EQT Corp (EQT) 2024 Q2 法說會逐字稿

(Operator Instructions)

I'd now like to turn the call over to Cameron Horwitz, Managing Director, Investor Relations and Strategy.

You may begin.

Good morning, and thank you for joining our second quarter 2024 earnings results conference call.

With me today are Toby Rice, President, 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 follo.

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 and 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 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, Cam, and good morning, everyone.

This week marked a significant milestone in the history of our company as we close the acquisition of Equitrans Midstream, transforming EQT into America's only large-scale, vertically integrated natural gas business.

To put the significance of our combined company into perspective, EQT's assets now encompass nearly 2 million acres of leasehold, producing more than 6 Bcfe per day with almost 4,000 low costs remaining drilling locations.

More than 2,000 miles of gathering lines with greater than 8 Bcf a day of throughput, nearly 500 miles of water lines, 43 Bcf of natural gas storage, 800,000 horsepower of compression, almost 950 miles of critical transmission infrastructure, plus the newly commissioned 300 mile Mountain Valley Pipeline, all of which are located at the gateway of Appalachia and ideally positioned to serve growing US and international natural gas demand for decades to come.

This combination creates a differentiated business model among the US energy landscape as EQT is now at the absolute low end of the North American natural gas cost curve.

A low cost structure is the only competitive advantage one can have in a commodity business.

And with the closing of Equitrans acquisition, EQT's unlevered free cash flow breakeven price is projected to be $2 per million Btu which further downside potential upon synergy capture.

This cost profile structurally derisks our business in the low parts of the commodity cycle, which in turn eliminates the longer term needs to defensively hedge, thus unlocking unmatched upside to higher price environments.

We believe this sustainable cost structure advantage, combined with our scale, peer-leading inventory depth, low emissions profile, and world-class operating team offers the best risk adjusted exposure to natural gas prices of any publicly investable asset in the world.

I also want to welcome Equitrans' employees and shareholders to the EQT crew.

We are excited to get to work unlocking the full potential of our combined company's asset base

.

With the acquisition closing a full quarter ahead of our original time line, we estimate savings of nearly $150 million relative to our initial underwriting assumptions, even before synergies.

We're also able to more rapidly mobilize our integration team, which has a proven track record of turning around EQT and efficiently integrating three large scale acquisitions over the past several years, including seamlessly onboarding and entire midstream division with the XcL acquisition last fall.

This accelerated closing amplifies our momentum and pulls forward our timeline to synergy capture.

We have continued to study synergy potential since announcement and have identified further upside potential driven by completion efficiency gains through water asset integration, which is on top of early compression uplift results that are exceeding our high end synergy assumption.

And we plan to share additional details as our teams worked through the integration process.

Shifting gears, June 14, 2024, marked a historic moment of progress for our country as natural gas began flowing through Mountain Valley Pipeline.

The gas moving through this critical infrastructure will provide low cost, low emission energy to millions of Americans while strengthening our National Security.

The upstream development underpinning flows on MVP will generate hundreds of millions of dollars of royalties every year to local communities in the Appalachian region, while supporting well-paying private sector jobs.

Downstream, the delivery of low cost Appalachian gas will strengthen the competitiveness of American manufacturers whose energy input costs will be a fraction of the price paid by global competitors, which should further support our manufacturing renaissance in America.

MVP will also provide utilities access to cheap, reliable fuel to power Americas data center and artificial intelligence buildout, which is one of the strongest secular growth stories in the world.

Since announcing the Equitrans acquisition earlier this year, we have fielded significant inbound interest from end users of gas in the region, underscoring the depth of demand in the value of EQT's MVP capacity.

MVPS volumes alone are estimated to reduce carbon emissions by up to 60 million tons per year via displacement of legacy coal generation, which to put in context, is 5 times the emission reductions associated with Tesla's electric vehicles.

In fact, thanks to MVPs completion, EVs in the Southeast region can now run on low emission EQT gas delivered through MVP rather than the coal generation powering many of them today.

Given the regional exposure, upstream inventory depth and counterparty quality, we believe MVP is among the most valuable natural gas pipelines in the world, and EQT is honored to be the operator and steward of this critical infrastructure.

Turning to second quarter results, we experienced yet another quarter of operational outperformance marked again by incremental efficiency gains.

A tangible example of this on a recent Mallory C Pad in Lycoming County, Pennsylvania, where our top hole rigs recently drilled the fastest well to kickoff point in EQT history, with the overall average drilling time to kick off point across the pad being 25% faster than the offset wells we drilled in 2022.

This efficiency improvement is resulting intangible well cost savings as the average top-hole drilling costs on the Mallory C Pad came in at 14% below our pre-drill estimate.

Within completions, recent improvements in logistics planning and water throughput have driven materially faster completion times on our latest wells.

Our average footage completed per day is up 6% year over year thus far in 2024.

But our most recent pads implementing new logistics techniques have outpaced our average 2023 completion speed by more than 35%, indicating the potential for material future capital efficiency improvements.

Notably, this average excludes a pad we are currently fracking, which to date has been completed footage per day that is a whopping 120% faster than our 2023 program average and set a new EQT record with more than 3,200 feet of lateral completed in a single day.

As I mentioned previously, we believe the integration of EQT and Equitrans water systems can help sustain these completion efficiency improvements.

And streamlining water logistics is one of the most imperative elements to systematically increasing completed [footage] per day.

Despite efficiency gains accelerating activity into Q2, our second quarter CapEx still came in below the midpoint of our guidance range, highlighting how operational efficiency gains are driving tangible for a well-cost savings.

Alongside well cost savings, we are also seeing strong well performance across our asset base base, which drove upside to our second quarter volumes despite price-related curtailments.

As shown on slide 6 of our investor deck, this represents a continuation of the track record of productivity gains that have been a hallmark of EQT since new management took over in 2019.

Over this period, third-party data shows, we have seen a nearly 40% improvement in average EUR per lateral foot, while most of our peers have seen productivity degradation as core inventory is exhausted.

As a result, EQT is now generating the highest average EUR per foot of any major operator across the Appalachian Basin.

I also want to highlight this productivity improvement has come despite a material increase in field pressures across Equitrans' gathering system over the same period, which essentially makes it more difficult to flow our wells.

We see significant upside from investing in compression to lower system pressures, which in turn should be further improve well productivity and further reduce our upstream maintenance capital requirements in future years.

On slide 7 of our investor deck, we highlight data from three recent infield examples showing how impactful adding compression and lowering line pressure can be on existing wells.

After lowering system pressures by approximately 300 PSI, we saw per well production rates immediately jumped by roughly 50% on average across the three projects.

Over the first 12 months post pressure reduction, we forecast cumulative production gains ranging from 18%, 27%, which in effect lowers our base PDP decline rate and we believe will translate to higher EURs per well.

Notably, the average production uplift from these projects is approximately 2 times more than what we assumed in our $175 million per annum of upside synergies with the E-Train deal, indicating potential for even more positive benefit than we originally expected.

These concrete examples underscore the impact of adding compression to lower system pressures on thousands of producing wells that comprise EQT's base production.

This uplift on base volumes should in turn, allow us to drill and complete fewer wells to maintain production, driving sustainable improvements in long term capital efficiency.

We are currently in the process of identifying optimal compression locations across the E-Train system and expected tailwinds from lower maintenance capital to begin accruing in 2026.

Turning to our recent ESG report, I am proud to highlight that we took another material step forward towards our ambitious environmental goals as our 2023 Scope 1 and 2 legacy production segment, greenhouse gas emissions declined by 35% year over year to approximately 281,000 tons.

We have now reduced our historical Scope 1 and 2 production emissions by nearly 70% over the past five years and are squarely on track to achieve our ambitious and peer-leading net-zero goal by 2025.

From an emissions intense any perspective, we achieved our 2025 greenhouse gas emissions intensity goal of 160 tonnes per Bcf, a full year ahead of schedule.

Looking at methane after significantly outperforming our pneumatic device replacement timeline, the methane intensity from our production operations is now 0.0074%, which is more than 60% below our 2025 goal and 97% below the one future 2025 target, making EQT among the lowest methane intensity producers of natural gas anywhere in the world.

With that, I'll now turn the call over to Jeremy.

Thanks, Toby.

Before I summarize Q2 results, I want to take a moment to thank our shareholders for their tremendous show of support in last week's vote on the Equitrans acquisition.

Of EQT shares cast, more than 99% voted in favor of the deal despite this being an unconventional acquisition relative to what investors have become accustomed to in upstream M&A over the past decade.

We see this vote underscoring the strong support from investors they share a philosophical view that being at the absolute low end of the cost curve will create differentiated and sustainable long-term value and amid a volatile commodity price landscape.

Since taking over EQT in 2019, we, as a management team have never been more convicted that this company is on the right strategic path, and we look forward to continuing our track record of execution on behalf of our shareholders.

Shifting to second quarter results.

As planned, we curtailed 1 Bcf per day of gross production throughout most of the quarter, which, along with non-operated curtailments, impacted net production by approximately 60 Bcfe during Q2.

Despite curtailments strong operational efficiency and well performance drove production of 508 Bcfe, above the high end of our guidance range.

Per unit operating costs came in at $1.40 per Mcfe below the low end of guidance due to LOE and G&A expenses coming in below expectations.

CapEx also came in below the midpoint of guidance despite an accelerated development pace as efficiency gains drove lower than expected well costs.

Turning to the balance sheet, we're off to a fast start on our deleveraging plan as we repaid $600 million of 2025 senior notes last month with cash on hand and proceeds from the Equinor transaction.

We exited the quarter with net debt of roughly $4.9 billion, down from $5.7 billion at the end of 2023.

Concurrent with the closing of Equitrans, we also upsized our revolver from $2.5 billion to $3.5 billion, which speaks to the depth of support for our bank group.

This revolver is on par with the largest companies in the energy industry and gives us ample liquidity to handle any foreseeable natural gas price scenario moving forward.

With the close of the Equitrans this week, pro forma gross debt is expected to be approximately $13.5 billion. inclusive of the redemption of Equitrans is 14% preferred equity at closing.

With the deal closing sooner than we originally anticipated, we expect our deleveraging timetable to be pulled forward by approximately six months.

On the midstream side, we plan to pursue a minority equity sale of Equitrans' regulated assets, which are projected to generate approximately $700 million of adjusted EBITDA.

This strategy will allow EQT to retain full operational control and upside value associated with synergy capture and future pipeline expansions.

We're also marketing the remaining 60% of our non-operated assets in Northeast Pennsylvania and are in active discussions with both domestic and international buyers.

We continue to target reducing our long-term debt to $5 billion to $7 billion and are highly confident in achieving our goal.

Alongside planned asset sales, we have further derisked our deleveraging plan by increasing our near-term hedge position.

We're approximately 60% hedged in the second half of 2024 with an average floor price of roughly $3.30 per MMBtu and approximately 60% hedged in the first half of 2025 at an average floor price of roughly $3.20 per MMBtu.

We are actively building our hedge position in the second half of 2025 in order to bulletproof our deleveraging plan in any reasonable that natural gas price scenario.

Turning briefly to the Appalachia macro landscape while the pace of Eastern storage builds has moderated, absolute storage levels remain high on the back of a warm winter weather last year.

That's pressuring Appalachia pricing this year.

In response to market fundamentals, we continue to tactically curtailed production, including over the past weeks and expect to continue this tactical curtailment program during the upcoming fall shoulder season.

To this end our second half 2024 production guidance assumes 90 Bcfe of anticipated curtailments, which should have a meaningful impact on both Eastern and total US storage levels as the market wraps up injection season.

I want to highlight that normalized for the roughly 180 Bcfe of total curtailments that we expect this year, our production would have been above the end of our original 2024 guidance range, which speaks to the productivity and operational efficiency gains that Toby spoke to a few minutes ago.

While Appalachian storage is elevated today, the startup of MVP last month should provide support to Appalachian differentials moving forward.

To put MVP's impacting context, assuming MVP flows at just half of its capacity on average for the year implies 300 to 400 Bcf of gas that otherwise would end up in Eastern storage that now will be directed to the southeast demand centers.

Given total maximum Eastern storage is roughly 975 Bcf.

MVP flows represents a material and structural shift and local supply-and-demand fundamentals, which in turn should help tighten local basis over the coming years.

In fact, between MVP, coal retirements in organic loan growth, we see implied Appalachia demand approaching 41 Bcf per day by 2030 compared with 35 to 36 Bcf per day of current basin supply, which should translate to better local pricing and present a sustainable growth opportunity for EQT at some point in the coming years given we have the deepest, highest quality inventory rate of any operator in the basin.

Turning to guidance, we have issued pro forma Q3 and Q4 metrics on slide 29 of our investor presentation.

Our cash operating expenses are expected to range from approximately $1.10 to $1.25 per Mcfe in the second half of the year, which at the midpoint is roughly $0.25 per Mcfe below our stand-alone operating expenses in Q2.

This reflects the benefit of eliminating expenses associated with the Equitrans acquisition of the most notable movement being our gathering rates, which are forecasted to decline from $0.59 per Mcfe in Q2 to just $0.05 to $0.09 per Mcfe in the second half of the year.

Inclusive of the benefits from third-party revenue in the full run rate distributions from our MVP ownership, our net operating expense should equate to roughly $0.75 to $0.85 per Mcfe by the fourth quarter, which is approximately $0.60 per Mcfe lower in stand alone EQT and drives home the relative advantage of our vertically integrated cost structure.

It's also worth highlighting that we do not embed any of the $250 million of base synergies into our Q3 or Q4 numbers as we have conservatively modeled based synergy capture beginning in mid-2025.

As I mentioned previously, our second half 2024 production outlook embeds approximately 98 Bcfe of strategic curtailments this fall, which we will opportunistically execute, should gas prices remain depressed.

I'd note that curtailments are driving approximately $0.05 per Mcfe of upward pressure on our second half 2024 cost structure.

So our 2025 expenses should be even lower in the range as I cited previously.

While we still need to go through our full budgeting process for 2025, we preliminarily expect an all in pro forma capital budget in the range of $2.3 billion to $2.6 billion.

Beyond 2025, we forecast long term pro forma capital spending ranging from $2.1 billion $2.4 billion per [annum] prior to capturing the $175 million of upside annual synergies we laid out with the Equitrans acquisition announcement.

Said another way, our long-term capital spending, inclusive of Equitrans should essentially be in line with standalone EQT capital spend in 2024.

And this is before capturing upside synergies, which speaks to the structural capital efficiency improvements accruing in our upstream business.

At recent strip pricing, we forecast pro forma cumulative free cash flow of approximately $16.5 billion from 2025 to 2029 at an average annual gas price of roughly $3.60 per MMBtu over this period.

Even assuming a $2.75 natural gas price over this period, EQT will still generate north of $9 billion, a five-year cumulate free cash flow, while the bulk of our peers would be cash flow neutral or negative, underscoring the power of our low cost structure highlighting how EQT is uniquely positioned to create differentiated shareholder value in all parts of the commodity cycle.

And with that, I'll turn the call back over to Toby for some concluding remarks.

Thanks, Jeremy.

In closing July 10 marks the five-year anniversary of the EQT takeover.

It has been a lifetime of work, but passed by the blink of an eye.

We have been reflecting recently on what this management team has accomplished together, taking a struggling company with great assets and transforming bring it into a best-in-class producer recognized as an industry leader.

We have increased production over 50% from 4 Bcfe per day to 6.3 Bcfe per day and have transformed our free cash flow cost structure from $3 per million Btu through a peer-leading $2 per million Btu through operational improvements and thoughtful and accretive M&A deals.

Normalized for natural gas prices, we have grown the free cash flow generation of EQT by 5 times and increased free cash flow per share by nearly 2 times.

And we have prepared our balance sheet and reattained investment grade credit ratings.

Today, we are executing at a high level operationally wth identified opportunities and completions and midstream set to drive yet another step change in operational improvements.

We are executing financially with a fast start to our deleveraging plan and robust support from our bank group and shareholders.

And we are executing strategically at an industry-leading pace as we continue to transform EQT into the energy company of the future.

I'd now like to open the call up for questions.

(Operator Instructions)

Arun Jayaram, JPMorgan.

Good morning, gentlemen.

My questions are regarding kind of the asset sales or divestiture program.

Jeremy, maybe I was wondering if you could start with the model or the process to sell some of your non-op in the Northeast.

Could do gauge the level of interest that you're seeing for the remaining 60% and you still believe the market is supportive of a similar valuation marker as you've gotten in the Equinor transaction?

Hey, Arun, and good morning.

Yeah, we're seeing really good interest.

I think I would characterize it as a really a renewed set of interest, a lot of new names actually in the process from the international space that we didn't see the first time around, so that's been really encouraging; a lot of great engagement side.

I think our feeling towards that process remains really positive.

And I hope to get that wrapped up by year end.

Great.

And then my follow-up is, you've highlighted kind of a structure you planned to pursue in terms of carving out your regulated assets and selling of minority interest in those assets.

Do you plan to reduce gross debt at the EQT parent level as part of that process?

And just a question that's come up is what type of partner approval?

Is there a reference on MVP, but could you just go through some of those types of things that you need to do to process that the next phase of your deleveraging program?

Yes, taking the route that we outlined in the prepared remarks actually bypasses most of the sort of considerations you might typically get hung up in with like drag rides, tag rides, and a deal like that.

So it really simplifies it and I think it really provides a better, higher quality, more diverse set of assets to back an investment which drives the cost of capital down.

So look, we've spent a lot of time, we've had a lot of discussions with a lot of parties on this already, even pre-closing.

And so with closing happening a couple days ago, we're really in the thick of getting that data organized so we can kick that process off.

And I hope to be able to get that wrapped up as soon as year end.

It might bleed into early Q1 but I think there's a real chance that all gets wrapped up this year as well.

Great.

Thanks a lot.

Doug Leggate, Wolfe Research.

Hey, guys, thanks for having me on.

Congratulations.

I didn't quite realize it had been five years Toby.

It has indeed flown by on higher.

I've got two quick questions.

The first one is on through budget for the next two or three years alongside the compression results that you've had.

What we're trying to figure out is how much of the spending is related to that de-bottlenecking, if you like on when does the rollover so that you basically get back to a steady state level of spending associated with your growing program?

Yeah, Doug, thanks for the question.

On the compression higher level we just referred to as pressure system optimization across our systems, we think this is going to be about a few hundred million dollars.

The timing of that there's some lead time there so that's probably going to start maybe 12months from now, and that could span over a couple of years to determine on the type of pace that we see.

But that being said, we have in our '25 budget right now, we have included some cushion to be will that get those projects started as quickly as possible.

And the results that we showed, the pilots that we showed today about the compression uplift is really encouraging and will lead to some really interact, really exciting returns that we'd like to accelerate as quickly as possible.

Yeah, Doug, and welcome back by the way.

If you look at what we've put it on your slide deck that we put out last time, we put up a couple of case studies and from some recent pad level compression projects that we've installed at, these are not a perfect proxy to centralized compression, which is a lot is going to have a much broader impact superior to what these example show.

But even those examples at $3 gas, I mean, these are you're generating 2.5 times to 3 times your money on that compression on just the PAD level.

So again, on a centralized basis, it's going to be higher than that.

And then beyond just uplifting that base PDP for the existing production, you're going to see an impact on all of our future development as well.

So the rate of return on this compression is superior to probably any well we could take to drill.

And as Toby said, the spend amount is really not that much when you space it out across a couple of years on an annual basis, it's mitigated even more.

But if you look at slide 8 of our investor presentation, that delta between that 2025 guidance number and then what we call long term, right below that, you can kind of think about that is the annual difference in sort of an uplift in spending we might see in a given year what we're doing that before reverting to a much lower range long term.

And as a reminder that lower range that we show from $2.1 billion to $2.4 billion long term, that excludes the $175 million synergies as we called upside synergies.

So I would say that outside synergy assumption assumed a level of uplift from compression at less than what we're already seeing on even had level basis.

So I think that number's probably biased higher as we see the benefits of these projects come to fruition.

So guys, I'm sorry for the follow-up of simplifying.

So would it be a stretch to say that when you're -- when you get to that point with the synergies, you run rate capital could be under $2 billion?

That's correct.

That's a simple way to put it, Doug.

Okay.

That's what I'm trying to get to.

Thank you, guys.

My follow-up is a quick one.

Hopefully, Jeremy, this is right on your fairway.

Why is any ownership of the regulated assets makes sense?

Yeah, that's great question.

Actually, some we've kind of debated internally as we've thought about the right structure here.

So after the regulated assets, specifically, if you start with the transmission and storage segment of Equitrans, that is really an extension of the gathering system.

There are a lot of big hitter pipes that cross state lines.

And so they are regulated on maintaining the right rate pressures on those system has been able to control things like expansions on is really integral to manage in the gathering systems appropriately.

And then when you think about those pipes that are flowing into a longer distance regulated pipeline like MVP, maintaining that, that interconnection that pressure at an appropriate level, it all kind of works together as a single system.

And then as we think about MVP, as we talked about last quarter, the expansion on that project we think is a highly economic expansion.

And that's something that we want to get done to evacuate more gas out of Appalachia and get it to a premium end market in the Southeast.

We want to make sure that project happens.

Whether 5 or 10 years from now it makes sense to still owned something like MVP once all that expansion is completed.

I think that's something we'll always evaluate.

But I think at this juncture, we do want to maintain operatorship and ownership of it.

Yeah, Doug, I'd say at a very high level, what we're doing here at EQT is creating a culture that is going to be able to take off every penny nickel and dime within our operating footprint.

And one of the ways that we can drive the operative, the value creation is to expand the size of the operational footprint.

And so there isn't out of having those transmissions is a bigger commercial system is going to make it a little bit easier for us to identify and capture some of those opportunities.

So that's another factor that we have in the back, whereas as well.

I guess that's very clear.

Thanks for taking my questions in place and thanks for your comments, Jeremey.

Neil Mehta Goldman Sachs.

Yeah, congratulations on closing the transaction team.

Two questions on the macro here for versus just to talk through your hedging strategy, both near and long term and and how does the E-Train acquisition playing into your hedging decisions going forward as you want to take advantage of the volatile market that you talked about?

Good morning, Neil.

I'll break it into kind of two pieces near term.

It's really all focused on balance sheet, derisking and deleveraging.

I call out through 2025 beyond 2025.

I think our view is that deal.

We just did not only unlocks the value we've been talking about it, but it really provides a structural hedge for our business.

So I need to hedge beyond that.

We won't have financial leverage to really protect.

We won't have operating leverage to protect.

And so we don't really have to hedge at all.

I think if we do, it will be more opportunistic, but it will be pretty small in nature and probably at max around a 20% level if we just get really bearish on the outlook for some reason.

But otherwise, I think the goal strategically what we're trying to do is set ourselves up where we don't have to hedge because we see so much more upside than downside but I think as you've even seen this year, you've seen gas prices go as low as about $1.60 readout over $3 and now trade back towards $2.

So you're already seeing this theme of volatility play out in the best way to capture value from that is to not have to hedge.

So that's really the long-term plan and how we're trying to position.

That's helpful.

And can you just talk through you've done a great job walking us through your long term views around data centers and power demand growth, which we agree.

It's a very compelling story, 2025, a little trickier.

And just because you've got some pushout of some major projects, the Golden Pass and trying to digest that spare capacity that might be in the system to.

So how do you think about the supply demand outlook for gas and as we think about 2025?

And what are you guys watching as markers?

Yeah.

So I think the key thing we're watching probably going to be here in this production.

And I think this number hovering around one or two, if it's a healthy number.

But if you see a surge into winter again, if other producers turn on a lot of volume, I think we are watching for that because that could be a near-term headwind to price on your I think it's most that would impact the first half of 2025.

I know the team at Goldman has that been pushed out into 2026 for go impact in service date.

I think with some of the updates that we've seen even this week with that bankruptcy process exactly holdings, it seems like that might get pulled back forward on a couple of these key factors on the LNG side are really going to drive that.

And I see it really is a story of production and a story of LNG.

I don't beyond that.

See any sort of step change benefits necessarily in 2025 that are going to move the needle nearly as much as those two factors?

Scott Hanold, RBC.

Good morning.

Hey, a question on now that MVPs online I'm just kind of curious, you know, is there any change in the dynamics you're seeing in the Appalachian into the Southeast market now that that's flowing?

And related that, have you seen any moves by some of the Appalachian and producers to increased activity, given the obviously the extraction of some of the volumes in the basin?

Yeah.

So this is actually something really exciting that we've been really pleasantly surprised by.

So I guess on the production side, we have not seen any reaction as we've productions continues to be flat, consistent with our expectations.

What has surprised us, though, is that in that end market, as we model the way we sort of March that station 165 pricing or we're selling gas.

We've sort of model that around a 20% premium depth to M2 pricing.

We have seen pricing recently had an average $0.50 to $0.7 above, so significantly higher than what we have assumed.

And there have been periods of time where it's well north of $1 above M2 until.

And so I think we've been really encouraged by how much gas that market has been taking part of it, and it has been impacted by some maintenance on Transco.

And but I think for being of a mid summer period, seen that demand in that premium price already show up, I think is an awesome really early find marker.

So I think that the benefit we might see in winter periods could be even better as well and certainly better than maybe what we have forecasted.

But it's still early.

There is a new price market place put out for that station 165 market.

So we're watching like everybody else to see how that develops.

But I think all signs are pointing to a really positive direction on that.

Yeah.

Scott, one of other thing I just have you take a look at on slide 6 where we talk about the improving [EURS] for EQT.

If you look at sort of where the peers or are you seeing the EURs come down over time.

This is the sign of some of the inventory, their core inventory depletion, the read-through there is there could be some pressure against operators and their willingness to go out there and accelerate or broke purely just a reserve inventory.

So that's another thing that's happening in the background.

And there's only a couple of operators that really have high-quality inventory like EQT and (Inaudible), we've been pretty vocal and staying in this maintenance mode, but can you describe the market.

So I think that's an important backdrop

(Inaudible).

I appreciate that.

Sounds good.

Is my follow-up, Toby.

Look at them, you've been never tried to discuss politics from time to time.

And as it relates to being a gas producer, what do you think the biggest issues are in for the upcoming election?

Like what are the things that are you really focused on.

I'd say, we align our politics with the politics of our customers, which is every American that use our products.

So we don't trying to be to bias one way or the other is really centered on the facts.

Listen, I think we're in a period of time where people are going to get smarter about energy.

There are some from clips talking about from politicians talking about banning fracking.

And this is time for us as an industry leader and he's Americas to hold leaders accountable for statements that I think are really damaging and cause completely on attendant impacts.

I mean, as it relates to hydraulic fracturing in the back of that, we cannot ignore the science on this over 10 years has been studied in under the Obama administration.

The EPA put out a report saying hydraulic fracturing safe.

And understanding the implications of these type of decisions, 98% of the wells in this country require hydraulic fracturing.

That goes away, the snap your fingers and a 30 production in the United States, which we thought for decades to create America as an energy powerhouse with sort of operate.

And we see reductions in this country, we dropped 35%.

That's going to lead to a lot of terrible things.

And the routing is or isn't oil and gas operator price times volume game, our production at EQT would go down , call it, 25%, our corporate decline ,but price would skyrocket.

And that's the tough part here is that we would actually be constructive for prices but it would be bad for Americans and that's why we need to make sure our politicians are putting the right policies, like all of the crazy things that are happening in this world, we're really encouraged to see that energy is still at the top of the list as a key issue for American voters.

And it's something that we need to take very seriously.

Appreciate the color.

Thanks.

Josh Silverstein from UBS.

Good morning, guys.

Just on the outlook for next year, I'm trying to think about the trajectory of the natural gas volumes.

Should we think about no kind of the second half run rate going forward with the curtailments coming back?

Do you think you'd probably keep is the volumes curtailed as maybe a little bit more clarity there would be helpful.

Thanks.

Yeah, Josh.

I think in our view is it's just maintenance mode.

I mean, I think in our prepared remarks, you commented that if we had not curtailed this year, we would have been above the high end of the range.

Originally that was [2300] Bcf a day on the high end out.

We're running our business in maintenance mode.

I would expect looking into next year.

That's the volume look at level you look at is the only difference there is that the divestment of our non-op interest and some of the transaction impacts from that.

But aside from that, we're running enough in a steady maintenance mode Cadence.

Got it.

So that kind of around maybe like [550] or so kind of quarterly cadence or around them?

Yeah call 550 to 600, depending on the quarter.

Right, got it, okay.

So kind of (Inaudible) growth into next year relative to the back half.

Got it.

Okay.

And then just on the pro forma kind of cash flow profile.

When you first announced the transaction with the train, you mentioned about 30% of the pro forma cash flow we would be midstream.

I'm wondering if that still holds, given the minority sale that you guys are looking at with the number actually be lower and if it is lower, would you want to we reduced debt even further and to where you guys want to be performing?

Thanks.

Yeah, it really comes down to kind of what value and multiple we would sell that at.

And but yes, I mean, all else equal, if you sell down some of that, it could drop a little bit, but that's factored into how look at pro forma leverage already.

So I don't think it really impacts how we think about our plans.

And the only other thing that's going to impact that next year or two is obviously gas prices at prices decline or go up a lot, that percent of midstream's that's going to oscillate with that as well.

Roger Read, Wells Fargo.

Yeah, thanks.

Good morning, everybody.

I'd like to take a look at Slide 11.

You have the organic deleveraging in the free cash flow expectations '25 through '29.

I'm just curious, clearly, you're not going to be on aggressive on the hedging side and in the future.

So what sort of the underlying assay option on gas prices, gas volumes against us, the numbers you lay out there?

Yeah.

So the numbers we look at on page 11 are really based on our internal assumptions around the asset sales and in our strip pricing is today.

But that is look, that's the reason why we're also hedging, if you look at that, just organic free cash flow up really between now and the end of 2025, at [$2.75] gas prices are still generating over $1 billion of free cash flow.

So I really in any case that we've laid out, if we take a more conservative lean to that things go wrong in the macro, for whatever reason, I think we still really good about that assumption.

So that initial target, we have the specific target of $7.5 billion by the end of 2025.

I'd call that our initial target level, I think that within a of a margin of safety added that rating agencies outline for us.

But longer term, we would like to take that lower.

It's where we talk about that $5 billion to $7 billion level that could oscillate in time, depending on where we are in a cycle, depending on the opportunities we're off to invest cash and look, we also won a very intentionally positioned ourselves.

So we have ample liquidity so that if there is volatility in the macro landscape in our stock that we're positioned to step in and buy a lot of stock back counter-stick quickly.

If you don't pay down our debt below mid-cycle level, if you don't have a lot of liquidity can't do that.

So another example of that, that that revolver, we just expanded by $1 billion to $3.5 billion size that also trying to tee up and position ourselves for volatility and to take advantage of those opportunities.

So this is all kind of play hand-in-hand together with how we're trying to position ourselves to maximize value as we reallocate capital in the coming years.

I appreciate.

That's very helpful.

Thanks.

I'll turn it back.

David Deckelbaum, TD Cowen.

Thanks, Toby and Jeremy for taking my questions.

I wanted to go back to the capital progression from just in the context of the benefits that you've seen on the upstream side, I think you highlighted obviously the impressive achievement is getting your cycle times down on completions like 35%.

How much of those reflected in the reduction in spend and '25 versus '24?

And I guess just in conjunction with that, how much do you expect upstream CapEx to moderate next year?

Yes, we have a small amount of that.

Those completion efficiencies baked into our '25 plan right now, given the newness of this step change and completion efficiencies, we want to see a little bit more time, but we'll continue to add that back in there.

And the second part of the question.

So just thinking about this, if you think year-over-year what you're spending on upstream and '25 in that $2.3 billion to $2.6 billion versus this year?

Yeah, I would say we think the upstream spending profile, we're going to be pretty similar to what we had previous train.

I'd say that the impacts of the reduced CapEx is going to really start once those compression projects targeting the front lines, which I'd say ballpark 12 to 18 months before that slowed down.

So from everything that you're seeing and from the upstream spending now is really just driven by base operating efficiencies and balancing those service pricing we see.

David, it from a modeling perspective, I think about it this way at a high level, we've baked in the guidance we've given on those capital cost numbers.

We' ve taken all the capital costs, but we haven't baked in the benefit.

We had a decent and related completion benefits nearly to the level that we're actually seeing right now.

We have baked in the $175 million of upside synergies.

Even though the more work we do, I think our bias is to that, that number probably grows.

So I think there's a lot still on the table beyond what we have given out that we're hopeful to achieve, but it's still early innings.

And so we want to see more definitive results there before we actually take that into our definitive guidance.

Thanks, Jeremy.

Just continuing on that.

I guess that long-term guidance of $2.1 billion to $2.4 billion at the midpoint, is it fair to say that's just reflecting the benefits from the installed compression, bringing down that upstream budget relative to sort of the $2.3 billion, the $2.6 billion and '25?

No, we'd say that $2.1 billion to $2.4 billion really reflects that the spend on the compression is behind us, as we mentioned earlier in the call that $175 million of annual cost reductions as a result of that spending would be reduce that $2.1 billion to $2.4 billion lower so I think we're going to just continue to quantify this and then you see that come down in the future.

Appreciate it, guys.

Kevin McCarthy, Pickering Energy Partners.

Hey, good morning. Appreciate all the details in 2025 and included in slide 8 and the further commentary you've offered in the Q&A.

I have just a few more clarifying questions on that slide.

I guess my first question is, does the adjusted EBITDA number include that in VP distributions for next year?

And it's just annualizing your 4Q guidance kind of a good run rate for that?

That number, that EBITDA number actually does not include the MVP distributions because that's going to be more of an equity method investment and some will provide clarity on that as we go forward.

And the second part of your question was what again?

And if it's just a good estimate to annualize the fourth quarter guidance and MVP distribution for 2025?

Yeah, I think it is for MVP specifically.

The I think drawn on our whole company basis, the main impact was what we noted in our remarks earlier, that curtailments are skewing the per unit cost metrics higher.

So I think as you look into 2025, if you were to look at per unit metrics, those should scale lower, assuming no curtailments.

But otherwise, I think it should be a pretty decent proxy, which is why we've broken out separately.

Great.

And then you mentioned that this outlook was building was built using and amendments production number.

What is the risk of shut-ins coming back next year?

And how have you thought about that in terms of your free cash flow?

Or does the lower cost structure kind of reduce that shut-in-risk?

Yeah.

We don't proactively on like a year ahead basis, bacon things like shut-ins, that's more of in response to the market.

And so if we did, if we did say that whole thesis and '25, '26, analogy just got derailed for some reason and there was a need to curtail that would take production below, you know that this would have quarterly annualized number that I think you're getting at.

But t hat's something that I think we would address more real-time as the market evolves.

Great.

I appreciate the detail and congratulations on a good quarter.

Jacob Roberts, TPH.

Good morning.

Maybe staying on that topic, is there any difference in how we should be thinking about the curtailments being baked into the guide of the back half of this year relative to what we saw in the first half?

And what we're trying to think about is if there's a change in EQT's elasticity of supply between the two periods, perhaps with MVP online?

No, I don't think MVP impacts that at all.

I think we maintain that flexibility.

I do think have a midstream, a wholly owned where those MVCs effectively have been integrated away.

I think that does give us a tremendous amount, more flexibility to be a little more on the.

Yes, I guess really to pursue curtailments at more than maybe we had in the past where we felt like we otherwise had a big debt obligation we're having to pay to the midstream service provider.

But I think our reaction in the back half of this year is more just governed by pricing.

We haven't changed sort of the pricing levels we outlined earlier this year.

We're we would look to curtail just because we own the midstream.

I think we still have that sort of floor threshold level are focused on earning returns on shareholder capital, not just well, CapEx, not just maintaining that realized pricing about cash costs.

It's got to be higher than that.

So that's why we're proactively trying to guide to that.

Got it.

Thank you.

Quick second one.

On slide 7, the three sites you've highlighted, I think you mentioned that you see kind of thousands of opportunities to across the field to implement this.

Can you give a sense of which how many wells each site touches so to speak?

Well, I wouldn't say that wouldn't be the way we think about it.

I would say at a very high level, we just look at the system pressures.

We've got over a dozen gathering systems that are all hydraulically connected.

Each one of those has a operating pressure that is sort of based on the amount of volume that's going through their vintage of the wells that feed that drive, that we also try and where our development program is going to go, and that will inform which pressures as well.

So the exercise of the teams that run through is sort of forecasting what doses compressors look like and then assessing through compression what the productivity uplift will be if we lowered the system pressures 300, 400, 500 PSI and what that will look like.

So I would say as a whole is this is a pretty large opportunity for us at EQT and it's really exciting to look at the evolution of the improvements we've made in this business.

That said, the last five years have really been focused on optimizing the efforts on site drilling, completing wells and being more efficient on the production side.

But now the efficiencies that we're focused on are going to be really more on the midstream footprint and the actual field-wide improvements.

Great. thank you.

Appriciate the time guys.

Michael Scialla, Stephens.

Good morning, everybody.

I just wanted to ask on the expansion of MVP.

Sounds like I heard you right, the timeframe, you're speaking, there's maybe five years down the road, even though you're seeing pricing, they're getting a pretty hefty premium to other parts of the basin.

So just wanted to explore that the timing is that because you do don't think the demand there is there right now or just anymore color you could provide on the timing of that expansion?

Yeah.

I'm not sure where the five years came from.

I think we're excited to tell pursue that expansion is possible.

Actually, I think, again, the only thing that we would that would cause us any delays, just making sure that it was time to come on line with that expansion project on Transco to take all the gas.

But beyond that, I think we are incentivized to get that that built as soon as possible.

And again, the Internet to EQT, that's a cost of probably $200 million to $250 million net to get that built.

And I would say that the guidance that we have given out in our slide deck, that longer-term guidance today, I just say there's ample cushion built in.

So I wouldn't expect that CapEx number lower term to really change it all out despite the timing that we decide to pursue that expansion project.

So that remains on that being a higher priority list to get knocked out.

No, okay, great. (Inaudible) on the surge on that they have you started the open season there yet?

Or is that those two down the road now?

I mean, we just closed two days ago, so it's a little quick to do that.

But I think it's something that we're going to start exploring quickly.

Got you.

And just wanted to ask on the curtailments, can you say how much you're currently curtailing in that 90 Bcf in the second half?

Is that all assumed in the third quarter team anymore color you can play there?

I always look at it in response to the market.

If the if we can make money selling gas wouldn't curtail anything obviously.

But our assumption rig ht now is that the majority of those curtailments probably to take place in September and October curtailed even over the past week, some volumes on given days, depending on whether depending on maybe it's over a weekend not up quite to 1 Bcf a day level, but we do on a very dynamic basis, optimizes our realized pricing to make sure that we're optimizing value creation and not just getting our product away for price where we can't make money.

And that's what we'll continue to do.

Noel Parks, Tuohy Brothers.

Hi, good morning.

Just had a couple.

I was wondering on you talked a bit about the impact of MVP and regional gas storage, especially in the east and where you say we are in some really offsetting the effect of seasonality as a big driver of some of gas pricing LNG eventually as it feeds and is going to offset that.

But just some thoughts on where you think we are at this point.

Yeah.

I mean, look, I with winter has always been I expect to continue to be the biggest source of demand for natural gas.

I think I'd love to see a rollover power-generation grows and helps increase that demand in the summertime as well.

So you kind of see two peaks in the market, but I think it's probably a little too early to say exactly how quickly that develops

.

Now, I will say, if you look at our slides from last quarter, what we outlined in power demand growth for natural gas and the fact that over the past decade, you've had increase of about 10 Bcf a day just on the power side.

And now what's happening with load growth on top of that on top of coal retirements, I do think we are moving that direction in time.

But yes, that doesn't mean you're getting away from seasonality.

It just means that you had a lot of demand at peak summer and a lot of demand peak winter as I just think the nature that's going to evolve a little bit.

And the LNG announcements of that, which also could be somewhat seasonally driven, I think only amplify that seasonality.

Got it.

And then I wondered, disappeared thoughts on the outlook for industrial demand on both sort of in region and out of region in terms of gas from Morgan energy security and resiliency level, just taking a greater role in some sort of on a microgrid level, some of those power demand overall keeps increasing.

Yeah.

I mean, look, I think the theme of reshoring manufacturing on what is going to continue.

It seems like there, but both sides of the aisle are very supportive of that.

I think that the sort of the globalization movement out of Asia for manufacturing will be a tailwind of that.

I think energy energy policy and prices in Europe or a tailwind for that.

That is something that is baked into our comments that we made early on about Appalachia demand growing upwards by the end of the decade, maybe to 40 Bcf, 41 Bcf a day.

There is a component of that baked in, but I would say the beauty of industrial, it's pretty steady.

It's pretty predictable.

And I think if you look at recent history of that, it has been flat to slowly growing.

And I think that trend should continue.

But I wouldn't say there's any sort of big catalyst needle movers that should really skew of fundamentals model that much.

Yeah, I'd say at a very high level, energy and security is going to continue to be a big theme around the world and even in parts of this country and the volatility that we see is only going to drive consumers of natural gas closer to the source of where that energy is produced t o reduce the number of things in between their manufacturing facility and the source of energy.

That's one where they protect their their supply and protect their business.

And that just is going to mean that we think this volatility is going to drive more in-basin demand for natural gas products.

Great.

Thanks a lot.

That concludes our question and answer session.

I will now turn the call back over to Toby Rice for closing remarks.

Thanks, everybody, for being here today.

You know that with this being our five year anniversary, I just want to reiterate to everybody that all of the progress that we've made at EQT would not have been possible without the shareholders and with you that voted 80% on to put in a new mine management team here and give us this opportunity to realize the full potential of EQT.

It was you all that voted, brought in a Board of Directors that has really been amazing and guiding us through this amazing transformation.

And with this 99% shareholder vote supporting a transformative transaction with the E-Train assets, you've given us a platform to continue this momentum, and we're really excited about working hard for you going forward.

This concludes today's conference call.

Thank you for your participation.

You may now disconnect.