Ladies and gentlemen, thank you for standing by. And welcome to the EQT Q2 2020 Quarter Results Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. Please be advised that today’s conference is being recorded. 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 seven-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 one-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 assets. 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, and 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, and 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 firm transportation portfolio, which looks even more promising with the cancellation of ACP. All of these actions proved 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 really 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 one out of every 8 households in America, and one 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 one 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 and 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 thousand feet drilled has decreased by 36%. What this means for EQT is we were able to achieve our target drilling costs with higher confidence and 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 Pennsylvania 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 and 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 in 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 with all our previously announced volume curtailment shut in. Earlier this month, we began a moderated approach to bringing these volumes back online and have seen no degradation to well performance. As of today, all curtailed production has returned 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're fortunate to be protected from the short term pricing pressures through our robust hedge portfolio in 2020. Looking forward, we believe the market will be much more supportive as a rapid decline in oil-directed activity and uncertainty around future oil pricing reduces a material amount of associated gas from the market. Additionally, with Appalachian rig count 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. As a result, we believe that 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've 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 $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 decline 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 convertible debt is having the flexibility to deem debt as 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 continue to target leverage of below 2 times and plan 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 a 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. Firstly, we achieved sales volumes of 346 Bcfe for the quarter with our production curtailments remaining intact 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 curtailments. Adjusted operating revenues were $816 million, down 15% compared to the second quarter 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 three-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 or 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 a path to rationalize our firm transportation portfolio. During the second quarter, we were able to execute several small firm transportation trades and we'll 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 a long-term cost reduction improvement, which will drive significant NAV and free cash flow enhancement. We believe that 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 Atlantic Coast 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 and completion. These actions increase the value of the current MVP capacity while also creating incremental value upside through 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 competence 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 continues 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 that 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 hedged. And we’ll 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 heading 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 overall 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 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.

Your first question comes from Arun Jayaram from JPMorgan Chase. Your line is open.

Good morning, Toby. 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 for offload, the bulk of your transportation at par or even your premium, and perhaps discuss some potential timelines on this.

Sure. So, with ACP being cancelled, that was about 1.5 Bcf a day of capacity that was going down at 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 the likelihood of being able to lay off capacity, it could be up to all of our capacity. I think one other thing 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 basis realizations down in that market now. So, that's obviously been 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 firm transportation portfolio, you look at the change in our net realization from '20 to '21, you're seeing about almost a dime of pricing realization difference in those years. I mean, that's largely due to the effect of MVP. So, that's sort of the price that we're looking at, if we can be successful in laying off our MVP capacity. Lastly, on timing, I think, it’s 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 authorized share count 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 you 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, 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 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 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. 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. Your line is open.

Thanks. Good morning, guys. Just following up on the ACP discussion, could 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 this as well?

Yes. Hi, this is Dave Khani. So, we're in the middle of discussions with a bunch of parties. So, I think we'll be very quiet on kind of the details. I'd just say, our goal would be to really sell it so that there's 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 a lot of discussion going on, and we should be very quiet 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. Would the shippers actually want this for 2021 or would they more likely want it for 2022?

Yes. I think there's different parties that want it for different time periods. Recognize that the need for gas is growing down in that southeast region over multiple years. One entity is building — there's a bunch of gas fired generation being built down there as well as some of the LDC needs. So, their needs are for many, many years. So I think that's probably the most important thing.

Got it. Thanks. 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 actually be a little bit lower?

Yes. So activity level in 2020 is around 1.1 million horizontal feet. To keep production flat, we're probably going to be maybe 5% to 8% lower footage in 2021. So it will be around 1 million horizontal feet.

Your next question comes from Welles Fitzpatrick with SunTrust. Your line is open.

Hey, good morning.

Good morning.

So, on page 14, it looks like you guys are dropping from three to four horizontal rigs to two to three. Is that — are you guys seeing that that's presumably via drilling efficiencies and you're drilling longer lateral, 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. We're talking about dropping our drilling times by 30%. So, dropping one horizontal rig is approximately 30%. So, you're seeing parity with our operational efficiencies timing up with the resources that we need to execute our program. And then, similar story with the completion crews as well.

Okay. And then, also the drop to — was it $680 on a per foot basis? I know 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 looking from this quarter to the past quarter, the service pricing environment hasn't changed. So what you're seeing now is purely sustainable operational efficiencies in the field. A couple of things as we shift from setting the bar is now 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 the average we report during the quarter. Our schedule is getting better. We're getting more and more combo development over time. Also, our lateral lengths are improving as well. So these are the three core parts of sustainability in your cost performance. And all of these things give us confidence that we'll be able to perform at these levels in the future. And as you mentioned, service cost pricing — you look at the utilization rates in the industry dropping significantly for rig activity and completion crews, that leaves a very low utilization rate and is a force keeping service pricing low. Another thing we're doing on the service pricing side is when you think about operating efficiently, using fewer rigs to drill the same amount of footage helps lock in rigs and frac crews with longer term price contracts. We've done that with two 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, two 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 2021 or should we maybe be a little biased below that current guide?

Yes. Two things. One, the ability to drill more this year is really setting the table for 2021. So, we are getting ahead of some activity here in the back half of this year that will set up 2021 favorably. The other thing is that we have not yet revised our well cost estimates in our model. So that hasn't flowed into guidance yet. That's something that we're working on now, and we'll update that with our 2021 guidance when we put it out.

Okay. That's perfect. Thank you so much.

Got it.

Your next question comes from Brian Singer with Goldman Sachs. Your line is open.

I wanted to actually follow up on the point that you were making with regards to the CapEx, and how that — how the lower cost flows into CapEx. It seems 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.

Brian, yes. This effectively means we're setting ourselves up for a little bit better CapEx number for next year. We want to keep the equipment running the way it is. It's running really well. 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. Does that help?

Got it. Thanks. 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, the goal for us was to really take the extra production and move it out into future periods. I think if you remember, we were running nicely ahead in the first quarter. So our goal was really to just take the excess production, keep our production relatively flat with 2019, and get the benefit in future periods of conserving production. We are very, very hedged. So even bringing it back, we're very well hedged and not impacted from bringing it back. Having said that, you're right, the economics still look 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. We could do that in late summer or in the fall.

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

Thanks. 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 David mentioned that having some production curtailed reduced the line pressure. Was that the majority of it, or is there stuff organically helping on improving new wells coming on line?

No, I'd say it's nice when your wells meet your type curve. That's happening, but that's no surprise to us. Part of it was having lower line pressures, increased productivity of wells that are still flowing. And then again, the 98% production uptime is something that was increased relative to our plans. Our field teams have been doing a really great job. I think we'd probably move our expectations a little bit higher.

And then just as a follow-up to maybe Brian'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, how willing are you guys to let production decline? What is it going to take to say look, it doesn't make sense right now to even keep production flat?

You're seeing that across the industry right now. Just look at the rig counts drilling for gas in the premier basins — they are down significantly. While we're fortunate to have large scale combo development executed in really core geology, that gives us confidence that our returns are there to continue to develop while keeping production flat. That's not the case for a lot of operators across the country, and production is going to decline for many. We think the set up is going to start showing up from reduced activity levels toward the back half of this year. You are absolutely right; the industry as a whole is responding to that.

Okay. So if I can interpret that — correct me if I'm wrong — effectively you guys want to maintain this production base in hopes 2021 looks stronger versus doing anything today that may impact future years. Is that fair?

Yes. That's correct.

But again, we might shut in again. We'll leave that option open and we'll update you if we do.

Your next question comes from Nitin Kumar with Wells Fargo. Your line is open.

Hi. Good morning and thanks for taking my questions. Maybe to start off on the D&C cost side, $680 per foot is well ahead of the target you had established a year ago. How sustainable are these costs? Are these systematic improvements? How much more room to go, or because, as you mentioned earlier, it's an underutilized capacity out there, are you getting some discounts that are baked in there?

Yes. Largely the cost improvements we've seen have been sustainable operational efficiencies: schedule, longer laterals, more combo development and a consistent well design that we have put in place. We feel pretty good about it. One thing worth highlighting: in the first and second quarter of this year, as we brought out some new electric frac fleets, one of these fleets was new and took us a few months of breaking them in. The efficiencies that we saw in the field on that crew improved materially — that crew was our worst performer when we started in January and now that crew is one of our best performers. That's a testament to our engineers and completions team who have been able to take advantage of new technology and develop it to meet the efficiency. Completion is the biggest part of our spend — over 60% — so it's the area where we have the most control over service cost inflation because we've set up procurement for that segment of our business. We're exiting at higher efficiencies than the averages we report, and that dynamic supports sustainability of these costs.

Great. And then on M&A — asset sales were part of the levers you indicated earlier as means of deleveraging. You made the comment it's a buyer's market. Is the urgency or the need for asset sales reduced now or is that still something you're working on?

We have a very big operating footprint. We consider our wells and leasehold within our core operating footprint as strategic, and we'll develop core combo development in core geology. We have other assets that don't fall within that core operating footprint that we would call non-strategic. A rise in commodity price, when that thesis plays out, will likely close the bid/ask spread between buyers and EQT as a seller for those types of assets. So we keep those processes open.

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

Good morning. Maybe just a quick follow-up on the well cost. Toby, it sounded like you are going to save that new well 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?

Hi. Think about the second half very similar to the first half on average. So third quarter and fourth quarter probably not meaningfully different. Just think about the average of the first half and the second half, which was around $280 million per quarter.

Okay, great. And then, Dave, maybe one final one. You mentioned you may monetize Equitrans 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. Because we have our tax refund coming in to help pay off and free cash flow to pay off the 2021 notes due in November, it kind of leaves the Equitrans stake really for 2022 retirement. Equitrans has about a 6% yield; our 2022 notes pay about a 3% interest rate. For us to want to monetize Equitrans, we want to make sure we get it at the right value. We're not going to force it into an arbitrary year-end time period to sell. If it gets to our target, we'll sell it; if it doesn't, we can be patient.

Your next question comes from Jeffrey Campbell with Tuohy Brothers. Your line is open.

Good morning and 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 commitments 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?

When we look at any consolidation opportunities, the things we're looking for are acquisitions that would be deleveraging to our business and also allow us to grow our free cash flow per share. Those are the two boxes we want to check. There are assets out there that would allow us to check those boxes. You have to get through the value discussion with any willing seller. We'll be disciplined in making sure that we can deliver on those two metrics for our shareholders.

And just at a higher level, MVP notwithstanding, after the ACP cancellation, what's your view on future pipeline development out of Appalachia going forward? On one hand, it sounds like there is going to be some demand for MVP volumes after the ACP cancellation. But, the cancellation itself is a reminder there's been talk to get these permitted and built. So, just interested in your thoughts there.

I think the argument that MVP is one of the last major pipelines that comes out of the basin is credible. You will see a tremendous amount of downstream pipeline opportunities that Equitrans will have now, because they've got that pipe coming out of Appalachia filled with sustainably produced natural gas coming from EQT. It is disheartening to see the pressures pipelines face to get put in service. Pipelines are the safest, most environmentally friendly way of transporting the energy people need. The cancellation of ACP is surprising, and it underscores the risks pipelines face. For us at EQT and other operators, it's important to continue to be vocal about the service we provide and how important energy is to the fuel mix. The conversation about ESG allows us to start telling our stories. The industry has done amazing things that we haven't talked about enough. Over the next year, you'll see EQT talking more about what we're doing and other players in the energy mix doing the same.

Your next question comes from David Deckelbaum with Cowen. Your line is open.

I wanted to circle up on a couple of things. On the curtailments, this was a significant curtailment in the second quarter in response to price. You talked about how the headline price doesn't necessarily justify bringing those volumes back, and there is 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 as you think about seasonality and maximizing your business around cash flow, is this something we should expect going forward where you would see lower periods of production or higher shut-ins during shoulder seasons?

One, we really wanted to carve out the extra production and push that into future periods. There was an arbitrage anywhere from about $0.50 to $1.30 when we did it, and around $1 now. So we could do more of this if we want to, but we have constraints like minimum volume commitments to think through. We also have goals to pay down a fair amount of debt, so we want to think through that as well. But yes, this is something we'll continue to do when it makes economic sense. Remember we're very hedged — over 90% in the near term — so if we want to shut in more, we might have to unwind hedges to capture some value to shut in and then add hedges in future periods. There are maneuvers we can do to take advantage of that arbitrage.

To summarize, we'll see pricing volatility every year in the shoulder seasons. These opportunities will present themselves. As we deleverage our business, that gives us more flexibility to be strategic in executing these shut-ins and incorporating the ability to do this into our operating model.

How do you view your shut-ins relative to the rest of the industry or your peers in Appalachia? Were you surprised at other activity?

Our shut-in was pretty large at about 1.4 Bcf a day gross gas, representing around 25% of our production base. Some of our peers had similar percentages; others were different. Many operators are seeing the same thing and making a statement that this product is undervalued at current prices and that prices will be higher in the future. You're seeing operator shut-ins and that is meaningful.

I appreciate that. And then one last one: when you look at potential M&A, are there a lot of assets out there that you feel you could offer a significant operational uplift on, or is it more benefits of scale on financial arbitrage?

I think it's across all fronts. This organization could take up more operations without having to add much headcount, so there are G&A savings out the gate. There are acreage overlaps that would allow us to drill longer laterals in greater combos and execute development at $680 per foot versus higher costs — that's a real benefit. Another dynamic unique to EQT is that we've set the table with our gathering agreements to lower our gathering rates if we can steer more volumes onto our Equitrans system. That's another lever we'll look to leverage if the opportunity comes.

Your next question comes from Michael Hall with Heikkinen Energy. Your line is open.

Thanks. Good morning. I appreciate the time. I wanted to follow up quickly on the ACP and MVP dynamic. Correct me if I'm wrong, but I believe the tariff on MVP is around $0.77. Is your expectation that in offloading those contracts, you would offload the 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. I appreciate that. And on the macro front, you seem quite confident in the 2021 outlook. In the context of the LNG market, we've seen cargo cancellations recently. What sort of confidence do you have in the LNG market in 2021? What broader economic recovery underlies that confidence, and any color would be helpful.

We are not surprised to see LNG levels in the 3.5 to 4 Bcf a day range right now. This is something we've taken into account in our pricing model. That said, we feel LNG will be restored to the 7 to 8 Bcf a day range toward the end of the year, depending on COVID. Our pricing view does not need LNG at full capacity of 10 Bcf a day; our outlook is more conservative and allows for this lower period of demand disruption over the next few months as well.

If you watch global gas supply it pulled back in various regions besides the U.S., demand is picking back up, and weather last year in the Northern Hemisphere was warm. Basing on normal weather, between supply recovery and demand recovery from COVID, gives us confidence that gas exports out of the U.S. will pick back up. Our model sits in that 7 to 8 Bcf range that Toby mentioned.

Your last question comes from Kashy Harrison with Simmons Energy. Your line is open.

Good morning. Thanks for taking my questions. It feels like takeaway out of Appalachia is probably in the high 30s Bcf per day versus current production of 33 Bcf per day. How do you balance the near-term benefits of offloading all that firm transportation relative to the longer term risk of widening in-basin basis in the future should commodity prices increase and producers start growing again? How do you think about the risk of in-basin basis blowouts?

Great question. Our firm transportation is a hedge against local basis blowing out. Current dynamics are Appalachia producing around 32 Bcf a day with takeaway and local demand around 35 Bcf a day, so there's a gap in capacity. Adding MVP takes you to about 37 Bcf a day of takeaway. There's a sizable gap between capacity and supply. Couple that with constrained basin growth — operators are largely in maintenance mode and activity levels suggest the basin will decline — and you widen the gap of takeaway capacity relative to production. Also, sustaining 32 Bcf a day is challenging given remaining core inventory for many producers. EQT has deep inventory of core combo-ready projects to develop, so it's not much of an issue for us, but it will be a headwind for many peers.

There are no further questions queued up at this time. I 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. I think this puts a pin in looking backwards and comparing to campaign promises. Now, everything going forward, I'm excited about looking forward to the future and continuing to build on our momentum. Thank you for your time and your support.

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