EQT Corp (EQT) 2020 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the EQT Q4 Quarterly Results Conference Call. (Operator Instructions) Please be advised that today's conference is being recorded. (Operator Instructions) I would now like to hand the conference over to Mr. Andrew Breese. Thank you. Please go ahead, sir.

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 5188472.

In a moment, Toby and Dave will present their prepared remarks with the question-and-answer session to follow. An updated investor presentation has been posted to the Investor Relation portion of our website, and we will refer to certain slides during today's discussion.

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 the factors described in today's earnings release, in our investor presentation, in the Risk Factors section of our Form 10-K 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 today's earnings release and our most recent investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures.

And with that, I'll turn the call over to Toby.

Thanks, Andrew, and good morning, everyone. Today, I will briefly touch on some of the key items we executed on in 2020 that reshaped the trajectory of this business, why natural gas and EQT, in particular, present a compelling investment thesis, review our operational and financial plans for 2021 and provide a free cash flow forecast of our base plan.

Our team has been pushing hard to bring our vision into reality. While 2020 brought many accomplishments, there were a handful of critical actions that have set us up for long-term sustainable success. First, we entered 2020 staring down $3.5 billion in debt maturities due through '22. We now sit with roughly $600 million, which can easily be managed with expected free cash flow, and we are on a glide path to sub 2x leverage.

Second, we drastically reduced our cost structure. We did this by slashing well costs by over $250 per foot, increasing our production uptime from 85% to 98% and renegotiating our gathering contracts with Equitrans. All told, our unhedged free cash flow breakevens, which is the Henry Hub price needed to generate positive free cash flow under our maintenance production plan, decreased from a legacy cost of over $2.80 in 2019 to $2.40 in 2021 and is expected to decline to approximately $2.15 by 2026. Much progress has been made in a year, and we are looking forward to continuing this trend in the future.

Lastly, we demonstrated the impact that our modern operating model can have to rapidly evolving our business and enhancing operational, financial and cultural performance while securing sustainability with respect to ESG. We continue to believe that there is a symbiotic relationship between these goals, and we've established an ESG committee focused on implementing company-wide initiatives to drive continuous improvement across all facets of our business.

Like many companies across the globe, we have navigated a challenging and unprecedented year. Along the way, we were aligned with our mission to be the operator of choice for all stakeholders. On Slide 3, we highlight key elements of our mission. We strive to be the security that investors want to own, the operator that service providers want to work for, the employer that employees want to work with, the lessee that landowners want to lease to and the industry partner that our local communities embrace.

Our core values of trust, heart, teamwork and evolution guide us along this path and remind us that it's not just about what we do, but how we do it. We hold the fundamental belief that success is driven by our people, and we strive to produce a team that is completely aligned with what we do and how we do it. I'm proud to announce that EQT was recently recognized as a top workplace in the U.S., demonstrating a clear linkage between cultural and operational excellence.

As we sit here today, EQT presents a compelling investment story, which we have highlighted on Slide 6. With 710,000 core net Marcellus acres and well over 15 years of low-risk core Marcellus inventory in hand, EQT's dominant asset position is primed to deliver long-term value to stakeholders. 80% of our inventory is set up for combo development, which provides high confidence and predictability in well performance, avoids parent-child interference and will lead to sustainable free cash flow generation. This will increasingly be a differentiator for EQT relative to its peers.

We have proven that we are disciplined capital allocators, and our 2021 plan demonstrates our commitment to our maintenance program. Under this maintenance mindset, we expect our base business to generate approximately $3.5 billion in cumulative free cash flow through 2026 at strip pricing. This base plan offers material upside opportunities, and our track record of delivering speaks for itself. On top of this, due to our tremendous scale, every NYMEX increase of $0.10 above current strip pricing generates an incremental $170 million of free cash flow.

And importantly, given the structure of our gathering agreements and the continued improvement in our operating efficiency, we expect 2026 free cash flow to be approximately $800 million to $900 million, 55% higher than 2021 despite a 4% lower natural gas price. Our current free cash flow and balance sheet projections highlight the achievements over the last year, significantly accelerating our ability to execute on shareholder-friendly actions while also achieving investment-grade metrics.

Lastly, we believe that access to energy is the most important factor driving human progress. We are proud of the work that we do to make low-carbon energy accessible to all. And we believe that natural gas will play a key role in meeting the growing demand for reliable, low-cost energy, helping reduce CO2 emissions globally and serving as a long-term low-carbon baseload fuel source, which is attracting new long-term investors.

Further supporting the favorable outlook for EQT are the improvements we continue to see in the natural gas macro trends. Both dry gas and associated gas producers have demonstrated strong conviction to maintenance volume production. Record cold temperatures in the Eastern Hemisphere have buoyed global LNG markets, which should drive a more robust 2021 U.S. LNG export market as there is growing sentiment that summer LNG demand will soon surpass expectations.

Coal production and deliverability issues have further increased an already robust gas power generation market. And industrial demand, specifically chemical output, has started its recovery to pre-COVID levels and should continue to climb as the economy improves. We believe that the most efficient, wide-reaching and environmentally responsible way to satisfy the growing global demand for energy is by utilizing natural gas. Natural gas produces significantly less CO2 compared to oil and coal, and the Appalachia Basin, in particular, is one of the lowest emitting shale plays in the United States.

At EQT, our goal is to be a differentiated producer of a differentiated commodity. Our ESG program will differentiate our business, and every aspect of our corporate strategy is underpinned by sustainable ESG goals. This program is more an embodiment of our intrinsic drive than a reactionary response. I'll remind you that in our first year of leadership, we transitioned to exclusively electric frac crews, have utilized hybrid drilling rigs and are now using electric pneumatics on all new sites. Furthermore, our Board recognizes the importance of alignment and has established a greenhouse gas emissions intensity STIP target reduction of 4% in 2021 alone.

Today, EQT has one of the lowest greenhouse gas emission intensity scores relative to our U.S. E&P operators. EQT also has one of the lowest methane emission intensities, but this is just the beginning. We plan to release our 2020 ESG report this summer, at which point we intend to publish net zero emissions and other targets. Until then, we continue to evaluate ways in which we can provide more timely, transparent and meaningful ESG performance disclosures to our stakeholders.

In early 2020, we established a cross-functional ESG committee, which includes both executive management participation and Board oversight. To date, some of the initiatives that the committee is focused on include: developing our proprietary ESG technology to bring transparency of our program to every member of our team; evaluating the most effective use of our resources to improve our emissions performance, which drove our pneumatic valve installation program in 2021; and working towards obtaining responsible gas certifications, leading to our announced partnership with Project Canary in early 2021. This focus is integral in not only making sure we set the right targets, but that we capture and report the most relevant information. We are confident that our vision and actions will make EQT a clear ESG leader.

This is a great segue into our 2021 operational and financial plans. Our strategy remains unchanged: execute maintenance program, enhanced margins, grow free cash flow and delever the business. I will point you to Slide 9 and 10 for an overview of our 2021 program. We plan to spend $1.1 billion to $1.2 billion of capital expenditures to deliver net production volumes of 1,620 to 1,700 Bcfe. At 1/31/'21 pricing, we expect to generate $1.85 billion to $1.95 billion in adjusted EBITDA and $500 million to $600 million in free cash flow.

On Slide 10, we further break out our capital program. We plan to spend between $800 million to $850 million on reserve development. We plan to direct more activity towards our expansive West Virginia assets in '21, resulting in capital allocation of approximately 65% to Pennsylvania, 30% to West Virginia and 5% to Ohio. Further details, including expected well counts and lateral lengths, can be found on Slide 11.

We also plan to spend $125 million to $140 million on land-related projects made up of approximately $85 million on leasehold maintenance, $50 million on infill leasing and mineral purchases. We plan to spend $85 million to $100 million on other CapEx, which is largely comprised of our asset maintenance projects and capitalized interest. Due to the capital program in 2021, we plan to construct a 45-mile mixed-use water system in West Virginia which will serve as the backbone for optimizing West Virginia development and is a key element in reducing well costs in the future. We plan to spend between $45 million to $55 million in 2021, and the system is expected to service its first pad in the third quarter of this year. Further details regarding this water infrastructure project can be found on Slide 12.

When normalizing for the water system, which is new to the 2021 program, year-over-year capital expenditures are essentially flat, while production is expected to be approximately 160 Bcfe or 11% higher due primarily to the Chevron acquisition. Going forward, and assuming maintenance level production, we expect capital efficiencies to trend favorably with total capital expenditures dropping by $50 million to $100 million per year over the next several years. Our expectations for 2021 are high.

And I'll now pass it to Dave Khani to discuss some of the other financial aspects of the business.

Thanks, Toby, and good morning, everyone. Before I jump into the details, I'd like to provide some reflection on 2020. Toby discussed some of the key highlights of our 2020 accomplishments relating to our cost-cutting and balance sheet-enhancing actions, which enabled us to go from playing defense to going on the offensive. But behind the scenes, there were significant time investment to digitize our processes to focus our teams on improving planning, accuracy, forecasting and real-time analysis. Although our head count has come down since 2019, our productivity has materially improved, and we have seamlessly integrated the Chevron assets as a result. The teams have done an outstanding job this past year, and we expect this to continue into 2021.

I'd like to provide details regarding our year-end reserves. At year-end 2020, we reported 19.8 Tcfe in total proved reserves, up 13% year-over-year and up 5% after normalizing for reserves associated with the Chevron acquisition despite a reduction of over $1 per Mcf in our 2020 realized pricing used for our [gas] reserves prescribed by SEC rules. The increase in reserves demonstrate the resilience of our premier asset base, our cost reduction effort and our very efficient combo development strategy.

As further described in the 10-K that we will file later today, our standardized measure of discounted future net cash flows was approximately $3.4 billion, which was calculated using historic SEC pricing of $1.38 per Mcf. We are all aware of the commodity price challenges the industry faced in 2020 which are not reflective of the go-forward price projections. Using the 5-year strip price as of the year-end 2020 of $2.08 per Mcf, this increases our standardized measure discounted future net cash flows by $5.6 billion to $9 billion. Although not a perfect gauge of value since gas prices are undervalued, it is much more reflective of the value of our booked to proved reserves.

I'd like to also note that only 279 PUDs were booked or nearly 17% of our remaining core inventory, and we have an extensive runway of value-accretive inventory. As we execute our combo development strategy, which significantly improves the band of EUR outcomes and well performance, the application these improving EURs will drive reserve enhancements. As a result, we saw a strong improvement in EUR performance for 2020 versus prior years.

I'd like to now discuss our hedge philosophy and positioning as we head into 2021. During the fourth quarter of 2020, we continued executing our hedging strategy to protect against downside commodity risk, opportunistically layering on incremental 2021 hedges. As of today, we have NYMEX hedges on approximately 85% of our expected 2021 gas production in conjunction with hedges on approximately 50% of our in-basin basis exposure. We are students of the commodity and understand the importance of getting the direction and timing as correct as possible. Accordingly, we are big believers in hedging and have added a significant amount of gas hedges this past year.

While we focused a lot of our attention on natural gas, we are able to take advantage of the nearly 15% Cal 2021 run-up in NGL prices that occurred in January, locking in hedges on approximately 55% of our expected 2021 NGL production. Although NGL only represents about 5% of our 2021 production base, we expect to produce approximately 33,000 barrels a day, which is meaningful to revenues and free cash flow.

We see 2022 as a real opportunity. Prices are starting to react to the cold weather, strong LNG demand and improving economic outlook. We currently stick with a 35% hedge position in 2022 for our dry gas production, and we'll be patient and methodical as we build that position throughout the year. In addition to hedging, we are working on to augment our risk mitigation strategy by increasing our direct sales exposure. And we are currently pursuing opportunities with both natural gas and LNG end market purchases.

Now I'd like to discuss the volatile regional pricing experienced in the back half of 2020 and what we are expecting for 2021 and beyond. Slide 19 in our presentation depicts some of the dynamics that contributed to this volatility. As you're aware, local basis blew out during the fourth quarter breaking below $2 at various points in October and November. This sharp decline in basis was driven by a combination of full Northeast storage, unusually high pipeline outages, large shut-ins coming back online and a significantly warmer-than-normal start to winter.

As these factors have normalized, basis has come down significantly. With the absence of Appalachian pipeline outage in 2021, we expect local pricing to improve. As operators, we have to be prepared for this volatility through hedging and other activities, but also be cognizant that these irregularities cause bias -- or basis to be unusually wide and be cautious not to overreact. Although we have a fulsome basis hedge position in place during the fourth quarter of 2020, we did feel some of the pricing weakness with average differentials coming in at a negative $0.66 per Mcf, $0.01 wide of our guidance range and inclusive of our $0.13 per Mcf gain realized on our basis swaps.

Looking ahead, we expect to realize 2021 average price differentials of negative $0.40 to negative $0.60, which is slightly wider than our full year 2020 realized differential of negative $0.42. The wider differentials are primarily driven by an incremental 2021 expected production associated with the acquired Chevron volumes, partially offset by the benefit of our contracted FT capacity coming back online in January.

Looking forward, there are some positive demand drivers on the horizon over the next few years, including accelerated coal retirements, driven by increased regulations such as RGGI and the start-up of the ethylene Shell cracker plant in 2022, among other things. The annualized spread between local demand and takeaway capacity compared to supply is approximately 3 Bcf per day, which is anticipated to grow by another 1 Bcf per day due to in-basin demand. The benefit and timing of the 2 Bcf per day MVP capacity is then incremental, creating an even greater spread, and we remind everyone that the Southeast needs the gas to help decarbonize and grow their local economies.

This takes me to a quick overview of our fourth quarter financial results. Sales volumes were 401 Bcfe, slightly above the high end of our guidance range. This included approximately 12 Bcf related to the assets acquired in the Chevron acquisition, offset by some small sporadic shut-ins executed during the period. Our adjusted operating revenues for the quarter were $922 million, and our total per unit operating costs were $1.30 per Mcfe, a $0.14 improvement from last quarter and below the low end of our annual guidance range. The capital expenditures were $266 million, in line with expectations and guidance. In aggregate, our performance drove adjusted operating cash flow for the quarter of $370 million and positive free cash flow of approximately $109 million.

For the full year 2020, sales volumes were 1,498 Bcfe, roughly flat with a 1,508 Bcfe produced in 2019, despite the impact of approximately 46 Bcfe of strategic volume curtailments during the 2020 period. Adjusted operating revenues were $3.55 billion with total operating cost per unit of $1.36 per Mcfe. Capital expenditures were $1.08 billion, an impressive $694 million reduction compared to 2019. With adjusted operating cash flow coming in at $1.4 billion, we generated positive free cash flow for the year of $325 million.

Turning to the first quarter of 2021 expectations. We expect production volumes to come in at 405 to 425 Bcfe. Based on the January 31, 2021, market pricing, combined with our basis hedge and our fixed price sales positions, we expect average differentials of negative $0.25 to $0.35. On the operating cost side of the business, we expect relatively uniform quarterly performance with total 2021 per unit operating costs landing in the $1.29 to $1.41 per Mcfe range. We also expect quarterly capital expenditures to be generally consistent during the 2021 period and expect first quarter capital expenditures of approximately $280 million to $305 million.

I also wanted to provide a brief update on our debt targets post the Chevron asset acquisition. We plan to utilize free cash flow to retire the remaining debt maturities through 2022 by the end of 2021, at which point we expect our long-term debt to be between $3.8 billion and $3.9 billion. This should put us at or near the 2.0x leverage target. We will continue to pay down additional debt in 2022 until we are comfortably trending below 2x leverage. With the recent ratings improvement, we reduced our annual interest expense by $10 million, raised our credit to hedge by nearly $350 million and trimmed a small amount of LCs. Our goal is to get back to investment-grade, and the recent credit upgrades from Moody's and S&P leaves us 2 notches away at all 3 agencies.

With respect to MVP, we are continually working with several companies to sell down incremental MVP capacity. While the delayed in-service date pushed back our anticipated timing of offloading our targeted amount, we are able to sell down approximately 125 million a day of capacity. We are currently assuming MVP will be operational at the beginning of 2022, but are carefully watching as progress unfolds. With ACP cancellation earlier, MVP is well positioned to fill this market demand. As we execute additional capacity releases, we will provide updates accordingly.

And with that, I'll turn it back over to Toby to wrap things up.

Thanks, Dave. 2020 was a critical inflection point for this company, and it was essential that this team perform at a very high level to stabilize the business and secure its longevity, which is exactly what we did. We exceeded our financial and operational plans, positioned the company for the long term by strengthening our balance sheet and evolved the organization with the implementation of our modern operating model to sustainably create value in any environment.

The evolution of our digital platform will bring even greater governance, efficiency and sustainability to our operational and financial performance as we move into 2021. As we continue this transformational journey, our commitment to the environment and the communities in which we operate will be at the heart of everything we do. We have the team in place, we have the strategy defined and we have the cultural alignment established to take EQT to the next level. I'm excited about the trajectory of this company and the value we plan to deliver to all of our stakeholders.

We appreciate everyone's interest and support along the way. And with that, I'll turn it over to the operator for Q&A.

(Operator Instructions) And your first question is from Arun Jayaram with JPMorgan.

Yes. Toby, I was wondering if you could start maybe with the higher mix of capital towards West Virginia. I was wondering if maybe you could go through how the economics stack up relative to Washington and Greene County as we did note that it looks like you will be developing West Virginia with quite longer laterals with some of those spuds being in that 15,000 foot. But wondering if you can maybe go through what kind of recoveries do you anticipate per 1,000 foot and just how the relative economics stack up?

Sure. Thanks, Arun. So the West Virginia Marcellus economics are going to be fairly similar to Pennsylvania. You can see on that slide where we showed the lateral length that we're spudding play a big factor in that. I think the other thing from a timing perspective, us having the ability to get this water infrastructure is also going to help from the cost perspective as well. So I think when you step back and you look at the assets that we have, about 40% of our leasehold -- of our core leasehold is in West Virginia. So it makes sense for us to start shifting some of our development to that area.

Makes sense. And then just a follow-up, David, on your comments on the partial sell-down of some of your MVP capacity. Did I hear that you sold down 125 [a square inch or] feet or so? Is it about 10% of your capacity or so?

That's right, yes.

Okay. Can you just talk about what kind of impacts we should anticipate on a go-forward from that? And it sounds like with the timing pushback a little bit, it may take a little bit more time, but you're noting some progress in terms of that strategic objective.

Yes. I would say we're still very confident that we'll get more done. I think we have multiple conversations still going on. And so you think about what we said is the impact to the cost structure is about a $0.10 on 100%. So if we -- 10% would represent about a $0.01 impact across the whole cost structure. So some progress. And so I'd just say, stay tuned. We'll give you more progress as we execute some more.

Our next question is from Josh Silverstein with Wolfe Research.

Dave, thanks for the comments on the diffs. Just a couple of questions here. I'm just curious if you're anticipating normal kind of seasonal wider diffs in the middle of the year because it seems like you're kind of guiding towards something wider in -- for the full year relative to the first quarter. So I just wanted to know if that was kind of the seasonal diffs there. And then I'm curious, too, if the recent spikes that we've seen in kind of the spot pricing has been rolling into that as well, if there's any benefit that you guys have received from the local pricing going up to $4 and $5 recently.

Yes. So one is, the recent pop in pricing is not in our forecast because we did our forecast as of January 31, so -- as the weather was more recent than that. So -- yes, and so our forecast of differentials is factoring in the seasonality of the spring and the fall, where you normally see wider differentials, a little bit more wider in the fall than you do in the spring. It will be very interesting to see what Eastern storage looks like at the end of this winter here and what coal deliverability as well as a lot of the coal companies' issues are very apparent. And the other thing to think about because of our FT portfolio, there's been a lot of, call it, volatility in different locations. And so having multiple pipes to multiple regions, and especially now that a big slug of it's back online, gives us, I'll call some -- I'll call it, optionality to create great value moving gas in and around to those regions.

Got it. Have you guys actually been able to sell some gas recently at some of these very high prices around the different regions?

Yes.

Got it. And then just a question on M&A. So you guys announced the Chevron acquisition. And then subsequent to that, we've now seen the other portion of that get acquired as well. Clearly, you guys wanted the bigger operated portion, but I'm curious why not take down both sides of the transaction here unless that might not have been an option for you guys 6 months ago?

Yes. Josh, we participated in that process. We bid conservatively and obviously didn't win. I think the move in commodity prices recently will be helpful in getting us to take down the ROFR that we do have on that portion of the asset.

Your next question is from Neal Dingmann with Truist Securities.

Toby, my first question for you or David, just wondering, your free cash flow just continues to do better and better each quarter, continue to be very impressed with that. My question when the shareholder returned, could one of you all discuss -- is it -- how you want to get the debt -- I know you've talked about wanting to get the debt down to a certain level. But you certainly have a hell of a lot of optionality to provide shareholder return as quick as you'd like. So maybe just talk about that a little bit.

Sure, Neal. I'd say everything we're doing here at EQT is to accelerate the return of capital to shareholders. So our goal is to get our leverage sub 2x before we can start thinking about that. I think the other thing that's important to keep in mind is as our cost structure continues to lower naturally through over time with the lowering gathering rates and then also some of the other capital efficiencies that we're going to be seeing in the operating program is just going to give us more flexibility to accelerate our ability to start returning capital to shareholders.

Yes. Yes. And I totally agree with that. And then one just follow-up. Toby, your rationale, moving over to the West Virginia Marcellus, is that just -- is there some delineation there? Or is it just you think there's appetite that you can lower cost? Or maybe just talk about as you turn there a little bit more.

Yes. Sure. From a reservoir perspective, if you look at the heat map we put on Slide, it 7 shows that the geology is similar in West Virginia [that] it is in Pennsylvania. So we feel really good about the reservoir performance side of things. I think what's really important in West Virginia to be as economic as our Pennsylvania Marcellus is just more critical to leverage combo development. In West Virginia, due to terrain and roads, civil costs are going to be a little bit higher. And combo development is just going to be much more important because combo development, one of the things that does is it let's you spread out those civil costs, lower those on a dollar per foot and also really streamline logistics. And so that helps alleviate any of logistics issues you have with local roads.

So we've been patient. We've always been excited about the West Virginia assets, but we've been patient to make sure that we can set the table for combo development. And the layout we have on Slide 11 shows the development that we're doing out there, the wells that we're spudding are going to be set for 15,000-foot laterals. Long laterals combo development is going to be a key to generating great returns on West Virginia.

(Operator Instructions) Your next question is from Brian Singer with Goldman Sachs.

I wanted to follow up on the West Virginia discussion from Neal and Arun. You mentioned on Slide 11 that your well cost assumptions are $775 per foot for West Virginia. And I wondered if that is where costs are now or if that would be costs -- well costs with the benefit of the drastic reduction that you're planning. If you could kind of quantify where costs have been coming from and where you expect those costs to get to once water infrastructure and the other measures that you're planning are online.

Sure. So the $775 is what we plan on doing this year. The investments we're making in water infrastructure will certainly help us get to that number in the first year. But I would say that the target is to get that number close to $735 as we get the full benefit of the water infrastructure, the civil spend that we're doing right now to set the table. So there's room for that number to come down. But right now, $775 is a good place where we feel comfortable we can deliver, but there's certainly upside to those numbers.

Got it. And is that kind of a fair expectation that you would have for 2022? Or does bringing on the infrastructure take a longer period to achieve?

Yes, it may tick down another 5%, so call that $25 a foot in '22.

Great. And then my follow-up is with regards to the leverage targets. And I wondered if you can talk both about any asset sales, including minority stake in -- or a. And then b, you mentioned that sub 2x is where you would think about returning capital to shareholders. And I wondered if that is the main, if not only, use of cash that you would expect once you've gone below 2x or if there's consideration to investing back in more activity in natural gas or NGLs, [whichever].

Yes. So to get to pay down the remainder of our debt, which is a very small amount in -- I think there's like $10 million left in 2021, there's about $550 million roughly in 2022 on the maturity, we will basically use free cash flow. We don't need asset sales. And if we -- we'll probably sell E-Train stake in 2021 as well, but we don't necessarily need that to pay down our maturities. And so we still like coal, have the optionality of selling, I'll call that, bucket of assets that's probably well north of $1 billion if we want to take a bazooka to an even bigger piece of our debt.

Yes. And as far as capital allocation, once we hit that sub 2x leverage, I mean the focus is certainly right now is returning capital to shareholders. I think we still have the mentality that for us to see any growth, you're probably going to need to see a strip that we think is more reflective of a fair price for gas, which is probably closer to $3 than what strip is showing right now. As a reminder, this base plan that we put out is based off the strip where gas prices are $2.55. So we think that there is material increase -- upside to where the commodity is right now. So we probably need to see a higher strip and even then, production growth would be in the low single digits.

Your next question is from John Abbott with Bank of America.

First question is on the trajectory of CapEx. It sounds like -- just going back with the commentary, it sounds like CapEx could go down over the next several years. You gave that free cash flow outlook through 2026 of roughly around $3.5 billion. When you think about long-term spending, is it not a possibility that you might be down in the -- or in the realm of possibility you could be down in the $800 million to $900 million range by around that time?

Yes, that's correct. And just a point -- there's a couple of things I just want to make sure everybody understands about our cost structure. The gathering rate reductions that we're going to see, those are already baked. That's going to happen. And then from a CapEx side of things, the natural [channel] of our PDP decline, our [corporate] decline is going to decrease from the upper 20s today to the low to mid-20s years from now. And all that is going to allow us to spend $50 million to $100 million less CapEx year-over-year to lower our CapEx numbers to the $800 million to $900 million that you mentioned.

Right. And then my second question is on the gas gathering agreement. So it's my understanding if MVP is still not online by the beginning of 2022, you have the optionality for a $200 million cash payments. Should we assume that you would take that payment? Or is there some reason that you would not take that payment?

Yes. I think we'll just -- we'll play it by ear. There's -- we'll just look and see what the odds of MVP timing is to make that decision. I think it either comes in the form of taking cash and repay debt or lowering our cost structure, which comes in as EBITDA. So we'll just have to think through the calculus of that.

Your next question is from Noel Parks with Tuohy Brothers.

I was interested to hear about just the plans for investment in the water handling system, and I apologize if you touched on this before. But if I understood right, part of it is from impact of the assets acquired from Chevron. And I was wondering sort of looking back a couple of years ago when the new management team came on board, just where -- kind of on the to-do list of efficiency measures that you had in mind, was water handling sort of on the back burner and it's just kind of risen as you've sort of ticked other efficiencies off the list? Or was this something that just from last year or recent period, you felt more of a need to invest in?

Yes, great question. I'd say when we came in here a couple of years ago, the focus really was on improving the capital efficiency of the organization. Part of that for us is going to be lowering our well costs. And one of the big things that we -- big drivers behind that is going to be leveraging infrastructure to do that, whether that's existing E-Train infrastructure or new water infrastructure to support our development in West Virginia. I think any time we spend any dollar, we look at the returns that we're going to generate. And this water infrastructure, I think, is -- we're really excited about the returns we can get. The cost savings we'll see from this would be -- on water infrastructure will be around $130 a foot. It will cost us around $60 a foot to install it. So it's a net $70 per foot gain.

One thing to point out there, that -- those economics are based assuming this water line is only going to schedule the wells that are already on our schedule. So that's about the 1.8 million horizontal feet. The fact that we have such a large amount of undeveloped inventory that's not on the schedule, it means that we're going to be able to enjoy the benefit of this water infrastructure for years to come. So we're pretty excited about the opportunity with this water. And I think just naturally, from an operator perspective, we certainly have the skills and experience in working with water. And I think that water infrastructure is probably one of those asset classes that really makes a lot of sense being owned and operated by the operator just because of the high [plus] points with logistics as it relates to servicing the completions.

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

A lot going on, obviously, right now on the macro front with supply and demand as we sit here in Houston without power. I know you guys do a ton of macro work. And with this polar event, just curious how your macro assumptions have changed. And then, Dave, I know you have an interesting perspective on the coal market. So -- and that obviously plays in as natural gas prices continue to rise here. So any sort of new updates that you guys could give us on just how your macro landscape is evolving here.

Holly, this is Toby. I think at a very high level, the extreme weather events that we're experiencing and the impact it's had on millions of Americans across the country, I think, really is a good time for everybody to step back and reassess how critical infrastructure and energy is for people to live our lives and enable a modern society. And I think when you -- when the smoke clears and people are doing the postmortems on exactly what we could have done better, I think that the balanced approach is going to be we need to think about not just a certain sector of the infrastructure but all infrastructure.

There's certainly more work we need to do with natural gas infrastructure. When we talked about some of the differentials we've seen across different parts of the country, one way to alleviate that is to put in more natural gas infrastructure. Projects like MVP are critical to connecting these markets and making sure that we can continue to supply the growing demand. So I think that's just an important reminder on how important energy is to our everyday lives and the things that we can do better.

Yes. I guess just to piggyback a little bit off that, just I would say, obviously, storage levels are going to be drawn down a little bit faster than people probably anticipate. And so I guess the -- probably puts more upward pressure, I'd call it, in the other periods to get back there. And as you point on the coal side, if you look at coal production, coal production is down about 20% in the rails and the producers. It's not a -- it's a big ship to turn in a quick amount of time. So the question is will there be deliverability. Utility stockpiles are actually not that high as you would expect.

And so the question is, as you head into maintenance season and then the summer season, we anticipate gas to coal switching to be somewhat meaningful, and that will be a big question mark because of the stockpiles, the deliverability and, I'll call it, an export market that has been meaningfully higher than the domestic market. So it creates the incentive to ship what you have out of the U.S. as opposed to keep it in.

Yes. Maybe, Toby, just another high-level question on the M&A market, which we saw in Appalachia heat up a little bit in 2020. And there's obviously a push, I think, from companies to be bigger and have more scale. Just how do you envision kind of this playing out? Maybe it doesn't need to be 2021. But certainly, over the next several years, you've got, I would say, a decent amount of rigs and a lot of different in hands -- and a lot of different hands in the Appalachian Basin. So any comments on just strategic view of the overall M&A landscape?

Yes. I think that it's similar to what we saw in 2020. I mean the reality is we're still looking at a strip that's in the $2.50 to $2.60 range. So low commodity prices and the need for scale is going to be critical. I mean I think that's going to be the next step for -- to show efficiency in this industry. I say it a lot, a lot of companies, EQT is not unique in the fact that we've made a significant improvement in pulling a lot of costs out of our business, but a lot of guys have done that. But when you step back and you realize that in Appalachia, we've got 30 teams running around 30 rigs, you may have very efficient companies, but when you look at that, it's -- it could be more efficient than that.

With -- the other thing is having multiple operators. It's -- you've got a lot of service providers that are running at, call it, 50% utilization. And you've got multiple gathering infrastructures as well that are maybe not being optimized and running at full utilization. So I think consolidation naturally will help get the -- allow operators to take a full advantage of their talent, allow service providers take full advantage of their equipment and allow the infrastructure players to take full utilization of their systems. All of this is going to deliver a healthier system and greater returns for our shareholders.

Your next question is from Kashy Harrison with Simmons Energy.

So first one for me. Toby, I was wondering if you could talk a little bit more about Project Canary. Maybe discuss the objectives of the project and how you think about the potential long-term implications for this project towards your business and maybe towards other gas companies in the future?

Sure. At a very high level, at EQT, we're driven to be a leader in the responsible production and consumption of natural gas. So the ESG efforts that we're doing are really going to highlight the responsible production aspect of that mission that we have. And so the Canary project, which is the responsible gas certification, is really just going to highlight that we are producing our gas in a responsible way.

And so this project is going to basically entail putting out sensors on a couple of our pads to measure the methane levels to get an accurate third party assessment. That data is going to be processed by another third party, the Colorado University. And then with that, we'll be able to really show how responsibly we produce our gases, and we'll look for opportunities to scale that across the plant. So when we look at the cost of this, this could be a few cents increase to get our gas certified. But I think that the demand could be there from our utilities to know that they're purchasing a differentiated commodity from EQT, that stamp that it's responsibly produced.

Yes. And I think if you think about what happened with some LNG trade that didn't occur because of the emissions footprint, there's going to be, I'll call it, a global search for really low emissions. And Appalachia sits amongst the lowest emissions, not just the U.S. but probably as well globally.

Yes. And I think what we -- the data -- the chart we put on Slide 14 really shows how there is a different level of performance across operators across the country and across the world. And I think for us to be able to say, this is what our performance looks like, it shows that there is a differentiation between the gas that we're producing up here in Appalachia, specifically EQT, and what other sources of gas have from an emissions perspective.

And so you think at some point, there will be some -- maybe some premium associated with responsibly produced gas is what I'm hearing?

Yes, there could be. I gave the commentary on the cost for us to do this responsible certification, just to give a marker on sort of what that premium would need to be for us to -- incentivize us to do this across our entire program.

Got it. And then maybe just building on the questions in West Virginia. It looks like the water infrastructure is maybe being built towards the western part of the acreage position. And so I'm just curious, is the plan to primarily target the wet gas acreage in West Virginia during 2021? Or is it going to be more dry gas focused in West Virginia?

Our West Virginia development is going to be about 25% liquids, 75% dry gas. The water infrastructure that we're putting really is driven by where we need it. Keep in mind, the Chevron assets we picked in Marshall, which would be -- picked up in Marshall, which is going to be the liquids portion of our production, they already have a -- we already have a pretty robust water system there. So we're really focusing our attention on areas that are sort of blank canvas.

Got it. Got it. And if I could sneak one more in. Just wanted to check if the capital allocation split between PA and West Virginia is a good proxy for the foreseeable future or over the next x years, maybe like 5 years or so. Or if you expect to maybe transition to more of an equal split between PA and West Virginia. And I'll leave it there.

Great. Yes. The long-term development is probably going to be 65% PA Marcellus. So that's still going to be the majority of our CapEx, but we do want to get moving on starting to bring some of the benefits that we have, developing shale and do that in West Virginia.

Your next question is from Scott Hanold with RBC.

I just have one quick question for you all. Historically, EQT has been a leader on looking at things like using CNG in vehicles and such. Are those still initiatives? I know you all are always looking to kind of being a leader. Is this still at a high level to you all? And is this something where you've been in conversations with people in the administration or maybe go down that path to demonstrate that as an option for gas going forward too?

Yes. I think that's a great question. No doubt, there's a lot of new opportunities, I think, that are being presented as people start thinking about the energy transition. My view on this is I think that companies like EQT are uniquely positioned to take advantage of those opportunities, whether it's the fact that we've got billions of dollars of assets already in the ground, finding new ways to take advantage of our product, whether that is using cheap Appalachian gases of feedstock to power manufacturing or convert it into another product that's more desirable, higher price, that's one option.

But I think when we step back and we look at energy transition in general, I think it's important for people to understand that shale has -- and the people in shale, particularly the people here at the management team here at EQT, we've been through an energy transition before. I mean this is not the first time. We -- the energy transition that was, I think, really impactful was the transition from conventional reservoirs to developing shale. And there's been some guys that have been very successful in navigating that path and capturing the opportunities that have made tremendous amount of dollars for their shareholders and also made a really positive impact on all stakeholders. I certainly feel like we're one of those groups of people.

And so that type of skill set, that type of experience is going to be really important as we look at other opportunities in front of us on the energy transition space. That being said, EQT is going to continue to focus on executing our base plan. And we're really excited about the opportunities to improve our core business, and we'll be opportunistic looking at other ways to extend the platform.

Your next question is from Mark Carlucci with Morgan Stanley.

Toby, you mentioned the importance of getting MVP online. Just curious, what your view of supply versus takeaway is, say, in a couple of years. If, in fact, that pipe does not enter service, what that can mean for basis differentials, especially in the shoulder months, and how that would impact your strategy, if at all?

Yes. So we say that local takeaway and demand is [about] 35 Bcf a day. We've got about 30 -- we've got about 32 Bcf a day of production. So you can look at that and say you've got cushion. But I think you look at what we put out on Slide 19 and really having some pipelines have any outages really creates a lot of volatility in this market. And so having extra outlets is going to be super, super constructive to the long-term local basis area. It's a pretty critical project for this basin and for other areas of the United States, like the Southeast that want to decarbonize that grid with low-carbon natural gas.

Yes. But don't forget there is in-basin demand growth as well. There are 9 coal plants within Pennsylvania alone that probably will be at risk of going off-line in the next few years. And then you have the Shell cracker. You have gas-fired generation. For example, there's a gas-fired generation plant coming online in our backyard that we will sell directly to in the spring. So there is going to be internal demand inside the basin, and then hopefully, MVP does come online.

And there are no further questions at this time. And I'll now turn the call back over to Mr. Toby Rice for closing remarks.

Thanks, everybody, for your time on this call today, and we will keep working hard to keep the gas flowing and creating greater results for our shareholders and all stakeholders. Thank you.

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.