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EQT Corp
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Ladies and gentlemen, thank you for standing by and welcome to the EQT Q4 Quarterly Results Conference Call. At this time, all participants are in listen-only mode. After the speakers' presentation, there will be a question-and-answer session. [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 seven-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 David will present their prepared remarks with a question-and-answer session to follow. An updated investor presentation has been posted to the Investor Relations 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 also contain forward-looking statements. Actual results and future events could materially different for these forward-looking statements because of the factors described in today's earnings release and our investor presentation and 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 of the most comparable GAAP financial measures.
And with that, I'll turn it over to Toby.
Thanks, Andrew, and good morning everyone. Today, I will briefly touch on some of the key items we executed on in 2020 that reshaped the trajectory of this business, while natural gas and EQT in particular presents 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 of debt maturities due through 2022. We now sit with roughly $600 million, which can easily be managed with expected free cash flow, and we are on a glide path with sub two times leverage. Second, we drastically reduced our cost structure. We did this by slashing well cost 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 breakeven, which is the Henry Hub price needed to generate positive free cash flow under our maintenance production plan decrease 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 companywide 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 three, we highlight key elements of our mission. We strive to be the security than investors want to own, the operator that service providers want to work for, the employer that employees wanted to work with, the lessee that land owners want at 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 six. 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 prime to deliver long-term value to stakeholders. 80% of our inventory is set up for combo-development, which provides high confidence and predictability and well performance, avoids parent-child interference and will lead to sustainable free cash flow generation. This will increasingly be a differentiator that EQT relative to its peers.
We have proven that we are disciplined capital allocators and our 2021 plan demonstrates our commitment to a 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 $990 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 our 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 base load 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 bullied global LNG markets, which should drive a more robust 2021 U.S. LNG export market as there was growing sentiment that summer LNG demand will soon surpass expectations. Coal production and deliverability issues have further increased in 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 Appalachian 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 interest and 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 rates and are using electric pneumatics on all new sites. Furthermore, our board recognizes the importance of alignment and it's established a greenhouse gas emissions intensity, steep target reduction of 4% in 2021 allow.
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 emissions intensity, 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 could 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 has focused on include developing our proprietary ESG technology to bring transparency of our program to every member of our team, evaluate 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 a maintenance program, enhance margins, grow free cash flow and delever the business. I will point you to slide nine 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 01/31/21 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 2021, resulting in capital allocation of approximately 65% to Pennsylvania, 30% to West Virginia and 5% to Ohio. Further details, including expected well count and lateral links 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 interests.
New 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 serve 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 efficiency 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 offenses. Behind the scenes there were significant time investments to digitize our processes, to focus our teams on improving planning, accuracy, forecasting, and real-time analysis. Although, our headcount has come down since 2019 our purchase productivity has materially improved, and we've seamlessly integrated the Chevron assets as a result. The team has 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 a dollar per Mcf in our 2020 realized pricing used for our gas reserves prescribed by SEC rules, the increase in reserves demonstrates 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 fire layer today our standardized measure of discounted future net cash flows was approximately $3.4 billion, which was calculating using historic SEC pricing of a $1.38 for Mcf. We were all aware of the commodity price challenges the industry faced in 2020, which are not reflected of the go-forward price projections. Using the five-year strip price as of year-end 2020 of $2.08 per Mcf, this increases our standardized measure of 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 book to prove reserves.
I'd like to also note that only 279 PUDs were booked or merely 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 increases the band of EURs outcomes in well performance, the Appalachia. These improving EURs will drive reserve enhancements. As a result, we saw a strong improvement in EUR performance for 2020 versus prior year.
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 understand that 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 focus a lot of our attention on natural gas, we're able to take advantage of the nearly 50% Cal 2021 run-up in NGL prices that occurred in January locking 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 a 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 sit 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 experience in the back half of 2020 and what we were expecting for 2021 and beyond. Slide 19 in our presentation depicts some of the dynamics that contributed to this volatility. As you aware, local basis blew out during fourth quarter, breaking below $2 at various points in October and November. This sharp decline of 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 prepare for this fall so the two 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 over 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 differentials of negative $0.42. The water differentials are primarily driven by an incremental 2021 expected production associated with acquired Chevron volumes, partially offset by the benefit of our contracted FTE capacity coming back online in January.
Looking forward, there are some positive advanced demand drivers on the horizon over the next few years, including accelerated coal retirements driven by increased regulations, such as Reg G 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 inpatient demand. The benefit and timing of the 2 Bcfe today MVP capacities, then incremental creating either even greater spread and we remind everyone that the Southeast needs the gas to help be carbonized and grow their local times.
This take me through a quick overview of a fourth quarter financial results. Sales volumes of 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 subreddit settings 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 are 1,498 Bcfe, roughly flat with 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 31st, 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 the 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 2.0 times leverage target. We will continue to paydown additional debt in 2022, until we are constantly trending below two times leverage.
With the recent ratings instrument, 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 product upgrades from Moody's and S&P leaves us two notches away at all three 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 position the company for the long-term by strengthening our balance sheet and evolve 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 appreciated 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.
Yeah. 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 the SPUDs being in the 15,000 foot. But wondering if he could maybe go through what kind of recoveries you anticipate per thousand foot and just how the relative economics stack up.
Sure. Thanks, Arun. Good morning. So, the West Virginia Marcellus economics are going to be fairly similar to Pennsylvania. You can see on that slide where we show the lateral length that were spudding played 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 shipping some of our development to that area.
Makes sense. And then just to follow up. David, on your comments on a partial sell-down of some of your MVP capacity, did I hear that you sold down 125?
Yeah.
… is about 10% of your capacity or so.
That’s right. Yes.
Okay. Can you just talk about what kind of impacts that we should anticipate on a go-forward from that? And it sounds like the timing -- a pushback a little bit, it may take a little bit more time, but you're noting some progress in terms of that strategic objective.
Yeah. I'd say we're still very confident that we will 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 dime on 100%. So if we -- 10% would represent about a penny 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 more.
Great. Thanks a lot.
You are welcome.
Your next question is from Josh Silverstein with Wolfe Research.
Thanks. Good morning, guys. Dave, thanks for the comments on the dis. Just a couple of questions here. I was curious if you're anticipating normal kind of seasonal water dis in the middle of the year. 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 dis there.
And then I'm curious too, if the recent spikes that we have seen and then 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 goes up to $4 and $5 recently.
Yeah. So, one is a recent pop in pricing is not in our forecast, that because we did our forecast as of January 31st. So as the weather was more recent than that. So, yeah. And so, our forecast of differentials is factoring in the seasonality of the spring and the fall, where you normally see water differentials, a little bit more wider in the fall than you do in the spring. It'll be very interesting to see what Eastern storage looks like at the end of this winter here. And what coal deliverability is as well as -- is 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 coal 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 awesome, 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?
Yeah.
Got it. Thanks for that. 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 on list that might not have been an option for you guys six months ago?
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 offer that we do have on that portion of the asset.
Got it. Thanks a lot, Toby.
Your next question is from Neal Dingmann with Truist Securities.
Morning. Hey, Toby. My first question for you David, just wanted a view with free cash flow just continues to do better, better each quarter. Continue to be very impressed with that. My question, when shareholder returned, if you wouldn't be able to discuss, is it, Hey, you want to get -- you talked about wanting to get the debt down to a certain level, but you certainly have a hell of a lot optionality that to provide shareholder return as quick as you'd like. So maybe just talk about that a little bit.
Sure. Neal, I would 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 two times before we can start thinking about that.
I think the other thing that's important to keep in mind is this is our cost structure continues to lower just 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. It's just going to give us more flexibility to accelerate our ability to start returning capital to shareholders.
Yeah. 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 not -- lower cost or maybe just talk about it as you turn there a little bit more?
Yeah. Sure. From a reservoir perspective, if you look at the heat map we put on slide seven shows that the geology is similar in West Virginia, that is in Pennsylvania. So we're -- 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. This combo-development one of the things that does is it lets you spread out those civil costs, lower those on a dollar per foot and also really streamlined 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 Western new 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 we are spudding that we are going to be set for 15,000 foot laterals, long laterals combo-development is going to be a key to generate great returns in West Virginia.
Agree. Thanks guys. Great free cash flow.
Yeah. Thank you.
Thanks, Neal.
[Operator Instructions]
Your next question is from Brian Singer with Goldman Sachs.
Thank you. Good morning.
Good morning.
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 cost 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 you 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'd say that the target is to get that number close to $735. As we get the full benefit of the water restructure, 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 it, 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 it does bringing on the infrastructure take a longer period to achieve?
Yeah. It may take down another 5%, so call that $25 a foot in 2022.
Great. Thank you. And then my follow-up is with regards to the leverage -- 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 two times 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 two times, or if there's consideration to investing back in more activity in natural gas and/or NGLs, which drill.
Yeah. So, to get to paydown the remainder of our debt, which is a very small amount in -- I mean there's 10 million left in 2021, there's about 550 roughly in 2022 on the maturity. We basically use free cash flow. We don't need asset sales. And if we -- we'll probably sell ETRN stake in 2021 as well, but we don't necessarily need that to paydown our maturities. And so, we still -- have the optionality of selling, I'll call that bucket of assets. That's probably well north of a $1 billion. We want to take a bazooka to a big piece of our debt.
Yeah. And as far as, capital allocation, once we hit that sub two times leverage, I mean, the focus is certainly right now, returning capital to shareholders. I think, we're still have the mentality that for us to see any growth. You'd probably get to see a strip that we think is more flexible of a fair price for gas, which is probably closer to $3. And what strip is showing right now is as a reminder. There's base plan that we put out is based off the strip where gas prices are $2.55. So we think that there's material increased upside to where the commodity is right now. So, we probably would need to see a higher strip and even then production growth would be low single digits.
Thank you very much.
You are welcome.
Your next question is from John Abbott with Bank of America.
Good morning. Thanks for taking my questions. First question is on the trajectory of CapEx. It sounds like -- just going back with the commentary, so the CapEx could go down over the next several years. You gave that free cash flow outlook through 2026 at roughly around $3.5 billion. When you think about long-term spending, is it out of the possibility that you might could be down in the -- or in the realm of possibility could be down in the $800 million and $900 million range by around that time?
Yeah. That's correct. And just this -- just to point of this, 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 shouting of our PDP decline -- our corporate decline is going to be increasing from the upper 20s today to the low to mid 20s years from now. And in 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 [ph]. 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 should we assume that you would take that payment or is there some reason that you would not take the payment?
Yeah. I think we'll just -- we'll play it by year. There's -- we'll just look and see what the odds of MVP timing is that to make that decision. I think, we -- 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.
Thank you very much on a great quarter.
Thank you, John.
Your next question is from Noel Parks with Tuohy Brothers.
Good morning.
Morning.
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 then it's just kind of risen as you've shared to 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?
Yeah. Great question. I'd say, we came in here a couple of years ago. Our 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've -- big drivers behind that is going to be leveraging infrastructure to do that, whether that's existing infrastructure or a new water infrastructure to support our development West Virginia. I think anytime 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 will be in water infrastructure, will be around $130 a foot. It'll 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 waterline 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 needs it 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, 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 if that really makes a lot of sense being owned and operated by -- the operator just because of the high price points with logistics, as it relates to servicing the population.
Great. Thanks a lot.
You got it.
Your next question is from Holly Stewart with Scotia Howard Weil.
Hello gentlemen. Good morning.
Good morning.
A lot going on, obviously right now on the macro front with supply and demand, as we sit here and 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 issue perspective on the coal market, so -- and that obviously plays in as a 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 this has had on millions of Americans across this country, I think really is a good time for everybody to step back and reassess how critical infrastructure and energy is to -- for people to live our lives and enable modern society. And I think when you -- when the smoke clears and people 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 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 use 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, it's just an important reminder on how important energy is to our everyday lives and the things that we can do better.
Yeah. I guess, just piggyback a little bit, just I would say obviously storage levels are going to get drawn down a little bit faster than people probably anticipate. And so, I guess, probably puts more upper pressure. I'd called it in the other periods to get back there. And your point on the coal side, if you look at coal production, coal production is down about 20% and 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 anticipated gas to coal switching to be somewhat meaningful. That'll be a big question mark, because of the stockpiles, the deliverability, and I'll call it an export market that's has been meaningfully higher than the domestic market. So it's creates the incentive to shift what you have out of the U.S. as opposed to keep it in.
Yeah. No, thank you for that. Maybe Toby, just another high level question on the M&A market, which we saw an 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 enhance -- a lot of different hands in the Appalachian basin. So any comments on just strategic view of the overall M&A landscape?
Yeah. 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 250 to 260 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 the show efficiency in this industry. I say it 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 30 efficient companies, but when you look at that, it's -- it could be more efficient.
And 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 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 much healthier system and greater returns for our shareholders.
Thank you, gentlemen.
Welcome.
Your next question is from Kashy Harrison with Simmons Energy.
Good morning all and thank you for taking my question. So first one from 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 our responsibility, 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 is responsibly produced.
Yeah. 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 call it, global search for really low emissions and Appalachia sits amongst the lowest emissions, not just the U.S., but probably as well globally.
Yeah. 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 pretty staff 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 an -- 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. Thanks. Thanks guys for the color there. 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, 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 water -- 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 ex-years, maybe like five years or so? Or if you expect maybe transition to more of an equal split between PA and West Virginia? And I'll leave it at. Thank you.
Great. Yeah. 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 -- sorry -- to bring some of the benefits that we have developing channel and do that in West Virginia.
Thank you.
Your next question is from Scott Hanold with RBC.
Thanks. I just have one quick question for you all. Historically, EQT has been leader on looking at things like using CNG in vehicles and such. Are those still initiatives or are always looking to kind of be 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?
Yeah. 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 gas as a feedstock to power manufacturing, converted into another product that's a 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 in 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 -- vantage of 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 skillset, 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.
Okay. Great. Thanks. Understood.
Your next question is from Mark Carlucci with Morgan Stanley.
Hey, guys. Thanks for taking the question. Toby, you mentioned the importance of getting MVP online, just curious what's your view of supply versus takeaway is say in a couple years? In fact that pipe does not enter service, what that can mean for basic differentials, especially in the shoulder months? And how that would impact your strategy, if at all.
Yeah. 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 the -- 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 constructive to long-term local base there. It's a pretty critical project for this basin and for other areas of the United States, like the Southeast, I want to decarbonize their grid with low carbon natural gas. If it don't, don't forget there is in-basin demand growth as well.
There are nine coal plants within Pennsylvania alone, that probably will be at risk of going offline in the next few years. And then you have the Shell cracker, you have gas per generation, for example, there's a gas power generation plant coming online in our backyard that we will sell directly to -- in the spring. So there's going to be internal demand inside the basin, and then, hopefully MVP does come online.
Got it. Thanks guys.
You're welcome.
And there are no further questions at this time. I'll 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.