But I think now that we're seeing consistent performance at that level from -- our field teams have been doing a really great job, I think we'd probably move our expectations a little bit higher.

Got it, okay. And then just as a follow-up to maybe Ryan's line of questioning on curtailments, can you just give us a sense -- you talked about value over volume and with respect to where prices are. I mean are -- how willing are you guys to let production decline? I mean what's it going to take to say, "Look, it's not even -- it doesn't make sense right now to even keep production flat"?

Yes. Well, I think you're seeing that across the industry right now. Just look at the rig counts that are drilling for gas right now in the 2 premier gas basins. I mean they're down significantly. So while we're fortunate enough to have large-scale combo development executed in really core geology, that gives us confidence that our returns are there to continue to develop the whole production flat.

That's not the case for a lot of operators across the country, and that's -- and production is going to decline. And we think the setup is going to start showing up from these reduced activity levels sort of towards the back half of this year. And so that -- I mean you're absolutely right, and I think the industry as a whole is responding to that.

Okay. So if I can interpret that and correct me if I'm wrong, I mean, effectively, you guys just want to sort of maintain this production base in hopes for -- 2021 looks pretty strong versus doing anything today that may impact future years. Is that a fair context?

Yes, that's correct.

But again, we might shut in again. We'll leave that option open for us if we want to do some more and then we'll update you if we do.

Your next question comes from Nitin Kumar with Wells Fargo.

Maybe start off on the D&C cost side, $680 per foot. That's well ahead of the target that you had established a year ago. I guess how sustainable are these costs here? I mean I guess what I'm trying to get at is, are these systematic improvements? And if so, how much more room to go? Or because as you mentioned earlier, there is underutilized capacity out there, are you getting some discounts as well that are baked in there?

Yes. I mean I think largely, the cost improvements we've seen have been sustainable, operational efficiency schedule, longer laterals, more combo development and a consistent well design that we have put in place. So we feel pretty good about it.

I mean one thing that's also worth highlighting in the first and second quarter of this year is we broke out some new electric frac fleets. One of these fleets was new and it took us a few months of just breaking them in. So I mean the efficiencies that we saw in the field on that crew were -- I mean that crew was our worst performer when we started back in January. Now that crew is our best performer. That's a testament to the quality engineers we have here. And our completions team have been able to take advantage of this new technology and develop it to meeting the efficiency.

So I mean this is one of those things we're looking at when we talk about the averages of what we report, and we're obviously exiting at higher rates. That's sort of the dynamic that's at play on the completions front, which is the biggest part of our spend. Over 60% of our spend is on completion.

So feel pretty good about where that's at. And that's also the area of our business where we have the most control over service cost inflation because we've got the most amount of procurement set up in place for that segment of our business.

Great. And then maybe a different tack on some of the earlier questioning around M&A. Asset sales were a part of one of the levers you had indicated earlier as a means of deleveraging. You made the comment, it's a buyer's market. So is the urgency or the need for asset sales reduced now? Or is that still something that you're working on?

Yes. I mean we have a very big operating footprint. We have -- what we consider strategic assets are wells and leasehold that's within our core operating footprint where we're going to develop core combo development in core geology. We've got other assets that don't fall in within that core operating footprint that we would call those nonstrategic.

And I think that a rise in commodity price when that thesis plays out is going to sort of close that bid/ask spread between buyers and EQT as a seller for those type of assets. So we keep those processes open.

Your next question comes from Holly Stewart with Scotia Howard Weil.

Maybe just a quick follow-up on the well cost. I know we're starting to beat the dead horse here. But Toby, it sounded like you're going to save sort of that new low-cost target for 2021. Is that fair?

That's correct.

Okay. And then maybe taking that a step further just for 3Q and thinking about CapEx for 3Q and 4Q, can we just sort of talk about the cadence there?

This is Dave. I would say, think about the second half very similar to the first half on average, so third quarter and fourth quarter, probably not much meaningfully different. So just think about the average of the first half and the second half, which was, I think, around $280 million per quarter.

Okay, okay. Great. And then, Dave, maybe one final one. You mentioned you may monetize E-Train in 2021. Is that just suggesting that you might push it from this year to next year?

Yes. We have a value in our head of what we want to sell it for. We think it's very much undervalued and it's improved clearly off the bottom. And so because we have our tax refund coming in to pay -- help us pay off -- and free cash flow pay off the 2021 notes, which are due in November, it kind of leaves the E-Train stake really for our '22 retirement.

And so as you know, E-Train has about a 6% yield. Our 2022 notes pay about a 3% interest rate. And so for us to want to monetize E-Train, we want to make sure we get it at the right value and so we're not going to have to force it in. And so if we get it to our value, we'll sell it. As we said before, we're not long-term holders. We just don't necessarily need to be in arbitrary year-end number -- time period to have to actually sell it. So again, if it gets to our target, we'll sell it. If it doesn't, we can be a little more patient.

Your next question comes from Jeffrey Campbell with Tuohy Brothers.

Congratulations on the strong results. There's a lot of M&A talk in the air, but a corporate acquisition seems contrary to EQT's commitment to reduce debt. I was just wondering, are there any acreage packages that are potentially coming to the market? And would this be a more likely route for EQT if and when you chose to make a transaction?

Yes. I would say, I mean, when we look at any type of consolidation opportunities, I think the things that we're going to be looking for are acquisition that would be deleveraging to our business and also allow us to grow our free cash flow per share. So I mean, that's -- those are sort of 2 boxes that we're looking to check.

Yes, there are assets out there on the market that would allow us to check those boxes. Like I said, it's -- you got to get through the value discussion with any willing seller. And to that end, we'll be disciplined in making sure that we can deliver on those 2 metrics for our shareholders.

Okay. That's fair. And just to kind of ask it a little bit higher level, MVP notwithstanding, after the ACP cancellation, what's your view on the future pipeline development out of Appalachia going forward?

On one hand, it sounds like there's going to be some demand for those MVP volumes after the ACP cancellation, but the cancellation itself is kind of a grim reminder there's been talk to get these things permitted and built. So just interested in your thoughts there.

Yes. I mean I think people are making the argument that MVP is the last major pipeline that comes out of the basin, I think it was pretty credible. And I think what you will see, and I think one of the things why we believe that E-Train is undervalued is that there is going to be a tremendous amount of sort of downstream pipeline opportunities that E-Train will have now because they've got that pipe coming out of Appalachia filled with sustainably produced natural gas coming from EQT.

Yes, it is disheartening to see just the pressure that pipelines have to get put in service. It is the most -- it is the safest, most environmentally friendly way of transporting energy that people need. And I think the other issue that came out, pulling the apple, was surprising. And it's -- even for pipelines that are in service, to have that risk is concerning for us. So I think for us at EQT, it's -- and other operators and other members of industry, it's really important for us to continue to be vocal about the great service that we provide and how important energy is to the fuel mix.

I think all the conversation about ESG is great because it now allows us to start telling our stories. And the industry has done really amazing things. We just haven't really talked about them. So I think over this next year, you're going to see EQT talking about a lot of great things that we're doing as well as other players in the energy [business].

Yes, I agree with that last point, and we'll look forward to hearing more about that.

Your next question comes from David Deckelbaum with Cowen.

Just wanted to just circle up on a couple of other things. Just on the curtailments, this was a significant curtailment in the second quarter in response to the price. You talked about how obviously, today, the headline price doesn't necessarily justify bringing those volumes back and there's obviously a trade-off.

If we were in a scenario in the future where you were more underlevered, would we expect to see a longer period of curtailment? And I guess, as you think about the seasonality and maximizing your business around cash flow, is this something that we should expect going forward, where you would just see lower periods of shut-in production or higher shut-ins during shoulder seasons?

Yes. So this is Dave. One, we really wanted to carve out the extra production as -- and really push that into the future period. And so that was really the impetus, and there was an arb we'll pull, anywhere from $0.50 to $1.30 when we did it. And so again, the arb right now is probably about $1 or so, so we could do more of this if we want to. We have constraints of MVCs we need to think through as part of this. And we all see -- we have new goals to pay down a certain amount of debt so we just want to think through that as well.

But yes, as far as is this something we'll want to do in the future? Probably. We'll continue to do this when it makes economic sense to do it. And remember, we're very hedged. We're over 90% hedged in this time period. So at times, we'll have to -- if we want to do more of this stuff, we might have to unwind hedges, grab some value to shut in. And then we want to maybe add hedges into the future period. So there's some things we need to do to maneuver around to really take advantage of that arb.

Yes. I mean I would just summarize and say, we're going to see the pricing volatility every year in the shoulder seasons. So these opportunities are going to present themselves. And I think as we deleverage our business, that gives us more flexibility to be strategic and executing these shut-ins and incorporating the ability to do this into our base operating model that we're working on.

I appreciate that. How do you -- and looking back, how do you view your shut-ins relative to the rest of the industry or your peers in Appalachia? And were you surprised at the rest of everyone else's activity?

Well, I think you're seeing other peers. I mean our shut-in -- while 1.4 Bcf a day of gross gas is pretty large, it represents around 25% of our production base. I think look at some of our other peers, I mean, the shut-ins, they're talking about -- are around 25% as well.

So I think that a lot of other operators are seeing the same thing we're seeing and making a statement that this product is undervalued at these prices and there is conviction that prices will be higher in the future. And so you're seeing operators shut-in and what I think is pretty meaningful.

Appreciate that. And then just the last one for me. There's been a lot of conjecture around M&A. I guess so you talked about screening for things that offer deleveraging capabilities and clearly, cash flow benefits. When you look at your data set internally, are there a lot of assets that are out there that you feel you could offer a significant operational uplift on? Or do you see it more as benefits of scale in that financial arbitrage?

I think it's across all fronts. I mean this organization could take up -- could carry more operations without having to add any headcount, so I mean, G&A savings right out the gate. There are some acreage overlaps that would be -- that would allow us to drill -- increase the confidence in drilling longer laterals in greater combos, and then also being able to execute development at $680 a foot versus higher cost is certainly a benefit.

And I think the last thing you look at is, which is unique to EQT, is we've set the table up with our gathering agreements to lower our gathering rates if we can steer more volumes onto our E-Train system. So that's another dynamic at play that we'll look forward to leveraging if that opportunity comes into play.

Your next question comes from Michael Hall with Heikkinen Energy.

I appreciate the time. I guess I wanted to follow up quickly on the ACP and MVP dynamic. Correct me if I'm wrong, I believe the tariff on the MVP side is around $0.77. Is your expectation that in offloading those contracts, you would offload that full tariff? Or do you think you'd have to offer some sort of discount?

No, it would be our goal to offload it at cost.

Okay, clear enough. Appreciate that. And I guess -- go ahead, sorry.

I was just going to say, customers on the ACP line, they were signing up for over $1.50 of fees. And so I mean, these costs would have been passed through to their customers. I mean these are utilities. So to be able to have the opportunity to pass-through $0.77 versus $1.50 is ultimately better for the consumers as well. So I mean that's one of the things that's underpinning why we believe we can get this done at cost.

Okay. Yes. No, that makes sense. Appreciate it. And then I guess on the macro front, you all seem quite confident in the 2021 outlook that you have. I guess I'm just curious, in the context of the LNG market, in particular, we've obviously seen a lot of cargo cancellations here recently. What sort of confidence do you have on the LNG market in 2021? What sort of broader economic recovery is underlying that confidence? And I guess, what sort of -- just any color you can provide on that would be helpful.

Sure. I mean we're not -- I think it's important. We're not surprised to see LNG levels in this 3.5 to 4 Bcf a day of demand right now. This is something that is -- that we've taken into account with our pricing model. That being said, we do feel like LNG will be restored to that 7, 8 Bcf a day range sort of towards the end of this year. Again, that is -- it is dependent on COVID. But our pricing view does not need to have LNG at 10 Bcf a day running at full capacity. It's something that's more conservative and allows for this lower period of demand disruption on LNG for the next few months as well.

Yes. And there's a few things, if you watch -- right now, you're watching global gas supply getting pull back in various different regions besides the U.S. You're watching demand picking back up again. And then really a third, which is a key piece too, is that weather in the Northern Hemisphere was very warm last year. So you want to base everything on normal weather and between supply, recovery from COVID and weather gives us confidence that gas exports out of the U.S. will pick back up. And we're not -- our model isn't set at 9.5 or 10 Bs. Our model is really sitting, as Toby mentioned, 7 to 8-ish.

Your last question comes from Kashy Harrison with Simmons Energy.

And so there's been a lot of discussion on the ACP cancellation, on that takeaway being -- on the remaining takeaway on MVP being valuable. And right now, correct me if I'm wrong, but it feels like takeaway out of Appalachia in general is probably in the -- maybe in the high 30s, 37-ish versus current production of 33. And so how do you balance the near-term benefits of offloading all that FT relative to the longer-term risk of widening in-basin basis in the future should commodity prices increase in the future and producers start growing again? How do you think about that, the risk of in-basin basis [blobs]?

Yes. That's a great question. I mean I think it highlights to one of the points that we make about our FT is it is a hedge. Our FT is a hedge against local bases blowing out. But the dynamics that are set up right now is Appalachia is producing around 32 Bcf a day. We've got about, call it, 35 Bcf a day of local -- of takeaway and local demand. So there's a 3 Bcf a day gap between what we're producing and what we're able to take away. Out in MVP, that takes you up to, call it, 37 Bcf a day.

So you've got a pretty big gap between capacity and supply in the basin. I think you couple that with the fact that the basin is going to struggle to grow. I mean you've got all operators saying that they're hanging in maintenance mode. We're also seeing activity levels today, which suggests that this basin is going to decline. All of that is going to widen the gap of takeaway.

And then I think the last point you look at is just sustaining 32 Bcf a day. Just looking at the amount of core inventory that's remaining to sustain that, I think, is also going to be a headwind for a lot of peers. And again, this comes back to EQT having a deep inventory of core combo-ready projects to develop, won't be much of our issue, but I think another thing that's going to be a headwind for the basin to keep up.

There are no further questions queued at this time. I'll turn the call back over to Toby Rice, President and CEO, for closing remarks.

Thank you. A lot of progress made in the past year, and I think this sort of puts a pin in us looking backwards and comparing to campaign promises. And now I think everything going forward, I'm excited about looking forward to the future and continue to build on our momentum, and thank you for your time and your support.

This concludes today's conference call. You may now disconnect.