Ladies and gentlemen, thank you for standing by, and welcome to the EQT Corporation Q4 2019 Quarterly Results conference call. At this time, all participant lines are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. To ask a question during this session, you will need to press star one on your telephone. Please be advised that today's conference is being recorded. If you require further assistance, please press star zero. I would now like to hand the conference over to your speaker, Andrew Breeze, Director of Investor Relations. Sir, please go ahead.
Good morning, and thank you for joining today's conference call. With me today are Toby Rice, President and Chief Executive Officer, David Conti, Chief Financial Officer, and Kyle Durham, former interim 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 7185478. In a moment, Toby and David will present their prepared remarks with a question-and-answer session to follow. During these prepared remarks, Toby and David will reference certain slides that have been published in a new investor presentation, which is available on the investor relations portion of our website. I'd like to remind you that today's call may contain forward-looking statements.
Actual results or future events could differ materially from these forward-looking statements because of factors described in today's earnings release and in our risk factor section on our Form 10-K for the year ended December 31st, 2019. We do not undertake any duty to update any forward-looking statements. Today's call may also contain certain non-GAAP financial measures. Please refer to this morning's earnings release for important disclosures regarding such measures, including reconciliations of the most comparable GAAP financial measures, and w ith that, I'll turn it over to Toby.
Good morning. Today, I will discuss the execution of certain strategic initiatives, provide an update on our evolution, and discuss our 2020 plans. I will pass the call to Dave Conti to discuss our balance sheet, liquidity, and the philosophy that he brings as our newly appointed CFO. Since our election in July, in only six months, we have taken decisive tactical steps to overhaul the strategy and execution at this company. We've removed over $400 million, or 25%, of annualized controllable costs across the business from the office to the oil field. Today, we've released a 2020 CapEx budget that is $150 million less than our guidance in October. This reflects $50 million that was removed as a result of our base production volume enhancement initiatives, which we announced in January, as well as an additional $100 million resulting from the continued optimization of the operation schedule.
We continue to find new ways to reduce our costs and create value for our shareholders. EQT has peer-leading G&A and LOE costs, marching towards the lowest well costs, and our recent focus has been on reducing our gathering and transportation costs. We are pleased to announce that we will be strengthening our partnership with EQM through the successful renegotiation of our gathering contracts, which is a big step towards our goals. At a high level, this deal provides EQT with meaningful fee relief in the short term, and favorable rates for the long term. This resulting rate structure represents a significant reduction from the legacy rate structure today. In exchange for lower rates, EQT will provide EQM with long-term contract extensions, an increase in our minimum volume commitments, and a dedication of essentially all of our undedicated acreage.
Realizing the true potential of our partnership rests on EQT's ability to efficiently deliver combo development projects to EQM's highly strategic gathering systems. To detail the components of the EQM agreement, I will direct you to slides seven and eight in our analyst presentation. The deal combines nearly all of the legacy Pennsylvania and West Virginia EQM agreements into one global gathering agreement extending to 2035. This affords EQT the operational flexibility to execute combo development across our entire operational footprint. The reduced gathering rate goes into effect upon the in-service of Mountain Valley Pipeline, which we have assumed to be January 1st, 2021. Over the first three-year period, we expect to receive approximately $535 million in fee relief, inclusive of the impact of our E-Train equity exchange, which I'll discuss in a moment, with nearly half of the relief coming in 2021.
This significantly enhances our EBITDA and leverage outlook, which is critical in navigating through this challenging commodity price environment. By 2024, and through the duration of the agreement, EQT will receive long-term gathering rates that are 35% lower than 2020 levels, solidifying our peer-leading cost structure and providing long-term rate visibility. Effective today, the minimum volume commitment increases from 2.2 Bcf a day to 3 Bcf a day, and upon the in-service of MVP, builds to 4 Bcf a day by 2023. Additionally, we have dedicated over 100,000 acres in West Virginia to EQM. EQM has also agreed to defer approximately $250 million in current credit assurance requirements that were triggered as a result of our recent credit downgrades, providing EQT with additional liquidity and flexibility.
We also executed an exchange transaction with Equitrans, under which we will exchange half of our equity stake in Equitrans for $52 million in cash, plus incremental fee relief. This is a strategic use of our stake, as the EBITDA impact of the embedded fee relief is meaningfully more accretive to leverage than if we were to monetize the stake and apply proceeds directly to debt reduction. That said, we are still focused on absolute debt reduction. Ultimately, this mutually beneficial agreement will provide EQT with the ability to grow modestly and generate free cash flow in a $2.50 gas environment if desired. Both EQT and Equitrans emerge stronger, a true win-win. While the gathering agreement was one large strategic step in the right direction, there is still more work to be done as we turn EQT into a sustainable and durable business.
The philosophy behind our plan is simple: Be the low-cost operator, strengthen the balance sheet, and maximize shareholder value through prudent capital allocation. To do this, there are three main objectives that our team is focused on delivering in 2020. First, we aim to execute our asset monetization plan by mid-year 2020. Second, we plan to meet or exceed our 2020 adjusted free cash flow guidance of $200 million to $300 million. Third, we will continue to optimize the business by removing incremental costs, enhancing operational efficiencies, and pushing the boundaries on technological innovation. All cash proceeds, free cash flow generation, efficiency gains realized, and incremental cost reduction will accrue to delever the business. On the asset monetization front, we continue to feel confident in our ability to execute our plan.
The aggregate potential value of these opportunities, in addition to the free cash flow generation, is greater than our $1.5 billion target despite weaker pricing. The debt refinancing we executed in January provides us with better footing as we no longer face maturities in the back half of the year. We'll be prudent, making certain EQT receives fair value for these assets that is in line with the intrinsic value benefiting all stakeholders. Management presentations are ongoing and the processes are progressing as planned. We have seen solid interest for both the minerals and E&P assets and will continue to keep the market updated as things progress. Our remaining equity stake in Equitrans as of 2/25 is valued at approximately $230 million. We continue to expect that we will be out of this position by mid-year, as we are not long-term holders of this stock.
While the asset monetizations are of high importance for the near-term balance sheet management, the best way that we can offset a lower commodity price is to continue to lower our breakeven costs. At the heart of EQT's cost reduction effort is our ability to execute combo development runs, leading to the most efficient capital deployment. In the fourth quarter, our PA Marcellus well costs averaged $800 per foot. This is down nearly 20% as compared to legacy costs and down 6% quarter-over-quarter. Slide nine highlights drilling efficiencies that we have seen across all operations since our election in July. Top hole drilling days have been reduced by 28%. Horizontal drilling speeds have improved by 38%. This leads to a 16% reduction in total drilling days per well.
These material improvements translate into real savings and give us confidence in our ability to achieve our $730 per foot well cost target in the PA Marcellus by the second half of 2020. In addition to driving down well costs, there are many other ways we can reduce costs and improve margins. On the G&A side, we have built processes and technology that reduce our dependency on contractors. For LOE costs, we continue to optimize our water logistics, aiming to increase our recycled water usage and production uptime. We continue to strategically optimize our firm transportation portfolio to improve our cost structure. Lastly, both hedging and our interest expense are places that we can strategically manage, which Dave will touch on in a moment. The gathering agreement with Equitrans allows better insight into our future cost structure.
With that constraint removed, the largest drivers of our future development decisions will be the macro environment, the outcome of the game board of strategic initiatives we have in process, and corporate returns. We are watching the natural gas fundamentals very closely and see a trend for improving prices. We are seeing rig counts decline, productivity trends materially slowing, DUC inventory being drawn down, and core inventory in key shale plays being drilled up. Gas production has declined in several basins off this November 2019 peak, as producers have recognized that fully loaded returns are the right measure. Our view on the commodity outlook is positive. However, we will continue to study and analyze the market as we determine the optimal activity levels for our development.
Until a market recovery is sustainably reflected in the fundamentals, the most prudent strategy that we can take is to follow a maintenance production cadence. With that, I will pass the call over to our newly appointed CFO, David Conti.
Thank you, Toby. I'm excited to have joined this team that has demonstrated past success in building a company from scratch and has already made significant progress in extracting value out of this business. This is a familiar territory for me. I've been through extensive corporate transformations and cost-cutting initiatives before. I look forward to continuing their progress and will leave no stone unturned to find incremental cost savings to drive sustainability. Today, I plan to address a quick snapshot of fourth quarter results, year-end reserves, liquidity, our balance sheet focus, and hedging. Overall, during the fourth quarter, we outperformed in many of our key metrics, including adjusted free cash flow. In the fourth quarter, we achieved sales volumes of 373 Mcfe, which came in at the high end of our guidance range, but 5% below last year.
Adjusted operating revenues were $947 million, down 23% compared to fourth quarter 2018, as realized prices were $2.54 or approximately $0.60 per Mcfe below last year. We intend to implement a more thorough hedging program that will minimize this volatility, which I will talk to in a little bit. Total operating expenses for the quarter increased $658 million compared to the fourth quarter 2018, primarily due to increased impairments on long-lived assets of $775 million in the fourth quarter of 2019.
The $1.6 billion in non-cash impairments recorded in the fourth quarter of 2019 were primarily related to depressed natural gas prices and changes in our development strategy, including the contemplated divestiture of certain of our non-strategic assets. At the unit cost level, fourth quarter 2019 total unit costs were $0.16 lower than the fourth quarter 2018, primarily driven by an increase in litigation expenses in the fourth quarter of 2018. We have paid approximately $100 million in the fourth quarter of 2019 to settle various legal matters, which we had accrued at the end of the third quarter using the majority of the free cash flow we generated during the fourth quarter. Our CapEx was $355 million, or $203 million lower than the fourth quarter of last year, and in line with our expectations. This reflects both reduced activity and significantly improved field efficiencies.
As Toby has highlighted, we are using all efficiencies to generate free cash flow instead of increasing production. We have reduced our 2020 CapEx budget twice already by a total of $150 million, and we'll look for additional opportunities to reduce the budget. Our adjusted operating cash flow for the quarter was $503 million, as compared to $693 million in the fourth quarter of 2018. An adjusted free cash flow of $148 million was at the high end of our guidance range of $100 million to $150 million. For the full year, there are a few items that I want to point to that impacted our comparative results from 2019 to 2018. In 2018, we divested our Permian and Huron assets, as well as completed the separation of our midstream business.
Excluding the sales volumes related to these divestitures in the prior year, gathering and transmission expense per Mcfe were $0.55 and $0.50 in 2019 and 2018, respectively. Our adjusted operating cash flow for the full- year 2019 of $1.8 billion exceeded our prior guidance, and adjusted free cash flow for the full- year 2019 of $60 million was at the high end of our guidance range. Both were negatively impacted by two items, which under SEC rules, cannot be adjusted out of pro forma operating and free cash flow, including $117 million of proxy, transaction, and reorganization costs, and $82 million of SG&A costs tied to litigation expenses. Now on to our year-end 2019 reserves. We have approximately 17.5 Tcfe of total natural gas, natural gas liquids, and oil-proved reserves. This represents a decrease of approximately 4.3 Tcfe driven by negative revisions in the undeveloped reserve category.
Slide 14 of our analyst presentation details how our shift to combo development has impacted our proved undeveloped reserves. Although combo development yields lower well costs, improved returns on invested capital, and enhanced well performance, there are certain booking rules that resulted in downward revisions to our year-end 2019 reserves, as more wells are now being classified as probable at year-end 2019. This gets translated into lower PUD conversion costs going forward, down $0.05 to $0.52 per Mcfe. The map on the left helps to visualize the shift in strategy. The blue combo development runs are in areas with more white space or virgin rock, whereas the green legacy wells are closer to producing offset wells. Thus, the combo development runs have fewer neighboring producing wells needed for the proved undeveloped classification.
Our planned combo development wells are located in high-quality core acreage, where we have a high confidence in well performance and where we intend to focus our future development. As we drill in these areas, we expect to convert these probable reserves to proven reserves, but in a more return-driven way. We are more focused on free cash flow generation and returns on invested capital than maximizing PUD bookings. Overall, the fourth quarter was another successful quarter under the new leadership, and the actions in the second half of 2019 have shaped a strong 2020 operational forecast. With that said, I'd like to discuss the several recent items that have impacted our business. As commodity prices have declined, this has put pressure on ratings, balance sheet, and liquidity. We face the wall of maturities, which we are addressing through the recent refinancing.
Our goal is to march back towards regaining our investment-grade metrics, and we believe that we will achieve this through the EQM transaction, asset monetizations, and a modest recovery in natural gas prices. Our team's focused to make this business truly sustainable. With that in mind, three initiatives we are pursuing in the near term. First, retiring 30% of our debt and driving our net leverage to below two times. Focusing on lowering our break evens, including our interest expense, is important. Second, a strong focus on access to capital, which ties to our economics of our business and a more differentiated focus on ESG matters, and t hird, adding a strong hedge process. We are students of the commodity, and our hedge book will be an important part of risk management program. Let's look at our slide 19 that provides a maturity schedule.
The January $1.75 billion refinancing helped to address our 2020 maturity and part of our 2021 maturities, as well as strengthened our position in negotiating our asset monetizations. Our monetizations and free cash flow will help retire the remaining and part of our 2021 and 2022 maturities respectively. Once all are completed, we'll have structured our debt towers with proper spacing between them, enabling easier refinancing going forward. On February 14th, we reinitiated a tender offer for $400 million of our 2021 notes. As of December 31st 2019, our trailing 12 months net leverage stands at 2.6x , and our overall cost of debt capital has risen from 3.6% to 4.9%. Our EQM negotiation, debt repayment, and continued focus on efficiencies will help us navigate the decline in 2020 commodity prices.
While we're focused on improving our net leverage ratios, we've been successful in maintaining a strong liquidity position. Look at slide 20, a s of February 25th, 2020, our liquidity stands at $1.9 billion, reflecting our actions to mitigate collateral calls from our recent downgrades. We are essentially through most of the impact and do not expect much change from here. There's always potential for some additional collateral calls, but we have much more offsetting liquidity options, so a quarter from now, we could easily show higher liquidity. We've been very active in working on our hedge strategy and received board approval to begin implementing an updated hedge program. Our hedge strategy goes out for four years, includes both NYMEX and basis hedges, and we use our large FT portfolio to help differentiate where and how we hedge.
Our goal is to protect the balance sheet while focusing on hedging at levels that generate free cash flow. We'll mostly use plain vanilla tools, including swaps and collars, and will execute a programmatic and active hedge process. Presently, we are 87% hedged for 2020 and stand at 26% for 2021, assuming flat production. Since the adoption of our revised hedging strategy, we have added to our basis hedge position for 2021. We are excited to get this process started, as we expect opportunities will arise as natural gas prices increase over time off the current bottom. I will now turn the call back to Toby.
Thanks, David. I am very proud of the hard work and results that this team has delivered in such a short period of time, despite external challenges. We continue to have constructive dialogue with all of our stakeholders as we set EQT up to be a sustainable and durable E&P business. The direction of the gas production declines, combined with the call on gas from increased LNG demand, can set us up for a compelling gas price that is not currently reflected in the forward curve. While we are optimistic about the future gas price, we recognize the need to run this business in a sustained low gas price environment. We are fully committed to withstanding commodity lows by aggressively pursuing our cost reductions, improving efficiencies, and executing upon our asset sales to improve our balance sheet. With that, I would like to open the call up for questions.
Okay. And as a reminder, to ask a question, press star one on your telephone keypad. Again, that's star one to ask a question. To remove yourself from the queue, you may press the pound key. Our first question comes from Arun Jayaram with J.P. Morgan.
Yeah. Good morning. The first question I have is, I was wondering, Toby, if you could help reconcile the rate release that you guys have identified over the next three years. You've highlighted $270 million, $230 million, and $35 million starting from 2021. The question I'm getting from the buy side is, can you reconcile this relative to what EQM put in their slides of $125 million, $140 million, and $35 million in their deck, slide five?
Sure. The $535 million, there's two components there. There's what I would consider base fee relief of about $300 million. There's the fee relief that we get from the exchange of our Equitrans stake, which would make up the remainder, $235 million, and so t hat's how it's broken out.
Got it, got it, t hat's helpful. Second question is, I wanted to see if you could maybe give us a little bit more color on what you're seeing in the asset sales market. I think you were reiterating your expectation to deliver $1.5 billion of asset sales by mid-year. I was just wondering if maybe you could give some insights on the Ohio Utica process as well as the minerals process that's underway.
Sure. I'd ask you to flip to slide 18, and I think this shows all of our initiatives and the progress that we've made to date. We've certainly made some good progress so far with the free cash flow we've been able to generate and the monetization of our Etrain stake, I'm sorry, that we get with fee relief. As far as minerals in Ohio, the E&P assets go, we see strong interest in those assets. We're in the process right now of collecting feedback from potential parties there. I'd say that the thing that gives us confidence is the fact that while commodity prices have come down a little bit, the one thing that hasn't changed is, you know, the assets are still core. That gives us some confidence.
The other thing is we've got with our refinancing that we've been able to do, it gives us some more time, and I think that time can be used in negotiations to maybe be a little bit more flexible on some terms, bridge any value gaps that we perceive. All to say, we're able to be a little bit more creative in the deals that we do and that's what gives us the confidence that we'll be able to reach our goals.
Great, t hanks a lot.
You're welcome.
Your next question comes from Josh Silverstein with Wolfe Research.
Hey. Good morning, guys, a c ouple questions for you. I was wondering on the debt reduction target, you have $1.5 billion, and you've started to put in there the four Q2019 free cash flow and then some of the rate relief from the Etrain deal. I just wanted to look at it the other way. Do you want to get your net debt down to $3.5 billion, or is it still going to be somewhere around that $4 billion range after all this?
No, I think we'd like to get it down to $3.5 billion. We'd like to get our leverage down to 2x or under. We're looking at both absolute debt reduction as well as the leverage metric.
Got it, and then i n the October update that you guys gave us, you had 2021 CapEx down $200 million versus 2020, i s the $150 million that you have now reduced your 2020 CapEx by relative to the October update, is that incremental to 2021, or is that an acceleration? I'm just wondering if, you know, based on the $235 outlook for natural gas, if now this and the rate relief would allow you to maintain volumes flat next year and still generate positive free cash flow.
Josh, this is Toby, so j ust to put some more color behind the $150 million that we've reduced from our 2020 budget since our October guidance. The $50 million was due to operational efficiencies that we outlined in one of our slides. That's just optimizing our base production. That allows us to get more production from the existing assets we have, which allows us to spend less capital on new activity to replace those volumes, and t hen the $100 million, and we announced that in January, the $100 million is really just optimization of our schedule. We've taken out some of the slack in our schedule as a result of just getting better confidence in hitting our deadlines. The other piece, which I think is probably more meaningful, is just a little bit of shifting of activity and capital allocation.
With our Etrain renegotiation, we're able to move some of our activity from West Virginia into Pennsylvania Marcellus to execute some combos. That obviously is a lower-cost well type for us to develop. That's also a portion of the reduction when we talk about schedule optimization.
Got it, so y ou still think a budget next year for 101 at this point is okay, just to hold volume slide? Is it there, or is it actually a little bit lower than that?
Yeah. No, Josh, I think we're looking forward to providing more color to everyone on what our 2021 plans are going to look like. I would say that, you know, with our Etrain renegotiation, this affords us an opportunity to sort of retool our schedule, understand the well types that we're going to put on the schedule, which will result in the CapEx that we'll be able to report back to you guys.
Yeah, with t he goal with every year is it'll be at least free cash flow neutral to free cash flow positive.
Great. Thanks.
Our next question comes from the line of Brian Singer with Goldman Sachs.
Thank you. Good morning.
Good morning.
You talked in your prepared comments on what some of the drivers of the movements in proved undeveloped reserves and bookings were. Can you talk a little bit about any changes in how you booked proved developed reserves and how the wells and well performance in EURs from the 2019 program compared, and what your expectations are for 2020?
Yeah, so t his is Toby. On our PDP, we improved, t hat has risen, and that was partly due to just better performance with some of the wells. The revisions we had really were on the PUD side. I think that was the story that we wanted to make sure people understood. We're still developing in what we consider to be core areas where performance will be consistent with the performance we have with our existing PDPs. It's just from the rules, we're not able to book those as PUDs, and t he other thing I would say is, you know, this is a good example of our commitment to capital efficiency and making the best choices for where we spend our dollars, and letting the capital efficiency drive where we spend our dollars, not trying to just book reserves.
Great, t hanks, then m y follow-up is on slide eight, and y ou talked about getting to post 2023 peer-leading gathering rates. Can you talk about where that was coming from, where those rates were prior to the renegotiation?
Sure. We talked sort of high level what our rate structure was. It was around $0.60 is sort of what our legacy gathering costs were. We were saying that, you know, market rates were somewhere in the $0.35 to $0.40 range. I think that's what we've been able to achieve with this negotiation with Etrain is, you know, we're able to get some near-term fee relief that accelerates the step-down into those long-term market rates that we're pretty excited about setting us up for the future low-cost aspect of our gathering in this business.
In many cases, particularly within Appalachia, we're probably below, I would say, market rates when we get down there.
Yeah.
Got it. Thanks, man. Thanks very much.
Our next question is from Michael Hall with Heikkinen Energy Advisors.
Thanks, g ood morning, a ppreciate the time. I got a couple, I guess, little bit of follow-ups on some of the prior questions. I guess, first, on the gathering rate that you show for 2023 steps up a bit, is there any dynamic at play there, or is that just kind of feathering in some of the old legacy contracts? Second, the big step-down in 2024 through 2035, is that at all contingent on any, I guess, production thresholds? Is it assuming , you know, you have good clearance of the MVCs? How does that play through in that forward guide?
Sure, so o n your first question, you know, I think we looked at the short term. The fee relief that we were going to get, instead of using that as a normal step rate over time, we were able to shift that to the earlier years, which in 2021 is really important for our business, so t hat was more of a negotiated point. On the 2024 to 2035, it's really not contingent on us growing volumes.
I think one thing that is important for us to note and gives us a lot of confidence in this deal is when you think about MVCs, you know, we have the coverage to meet those MVCs today, and that was something that we were thoughtful about, pairing that up with our operation schedule, with our inventory, and making sure that we can deliver the volumes to get these rates, and meet our MVCs over time.
Okay.
The interesting dynamic here, though is, you know, we've set this business up. If there was an opportunity to grow with this overrun rate concept, we'd be able to deliver those molecules and get gathering rates at an overrun rate, which is significantly lower than what the blended rate we're showing here on this page.
Okay. Yeah. That was kind of a follow-up I had. Yeah, that green bar is not assuming any substantial overrun rates.
No.
Okay. I guess maybe can you just frame your perspective around MVP in service timing and how you're thinking about the potential risks around that, and how you got comfortable with the January 1?
I think that Etrain will certainly provide some more color on their call today on that. I think we've been consistent by saying 2021. I think the fact that the pipe is 90% complete, I think is definitely positive. I think it's a little bit of a unique situation compared to ACP. All of these that we just heard, I think, last week, would give people indications that the Supreme Court will overrule the Fourth Circuit. With that happening, that would be a direct read-through towards resolving one of the issues that's keeping MVP from crossing the trail and getting in service, so I think that this pipe is going to get built and, you know, we're pegging January 2021 as our best guess.
Okay, a ppreciate it. Thanks, guys.
Your next question comes from Welles Fitzpatrick with SunTrust.
Hey, good morning.
Good morning.
Obviously, the revolver's in good shape, but could you talk to your thoughts about the potential impact of that $600 million a day E&P sale, what that might do to the revolver? Also, would you sell any hedges in conjunction with that divestiture?
Yeah, so j ust to understand, we do not have a reserve-based revolver, and v ery different. We don't have semiannual redeterminations. We're good through, let's call it, end of July of 2022, so t hat's the time period we'd have to go refinance. Any asset sale would have no impact on the revolver today. It's really about our ability to generate free cash flow, retire the rest of the 2021s, and try to retire the rest of the 2022. That's really what the goal is.
The second part of your question, just the impact on our hedging. We're sitting with at 87% hedged right now. Obviously, if we s old that asset, it would improve our percentage hedged.
Yeah, and wh ether we sell the hedge or not, I think that's probably a decision that we would make depending on each independent asset sale that we go through.
Okay, pe rfect, m akes sense, and then f or the follow-up, you guys updated Pennsylvania cost per foot, obviously looking strong. Could we get an update on West Virginia?
Yeah, the o perational efficiencies you're seeing is one part of driving our cost improvements. You're seeing that in both Pennsylvania and West Virginia. To be honest, there hasn't been a tremendous amount of activity in West Virginia, so r eally, it's looking at what we're doing in Pennsylvania as a read-through to West Virginia. I will say that being able to shift more activity into Pennsylvania in 2020, that affords us more time in West Virginia to install the necessary water infrastructure that will lower our costs on the completions front. That will certainly help ensure that West Virginia can be on par with Pennsylvania Marcellus.
Perfect. Thank you all so much.
Welcome.
Our final question comes from Holly Stewart with Scotiabank Howard Weil.
Good morning, gentlemen. A lot to digest here between the two companies. I thought maybe I would just sort of dumb it down here but, you know, l ooking at that, or I guess eyeballing that bar chart on slide eight, it looks like your long-term rate would go down to be to what you're kind of talking about as market rates of roughly $0.40. If you hit above those MVC levels, that rate would fall to roughly $0.30. Is that the right way to think about this over the long term?
Probably somewhere in the high 30s is where I think we check out.
Over the long term?
Yes.
Okay, and then D ave, you mentioned several times revised hedging strategy. I know you all are pretty fully hedged for this year. Can you just sort of talk through what you're doing differently from a revised hedging strategy perspective?
Yeah, so one is duration. We talked about four years. We didn't have a four-year hedge strategy. We will probably enter into the next year at a much higher hedge position. I'll call it somewhere in the same vicinity as we started this year. I think third is we'll be more thoughtful on how we add basis hedges, so we have more visibility on really that differential. We'll use our FT portfolio really to help us with that as well because it gives us, I think, a lot of flexibility to pick and choose which of those locations we want to do and what we're trying to isolate. I think those are really the three major things.
Okay, t hat's helpful. Maybe just one final one from me. Given the magnitude of MVP, this is probably one of the last major greenfield projects, at least it feels like right now, to go into service in the Northeast. Is there an appetite to sort of monetize any of that firm transportation associated with that project either, you know, maybe both speaking from your standpoint as well as that demand pull side up there?
Yeah, Holly, I'd say that, you know, optimizing our FT portfolio is I think one initiative that we're going through that would lower our cost structure. Yeah, certainly MVP would be included in that. Then you couple MVP and ACP would add about another 3 Bcf a day on top of that. I think when we look sort of high level at the basin, about 33 Bcf a day being produced in Appalachia. We've got about 35 Bcf a day of local takeaway and demand, and t hen you couple MVP and ACP, we'd add another 3 Bcf on top of that. So there's pretty decent pipe capacity in the basin right now.
When you think about that and realize that there's only about 49 rigs running in the basin, we think you could see Appalachia start to decline. That's only going to widen the gap and, you know, allow us to sell more of our gas in basin.
Stay tuned, Holly.
Yeah, well, m aybe I would just follow up on that and say, Toby, as you think about all that's going on with producers in the basin and, you know, let's just say we have to enter some sort of bankruptcy perspective from some of the producers, and some of those FT contracts are to be thrown out. How do you think about in-basin basis responding to that?
Well, the pipe's going to be there already. If the question is what the rates will be, that's another equation, I guess, if producers go and sort of break contracts. If the pipe's built already and, you know, if producers go into bankruptcy, the ability to spend capital gets harder.
Sure.
There'll probably be even less production. The pipes will be less filled, and so local basis might be better, but t hat's probably what would happen.
I look at that, Holly, I think that there's, you know, when you look at one of the benefits with Equitrans is they've got such a expansive gathering system coverage across a lot of interconnects. As that capacity frees up on those pipes, it gives our commercial team more optionality to optimize our production, where we sell, and the any access to the markets that we sell to, so I see that could be a net positive.
Great color, guys.
Our next question comes from Sameer Panjwani with Tudor, Pickering, and Holt .
Hey, guys, j ust a couple of follow-up questions on the hedging commentary. I think you just mentioned that the goal is to have the 2021 profile hedge book kind of in a similar position to 2020 as you kind of get to the end of this year. I guess I just wanted to kind of reconfirm that you guys feel comfortable hedging at the current 2021 strip to kind of bolster that position.
Yeah. I'd just say we're going to be a combination of programmatic and as well as an active hedge process. It's a process that takes a lot of time to do, so t hink about it in some cases, dollar cost averaging, t hink about it as being very tactical in certain areas where we can actually hedge at prices we like. We're not going to force and lock in the bottom here. We're going to lock in, I call the commodity as it rallies up over time. For example, we did some basis hedges recently that effectively give us a $2.50 NYMEX kind of floor. We're able to do certain things in different locations to be able to take advantage of what the market gives us at moments in time.
Yeah. Sameer, high level, you know, our activity levels, the returns that we're generating on our operations, understanding what we need to do to take care of our balance sheet, and coupled with our macro perspective on what gas prices will be, are all the factors that we're weaving together to generate the right hedging strategy. I think the progress we've made over the past six months have given us a really good handle on what the operations, the activity levels, the balance sheet looks like. Now, i t's really just figuring out what our view is on the macro, and how much we need to hedge.
Okay, g ot it, t hat definitely helps clarify that. I guess the second question, as it relates to the hedge booking activity, as you referenced. You guys mentioned earlier you have about 87% hedged right now, and if you sold some assets that would, you know, help the percentage. If we put a what if scenario out there of maybe you don't get any asset sales done, would you think about pulling back on the production for this year to better match the hedge book versus the production profile, given where prices are today, or do we need to think about it from a longer-term perspective as you think about the leverage profile as well?
We will always optimize, and so, ac tivity can move in and around from one year to the other. We're going to make sure we do everything on a pure return and economic basis, and we obviously have to take into consideration levered metrics and ability to generate free cash flow and paying down debt. There's a multitude of things that go into it.
Okay. I guess within that, would you guys consider curtailing production without necessarily impairing maybe the 2021 profile from an activity standpoint or anything, but just trying to be a little bit more accommodative of the price on unhedged volumes?
Yeah. We could, because if the commodity basically doesn't give us the return that we want, absolutely.
Okay. Thank you.
With that, I will turn the program back over to Toby Rice.
Thanks, everybody, for your time today. Stepping back, just looking over the past six months, we've made some very big strides on the transformation and evolution of EQT, starting with the organization, bringing in, you know, a dedicated team of leaders to complement the existing staff here. We've aligned the operations with our schedule and evolved well design. We've now, with this Etrain negotiation, we've aligned our infrastructure to our strategy. All of this is going to allow us to be better capital allocators and create more value for our shareholders. In closing, I'd just like to thank the Etrain team and all the work they've done. I know the EQT team, we're excited about the partnership and excited about delivering on the results that our shareholders deserve. With that, thanks, everybody, and h ave a good day.
Thank you again for joining us today. This does conclude today's conference call. You may now disconnect.