Thank you for standing by.
My name is Deanna, and I will be your conference operator today.
This time, I would like to welcome everyone to the EQT, Q3 2024 quarterly results conference call.
All lines have been placed on mute to prevent any background noise.
After the speakers' remarks, there will be a question-and-answer session.
You would like to ask a question during this time, simply press star followed by the number one on your telephone keypad.
I would like to withdraw your question, press star one again.
Thank you.
I would now like to turn the call over to Cameron Horwitz, Managing Director, Investor Relations and Strategy.
Please go ahead.
Good morning and thank you for joining our third quarter 2024 earnings results conference call.
With me today are Toby Rice, President and Chief Executive Officer, and Jeremy knop, Chief Financial Officer.
In a moment, Toby and Jeremy 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 reference certain slides during today's discussion.
A replay of today's call will be available on our website beginning this evening.
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 yesterday's earnings release in our investor presentation, the Risk Factors section of our most recent Form 10-K and Form 10-Q and in subsequent filings we make with the SEC.
We do not undertake any duty to update any forward-looking statements.
Today's call also contains certain non-GAAP financial measures.
Please refer to our most recent earnings release and investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures.
With that, I'll turn the call over to Toby.
Thanks, Cameron, and good morning, everyone.
The third quarter was hallmarked by the closing of our strategic acquisition of Equitrans Midstream, which transformed ETT. into Americas, only large-scale vertically integrated natural gas business.
This combination has created a differentiated business model among the energy landscape, one that has leading inventory duration at the absolute low end of the North American natural gas cost curve.
EQT's position at the lowest cost producer, structurally derisks our business in the low parts of the commodity cycle, while simultaneously unlocking unmatched upside to a higher price environment by eliminating the need to defensively hedge longer term, we believe these characteristics position EQT to generate disproportionate value for our shareholders, regardless of where we are in the commodity cycle.
Since we closed the Equitrans acquisition, our integration team has been sprinting ahead with more than 60% of total integration tasks completed in just three months.
This remarkable pace is a testament to our proprietary integration system, which has been honed across multiple successful transactions over the past several years.
The highly efficient integration pace we've seen to date is resulting in synergy capture our current quicker than we originally expected.
Recall, we had previously assumed based synergies would start accruing by the middle of 2025 for what our integration progress.
To date, we have already achieved $145 million of annualized financial and corporate cost savings, which is $25 billion more than our original underwriting assumptions that another way we have already derisked more than half of our $250 million base synergies in just three months of owning Equitrans.
This rapid pace of base synergy capture, along with longer term system compression upside, further increases confidence in our ability to optimize value from the combined entities.
We are also seeing Equitrans employees are excited to be integrated into EQT's culture.
This is a similar situation to what we observed when we took over etc. In 2019, where the cultural buying of our employee base enabled us to create more value than we originally anticipated.
I'm extremely excited to see what the combined EQT an equity transaction teams can accomplish together over the coming years.
Alongside rapid integration and synergy capture, we are already unlocking operational efficiency gains as a direct consequence of the acquisition.
An example of this can be seen in our investor presentation where we highlight a new EQT record for water delivered to a well site.
This record water delivery pays in turn, Facil allocated another all-time record for completions pumping time, getting our prior record set earlier this year by 10% pace of water delivery of the key factor in completion efficiency put simply the faster you deliver water to the wellsite, the faster you can frac, which in turn drives down well costs.
This record is only possible because of the seamless coordination of our now internal Equitrans water system with EQT's upstream operations highlighting that optimization of the Equitrans water assets has the potential to drive additional operational efficiencies that we could not have achieved stand alone.
We also recently completed the connection of EQT's water network in West Virginia with equity tranches water system in Pennsylvania, which structurally improves our ability to deliver water to well sites.
Disconnection should also say more than $70 million in water disposal costs over the next two years from an investment of just $15 million, highlighting an example of the type of low risk, high return investment opportunities that are unlocked by the acquisition.
Efficient water delivery, along with various other supply chain initiatives are supercharging the recent completion efficiency gains that we highlighted with Q2 results.
During the third quarter, we set a new EQT record for completion efficiency, with footage completed per day averaging 35% faster than our 2023 pace.
The past two quarters of operational performance, along with our EQT grants, integration momentum is increasing our confidence in a sustainably faster complete space, and we see the opportunity to complete 50% more footage per day in 2025 compared to our historic average.
With continued success, we may ultimately be able to drop from three to two frac crews' overtime, which is remarkable.
Given we are able to hold flat seven these activities, we are still quantifying the potential impacts to our capital budget, but we believe these gains could have the potential to sustainably save approximately $50 per foot, which could translate to 50 to $60 million per year.
Shifting gears, we recently announced that EQT has become the first traditional energy producer of scale in the world to achieve net zero Scope one and two greenhouse gas emissions.
Not only did we accomplish this ahead of our 2025 goal, but we achieved this net zero status across the entirety of our upstream operations, inclusive of the recently acquired tug Hill, actually on midstream and all the assets, which are not included in the target originally set in 2021.
This means that over the past five years, EQT has reduced total scope one and scope two GHG emissions by over 900,000 tons, which is the equivalent of taking approximately 195,000 cars off the road annually.
The bulk of these reductions came from structural emissions abatement, including replacing more than 9,000 pneumatic devices shifting to electric frac fleets, deploying combo development and installing advanced emissions control devices for the remaining emissions that are not available with current technologies.
EQT has generated carbon offsets through force management projects as opposed to purchasing third party carbon credits.
This was done via our partnership with the State of West Virginia and includes conservation management practices such as the removal of invasive species, wildfire risk monitoring and native trees and shrubs placement.
All of which have coal benefits for our local stakeholders.
These efforts are verified by West Virginia University, ensuring both economic and environmental benefits to the region.
Over the life of this partnership, we expect to generate approximately $10 million tons of high-quality carbon offsets at a cost to EQT below $3 per ton, underscoring EQT's capital efficient path to achieving net zero emissions.
We believe EQT's unique position as the only vertically integrated low-cost natural gas producer with multi-decade inventory and net zero Scope one and two emissions will continue to open differentiated ways to maximize the value you have each molecule similar to the long-term supply deals, we announced with utilities in the Southeast last year.
With that, I'll now turn the call over to Jeremy.
Jeremy Knop
Thanks, Toby.
I'll start by summarizing our third quarter results for prior to doing so, I'd like to note that results shown on our financial statements include Equitrans for 70 days during the quarter.
So, we've also provided pro forma numbers, assuming a full quarter of Equitrans results for the purpose of comparability to guidance and consensus estimates.
Strong well performance, continued efficiency gains and modestly lower than expected curtailments drove Q3 sales volumes to 581 BCFE for 4% above the high end of our guidance range.
It's worth noting that had we not curtailed.
We estimate production would have come in at 616 BCFE for the quarter or 6.8 BCFE per day, highlighting the true strength of our performance as it relates to curtailments, we have been taking a highly tactical approach over the past few months in response to the volatile gas price environment.
This strategy has allowed us to match supply with demand on a daily basis, thus maximizing our price realizations.
Consequently, our differential for the third quarter came in $0.1 better than the midpoint of our guidance range at $0.65 per MCFE.
Underscoring how this tactical approach is creating value in real time without disrupting operations are impairing productive capacity.
We believe these impressive results prove why tactically curtailing volumes in periods of weak pricing is the right strategy and a volatile world.
The acquisition of equity trends and gives us greater ability to deploy the strategy as it eliminated 4 Bcf per day of minimum volume commitments while simultaneously lowering cost structure to a level that we can maintain steady operations even in the low parts of the commodity cycle.
Rather than being forced to slash activity due to high operating leverage.
Pro forma for the full quarter of EQT's, our operating costs came in $0.05 below the low end of guidance and $1.7 per MCFE due to production outperformance and LOE and G&A expenses below expectations.
Pro forma CapEx was nearly $100 million below the midpoint of our guidance range at $573 million as an efficiency gains and lower midstream and pad construction spending accrued to our benefit.
On the midstream side, pro forma third-party revenue came in at 142 million at the high end of guidance, driven by better-than-expected uptime. NVP capital contributions were $160 million in line with expectations.
Turning to the balance sheet, Q3 was an eventful quarter with the closing of EQT trends in July.
As we discussed in our last conference call ahead of closing, we negotiated an upside of EQT's unsecured revolver capacity from $2.5 billion to $3.5 billion.
At closing, EQT again to all of EQT is outstanding preferred shares, followed shortly thereafter by the redemption of EQM.s, $300 million of bonds due in August 2020 for saving approximately $50 million annually from reduced cost of capital.
Yesterday, we announced the divestiture of our remaining non-operated assets in Northeastern Pennsylvania to Ecuador for $1.25 billion in cash.
Recall, these non-operated assets came with our all acquisition in 2021, and we allocated approximately $1.1 billion of value to them.
At the time between asset level, cash flows and the two transactions announced this year, we expect to realize approximately $3.6 Billion of total value, implying a 3.3 times return on investment since 2021.
We expect this transaction of Ecuador to close by year end, with proceeds expected to be used for debt repayment.
With this latest sale, we have now announced cash proceeded $1.75 billion compared to our 3 to $5 billion asset sale target.
We are simultaneously making rapid progress in our regulated midstream sale process, giving us confidence in achieving the high end of our asset sale target range by year end 2024.
Dusty risks, our balance sheet several quarters ahead of schedule.
Turning to hedging.
Since our last update, we have added a significant number of hedges in the back half of 2025 to bullet proof our deleveraging plan.
Post these additions and pro forma for the non-op sale, we are now approximately 60% hedged for calendar year 2025 with an average floor price of $3.25 for MMBTU for anther upside as high as $5.50 per MMBTU in Q4.
With our updated hedge book and low breakeven cost structure, we estimate EQT can generate free cash flow next year down to a nine next natural gas price of approximately $1 per MMBTU and generate nearly $1 billion of free cash flow at $2 per MMBTU.
Henry Hub prices, underscoring the unrivalled earnings power of our business.
In any scenario beyond 2025, we expect to use commodity derivatives opportunistically rather than defensively as our position at the low end of that natural gas cost curve acts as a structural hedge, which in turn facilitates unmasked exposure to high price scenarios.
By limiting our need to financially hedge.
Turning to Q2, the power markets, which are awakening from to lost decades and becoming one of the most interesting corners of the energy industry with a direct impact on natural gas demand.
Over the course of this year, we have witnessed a reluctance to entertain the idea of gas power generation for data centers evolve into a widespread acceptance of natural gas as critical at the same time, more than 80 gigawatts of coal generation capacity is scheduled to be retired by 2030 and nearly 200 gigawatts by 2035, leading a hole in the U.S. baseload power stack, they can only be filled quickly by reliable natural gas generation.
We expect natural gas to take 50% to 80% of new power generation market share has intermittent renewables are not suited for 24 seven reliabilities, and we believe there are just a handful of more nuclear facilities that can be restarted through the end of the decade.
These dynamics are giving us greater confidence in our base case view, the data centers and additional coal retirements will drive up to 10 Bcf per day of incremental natural gas power demand by 2030.
Notably, this demand will be regional in nature with more than half likely to come from the Southeast in PJM markets.
Given EQT is the only large-scale integrated natural gas producer with exposure.
To these reasons, we stand ready to support and directly benefit from this megatrend.
Turning to fourth quarter guidance, we've made some modest tweaks to our prior outlook.
We now expect fourth quarter production to range from 555 to 605 BCFE, up 7% from our prior outlook of 515 to 565 BCFE due to robust well results and less curtailed volumes than we previously expected.
Amid an improving app Appalachia price environment.
For perspective, we estimate our 2020 for production is tracking above the high end of our original 2200 to 2300 Bcf.
The guidance range when normalized for curtailments demonstrating the strength of this year's underlying performance before the impact of our decision to curtail production.
Looking into 2025, we still intend to maintain flat year over year sales volumes, pro forma the transactions with Ecuador around 2100 BCFE and expect a pullback activity if efficiency improvements continue to pull forward volumes on basis differentials, we are tightening our fourth quarter differential guidance range by $0.05 to 50 to $0.6 per Mcf as eastern storage levels have normalized improving local pricing.
This winter.
Looking at operating expenses, we are lowering the midpoint of our fourth quarter operating expense guidance range, $0.05 per MCFE, largely driven by higher volumes and lower upstream LOE and G&A expenses.
Note, we reallocated some expenses within our GPNT. outlook as we fine-tuned.
Our pro forma accounting for Equitrans, but this had essentially no net impact on our total GPNT expenses on CapEx, as I mentioned previously, third quarter spending came in nearly 100 million below expectations with part of this variance driven by pad construction shifting from Q3 into Q4.
This shift, along with embedding some conservativism around non-op spending, drove a $50 million increase in our fourth quarter capital guidance.
That said, our total second half spending is still trending below the midpoint of guidance.
We put out last quarter by a net $15 million, reflecting the official currency gains referenced previously at MVP.
We have fine-tuned estimates for slightly higher capital contributions to complete the right away reclamation post hurricane Helene and a slightly lower distribution in the fourth quarter, simply driven by payment timing at recent strip pricing and pro forma the non-op sale, we forecast cumulative free cash flow of approximately $14.5 billion from 2025 to 2029 at an average natural gas price of roughly $3.50 per MMBTU at $2.75 natural gas prices, EQT would still generate approximately $8 billion of five-year cumulative free cash flow was about $5 gas.
This number swelled to almost $25 billion, which we can realize as we do not need to defensively hedge.
There is no other natural gas business that comes close to provide in the same combination of downside protection and upside exposure for investors.
We believe EQT is now in a classic zone.
Our simple goal is to be too easy to own way for investors to gain exposure to natural gas, meaning if you were at the medically bullish natural gas, whether it's because of coal retirements, power growth, LNG exports, dwindling core inventory, bearish oil prices due to OPEC oversupply or anything else, we are positioning EQT to be the go-to natural gas stock, and it's a through this cycle fixture of your energy portfolio.
We see our story increasingly resonating with long-term investors who trust we will continue to operate from the same principle framework that has brought us success to date.
Compounding cash flow year after year.
And with that, I will turn it back to Toby for some concluding remarks.
Toby Rice
Thanks, Jeremy.
EQT today is operating at the highest levels of efficiency in history and quarter-after-quarter.
We continue to break records.
We've built an unrivalled integrated natural gas business with the key catalyst for continued value creation.
We have high confidence in the successful completion of our deleveraging program and continuing our long track record of delivering on our promises to shareholders ahead of schedule with better-than-expected results. And with that, I'd now like to open the call to questions.
Operator
At this time, I'd like to remind everyone in order to ask a question, press star then the number one on your telephone keypad.
Please only ask one question and one follow-up. During this time.
Your first question comes from Doug Leggate with Wolfe Research.
Please go ahead.
Doug Leggate
Thanks, (inaudible).
Good morning, guys.
Sunday, gosh, you guys are moving quite quickly on the Sunday.
Congratulations on from what you've done.
But Toby, I guess I am never happy with the pace, especially given that you're moving a lot faster than perhaps you initially guided.
So, my question is I look at Slide 6, which is obviously your progress on the $250 million.
And then I look at slide 25, which is the upside case to 425 on how would you how would you help us think about the timing on derisking of from both those numbers, particularly the upside synergies from Pinterest for optimization?
Toby Rice
What I'd say we're ahead of schedule, both from a time perspective and realizing synergies that are a little bit greater than what we anticipated.
What's in front of us now really are the synergies related to the operational execution and does the pace at which were movement in this integration being 60% through this may help frame those up a little bit better.
And Doug, those are synergy capture estimates will be folded into our 2025 budget, which we're currently working through, and we'll provide updates in future calls.
Doug Leggate
Okay.
Because of all again, and that seems to be somewhat ahead of what you were expecting to be.
My next question is, are mindful of others a little bit tricky to us come not quite sure how to articulate it.
But if I look at the volatility of gas prices through the third quarter and then ultimately the way that you abide volumes, I'm trying to understand how malleable the I mean, how easy is to bring things on off in response to pay price.
And what was behind my question is you no longer have any MVP. obligations really relate to your ownership of Wellbutrin.
So, you have tremendous flexibility to really navigate run very short term versus price.
Is that how we should think about this curtailment strategy?
Or what am I thinking about it wrong with them?
Toby Rice
Yes.
I think it's really important to understand.
And I think the dynamic that we laid out on slide 21, which is a framing up sort of the natural gas market characteristics and how they've changed, I think, was a really powerful start that sort of supports the fact that we're going to be in a more highly volatile world going forward.
Howard.
And the question that people need to ask is how these businesses are going to perform in this more volatile world where you're going to have lower lows and higher highs on the way that our business is going to manage in those low-price periods is really two things.
It's the integrated is the integrated nature of our business, which, as you mentioned, will give us tremendous flexibility to by removing MDC's that we had in place.
So, we've listed a huge constraint and have more flexibility there.
But the other thing that's going to allow us to curtail that's equally as important is having a super low-cost structure and that will give us the ability to curtail volumes and not have to alter slash activity levels.
What that means is that when those higher price environments show up, we're going to be positioned to capture that.
And we're not going to be sitting six months.
Our production is not going to be sitting behind six months of restart.
It's something that we can turn on some pretty rapidly, and that's a muscle that we've been flexing in the past.
And this is going to be a muscle that's going to be really important in this environment that we're looking at.
Jeremy Knop
Doug, if you look at Q3 specifically and we had been turning on and off up to a Bcf a day on a near daily basis in response to where pricing is, that is really the reason we've realized that $0.1 better differential this quarter as has been able to tactically do that now I think in a low price environment, that's a great tool.
It's telling hedging type basis hedging away.
And when you look at that chart, Toby reference on page 21, 60% of the data points you see on that bottom chart are really below $3.
So about 20% of those are below $2.
And that in that environment, that's generally where you're going to see us turn volumes off because of the you just can't make money there.
The rest of that time.
And we plan to be supplying gas to the market.
And so, it allows us some of the lead the loan was out of us out of our sales volumes, but there's still be positioned to capture the highs.
And so if you look at the data shown there, the difference between the median and the averages over $0.8, and that's effectively the difference if you pursue the strategy we're pursuing for you don't have to hedge away at highs, but you still are protected against below as you can curtail and you have a structurally resilient business at $0.8 for us over, you know, to (inaudible)or production is a tremendous amount of value added at certainly when you look out long term.
So, it's very hard to model for that.
I think the character of the market, as I keep talking about is United discussed a lot is changing, and that's how we're trying to position it does.
Doug Leggate
Pardon the clarification and I of course, I'm NNBC. and INVP. and you got to and pipelines, I guess, but just to be clear, so when we looked at the volatility intra-quarter in your curtailment's strategy, you have the ability to basically pick your spots.
And therefore, because on your best friend does otherwise, we should think about it,
Jeremy Knop
correct.
Doug Leggate
Thank you.
So, I was looking for.
Thanks, guys.
Appreciate the time.
Got it.
Operator
Next question comes from Roger Read with Wells Fargo.
Please go ahead.
Roger Read
Yes.
Thanks.
Good morning and appreciate the clarity on that previous question.
I think a lot of us for a figure that out on the curtailment side.
I think one of the other questions I have is still early days, obviously with the macrotrends acquisition.
But as you think about synergies and a 25, maybe a little bit of a what have you seen that surprised you so far, what do you think it might take a little bit longer?
And just trying to get the idea, you know, we're used to companies setting a synergy target and now performing at.
Yes, I think that's something that's likely to play out for year.
Toby Rice
Yes.
So, the biggest thing for us operationally, which I think Jeff, most of the conservatism baked in in the synergy estimates really as outlined on slide 26 from the uplift we're going to see from compression from.
It's important to know when we framed up that synergy, we were assuming a 10% uplift from the benefits of compressed adding compression.
And these pilots that we're showing there are showing that we're seeing nearly two times at uplifts.
So that will be helpful.
Timing is a timing on when we can get these.
These compression projects rolling at a larger scale is going to be the big determining factor.
And the team has been hard at work and that will be putting those projects into our budgets of timing.
And all that will be framed up in our 25-budget plan.
Roger Read
Okay.
And then my other question is, obviously things have gone fairly well on the asset dispositions, the non-op stuff you cited.
I think we've seen rumours in the press about MVK. sale.
If you're able to generate more cash just from operations in addition to the asset sales, what's the right way to think about how you would have right sized the balance sheet, meaning how much of a premium would you have to pay on a debt to retire early?
And I'm just trying to think of about it as you build cash to return cash and pay the debt off in a more methodical pattern?
Toby Rice
No, I we've been spending a lot of time on this.
I think we had a pretty efficient plan to eliminate the debt that we have in front of us and smooth out our maturity stacks.
And so, I don't expect any sort of inefficiency that come out of that.
I think it will be pretty straightforward.
Roger Read
I appreciate it.
Thank you.
Toby Rice
Thanks.
Operator
Our next question comes from Neil Mehta with Goldman Sachs.
Please go ahead, ma'am.
Neil Meht
Thank you, Team and congrats on making progress on around the asset sales.
Hey, you mentioned in your prepared or prepared remarks, he has spent a lot of time in the power markets.
Just curious what your real-time assessment is around the AI. in data demand and status center theme?
And how do you see that specifically in the Marcellus is do you see a case for a step-up in at in in-basin demand around data centers as well?
So just any real time conversations perspective and a mark to market of your views as he kept on the forefront of this.
Toby Rice
Yes.
So, we lay out sort of our plan on 16.
We're seeing between 10 and 18 Bcf a day of demand growth for natural gas due to power some of the real times data that we're looking at because this is the question is a I don't know, power generations coming, what percentage of that is going to be natural gas.
So, like a lot of you were looking at the orders that are coming in for natural gas turbines.
And you see one of the largest turbine manufacturers in the world, Mitsubishi seeing a 50% increase in their orders are 90%.
So, while this stuff isn't making the headlines of how much market share natural gas is taking, the orders are building up and in strengthening that natural gas is going to continue to be the workhorse of that as a lot of this power demand.
And just looking at the baseline of what we've done over the last 10 years means natural gas and power demand, needs requiring 14 Bcf a day.
That's what we've done over the last decade.
Not a lot of people have talked about it about that.
That was largely driven by coal to gas switching, which is still a theme going forward.
And now you add on to the power generation growth from AI. and it's not too hard to believe some of these numbers that were put forward.
Neil Meht
Toby, we've seen in nuclear restart in PKMBC. and some talk about at the license three extensions on the nuclear side as well.
As you think about competition for that natural gas demand, how do you think about the alternatives, whether it's renewables or nuclear and how does that fit into the mat fourth for the TAMP around this market.
Toby Rice
On nuclear, there was some we looked at what would be the other options like three Mile Island that could come back online.
Keeping in mind some power demand growth investments is around, call it 70 to 80 gigawatts.
Our view on this, looking at similar nuclear facilities that would have the potential to add about three gigawatts of power demand relative to what's required.
It's a drop in the bucket.
It's not meaningful, and it still needs to happen.
But the world is going to be looking for fresh, reliable, affordable energy sources of that's going to be that's going to mean more natural gas.
And that's what we're seeing in the order books when people are looking to pick up disturbance.
Neil Meht
Thank you.
Operator
The next question comes from Jake Roberts with TPH.
Please go ahead.
Jake Roberts
Morning.
Toby Rice
Morning.
Jake Roberts
Just wanted to see if we can hit on in early 2025 work.
But looking at Q3 and Q4, excluding shut-ins, I think the run rate closer to 2400 and should the market be thinking about slight declines on your production based in 2025, given the earlier comments kind of a 2100 level net of the sale?
Toby Rice
Yes.
Look, I think from where we are within the year, I think we're in a period of time right now.
So, I do expect that to come up a little bit is we get into 2025.
And but I would say year over year, we see it is relatively flat growth on our remaining assets that we've not divested.
Jake Roberts
Okay.
I appreciate that.
And then lastly, I know there are always noted the production and capital impact from the non-op sale.
Should we be thinking about any changes to operating expense?
Toby Rice
No, I wouldn't say materially at this time.
Jake Roberts
I appreciate that guys.
Operator
Your next question comes from Kalei Akamine, with Bank of America.
Please go ahead.
Kalei Akamine
Good morning, guys.
Thanks for getting me on.
My first question is on operational synergies, water in particular, can you talk a little bit more about how putting water in the right places can help you drop one frac crew?
Are you simply cutting the standby time?
When could this happen?
And what does the impact on capital look like?
Toby Rice
Yes, it's pretty simple.
When we look at the driving factor for completions efficiencies, it's the amount of FEED contract per day that is driven by the amount of hours that were pumping per day.
So, we look at the EQT and when we're not pumping for us a big part of that nonproductive time, which was waiting on water, we've eliminated a large part of that.
So you take out a lot of NVT. time.
You replace that with a pump time and your 40s per day increases.
So if you can increase your efficiencies by 30% and you're running three frac crews, you've positioned yourself to get the same amount of footage and have 33% less frac crews.
And that's what we're set up come in and monitoring the bake that into the 25 plan.
From a cost perspective that could translate to about $50 per foot of savings are roughly $50 million per year of operational efficiency value.
Kalei Akamine
And Toby, to clarify, is this in your synergy target, I guess from our perspective, it's hard to tease out what the synergy and with the natural evolution of your business and as opposed over time, that's going to make it more blurry.
But just to be clear, is this the target or or is this separate,
Toby Rice
That would be separate?
That was not included in our synergies.
Kalei Akamine
I appreciate the clarity on the second one goes to gas balances and it gets it's two parts.
First, can you remind us on curtailments how much you currently have and how you're thinking about bringing that back and you look at the winter in-basin pricing?
And then on NDP. understanding is that it can flow more fully in the winter.
Toby, can you give us an idea what that looks like?
And then what that what could that look at that need for headline in basin production numbers?
Toby Rice
Yes.
So on the first question of what we have curtailed, we've been fully back online for several weeks, actually.
So I wouldn't expect when you're looking at your gas balances, that EQT is bringing back on additional one Bcf a day, which we had curtailed at the peak.
But that's already back, it's been back on.
And so I think is everyone's trying to look at their gas models.
I think that's a pretty important factor in look, we did that because the market showed that there is a need for that gas.
It was above our price targets.
And though is you look at our improved guidance for Q4 for a lot of that's because the assumptions we had previously made for curtailments in October just haven't played out.
We just haven't needed to curtail in response to what the market's told us.
And so that's why you've seen that move up in addition to better well performance.
And then in your NBP question, look at the assumption we are making is effectively that between December and February, NBP. should flowed at full capacity or Nerites as you see that, that's hard open up and there's that downstream demand.
So that's effectively what you'll see baked into our guidance
Kalei Akamine
Awesome and I appreciate that.
Thanks, guys.
Operator
Your next question comes from David Deckelbaum with TD. Cowen.
Please go ahead, ma'am.
David Deckelbaum
Morning, guys.
Morning, Toby.
Thanks for taking my questions this morning.
I was I was hoping that you guys could give a little bit of color and update around the regulated asset sales process of just given the success of the non-op now, how do you think about time line?
I know that you have a year of 25 that target.
So presumably, I guess you have roughly, I guess, 15 months or so before we get down to that level.
This is something you want to get it done sooner than later.
And then as you think about selling those a portion of those assets, is there a right ownership percentage that you would like to retain outside of just the controlling stake?
Toby Rice
Look, I think we've provided pretty good clarity of the structure that we're pursuing in prior calls.
We've been pretty open about that.
I don't think there's going to be a deviation from what we outlined previously.
There has been robust interest.
I said a cost of capital that we are seeing and it exceeded our expectations.
I think the quantity of Canada, there's high quality, natural gas gas pipes like this is above expectations.
And I think that's really what's pushing forward to our expectations, like we said in prepared remarks of when when a deal gets done.
But beyond that, look, we're in discussions with parties are working through that.
We hope it's sooner than later, but it's certainly above our original expectations were ahead of our original expectations.
Which initially we had to be in the first half of next year.
We expect that to probably get done before the end of this into this year.
David Deckelbaum
That's helpful.
If I could just ask one more.
You obviously are I know the industry has focused on this, a I, um, power-generation somatic and you talked about obviously the regionalization of demand with a lot of that proliferating in the Southeast for EQT has a ton of egress, VMBP. and expansion.
I know that you guys I have already guided to, obviously benefiting from the firm demand, the contracts that you have in place in late 27 with the Transco expansion with utilities.
As we think about AI and its commercial impact of EQTA., you talked about and benefiting from this directly is sort of what is like the remaining quantum.
If you see this proliferation in the southeast of how much more, we could see contracted on top of those firm sales.
And that is something that is much more of a 2030 and beyond expectation or should we expect the potential for incremental basis improvement between now and the end of the decade?
Toby Rice
Yes, great question.
So in our view on Appalachian demand and include West is taken or is it really exported out of face and plus in-basin demand, we think between now and the end of this decade, that should increase to from about 35, 36 Bcf a day to about 42.
So effectively adding the whole energy to key in terms of demand.
And I think that is overlooked in many ways.
And really in our in our assumption, no new pipes are getting the Delta side from the expansion we expect to pursue on NBC through the compression that we've talked about previously.
Beyond that, it's really in-basin demand.
And when we step back and think about how that plays out in impact, our business is either one of two ways is probably a combination of both.
one we can get tightened in basin differentials, but it all it also allows us to grow.
Sales were up really a price times volume business.
We expect to see benefits on both sides of that.
And now in our new integrated business model, we effectively control a lot of the toll roads in the basin.
We expect to be the ones that probably disproportionately benefit from that growth where we can connect our low cost decades of supply to those different sources of demand as they come online.
So that's something that we're hyper-focused on.
And that's one reason we haven't gone out to other plays because we do see that backdrop playing out in Appalachia.
And I think we're as well-positioned as anybody to benefit from that.
David Deckelbaum
Appreciate that color.
Operator
Our next question comes from Josh Silverstein with UBS.
Please go ahead.
Josh Silverstein
Good morning, guys and what does the last quarter
You talked about an initial outlook for spending next year on the three to six range.
Given the efficiency gains that you guys have seen this year than out of sales and a pending midstream sale.
Do you think of the lower end of that range is now more likely relative to the initial views.
Toby Rice
So, if you're at a high level kind of bridge that and just start with the midpoint for ease of discussion, the midpoint of that range we gave out was (inaudible) than non-op sale, removes about $75 million out of 2025.
On the efficiency gains we referenced in prepared remarks, we equate to about$ 50 million of additional savings beyond what we had assumed at the time.
So, I would expect that to probably be towards the lower end of that range at this point in time.
But look, we're still working through it and to figure out exactly how we might be even put some of those savings into accelerating some of the midstream synergy.
So it's a work in process, but I'd say directionally, things are moving to the positive side of that range that we looked at preview.
Josh Silverstein
Thanks.
And sorry to come back to the curtailments, but I'm curious what specifically in the markets you guys see to bring back all of your volumes that were previously curtailed Henry Hub in the fourth quarter, pricing is lower versus when you announced the 45 Bcf of expected for settlements for the fourth quarter.
Is it something in Appalachia?
Is there something else or what is it that you guys are looking at it that we should be thinking about going forward, the kind of adjust our quarterly numbers for you guys?
Toby Rice
Yes.
So all the volumes, we curtailed volumes that we are selling into Appalachian market and those are in excess beyond what we have had a database.
And so, the number we're looking at in Appalachia is about a buck 50 it into.
So, when you see into above that, you should assume we're generally going to be flowing at full capacity.
When it gets below that, you'll see us pull volumes off them market and that it at a higher level is really our cash costs, excluding this sort of integrated midstream payments, we pay ourselves plus F & D about that, but 50 level.
And so, when you kind of put that all together, I think about what it means for the gas market.
I think there's kind of three bands of the way you'll see their market evolve in the next 12 months, call it, I think you will contain this for a ping-pong between $2 and $3 until all curtailments are back online because as you approach three, all of that should come back online.
I think there's a second band between probably three increased 50, where you see some of the short-cycle docs and deferred tills sitting out there.
This of our peers have I would expect that the band with some of that starts coming online.
So, you see that additional resistance level.
But I think once you get beyond that need to add real activity and there's a delayed effect to that, as we saw on the downside is delayed effective production falling.
There's a delayed effect to production at resuming growth when Active Beauty is added.
And I think the longer production stays down where it is them the more difficult it is going to be it bring it back.
So going back, that's 21 that we referenced.
I think we're likely to set the kind of adapt below $3 level until you see a lot of this production back in very quickly.
You're going to snap towards the high end to that level as you get towards the back half of 2025 and into 2026, which is also why we hedge the way we have.
We remain unhedged in 2026 and highly exposed in Q4 next year.
But I think it is going to be it has to get back to that level at putting aside how when it goes.
(inaudible)
Operator
Our next question comes from Bertrand Donnes with Truist Securities.
Please go ahead.
Good morning team.
You mentioned that the production should be kind of directionally flattish on the remaining upstream assets, historically that we've seen some operators attempt to take advantage of shoulder months shape their production.
Should we expect to see that come about naturally as you use curtailments throughout the year next year?
Or is that strategy just not viable anymore because of the loss of inefficiencies you tried to bring all those wells on at once?
Toby Rice
Yes, that's never really been our strategy.
I mean, we've always done really focused on on most of that really do have sufficient lead us to operate and execute, which is not related to start stop nature of that operations cadence, but you need to need to execute to pursue that strategy.
So, I don't think, you know, at least from EQT, you're going to see that sort of a seasonal up and down that you see in the market more broadly, we're out of Appalachia and more broadly.
And I think for us, we tried to run that pretty consistently.
You will see like like in Q3 this year, there are some quarters that will be higher than it to be flat until there's a real need in the market for that production, which I think you'll see in terms of Henry Hub pricing rising and local basis being relatively tight.
Makes sense.
And then this on a little more more pointed on the on the timing of the asset sale.
Obviously, you've got a pretty strong price on the non-op, but we've got a few questions on maybe selling assets with low capital requirements during the lower near-term gas pricing.
So maybe you could talk about how you balance selling assets versus achieving your lead average target or maybe or buyers just willing to look past near term gas prices.
And we should all just everybody started looking at 26.
We made a deal with AMD.
Toby Rice
Yes, I'd characterize it at least in our view of the assets we sold this way and a under how we would have underwritten it.
We still see it as like a three PPV. 10 before-tax type value at about three 50 gas.
So, we felt like despite what upfront price it is on the strip, we got we have pretty good value for it.
And that includes value for the Upper Marcellus, which we think in Northeast Pennsylvania in the next couple of years is going to be predominantly driven by Upper Marcellus development.
And there's just not a lot of core lower left.
And so, I think for us, we're really happy with it on just an intrinsic value basis.
And you know, taking those assets, specifically the next five years, we estimated would generate about $250 million or $750 million of free cash when we receive $1.25 billion right now without the effect of discounting.
And so again, we feel like really happen no matter how your kind of valuations pretty strong.
If you compare it to the deal that we did also with equity or six months prior on yad two real differences, one back into that curve has come down probably $0.5.
So that impacts value that prior deal also had the asset swap component.
And so that obviously monies that a little bit that was also a strategic asset for them out of US onshore operations is probably some element of a premium for that.
But overall, we feel like it's an it's a really strong outcome out of the entirety of the process.
And just to clarify on the on the (inaudible) do the work both ways if you were saying that you've got value for later periods of strip pricing, are you seeing that on the other side, when you're looking at potentially acquiring assets, does that does that work with sellers as well?
It's all CapEx.
Toby Rice
I think 80, it just depends.
It's kind of hard to say.
And it just depends on the environment.
And I think for core assets, you're more likely to see value for those that that longer term inventory.
And but I think in the mode we are in right now.
Now we've gone through it would tell you now like to think of as like a transformation or the Keno last five years, that M&A has been a very key part of that path to transform EQT to the into the lowest cost producer with most inventory.
I think where we're at today, it is no other assets out there that compare to what we've built.
So, I don't think we're as focused on M&A going forward.
I think we look at if we had extra cash available, where can we actually put that to work acquisitively and by the most duration of inventory at the lowest cost and this just buying shares back historically, we haven't really had that option because we didn't to our business wasn't the character of what it is now.
But I think going forward, that's what you're going to see us focused pretty heavily on at once we clear the balance sheet and ensure that through the cycle, we have the ability to do that with confidence.
Thank you.
Operator
Our final question for today comes from Noel Parks with Tuohy Brothers.
Please go ahead.
Hi, good morning.
I was really interested to hear your comments about (inaudible).
Just as you have become more and more integrated again, your thoughts about volatility going forward and dumb, do you see us reaching a point where this greater volatility winds up reflected in the script?
I'm thinking about how low the liquidity is out, you know, beyond a year or so compared to what we saw in prior areas registrations, more speculative capital out there.
So just curious what your thoughts on that.
Toby Rice
I think I mean, what the market will be short of its storage capacity and the way to incentivize more storage capacity to get billed, especially like short-cycle self-storage is unique seasonal spreads to widen out and sought.
So, I think is the market evolves in the years ahead.
I think you see summer winter spreads widened out quite a bit from where they are because that's the incentive to build that storage capacity.
I think the other place you will see that begin it expresses and the options market.
And so that's what I'd be looking towards in terms of like how the market in a price that extra volatility.
Got it, storage again, always on always comes from the far sooner or later and
Just wondering as you one of our outlines your strategy around curtailments, and I'm just how close can be useful. Do any scenario that you look at contemplate the possibility of LNG capacity that had been planned to get pushed out and its startup.
And with your strategy, I just trying to get a sense of whether that could actually be something favourable for you is some sort of that demand burst some given your low-cost structure and everything does get delayed or more or less neutral effect.
Toby Rice
If that happens on gas prices would react much more lower prices.
And I think it's going to reflect on why we work so hard to position this business really get our cost structure to where it is to withstand those low-cost environments and not have the correct sale activity.
I mean, I think it's just a matter of time for this gas demand comes and being able to get through those troughs and remain unhedged, you can take advantage of higher prices when that demand does come on is how we've set up the business.
I think it's the volatility that will come, whether it's LNGO or weather event ends, or geopolitical instances mean step back and look at the last few years, we've seen some major things happen that have created some up pretty big opportunities.
We're busy in the business to be able to take advantage of those.
And I think to your prior question on like pricing in the strip, I think it's the dynamic that we've proven in the third quarter that being able to curtail opportunistically as translate to higher realized pricing.
I think that opportunities that would be hard to model when you look at companies and just pick a gas price because we are going to be moving our volumes, curtailing them and and and optimizing for better pricing.
Noel of your question, and we tend to think about what exactly you mean by some of this to your question is getting asked, for example, and Golden Pass or other facility is getting delayed total call at the back half of next year.
I think one of the most foolish things for the gas market right now is it all that capacity comes online in a very short amount of time.
So that's still a really comes online towards the end of 2025, along with other facilities instead of it slowly and progressively, I think three asset comes online in very short order over 365.
That's a Tcf of incremental demand.
Producers simply cannot respond that quickly.
And that is a that is a material swing in U.S. balances.
If that happens actually for a while, it is a little more bearish near term, I think once that happens and as you get into 2026, that is unbelievably bullish and so, look, we're going to be opportunistic.
I think we're going to be well positioned for whatever happens either way.
And but that is that is kind of the silver lining to some of this getting delayed and really getting stuck together all the time potentially in the back half of next year.
Right.
That was exactly what I was getting at your remark earlier about the longer prices stay stay low and it suppresses overall industry activity, the harder it is to come back beyond docs and kills to build activity back to that.
We've got what kind of what I was thinking for Thanks.
Operator
All right.
Thank you all for joining.
That concludes today's call.
You may now disconnect.
