Q3 2023 EQT Corp Earnings Call

Yeah.

Thank you for standing by my name is Eric and I will be your conference operator today.

At this time I would like to welcome everyone to the EQT Q3, 2023 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.

Like to ask a question during this time simply press star followed by the number one on your telephone keypad.

If you would like to withdraw your question Press Star one again, thank you.

I would now like to turn the call over to Cameron Horowitz director of Investor Relations and strategy. Please go ahead.

Good morning, and thank you for joining our third quarter 2023 earnings results Conference call with me today are Toby Rice, President and Chief Executive Officer, Jeremy <unk>, 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 factors described in yesterday's earnings release, and our Investor presentation. The risk factors section of our Form 10-K and in subsequent filings we make with the SEC, we do not undertake any duty to update any forward looking statements. Today's call 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 Tobi.

Thanks, Cam and good morning, everyone. The third quarter, so our multitude of positive highlights and record breaking performance at EQT, including closing the strategic acquisition of Tokyo and Xdr Midstream in late August as shown on slide five of our investor deck with roughly 60 days under our belt post closing, we currently have 74% of <unk>.

<unk> integration milestones actions completed.

Put this in context. This is a record pace for EQT in the most efficient integration yet despite significantly greater deal complexity relative to Alta and Chevron.

The success of improvement in our integration pace is reflective of leveraging lessons learned from previous transactions to refine our integration playbook, which is unique to eqt's proprietary digital platform and is a repeatable process that we have honed with each successful acquisition.

Eric: Thank you for standing by. My name is Eric and I will be your conference operator today.

Cameron Horwitz: At this time, I would like to welcome everyone to the EQT Q3 2023 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. If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question, press star one again. Thank you.

I want to take a moment to send a huge shout out to the EQT crew for all the hard work that has facilitated the incredible integration efficiency achieved over the past two months.

Alongside efficiently integrating the tug Hill and Xel midstream assets. The teams have identified multiple areas of potential operational improvements that we did not contemplate when underwriting the acquisition, we broadly see these opportunities falling into two buckets comprised of well design and operational efficiencies.

Cameron Horwitz: I would now like to turn the call over to Cameron Horwitz, director of investor relations and strategy. Please go ahead. Good morning and thank you for joining our third quarter 2023 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 slide during today's discussion.

As it relates to operational efficiencies I want to first talk about third quarter performance for Standalone EQT and then provide some stats on what the teams have already achieved on the <unk> assets.

As shown on slide seven of our investor deck after posting stellar second quarter operational performance, both our drilling and completions again set new internal and World Records in <unk> recall last quarter, we highlighted eqt's world record of drilling over 18200 feet in 48 hours on the same run this record low.

Cameron Horwitz: A replay of today's call will be available in our website beginning this evening. I'd like to remind you that today's call may contain for looking statements. Actual results and feature events could materially differ from these forward-looking statements because the factors described in yesterday's earnings release. In our investor presentation, the risk factor section of our form 10k and its 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-gap financial measures. Please refer to our most recent earnings release and investor presentation for important disclosures regarding such measures, including reconciliation for the most comparable gap financial measures.

At EMEA 60 days as our team bested that effort by drilling 18264 feet and 48 hours on our Denver five H well in August.

On the completions front, our teams are firing on all cylinders with third quarter pumping hours per crew, averaging north of 400 hours, which is an all time high pace for EQT. This includes besting our prior record for monthly pumping hours twice during the quarter with two crews each achieving north of 500.

Pumping hours in a month.

To put this into context, the theoretical maximum pumping hours in a month for a single Frac crew is roughly 600 hours after accounting for minimum maintenance time. So our teams are knocking on the doorstep of perfection. This performance reflects our strategy of aggressively attacking all facets of the supply chain to eliminate as many <unk>.

Toby Rice: With that, I'll turn the call over to Toby. Thanks, Cam, and good morning, everyone. The third quarter saw a multitude of positive highlights and record-breaking performance at EQT, including closing the strategic acquisition of Tug Hill and ex-Theum midstream in late August. As shown on slide five of our investor deck with roughly 60 days under our belt post-closing, we currently have 74% of total integration milestones actions completed. Put this in context. This is a record pace for EQT and the most efficient integration yet, despite significantly greater deal complexity relative to ALTA and Chevron.

Bottlenecks as possible for our completions team and our Q3 execution underscores the dividends accruing from these efforts.

Turning back to tug Hill as shown on slide six of our Investor deck. Our teams are wasting no time on leasing eqt's industry, leading operational progress as we've taken over the assets.

Toby Rice: The success of improvement in our integration pace is reflective of leveraging lessons learned from previous transactions to refine our integration playbook, which is unique to EQT's proprietary digital platform and is a repeatable process that we have honed with each successful acquisition.

Put some numbers around this in just 60 days since taking over operations. Our completions team has already increased the amount of stages completed per day by 35% relative to legacy tug Hill development, and we see room for additional upside as our teams optimized water handling and sand logistics across the asset base.

Toby Rice: I want to take a moment to send a huge shout out to the EQT crew for all the hard work that has facilitated the incredible integration efficiency achieved over the past two months. Alongside efficiently integrating the Tug Hill and ex-Theum midstream assets, the teams have identified multiple areas of potential operational improvements that we did not contemplate when underwriting the acquisition. We broadly see these opportunities falling into two buckets comprised of well design and operational efficiencies.

On the drilling front since taking over operations. Our team has already improved horizontal drilling speeds by 50% relative to legacy Tal Gil performance and driven down horizontal drilling cost per foot by more than 40% as we high grade equipment and fully implement EQT best practices. We expect further efficiency gains that will allow us to draw.

<unk> drilling activity on tugs acreage from two rigs to one by the end of the year, all while still drilling the same amount of lateral footage year over year in 2024.

Toby Rice: As it relates to operational efficiencies, I want to first talk about third quarter performance for standalone EQT and then provide some stats on what the teams have already achieved on the Tug Hill assets. As shown on slide seven of our investor deck, after posting stellar second quarter operational performance, both our drilling and completions again set new internal and world records and three Q. Recall last quarter, we highlighted EQT's world record of drilling over 18,200 feet and 48 hours on the same run.

Our teams also plan to methodically test various EQT well design changes on the tug hill assets, including cluster spacing clusters per stage proppant loading proppant type and casing way to name a few while it is still early to quantify the full impact of the efficiency gains and operational synergies on the Togo assets, we preliminarily see the potential for us.

$150 per foot of well cost savings associated with these efforts the potential impact from optimizing well design parameters and improving operational efficiencies represented value creation upside on top of the $80 million of synergy value potential we announced with the deal.

Toby Rice: This record lasted a mere 60 days, as our team bested that effort by drilling 18,264 feet and 48 hours on our Denver 5A12 in August. On the completions front, our teams are firing on all cylinders with third quarter pumping hours per crew averaging north of 400 hours, which is an all-time high-paced for EQT. This includes besting our prior record for monthly pumping hours twice during the quarter, with two crews each achieving north of 500 pumping hours and a month.

As a reminder, the original synergies we discussed were only driven by water system integration firm transport optimization and land spend efficiencies, which should accrue over the next several years.

Looking ahead to 2024, while we are still in the process of fine tuning our pro forma operation schedule, we preliminarily expect to run three horizontal rigs and three to four frac crews in total next year, which is the level of activity that maintains production at approximately two three tcf fee per annum at <unk>.

Toby Rice: To put this into context, the theoretical maximum pumping hours in a month for a single-fract crew is roughly 600 hours after accounting for minimum maintenance time, so our teams are knocking on the doorstep of perfection. This performance reflects our strategy of aggressively attacking all facets of the supply chain to eliminate as many bottlenecks as possible for our completion team and our Q3 execution underscores the dividends accruing from these efforts. Starting back to Tughill, as shown on slide six of our investor deck, our teams are wasting no time unleashing EQT's industry-leading operational prowess as we've taken over the assets.

Current strip pricing of approximately $3 40 per million Btu next year, we preliminarily see roughly $1 7 billion.

A pro forma free cash flow in 2024, and cumulative free cash flow of approximately $14 billion from 2024 to 2028.

Toby Rice: To put the numbers around this in just 60 days since taking over operations, our completion team has already increased the amount of stages completed per day by 35% relative to legacy Tughill development, and we see room for additional upside as our teams optimize water handling and sand logistics across the asset days. On the drilling front, since taking over operations, our team has already improved horizontal drilling speeds by 50% relative to legacy Tughill performance and driven down horizontal drilling costs per foot by more than 40%.

As shown on slide 11 of our Investor deck. This equates to cumulative free cash flow of approximately 60% of our enterprise value, which is the highest not only among our gas peers, but also the broader upstream energy sector. We believe this outlook underscores the tremendous absolute and relative value proposition of EQT shares.

Even after a strong relative stock performance over the past several years.

Shifting gears to slide eight of our Investor presentation. We are excited to announce that we have signed 210 year firm sales agreements with investment grade utilities, covering all one two bcf per day of our capacity on MVP that will commence concurrent with the completion of downstream expansion projects in 2000.

Toby Rice: As we high-grade equipment and fully implement EQT best practices, we expect further efficiency gains that will allow us to drop drilling activity on Tug's acreage from two rigs to one by the end of the year, all while still drilling the same amount of lateral footage year over year in 2024. Our teams also plan to methodically test various EQT well-designed changes on the Tughill assets, including cluster spacing, clusters per stage, profit loading, profit types, and casing weight to name a few.

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Recall, we had previously entered into an <unk> for 525 million cubic feet per day of our MVP capacity, which we have restructured into an 800 million cubic feet per day firm sales arrangement with the same counterparty and entered into an additional 400 million cubic feet per day firm sale with a separate <unk>.

Your party. These are two of the largest long term physical supply deals ever executed in the North American natural gas market and we believe signaled the buyers confidence in eqt's unique ability to deliver reliable clean and affordable natural gas supply to millions of customers in the southeastern part of.

Toby Rice: While it's still early to quantify the full impact of efficiency gains and operational synergies on the Tughill assets, we preliminarily see the potential for up to $150 per foot of well-cost savings associated with these efforts. The potential impacts from optimizing well-designed parameters and improving operational efficiencies represent value creation upside on top of the $80 million of synergy value potential we announced with the deal. As a reminder, the original synergies we discussed were only driven by water system integration from transport optimization and land-spend efficiencies, which should accrue over the next several years.

The United States.

These agreements also highlight how eqt's scale and depth of inventory are catalyzing the expansion opportunities downstream of MVP, which will bring gas further into the southeast demand centers, where it is critically needed to replace coal fired power generation and meet the region's climate goals.

Toby Rice: Looking ahead to 2024, while we are still in the process of fine-tuning our pro-former operations schedule, we preliminarily expect to run three horizontal rigs and three to four frat crews in total next year, which is a level of activity that maintains production at approximately 2.3 TCFE per annum. At current strip pricing of approximately $3.40 per million BTU next year, we preliminarily see roughly $1.7 billion of pro-former free cash flow in 2024 and cumulative free cash flow of approximately $14 billion from 2024 to 2028.

To put the environmental benefits into perspective, assuming eqt's natural gas displacing coal fired power generation. The combined impact of these supply agreements would result in approximately 40 million tons per annum of emissions reductions, which is equivalent to taking more than $8 million gasoline powered vehicles off the <unk>.

Road every year.

On top of the environmental benefits. These deals should create a win win economic impact providing cash flow uplift for EQT, while concurrently dampening natural gas price volatility for consumers in the southeast region recall, our capacity on MVP will initially receive pricing at station 165, but as downstream projects.

Toby Rice: As shown on slide 11 of our investor deck, this equates to cumulative free cash flow of approximately 60% of our enterprise value, which is the highest not only among our gas peers, but also the broader upstream energy sector. We believe this outlook underscores the tremendous absolute and relative value proposition of EQT shares even after strong relative stock performance over the past several years.

And these new firm sales arrangements commence eqt's capacity will be debottleneck, and our pricing exposure will shift to a blend of premium demand areas, including Henry hub, and Transco zone, four and five salad.

To put the impact of this in context, we see these firm sales arrangements and associated downstream debottlenecking projects, increasing our annual free cash flow by more than $300 million beginning in 2028 at.

Toby Rice: Schifting gear to slide 8 of our investor presentation, we are excited to announce that we have signed two 10-year firm sales agreements with investment grade utilities covering all 1.2 BCF per day of our capacity on MVP that will commence concurrent with the completion of downstream expansion projects in 2027. Recall we had previously entered into an AMA for 525 million cubic feet per day of our MVP capacity, which we have restructured into an 800 million cubic feet per day, firm sales arrangement with the same counterparty and entered into an additional 400 million cubic feet per day firm sale with a separate counterparty.

At the same time, the Debottlenecking of Eqt's supply further into the southeast should dampen natural gas price volatility for consumers in the region improve grid reliability and materially reduce the risk of service interruptions.

In our view these agreements represent clear and tangible examples of eqt's ability to generate differentiated shareholder value out of each molecule, while simultaneously fostering better outcomes for American consumers by leveraging our unique platform consisting of peer leading scale a strong investment grade balance sheet.

Low cost structure deep high quality inventory and advantaged environmental attributes.

Toby Rice: These are two of the largest long-term physical supply deals ever executed in the North American natural gas market. And we believe signal the buyer's confidence in EQT's unique ability to deliver reliable, clean, and affordable natural gas supply to millions of customers in the southeastern part of the United States. These agreements also highlight how EQT's scale and depth of inventory are catalyzing the expansion opportunities downstream of MVP, which will bring gas further into the southeastern man centers where it is critically needed to replace coal-fired power generation and meet the region's climate goals.

Turning to LNG last month, we announced a heads of agreement for liquefaction services from Commonwealth LNG facility in Cameron parish, Louisiana to produce 1 million tonnes per annum of LNG under a 15 year tolling agreement.

Toby Rice: To put the environmental benefits into perspective, assuming EQT's natural gas displaces coal-fired power generation, the combined impact of these supply agreements would result in approximately 40 million tons per annum of emissions reductions, which is equivalent to taking more than 8 million gasoline-powered vehicles off the road every year. On top of the environmental benefits, these deals should create a win-win economic impact, providing cash flow uplift for EQT, while concurrently dampening natural gas-price volatility for consumers in the southeastern region.

This comes on the heel of a prior HOA with Lake Charles LNG and upon completion of definitive agreements, we will take our total committed LNG tolling capacity to 2 million tons per annum or roughly 270 million cubic feet of gas per day.

The Commonwealth agreement is a continuation of our LNG strategy. We described on our last call, which entails diversifying a portion of the one two bcf per day, we delivered to the Gulf coast via firm pipeline capacity into international markets.

As a reminder, EQT is pursuing a differentiated and more integrated approach to international exposure through tolling arrangements, which we believe provides the best combination of upside exposure with downside risk mitigation. Our strategy gives us direct connectivity to end users of our gas globally allows for end market restructuring.

Alrighty and superior downside protection, we are currently pursuing signing sba's with prospective international buyers as well as additional opportunities to increase our tolling exposure.

Toby Rice: Recall our capacity on MVP will initially receive pricing at station 165, but as downstream projects and these new firm sales arrangements commence, EQT's capacity will be de-bottle-necked, and our pricing exposure will shift to a blend of premium-demand areas, including Henry Hub and TranscoZones 4 and 5 South. To put the impact of this in context, we see these firm sales arrangements and associated downstream de-bottle-necking projects increasing our annual free cash flow by more than $300 million beginning in 2028.

Our scale low cost structure peer, leading core inventory depth and environmental attributes uniquely position us to compete and win in the global Energy Arena and we believe the international market will increasingly covet eqt's molecules is a long duration secure supply source that can drive meaningful emissions reductions vehicle displacement.

Similar to the precedent we are setting in the U S southeast market with our newly announced firm sales agreements directly with utilities.

Toby Rice: At the same time, the de-bottle-necking of EQT supply further into the southeastern region should and materially reduce the risk of service interruptions. In our view, these agreements represent clear and tangible examples of EQT's ability to generate differentiated shareholder value out of each molecule, while simultaneously fostering better outcomes for American consumers by leveraging our unique platform consisting of pure leading scale, a strong investment grade balance sheet, low cost structure, deep high-quality inventory, and advantaged environmental attributes.

Shifting to slide 16 of our Investor deck, We recently announced a first of its kind public private partnership with the state of West Virginia to identify and implement forest management practices across the state.

Facilitated by the States Department of Commerce Division of Forestry and division of natural resources.

Partnership brings together eqt's transparent data driven approach to emissions reduction and west Virginia's commitment to the conservation development and protection of its renowned forest lands to advance Appalachia position as a premier world partner and de Carbonization we.

We plan to deploy advanced soil probe technology from our partners at <unk>, which allow for real time soil measurement to ensure the quantification of carbon reduction is accurate and transparent.

Toby Rice: Turning to LNG, last month, we announced the heads of agreement for liquefaction services from Commonwealth LNG facility in Cameron, Paris, Louisiana to produce 1 million tons per animal balance v under a 15-year polling agreement. This comes on the heel of a prior age away with Lake Charles LNG, and upon completion of definitive agreements, we'll take our total committed LNG toll and capacity to two million tons per annum, or roughly 270 million cubic feet of gas per day.

We will also leverage our strategic partnership with context labs to provide full digital integration and accountability of our carbon reduction effort.

Operational efficacy of these projects will be assured unaudited by West Virginia University as natural resources analysis Center, a multidisciplinary research and teaching facility.

We believe the processes being deployed in our partnership with West Virginia will create one of the highest quality most verifiable nature based carbon sequestration projects anywhere around the globe.

Toby Rice: The Commonwealth agreement is a continuation of our LNG strategy we described in our last call, which entails diversifying a portion of the 1.2 BCF per day we delivered to the capacity into international markets. As a reminder, EQT is pursuing a differentiated and more integrated approach to international exposure through tolling arrangements, which we believe provide the best combination of upside exposure with downside risk mitigation. Our strategy gives us direct connectivity to end users of our gas globally, allows for end market structuring flexibility in superior downside protection.

The output of this effort will be a key enabling factor for EQT to become the first energy company in the world of meaningful scale to achieve verifiable net zero scope, one and two ghd emissions.

Turning to slide 17 of our Investor presentation, we were excited to see the Appalachia regional clean hydrogen or arch to recently selected as one of seven hydrogen hubs in the country to receive funding to accelerate the deployment of use hydrogen technologies and contribute to decarbonising.

Toby Rice: We are currently pursuing signing SBAs with prospective international buyers, as well as additional opportunities to increase our tolling exposure. Our scale, low cost structure, peer leading core inventory depth and environmental attributes uniquely position us to compete and win in the global energy arena, and we believe the international market will increasingly cover EQT's molecules as a long duration, secure supply source that can drive meaningful emissions reductions via cold displacement. Similar to the precedent, we are setting in the US Southeast market with our newly announced firm sales agreements directly with utilities.

Multiple sectors of the economy as a reminder, arch to was a collaboration initiated by EQT. The state of West, Virginia, Battelle, GTI energy and Alleghany science and technology. The broader arch to team is comprised of multiple entities with operations across the Appalachian region spanning the hydrogen value chain as.

Well as technology organizations consultants academic institutions community organizations, and Ngos that will provide commercial and technical leadership for the development and build out of the hub.

The Doe has allocated up to $925 million to arch to noting the hub will leverage the region's ample access to low cost low emissions natural gas to produce clean hydrogen and permanently sequester cotwo.

Toby Rice: Chifting to slide 16 of our investor deck, we recently announced a first of its kind public private partnership with the state of West Virginia to identify and implement forest management practices across the state, facilitated by the state's Department of Commerce, Division of Forestry, and Division of Natural Resources. The partnership brings together EQT's transparent, data-driven approach to emissions reduction, and West Virginia's commitment to the conservation, development, and protection of its renowned forest lands to advance population position as a premier world partner in decarbonization.

Along with the de Carbonization impact arch two is anticipated to facilitate various community benefits, including the potential to create more than 21000 high paying jobs.

The deal we selection of arch to deeply reinforces the critical role natural gas, particularly Appalachian natural gas will play in our nation's transitioned to a lower carbon energy future and EQT is uniquely positioned to be at the forefront of this process.

Toby Rice: We plan to deploy advanced soil probe technology from our partners at Teralidics, which allow for real-time soil measurement to ensure the quantification of carbon reduction is accurate and transparent. We will also leverage our strategic partnership with Context Labs to provide full digital integration and accountability of our carbon reduction efforts. Operational efficacy of these projects will be assured and audited by West Virginia's University's Natural Resources Analysis Center, a multi-disciplinary research and teaching facility.

In terms of Eqt's participation. We are in the early stages of formulating a high level development plan with rigorous assessment of project economics to better understand value creation potential and we expect minimal capital requirements over the next couple of years over the medium term EQT will have significant optionality to.

<unk> and participate in projects within the arch to.

All while retaining complete flexibility as it relates to our level of exposure.

Toby Rice: We believe the processes being deployed in our partnership with West Virginia will create one of the highest quality, most verifiable nature-based carbon sequestration projects anywhere around the globe. The output of this effort will be a key enabling factor for EQT to become the first energy company in the world of meaningful scale to achieve verifiable net zero scope one and two GHG emissions.

Outside of our direct participation. We expect arch to will also have second order effects of driving greater in basin demand for Eqt's low emissions natural gas and could present opportunities for us to leverage our subsurface expertise and $1 9 million net acreage position for Cotwo sequestration.

While still very early in the evolution of <unk> II, we believe eqt's participation in the hub along with various other pillars of our new venture strategy are planting the seeds that have the potential to catalyze the transformation of natural gas into the Holy Grail of cheap reliable and zero carbon energy.

Toby Rice: During the slide 17 of our investor presentation, we were excited to see the Appalachia Regional Clean Hydrogen Hub, or ARCH2, recently selected as one of seven hydrogen hubs in the country to receive DOE funding to accelerate the deployment of U.S, hydrogen technologies and contribute to decarbonizing multiple sectors of the economy. As a reminder, ARCH2 was a collaboration initiated by EQT, the state of West Virginia, but tell GTI Energy and Allegheny Science and Technology.

Now I'll turn the call over to Jeremy.

Thanks, Toby and good morning, everyone I'll start by briefly summarizing our third quarter results, which as a reminder include 39 days of contribution from the tug Hill and <unk> assets.

Volumes in the third quarter were 523 Bcf comprised.

Toby Rice: The broader ARCH2 team is comprised of multiple entities with operations across the Appalachian region spanning the hydrogen value chain as well as technology organizations, consultants, academic institutions, community organizations, and NGOs that will provide commercial and technical leadership for the development and build out of the hub. The DOE has allocated up to $925 million to Arch2, noting the hub will leverage the region's ample access to low cost, low emissions natural gas to produce clean hydrogen and permanently sequester CO2.

Comprised of 491 Bcf of natural gas and $5 2 million barrels of liquids.

Third quarter production volumes included roughly five Bcf of curtailment, principally in response to weak local demand and approximately eight bcf associated with lower than expected non operated turn in lines and curtailments.

On a per unit basis, adjusted operating revenues were $2 28 per Mcf.

And our total per unit operating costs were $1 29 down from $1 37 in the second quarter, reflecting the accretion benefit from a partial quarter contribution of tug hills, low cost assets and lower than expected low due.

Toby Rice: Along with the decarbonization impact, Arch2 has anticipated to facilitate various community benefits, including the potential to create more than 21,000 high-paying jobs. The DOE selection of Arch2 deeply reinforces the critical role natural gas, particularly appellation natural gas, will play in our nation's transition to a lower carbon energy future, and EQT is uniquely positioned to be at the forefront of this process. In terms of EQT's participation, we are in the early stages of formulating a high-level development plan with rigorous assessment of project economics to better understand value creation potential, and we expect minimal capital requirements over the next couple of years.

Toby Rice: Over the medium term, EQT will have significant optionality to evaluate and participate in projects within the Arch2 hub, all while retaining complete flexibility as it relates to our level of exposure. Outside of our direct participation, we expect Arch2 will also have second-order effects of driving greater in-base and demand for EQT's low emissions natural gas, and could present opportunities for us to leverage our subsurface expertise and 1.9 million net acreage position for CO2 sequestration.

Due to increased produced water recycling.

Capital expenditures, excluding noncontrolling interests were $445 million, including Standalone EQT capex of approximately $400 million, which was at the low end of our guidance range, reflecting the continued operational efficiency gains Toby mentioned previously.

Adjusted operating cash flow and free cash flow of $443 million and negative $2 million respectively.

Noting however, free cash flow was negatively impacted by $28 million of nonrecurring expenses from the <unk> transaction without which we would have generated positive free cash flow during the quarter.

Looking ahead to the fourth quarter, we provided guidance on slide 33, which reflects a full quarter of contribution from <unk> and <unk> midstream acquisition.

It's worth highlighting that the midpoint of our <unk> guidance range of $1 per Mcf is roughly 10 cents lower than our Standalone AT&T in the second quarter, which underscores the cost structure accretion from the low breakeven tug Yale and <unk> assets.

Toby Rice: While still very early in the evolution of Arch2, we believe EQT's participation in the hub, along with various other pillars of our new venture strategy, are planting the seeds that have the potential to catalyze the transformation of natural gas into the holy grail of cheap, reliable, and zero-carbon energy.

I'd also note our fourth quarter production outlook embed expectations of curtailments in the first half of the quarter, given elevated eastern storage and seasonal demand weakness.

Over still early in the budgeting process and working through the optimization of our development schedule for 2024, we preliminarily expect to run three rigs and three to four Frac crews next year, which should allow us to maintain pro forma production at approximately two three tcf.

Jeremy Knop: I'll now turn the call over to Jeremy. Thanks, Toby, and good morning, everyone. I'll start by briefly summarizing our third-quarter results, which as a reminder includes 39 days of contribution from the Tughill and XCl assets. Sales volumes in the third quarter were 523 BCFE comprised of 491 BCF of natural gas, in 5.2 million barrels of liquids. We note third-quarter production volumes included roughly 5 BCFE of procurement principally in response to weak local demand, and approximately 8 BCFE associated with lower than expected non-operated turn in lines in procurement.

We anticipate free cash flow of roughly $1 $7 billion next year at recent strip pricing of approximately $3 40 per annum btu.

This equates to a 2020 for free cash flow yield of 10%.

On a cumulative basis, we project nearly $14 billion of free cash flow from 2024 to 2028, which is roughly 60% of our enterprise value and 80%.

Equity market capitalization.

This means at our current valuation investors have the opportunity to buy the Premier natural gas company in North America with most scale, the deepest and highest quality inventory and among the lowest cost structures in the best credit rating at a material discount to peers.

Jeremy Knop: On a per unit basis, adjusted operating revenues were $2.28 per MCFE, and our total per unit operating costs were $1.29, down from $1.37 in the second quarter, reflecting the accretion benefit from a partial quarter contribution of Tughill's low-cost assets and lower than expected LOE due to increased produced water recycling. Capital expenditures, excluding non-controlling interests, were $445 million, including standalone EQT capex of approximately $400 million, which was at the low end of our guidance range, reflecting the continued operational efficiency gains Toby mentioned previously.

Turning to the balance sheet.

Recall, we funded the cash consideration of the <unk> acquisition upon close in August with $1 billion of cash on hand, and $125 billion of term loan borrowings.

We exited the third quarter with $5 9 billion of total debt, including $400 million related to equity like convertible notes.

This equates to an LTM leverage of two one times.

Though we note. This figure includes the full impact of financing the <unk> acquisition with just 39 days of EBITDA contribution for.

Jeremy Knop: Adjusted operating cash flow and pre-cash flow were $443 million and negative $2 million respectively. It's worth noting, however, pre-cash flow was negatively impacted by $28 million of non-recurring expenses from the Tughill transaction, without which we would have generated positive pre-cash flow during the quarter. Looking ahead to the fourth quarter, we provided guidance on slide 33, which reflects a full quarter of contribution from Tughill and X-Sail midstream acquisitions. It's worth highlighting that the midpoint of our GP&T guidance range of $1 per MCFE is roughly $0.10 lower than our standalone GP&T in the second quarter, which underscores the cost structure of creation from the low-break even Tughill and X-Sail assets.

For reference excluding <unk> impact, we estimate LTM net debt to EBITDA would've been approximately 1.25 times at the end of the third quarter.

Despite rising treasury yields eqt's credit spreads have tightened.

Highlighting our strong credit profile.

Recall, we were upgraded to beat <unk> by Moody's shortly after we closed the <unk> acquisition. So we are now investment grade across all three credit rating agencies.

I will also note that EQT has the lowest five year bond yields.

Among natural gas weighted peers.

100 basis points below the average, which also reflects the strength of our credit quality and unwavering commitment to low leverage and our differentiated scale inventory quality and low cost structure.

Jeremy Knop: I'd also note our fourth quarter production outlook embeds expectations of protellments in the first half of the quarter, given elevated eastern storage and seasonal demand weakness. Well, we're still early in the budgeting process and working through the optimization of our development schedule for 2024, we preliminarily expect to run three rigs and three to four crack crews next year, which should allow us to maintain pro forma production in approximately two .3 TCFE.

As it relates to capital allocation, we remain pleased with the execution of our shareholder return framework to date, and we'll continue with our opportunistic all the above strategy, but our north star being the counter cyclical long term compounding of cash flow.

Consistent with our track record, we will maintain a strong bias towards debt repayment over the coming quarters at least until we achieve our one time leverage target at $2 75 per M Btu natural gas pricing.

Jeremy Knop: We anticipate free cash flow of roughly $1.7 billion next year at recent strip pricing of approximately $3.40 per MMBTU, which equates to a 2024 free cash flow yield of 10%. On a cumulative basis, we project nearly $14 billion of free cash flow from 2024 to 2028, which is roughly 60% of our enterprise value and 80% of equity market capitalization . This means that our current valuation investors have the opportunity to buy the premier natural gas company in North America with the most scale, the deepest and highest quality inventory and among the lowest cost structures and the best credit rating at a material discount appears.

This will provide a fortress balance sheet through all parts of the commodity cycle.

This will in turn minimize downside risk to our enterprise, while allowing us to limit the need to defensively hedge and cap, what we anticipate being unpredictable asymmetric price movements to the upside in the years ahead.

We also continue to rigorously assess new investment opportunities with strong risk adjusted returns that improve the quality of our business.

Similar to our West Virginia water system, we highlighted last quarter.

With the <unk> midstream team now part of EQT, we are actively exploring opportunities to deploy capital into differentiated infrastructure investments. They can debottleneck, our upstream production allow us to durably compound cash flow at very attractive rates of return with minimal risk while simultaneously improving our operational efficiency.

Jeremy Knop: Turning to the balance sheet, recall we funded the cash consideration of the Tughill and X-Sail acquisition upon close in August with $1 billion of cash on hand and $1.25 billion of terminal and borrowings. We exited the third quarter with $5.9 billion of total debt, including $400 million related to equity-like convertible notes, which equates to an LTM leverage of 2.1 times. Though we note this figure includes the full impact of financing the Tughill and X-Sail acquisition with just 39 days of EBITDAF contribution.

Our share buyback program also remains a key tool for opportunistic execution at points in the cycle, where we see favorable risk reward potential for generating returns well in excess of our weighted average cost of capital.

Recall at our current share price, we have generated an approximate 40% return for shareholders on.

Jeremy Knop: For reference, excluding Tughill and X-Sail impact, we estimate LTM net debt to EBITDAF would have been approximately 1.25 times at the end of the third quarter. Despite rising treasury yield, EQT's credit spreads have tightened, highlighting our strong credit profile. For call, we were upgraded to BAA3 by Moody's shortly after we closed the Tughill acquisition, so we were now investment rate across all three credit rating agencies. I will also note that EQT has the lowest five-year bond yield among natural gas weighted peers.

On the roughly $600 million of share repurchases, we have executed to date, which.

Which is the highest amongst our peer group and we still have approximately $1 4 billion remaining under our existing authorization.

And finally sustainable long term base dividend growth is a key pillar of our shareholder return strategy and to the thinned. We recently raised our dividend by 5% to 63 per share on an annualized basis.

Since initiating our dividend in late 2021, we have now increased it by more than 25% cumulatively over that period, which underscores our confidence in the sustainability of our business and our corporate free cash flow breakeven price that is amongst the lowest in North America.

Jeremy Knop: 100 basis points below the average, which also reflects the strength of our credit quality and unwavering commitment to low leverage and our differentiated scale inventory quality and low cost structure. As it relates to capital allocation, we remain pleased with the execution of our shareholder return framework to date and will continue with our opportunistic all-the-above strategy, with our north star being the counter-cyclical long-term compounding of cash flow. Consistent with our track record, we will maintain a strong bias toward debt repayment over the coming quarters, at least until we achieve our one-time leverage target at $2.75 per MMBCU natural gas pricing, which will provide a fortress balance sheet through all parts of the Charles.

As we eliminate structural costs from the business through actions such as debt repayment share repurchases and synergy capture we expect to continue growing our base dividend over time without putting upward pressure on our corporate cost structure.

Turning to the macro environment, we see several factors lending support the natural gas market in 2024 and beyond.

First strong gas fired power generation resilient LNG export demand and lower than expected production. This summer reduced expected storage overhang than many were forecasting back in the spring by over 300 Bcf.

Second while we do expect some incremental supply from associated gas in connection with new Permian pipeline capacity commencing in the fourth quarter, we see lower 48 volumes exiting this year flat to slightly down compared to Q3 of 2023.

Jeremy Knop: This will in turn minimize downside risks to our enterprise while allowing us to limit the need to defensively hedge and tap what we anticipate being unpredictable asymmetric price movements to the upside in the years ahead. We also continue to rigorously assess new investment opportunities with strong risk adjust returns that improve the quality of our business. Similar to our West Virginia water system, we highlighted last quarter. With the XTL midstream team now part of EQT, we are actively exploring opportunities to deploy capital into differentiated infrastructure investments that can debobble neck our upstream production, allow us to durably compound cash flow at very attractive rates return with minimal risk while simultaneously improving our operational efficiency.

And we see further declines in the first half of 2024 as the impact from a 25% plus drop in gas rigs since March begins to set in especially in the high decline Haynesville play, where the rig count remains well below maintenance levels.

Third the progress demonstrated commissioning the Golden pass and Plaquemines LNG facilities has been encouraging and will create structural tailwind, allowing LNG demand to reach a record 15 Bcf per day, even before the facilities are fully operational.

Jeremy Knop: Our sheer buyback program also remains a key tool for opportunistic execution at points in the cycle where we see favorable risk reward potential for generating returns well in excess of our weighted average cost to capital. Recall at our current share price, we have generated an approximate 40% return for shareholders on the roughly 600 million of cherry purchases we have executed to date, which is the highest amongst our peer group, and we still have approximately $1.4 billion remaining under our existing authorization.

Fourth we expect natural gas power generation to continue taking away share from coal is the investment case for cole weakens further with the market increasingly turning to cleaner burning natural gas.

We expect coal production dropped by over 20% year over year and 2024 has the effect of the recent wave of coal retirement takes hold.

And a tightening coal market will further support the natural gas fundamentals in the power sector moving forward, where total gas equivalent demand for coal still stands at 14 Bcf per day in the United States alone.

Jeremy Knop: And finally, sustainable long-term base dividend growth is a key pillar of our shareholder return strategy, and to descend, we recently raised our dividend by 5% to 63 cents per share on an annualized basis. Since initiating our dividend in late 2021, we have now increased it by more than 25% cumulatively over that period, which underscores our confidence in the sustainability of our business and a corporate pre-cash flow break even price that is amongst the lowest in North America.

Moving to hedging we tactically added to our hedge position during the quarter to further derisk a portion of our expected free cash flow and debt repayment goals. We now have greater than 40% of our Q1 through Q3 2024 production hedged inclusive of tug hills volumes with a weighted average floor price of.

Approximately $3 60 per Btu, and a weighted average ceiling of $4 10 Permian Btu.

Jeremy Knop: As we eliminate structural costs from the business through actions such as debt repayment, cherry purchases, and synergy capture, we expect to continue growing our base dividend over time without putting upward pressure on our corporate cost structures. Turning to the macro environment, we see several factors lending support the natural gas market in 2024 and beyond. First, strong gas-fired power generation, resilient LNG export demand, and lower than expected production this summer reduced expected storage overhang that many were forecasting back in the spring by over 300 BCF.

Note, our hedge position remains strategically tilted towards the first half of 2024, where we see the most potential downside risk should normal weather again not materialize.

While protecting near term cash flow and prioritizing our debt repayment goals, we are intentionally creating the flexibility to maintain maximum upside price exposure in late 2020 for 2025 and beyond.

The natural gas market looks increasingly tight and we see the potential for pricing to move asymmetrically higher.

As it relates to basis Appalachian differentials have been relatively wide of late driven by elevated eastern storage levels, a byproduct of the warm prior winter.

Jeremy Knop: Second, while we do expect some incremental supply from associated gas and connection with new Permian pipeline capacity commencing in the fourth quarter, we see lower 48 volumes exiting this year flat to slightly down compared to Q3 of 2023. And we see further declines from the first half of 2024 is the impact from a 25% plus drop in gas rigs since March begins to set in, especially in the high decline Haynesville play where the rig count remains well below maintenance levels.

Our strong basis hedge position pay dividends this quarter boosting our corporate wide realized natural gas price by <unk> 12 per annum Btu.

We have roughly 80% of expected fourth quarter local volumes covered with basis hedges that are in the money relative to the current strip. So we remain in an advantaged position near term.

Over the medium to long term, we see several factors that could linked structural support to Appalachian basis, including the commencement of MVP and additional coal fired power retirements in the PJM market, creating incremental demand upward of four Bcf per day.

Jeremy Knop: Third, the progress demonstrated commissioning the golden pass and black men's LNG facilities has been encouraging and will create structural tailwinds allowing LNG demand to reach a record 15 BCF per day, even before the facilities are fully operational. Fourth, we expect natural gas power generation to continue taking away share from coal is the investment case for coal we can further with the market increasingly turning to cleaner burning natural gas. We expect coal production dropped by over 20% year over year in 2024 is the effect of the recent wave of coal retirements takes hold.

As it relates to MVP timing, we are encouraged by the recent <unk> and things that consent order and continue to model. The first quarter of 2024 in service date.

The outlook for MVP increasingly derisked expansion projects to move production further into the southeast U S are progressing.

As Toby highlighted eqt's scale quality and depth of inventory low cost structure and investment grade balance sheet uniquely position us to help facilitate these expansion projects.

Jeremy Knop: In a tightening coal market will further support the natural gas fund mills in the power sector moving forward, where total gas equivalent demand for coal still stands at 14 BCF per day in the United States alone. Moving to hedging, we tactically added to our hedge position during the quarter to further de-risk of course of our expected pre-cash flow and debt repayment goals. We now have greater than 40% of our Q1 through Q3 2024 production hedge, inclusive of tug hills volumes, with a weighted average for price of approximately $3.60 per MMBTU in a weighted average ceiling of $4.10 per MMBTU.

This dynamic is underscored by the one two bcf per day of long term firm sales agreements that we recently signed with investment grade utilities in the southeast region.

Jeremy Knop: Note our hedge position remains strategically tilted towards the first half of 2024, where we see the most potential downside risk should normal weather, again, not materialize. While protecting near-term cash flow and prioritizing our debt repayment goals, we are intentionally creating the flexibility to maintain maximum upside price exposure in late 2024, 2025, and beyond. But the natural gas market looks increasingly tight and we see the potential for pricing to move asymmetrically higher.

These deals create a win win outcome as they underpin the debottlenecking of downstream markets and directly link eqt's volumes to our market price and a meaningful premium to Henry hub, while simultaneously, providing utility customers with surety of low cost natural gas supply for decades to come.

Upon commencement, we see these agreements and the associated Debottlenecking projects, improving our 2028 corporate wide differentials by 18 per Mcf, which in turn should drive more than $300 million of annualized free cash flow uplift in 2028 and beyond.

These deals provide EQT long term supply growth optionality that is paired with a sustainable utility demand dynamics, which could drive an even greater uplift to long term free cash flow over time.

Importantly, these contracts and debottlenecking occur around the same time, our gathering rates with <unk> complete the contractual step down from 80 today to 30 per Mcf in 2028 further accelerating the decline in our free cash flow breakeven price and Supercharging the free cash flow growth at a time.

Jeremy Knop: As it relates to basis, appellation differentials have been relatively wide of late, driven by elevated eastern storage levels, a byproduct of the warm prior winter. Our strong basis hedge position paid dividends this quarter, boosting our corporate wide, realized natural gas price by $12 per MMBTU. We have roughly 80% of expected fourth quarter local volumes covered with basis hedges that are in the money relative to the current strip, so we remain in an advantaged position near-term.

When do we expect other gas plays like the haynesville to be approaching inventory depletion, that's driving up the marginal cost of natural gas.

Quite simply the difference between a higher marginal cost of natural gas experienced by peers compared to EQT is declining cost structure should uniquely accrue to EQT shareholders in the form of free cash flow growth and value creation.

Jeremy Knop: Over the medium to long-term, we see several factors that could link structural support to appellation basis, including the commencement of MVP and additional coal-fired power retirements in the PJM market, creating incremental demand upward of four BCF per day. As it relates to MVP timing, we are encouraged by the recent equitrans in Simza Consent Order and continue to model the first quarter of 2024 in service date. The outlook for MVP increasingly be risked, expansion projects to move production further into the Southeast US are progressing.

These firm sales agreements represent examples of the various differentiated opportunities we are seeing arise from eqt's gravity and momentum as the clear operator of choice for the highest quality long duration inventory in the North American natural gas market and we believe these opportunities will ultimately allow us to continue to create differentiated shareholder value.

Relative to peers in the years ahead.

Importantly, these types of opportunities they are not simply due to scale, what underpinned by Eqt's World class assets, coupled with our culture and teams that are relentless in our pursuit of excellence as the operator of choice and driven to maximize value for shareholders.

Jeremy Knop: As Toby highlighted, EQT scale, quality and depth of inventory, low cost structure and investment grade balance sheet uniquely position us to help facilitate these expansion projects. This dynamic is underscored by the 1.2 BCF per day of long-term firm sales agreements that we recently signed with investment grade utilities in the Southeast region. These deals create a win-win outcome as they underpin the debodal necking of downstream markets and directly link EQT's volumes to a market price and a meaningful premium to Henry Hub, while simultaneously providing utility customers with surety of low cost natural gas supply per decade to come.

I'll close by highlighting slide 12 of our Investor presentation, which illustrates an internal analysis of the natural gas price required to generate sufficient free cash flow such that a gas producer generates a simple 10% return on.

Jeremy Knop: Upon commencement, we see these agreements and the associated debodal necking projects improving our 2028 corporate-wide differential by 18 cents per MCF, which in turn should drive more than $300 million of annualized free cash flow uplift in 2028 and beyond. These deals provide EOT long-term supply growth optionality that is paired with sustainable utility demand, dynamics which could drive an even greater uplift to long-term free cash flow over time. Importantly, these contracts and debuddle neckings occur around the same time our gathering rates with equitrants, some police that contractual step down from 80 cents today to 30 cents per NCF in 2028.

On current respective enterprise value, what we view to be the most basic tenant of shareholder value creation.

We believe the days of wellhead IRR is driving activity levels amongst U S. Gas producers are in the rearview mirror as this behavior relate to the destruction of hundreds of billions of dollars of capital in the last decade.

Put very simply wellhead IRR on D&C capex are unrelated to corporate returns and cost of capital.

Instead, we see the marginal cost of U S natural gas supply the holding to a fully burdened corporate cost curve that requires a sufficient return on corporate capital our enterprise value not just a return on field level Capex.

I want to highlight a few observations from this slide.

First the marginal molecule of U S gas supply is coming from the Haynesville, requiring a natural gas price of approximately $3 50 per btu to even begin generating cash flow in maintenance mode.

Jeremy Knop: Further accelerating the decline in our free cash flow break even price and supercharging the free cash flow growth at a time when we expect other gas plays like the Haynesville to be approaching inventory depletion, thus driving up the marginal cost of natural gas. Quite simply the difference between a higher marginal cost of natural gas experienced by peers compared to EQT's declining cost structure should uniquely accrue to EQT shareholders in the form of free cash flow growth and value growth.

Meaning below this price no shareholder value is being created in inventory optionality is being depleted.

On the other hand EQT is at the low end of the cost of supply curve, which translates to structurally more durable through the cycle free cash flow generation and returns for our shareholders and also less need to defensively hedge away gas price upside.

Further we see the price required to generate corporate return for Haynesville producers already at north of $4 per Btu based on current market valuations.

Jeremy Knop: These firm sales agreements represent examples of the various differentiated opportunities we are seeing arise from EQT's gravity and momentum is the clear operator of choice for the highest quality, long duration inventory and the North American natural gas market. And we believe these opportunities will ultimately allow us to continue to create differentiated shareholder value relative to peers in the years ahead. Importantly, these types of opportunities are not simply due to scale, but underpinned by EQT's world class assets coupled with a culture and teams that are relentless in the pursuit of excellence as the operator of choice and driven to maximize value for shareholders.

On the other hand, EQT shares are pricing in a level embedding a mid $3 gas price <unk>.

Providing a superior entry point to gain exposure to natural gas prices and in a superior risk adjusted manner due to eqt's lower cost of supply.

As previously noted our contractual gathering rate improvement unrivaled depth of repeatable low cost inventory and new firm sales agreements will drive eqt's cost of supply even lower over the next five years in contrast to the rest of the industry, which will likely see upward pressure over this period as peer producers move toward lower <unk>.

Jeremy Knop: I'll close by highlighting slide 12 of our investor presentation, which illustrates an internal analysis of the natural gas price required to generate sufficient free cash flow such that a gas producer generates a simple 10% return on current respective enterprise value what we view to be the most basic tenant of shareholder value creations. We believe the days of well head IRR's driving activity levels amongst US gas producers are in the rear view mirror is this behavior led to the destruction of hundreds of billions of dollars of capital in the last decade.

<unk> inventory.

As a result, we believe EQT is uniquely positioned to capture a disproportionate amount of natural gas price upside relative to peers in the years ahead.

I'll now turn the call back over to Toby for some concluding remarks.

Thanks, Jeremy to conclude today's prepared remarks, I want to reiterate a few key points number one the momentum and gravity at EQT right now is unrivaled and I've never felt anything like it in my career, we are executing at record levels, signing historic physical supply deals that simultaneously maximize the value of each molecule.

Jeremy Knop: Put very simply well head IRR's in on DNC CapEx are unrelated to corporate returns and cost of capital. Instead, we see the marginal cost of US natural gas supply, the home to a fully burdened corporate cost curve that requires a sufficient return on corporate capital or enterprise value, not just a return on field level CapEx. I want to highlight a few observations from the slide. First, the marginal molecule of US gas supply is coming from the Hainesville, requiring a natural gas price of approximately $3.50 from an BTU to even begin generating cash flow in maintenance mode, meaning below this price, no shareholder value is being created in inventory optionality is being depleted.

And provide secure supply to end customers, while cutting emissions and executing on our vision to create the preeminent low cost producer of natural gas on the global stage.

Integration of the <unk> and <unk> assets is blazing ahead at record pace, which speaks to the power of our proprietary digital platform and continued refinements of our integration playbook.

Third after a stellar second quarter, our drilling and completions teams, yet again set new internal and World Records in Q3.

The superior operational execution is facilitating additional value creation potential on the tug of assets with Eqt's team already improving drilling and completion efficiency by 40% in just 60 days of operating the assets driving the potential for $150 per foot of well cost savings.

Jeremy Knop: On the other hand, EQT is at the low end of the cost of supply curve, which translates destructurally more durable through the cycle free cash flow generation and returns for our shareholders and also less need to defensively hedge away gas price upside. Further, we see the price required to generate corporate return for Hainesville producers already at north of $4 for an in BTU based on current market valuation.

Fifth the firm sales agreements, we announced associated with our MVP capacity are materially accretive to our long term free cash flow outlook and shareholder value and highlight the differentiated opportunities arising from eqt's pure leading scale low cost structure inventory depth and environmental attributes and finally sixth.

Our first of its kind public private forest management partnership with the state of West Virginia should create one of the highest quality most verifiable nature based carbon sequestration projects and should help facilitate EQT, becoming the first energy company in the world of meaningful scale to achieve net zero emissions and with that.

Jeremy Knop: Dewey. On the other hand, EQT shares are pricing in a level embedding a mid $3 gas price, providing a superior entry point to gain exposure to natural gas prices, and in a superior risk-adjusted manner due to EQT's lower cost of supply. As previously noted, our contractual gathering rate improvement unrivaled depth of repeatable low-cost inventory and new firm sales agreements will drive EQT's cost of supply even lower over the next five years, in contrast to the rest of the industry which will likely see upward pressure over this period as peer producers move toward lower quality inventory. As a result, we believe EQT is uniquely positioned to capture a disproportionate amount of natural gas price upside relative to peers in the years ahead.

I would now like to open the call to questions.

Thank you at this time I would like to remind everyone in order to ask a question press star one on the number.

Star then the number one on your telephone keypad.

Participants will be allowed one question and one follow up question.

We'll pause for just a moment to compile the Q&A roster.

Your first question comes from the line of <unk> Hari with Goldman Sachs. Please go ahead.

Toby Rice: I'll now turn the call back over to Toby for some concluding remarks. Thanks, Jeremy.

Hi, Good morning, Thank you for taking my questions.

The film sales contract on the Mountain Valley pipeline is notable.

Toby Rice: To conclude today's prepared remarks, I want to reiterate a few key points. Number one, the momentum and gravity at EQT right now is unrivaled, and I have never felt anything like it in my career. We are executing at record levels, signing historic physical supply deals that simultaneously maximize the value of each molecule and provide secure supply to end customers while cutting emissions and executing on a vision to create the pre-eminent low-cost producer of natural gas on the global stage.

It improves the company's long term supply cost positioning.

Which I assume is that completely reflected in slide on slide number 12.

So a couple of questions here.

How did this deal.

Come together is there potential for similar opportunities in the future.

And also if you can help investors get a better sense of the risk in achieving the free cash flow uplift of more than $300 million.

Hi, <unk>. This is Toby let me just put some some broader color on what's happening in the United States and then I'll kick it over to Jeremy for more of the details.

Toby Rice: Second, integration of the Tug Hill and XCL assets is blazing ahead at record pace, which speaks to the power of a proprietary digital platform and continued refinements of our integration playbook. Third, after a stellar second quarter are drilling a completion teams yet again set new internal and world records in Q3. Fourth, this superior operational execution is facilitating additional value creation potential on the Tug Hill assets. With EQT's team already improving drilling and completion efficiency by 40% in just 60 days of operating the assets, driving the potential for $150 per foot of well-cost savings.

Over the last 10 years, we've seen natural gas demands grow above 50% in this country during that period of time the pipeline capacity. That's been built has only grown about 25% and so.

Toby Rice: Fifth, the firm sales agreements we announced associated with our MVP capacity are materially accreted to our long-term free cash well outlook and shareholder value and highlights the differentiated opportunities arising from EQT's peer-leading scale, low-cost structure, inventory depth and environmental attributes. And finally, sixth, our first of its kind public private forest management partnership with the state of West Virginia should create one of the highest quality, most verifiable nature-based carbon sequestration projects and should help facilitate EQT becoming the first energy company in the world of meaningful scale to achieve net zero emissions.

It shows the the drive from a need for more pipeline infrastructure that would.

Lead to opportunities like this going forward.

Jeremy you want to cover some of the more detailed points about this transaction how it came together.

Totally.

So this is something we've been working on for several months.

It's part of just our ongoing commercial strategy.

To really find opportunities like this.

If you want to think about at a high level, we're effectively taking one two bcf a day of volume Thats currently being sold in the local into market and instead through these transactions. The net effect is selling that at about a nymex minus <unk> 40 type differential when you take into account the premium end market pricing, we're getting in the cost.

Transported there on MVP.

That gets you to that call it 15% to 20 <unk> of all in company wide differential improvement in 2028 and beyond.

Cameron Horwitz: And with that, I'd now like to open the call to questions. Thank you. At this time, I would like to remind everyone in order to ask a question, press star one and the number, press star that the number one on your telephone keypad. Participants will be allowed one question and one follow-up question. We'll pause for just a moment to compile the Q&A roster.

That's what gets that that $300 million just in total of annual cash flow uplift.

Great and is there any further opportunities of such nature, which you foresee in the future and also if you can help us quantify the risk around that free cash flow uplift of $300 million do you see.

Any any scenarios, where that $200 million, we did not come through for EQT.

Umang Choudhary: Your first question comes from the line of humane Tudari with Goldman Sachs. Please go ahead. Hi, good morning. Thank you for taking my questions. The firm sales contract on the Mountain Valley pipeline is notable, given it improves the company's long-term supply quest positioning, which I assume is not completely reflected on slide number 12. So a couple of questions here. Like, how do these deals come together? Is there potential for similar opportunities in the future? And also, if you can help investors get a better sense of the risk in achieving the free cash flow up left of more than 300 million dollars. Hi, Umang, this is Toby.

Yeah. Good question, we think the risk is relatively low because the contracts while structured in different tranches.

In many ways are actually linked to Nymex pricing and Gulf coast pricing.

And so any change in Nymex or just from the poll on the LNG market and that export Gulf Coast region should really benefit.

These contracts and the way they're priced directly in terms of further uplift look we hope. This is really the first of a lot of contracts like this we still have plenty of volume at our scale that we can that.

We can use to try to try to pair enter into deals like this and really if you think about the way we are approaching our LNG strategy through the tolling structure, but we'd really like to do is try to replicate the essence of what we're doing here really on the global stage, taking molecules that are sold domestically and pairing them up with contracts like this.

Toby Rice: Let me just put some broader color of what's happening in the United States, and then I'll kick it over to Jeremy for more of the details. You know, over the last 10 years, we've seen natural gas demands grow about 50% in this country. During that period of time, the pipeline capacity has been built has only grown about 25%. And so it shows the drive from a need for more pipeline infrastructure that would lead to opportunities like this going forward.

And selling them abroad.

We really hope across the business. This is the first of many deals like this but they take time to do.

But again, it's I think it's evidenced for building the business for the long run doing deals like this that even if there might be some sort of near term.

Cost I mean, you think about a deal like like these firm sales deals there might be near term.

Toby Rice: Jeremy, you want to cover some of the more detailed points about this transaction how it came together? Yeah, absolutely. So this is something we've been working on for several months, and it's part of just our ongoing commercial strategy to really find opportunities like this. If you want to think about it at high level, we're effectively taking 1.2 BCF a day of volume that's currently being sold in the local M2 market, and instead through these transactions, the net effect is selling that at about a 9x minus 40 cent type differential when you take into account the premium in market pricing we're getting and the cost to transport it there on MVP.

A little bit of downside to cash flow, but think about it the ami that we restructured here.

Toby Rice: That gets you to that call it 15 to 20 cents of all in company-wide differential improvement in 2028 beyond, and that's what gets that $300 million just in total of annual cash flow uplift. Great, and is there any further opportunities of such nature which you foresee in the future, and also if you can help us quantify the risk around that free cash flow uplift of $300 million, do you see any scenarios where that $300 million will not come through for EQT?

As maybe a couple of hundred million dollars in the next year or two.

But that's really made up by 10 X that over the life of these contracts. So it's really restructuring something.

For kind of a 10 to one investment return is really how we look at it as we're really trying to build long term value.

That's very helpful. Thank you.

Thank you. Your next question comes from the line of John Abbott with Bank of America. Please go ahead.

Good morning, and thank you for taking our questions.

Toby Theres been a lot of press speculation recently about further industry consolidation.

Even between gassy companies.

How do you think about industry consolidation from here.

How do you see eqt's potential role on that.

While my view Hasnt changed we think consolidation.

As a tool when used correctly to create a lot of value for shareholders.

I think you look at the track record that we've established over the past few years, we've done really smart deals and we've created a lot of value.

Look at the <unk> acquisition.

Focus on lowering our cost structure those assets have lowered our cost structure by about 15 pre synergies.

Toby Rice: Yeah, good question. You know what, we think the risk is relatively low because the contracts are well structured in different tranches. In many ways, we're actually linked to 9x pricing and Gulf Coast pricing, and so any change in 9x or just from the poll on the LNG market in that export Gulf Coast region should really benefit these contracts in the way they're priced directly. In terms of further uplift, look, we hope this is really the first of a lot of contracts like this.

So the operational efficiencies that we're demonstrating now will be additive on top of that.

Improved our long life inventory.

And also making the energy cleaner.

<unk> ran a pretty clean program, but now these assets are going to be incorporated into our net zero goal. So make the energy we produce cleaner as well so.

Every opportunity has to be looked at it.

Toby Rice: We still have plenty of volume in our scale that we can use to try to pair into deals like this, and really if you think about the way we're approaching our LNG strategy through the tolling structure, what we'd really like to do is try to replicate the essence of what we're doing here, really on the global stage, taking molecules that are sold domestically and pairing them up with contracts like this and selling them abroad. So we really hope across the business, this is the first of many deals like this, but they take time to do, but again, it's evidence we're building the business for the long run at doing deals like this, that even if there might be some sort of near-term cost, I mean, you think about a deal like these firm sales deals, there might be near-term a little bit of downside to cash flow, but think about it.

Standalone basis, but for us the guiding light is always what can we do to lower our cost structure make us a better business produce more reliable and cleaner energy and we'll be disciplined and continue to.

Until we see anything that looks attractive to us.

I appreciate that and then for a follow up question. So appreciate.

Appreciate the free cash flow.

These sort of provided right there but.

But when you think about spending I mean do you ever put out your budget, but when you think about long term through long term maintenance capex.

Without taking into account potential debottlenecking opportunities, how do you think of that at this point in time.

I spent perspective to hold maybe two three tcf flat.

Toby Rice: The AMA that we restructured here is maybe a couple hundred million dollars in the next year or two of Hit, but that's really made up by 10X that over the life of these contracts. So it's really restructuring something for kind of a 10-to-1 investment return, is really how we look at it as we're really trying to build long-term value.

Yes, let me take that one so let's use next year as a proxy. So we expect what we're still working through the budget, we expect a low $2 billion type all in Capex number.

Toby Rice: Thank you.

We'll provide more color at a later date on this but it's really important to note that the capex required to just maintain our base business is really quite a bit below that.

Really what we're trying to do right now is find new opportunities to reinvest into low low risk strong return.

John Abbott: Your next question comes from the line of John Abbott with Bank of America. Please go ahead. Good morning and thank you for taking our questions. Toby, there's been a lot of press speculation recently about further industry consolidation, even between gas and companies. How do you think about industry consolidation from here and how do you see EQ2's potential role in that? Well, my view hasn't changed. We think consolidation is a tool when used correctly to create a lot of value for shareholders.

Opportunities so things like the West Virginia water system that we invested and talked about last quarter. Good example of that we're looking at a couple of other infrastructure projects through our <unk> platform now to Debottleneck volumes.

To realize better pricing. We're also seeing opportunity is really on the land front, which we think are unique to appalachia opportunities, where we effectively can acquire new locations for about $1 million per location and these are locations with $5 million to $10 million when drilled so we have a pretty active program, replacing about 80.

John Abbott: I think you look at the track record that we've established over the past few years. We've done really smart deals and we've created a lot of value. You know, look at the Tug Hill acquisition. We're focused on lowering our cost structure. Those assets have lowered our cost structure by about 15 cents, pre synergies. So the operational efficiencies that we're demonstrating now will be additive on top of that. I improved our long life inventory and also making the energy cleaner.

Percent of our lateral footage developed each year, we're sort of perpetually extends our inventory and so on a rate of return basis, we see those as Perl at five to 110 to one type investments and so as we see those come up we'll continue to allocate capex towards that but really that long term just maintenance capex number for the base business is probably closer to right.

Right about $2 billion, and we don't see that changing materially.

John Abbott: You know, the Tug Hill ran a pretty clean program, but now these assets are going to be incorporated into our net zero goal. So make the energy we produce cleaner as well. So I think every opportunity has to be looked at at a standalone basis. But for us, the guiding light is always what can we do to lower our cost structure, make us a better business, produce more reliable and cleaner energy. And we'll be disciplined and continue to wait until we see anything that looks attractive to us. Appreciate that.

Really five year forecast at least.

Very very helpful. Thank you for taking our questions.

Thank you. Your next question comes from the line of Arun <unk> with Jpmorgan. Please go ahead.

Yes, good morning.

Tobey.

The crown jewel of the tug Hill deal X sale midstream system I wanted to get your thoughts on value creation opportunities from integrating the midstream further terms of internal and third party opportunities.

John Abbott: And then for our follow up question, you know, appreciate the free cashflow, a galaxy sort of provided right there. But when you think about spending, I mean, you haven't put out your budget. But when you think about long term, too long term maintenance cap back without taking to account potential, the bottlenecking opportunities, how do you think of that at this point of time? A spend perspective to hold maybe 2.3 T C F E flat.

Obviously, it is going to help your cost structures are highlighted as well.

Yes, we're excited about the potential for this.

Asset base and the leadership team, we picked up to create value.

In this area, but I would say.

We're looking for more.

<unk> opportunities that will generate the <unk>.

Pretty attractive returns low risk.

John Abbott: Yeah, let me take that one. So let's use next year's a proxy. So we expect, well, we're still working through the budget. We expect a low $2 billion type all in CapEx number. But you know, we'll provide more color to later date on this, but it's really important to note that the CapEx required to just maintain our base business is really quite a bit below that. Really, what we're trying to do right now is find new opportunities to reinvest into low low risk, strong return.

The returns that we're looking for.

We're going to continue to just keep pushing the ball along are capturing those synergies that we identified that clearance and connector is something that's top of mind for us.

Looking to accelerate any water debottlenecking.

One thing that's really important to just highlight is a lot of the completion efficiency gains have come from Debottlenecking water. So that will continue to be a big focus there.

On that front and hopefully these these investments in water infrastructure will give us an opportunity to continually come back and talk about the cost savings both on an LOE front and the completion side of things from a third party business opportunity.

John Abbott: You know, opportunities. So things like the West Virginia water system that we invested in talked about last quarter. Good example of that. You know, we're looking at a couple other infrastructure projects through our XCL platform now to deboddle neck volumes to realize that are pricing. You know, we're also seeing opportunities really on the landfront, which we think are unique to Appalachia opportunities where, you know, we effectively can acquire new locations for about a million dollars per location.

This team is definitely capable and with our systems that we have.

We're able to provide those opportunities others, where it makes sense, but.

One of the things with the really large contiguous acreage position as third party opportunities are limited, but if they do pop up.

We've got our eyes out for them and what will be taken advantage of those.

John Abbott: And these are locations worth $5 to $10 million when drilled. So we have a pretty active program replacing about 80% of our lateral footage developed each year. We're sort of perpetually extends our inventory. And so on a rate of return basis, we see those is pellet five to one 10 to one type investments. And so as we see those come up, we'll continue to allocate CapEx towards that, but really that long term just maintenance CapEx number for the base business is probably closer to to right of it right about 2 billion. And we don't see that changing materially in the really five year forecast at least. Very, very helpful.

Great.

Just maybe a follow up on the 2024 outlook, we've highlighted $1 7 billion of free cash flow potential sounds like capex will be in the low <unk>.

$2 billion range.

Can you give us a sense on your thoughts on differentials.

For next year.

Yes, I would say on a.

Kind of what's embedded in that is on an all in company basis like a 55 to 60 kind of all in differential and we're seeing quite a bit of movement right now, but that's probably the appropriate range. If you try to tie numbers out.

John Abbott: Thank you for taking our questions. Thank you.

Arun Jayaram: Your next question comes from the line of Arun Jayaram with JP Morgan. Please go ahead. Yeah, good morning. Toby, you know, the crown jewel of the tug heel deal is the XCL midstream system. I want to get your thoughts on value creation opportunities from integrating the midstream further terms of internal and third party opportunities. You know, obviously it is going to help your your cost structures is highlighted as well. Yeah, Arun, we're excited about the potential for this asset base and the leadership team.

Great. Thanks, a lot.

Thank you. Your next question comes from the line of <unk> Kumar with Mizuho. Please go ahead.

Hi, Good morning, guys and thanks for taking my questions I can I want to start on this new firm sales contract I think Josh you mentioned joining me you mentioned that.

There is an impact of about $100 million to $200 million in near term.

Could you help US bridge the gap of what is driving that I understand that the longer term.

Benefit comes from better pricing.

Arun Jayaram: We picked up the create value in this area. But I'd say, as we're looking for more investment opportunities that'll generate the pretty attractive return low risk returns that we're looking for. We're going to continue to just keep pushing the ball along on capturing those synergies that we identified, you know, that Clarington connector is something that that's top of mind for us. You know, looking to accelerate any water debottle necking, you know, one thing that's really important to just highlight is a lot of the completion of fish begins have come from debottle necking water.

Whats the restructuring of the MA costing you.

Yes, so that <unk>. Originally if you remember was 525 million a day.

And so the cost of MVP during this call. It two to three year period until these expansion projects are built out effectively what that saying is thats, probably a $125 million to $150 million a year of near term free cash flow that we opted to give up so call it $300 million maybe in total.

And if you use some high level math and say.

The total annual free cash flow, we gain when these projects come online about $300 million I'd like a 10.

Arun Jayaram: So that will be continue to be a big focus there. On that front and hopefully these these investments in water for structure will will give us an opportunity to continually come back and talk about the cost savings both on an L.O.E, front and completion side of things from a third party business opportunity. You know, this team is definitely capable and with our systems that we have, we're able to provide those opportunities to others where it makes sense.

Percent free cash flow yield is about $3 billion. So we kind of see it as again 3 billion over 300 about a 10 to one.

So again, we think about it more from an investment perspective near term investment for a pretty material long term value uplift.

Got it that makes sense.

And then just maybe.

Arun Jayaram: But, you know, one of the things with a really large continuous acres position is third party opportunities are limited, but if they do pop up, we've got our eyes out for them and we'll be taking advantage of those.

<unk>.

A quick question on service costs.

You mentioned, a low 2 billion type of Capex number for next year.

If you could maybe help us peel the onion, a little bit around assumptions around deflation you talked about pretty material.

Arun Jayaram: Great. It just maybe a follow up on the on the 2024 outlook where we've highlighted 1.7 billion of free cashflow potential sounds like CapEx will be in the low to billion range. Can you give us a sense in your thoughts on differentials, you know, for next year. Yeah, I'd say on a kind of what's embedded in that is on an all in company basis, like a 55 to 60 cent kind of all in differential. And we're seeing quite a bit of movement right now, but that's probably the appropriate range if you're trying to tie numbers out. Great. Thanks a lot.

Arun Jayaram: Thank you.

Capital savings from operating efficiencies when in Tokyo.

<unk> hundred 50 per foot.

How much of that is baked in or what are your thoughts on the service cost environment right now.

So at a very high level.

<unk>, let's say single digit service cost deflation bigger.

The biggest driver there is is on the steel, where we'll see a 20% reduction in steel costs.

I'd say the bigger opportunity for us to lower our cost is going to come from continued operational excellence in the field.

One of the examples that sort of underpinning our budget. This upcoming year is assuming a 400 hours per month.

Nitin Kumar: Your next question comes from the line of Nitin Kumar with Mizzouho. Please go ahead.

Frac pace and as we've seen with the teams.

500 hours as possible. So we're working to shore up what we can do to make the 500 number more of the average not just the high watermark.

Nitin Kumar: Hi, good morning, guys, and thanks for taking my questions. I kind of want to start on this new form sales contract. I think Josh, you mentioned during the you mentioned that there's an impact of about 100 to 200 million year term. Could you help us bridge the gap of what is driving that? I understand that the longer term benefit comes from better pricing. What's the restructuring of the AMA costing you? Yeah, so that AMA originally, if you remember, was 525 million a day.

And those will translate to.

Probably more significant cost savings and what we're seeing on the service side.

Okay. Thanks, guys.

Thank you. Your next question comes from the line of David <unk> with TD Cowen. Please go ahead.

Hey, guys. Thanks for the questions.

I wanted to ask just you provided a 24 outlook I assume that at this point it sounds like this is the original budget.

Nitin Kumar: And so the cost of MVP during this call it two to three year period until these expansion projects are built out. Effectively, what that saying is that's probably 125 to 150 million a year of near term free casual that we opted to give up so call it 300 million, maybe in total. And if you use some high level map and say, you know, the total annual free cash flow we gain when these projects come online about 300 million.

107 base for EQT, and then the 300 plus or so for tug Hill. So it doesn't seem like you're incorporating any of the benefits that youre seeing so far.

Improvements, especially on the <unk> side.

Well I would say again the important caveat to that is is.

From a true maintenance perspective from our business. If you don't count infrastructure spend some of the opportunistic land spend.

Nitin Kumar: It's like a 10% free cash flow yield is about $3 billion. So we kind of see it as again, $3 billion over 300 is about a 10 to 1. So again, we think about it more from an investment perspective. It's, you know, a near term investment for a pretty material long term value uplift. Guy, that makes sense.

And maybe a couple of other small items, we have in there.

The actual maintenance Capex number would come in very much the low end.

So we're guiding more towards towards total capex, including including some of that growth opportunistic.

Capital.

That makes sense, so that I think should bridge the numbers that youre talking to.

So maybe if you could spend expand on that a bit because I think thats helpful. As we think about improvements into the business from an efficiency standpoint and to 'twenty five.

Nitin Kumar: And then just maybe a quick question around service cost, you know, you mentioned a low two billion type of CapEx number for next year. If you could maybe help us build the onion a little bit around assumptions around deflation, you talked about pretty material, uh, uh, cat, capples savings from operating efficiencies on target, 150 per foot. How much of that is baked in, or what are your thoughts on the service cost environment right now?

Could you sort of quantify some of the maybe frontloaded opportunistic investments around infrastructure and land that would be in 'twenty. Four is that extends through 'twenty. Five 'twenty. Six is this is a multiyear integration in the investment process or is this more of a.

And upfront 24 situations.

Look I think it's just opportunistic its based on when we see when we see opportunities come about.

Nitin Kumar: So at a very high level, you know, we're expecting, um, I'd say single digit service cost deflation. Biggest driver there is on the steel. We'll see a 20% reduction in steel costs. Um, I'd say the, the bigger opportunity for us to lower our costs is going to come from continued operational excellence in the field. Um, you know, one of the examples that's sort of underpinning our budget in this upcoming year is, is assuming a 400 hour per month, um, frack pace.

Obviously, they have to they have to meet our pretty stringent criteria to justify investment, but again, if we're if we're looking at the opportunity to.

Pick up some additional land in one to two years ahead of the drill bit and make five to 110 to one on that investment we're going to do that every time.

If we see the opportunity to invest in long term infrastructure and get it 20%, 25% cash flow yield on that with virtually no risk.

We're going to do that.

And so look I think next year it could be in the $100 million to $200 million range of that additional growth capital.

Nitin Kumar: And as we've seen with the teams, you know, 500 hours is, is possible. So we're working to shore up what we can do to make the 500 number more of the average, not just the, the high water mark. And those will translate to the probably more significant cost savings than what we're seeing on the service side.

And I think what's true maintenance, if you want to think about that is probably much closer to that $2 billion number.

Yes.

I appreciate it if I could just sneak in a housekeeping one is there a meaningful shift in your deferred tax assumptions for next year cash taxes as a percentage of of.

Nitin Kumar: Hey, thanks guys.

David Deckelbaum: Thank you. Your next question comes from the line of David Decladone with TD Cohen. Please go ahead. Hey guys, thanks for the questions. Um, I, I wanted to ask just that you provided the 24 outlook. I assume at this point, it sounds like that's the original budget of the, the one seven base for EQT and then 300 plus or so for tug hill. It doesn't seem like you're incorporating any of the benefits that you're seeing so far of improvements, especially on the tug hill side.

Overall burden.

No we don't see any material taxes paid in 2024, and then I think as you get into 2025 at least where strip is today or maybe looking at closer to like a 15%.

Tax rate and then by the time you get to 2026 for a full cash taxpayer kind of a low 20%.

Cash tax rate.

I appreciate it will help thank you guys.

Thank you and next question comes from the line of Michael <unk> with Stephens. Please go ahead.

David Deckelbaum: Well, I would say again that the important caveat to that is, is, um, you know, from a true maintenance perspective from our business, if you don't count infrastructure spend, some of the opportunistic land spend, um, and maybe a couple other small items we have in there. I think that actual maintenance capEx number would come in very much the low end. Um, so what we're guiding more towards towards total CapEx, including, including some of that growth opportunistic, uh, capital. That makes sense. So that, that I think should bridge the numbers that you're, you're talking to.

Okay.

Good morning, everybody.

Wanted to see talk.

<unk> talked about the potential for the 150 per foot.

Savings.

The operational efficiencies that you're applying to the tocqueville asset what needs to happen. So thats become reality and I guess where are those.

Relative costs based on <unk>.

Wells completed there so far.

Well the cost savings that we had 150 about half of that is operational efficiency.

David Deckelbaum: Well, maybe like if you could expand, expand on that a bit because I think that's helpful as we think about improvements into the, the business from an efficiency standpoint and to 25. Um, could you sort of quantify some of like the maybe front loaded opportunistic investments around infrastructure and lands that would be in 24? Is that extends through 25, 26? Is this a, is this a multi-year integration and investment process? Or is this more of a, a, uh, an upfront 24 situation?

<unk> is well designed so.

For that to materialize, we need to continue executing in the field and putting out some big numbers on drilling speeds.

Completion pace.

Obviously doing it.

As safely as possible to accomplish that the other thing I'd say on the well design side of things Thats, probably going to take a little bit more time to.

To materialize, because we will take a more methodical pace on the science, we don't just run out and make all the changes at once.

David Deckelbaum: Look, I think it's, it's just opportunistic. It's based on when we see, when we see opportunities come about, um, and obviously they have to, they have to meet our pretty stringent criteria to justify investment. But again, if we're, if we're looking at the opportunity to, to pick up some additional land and the, you know, one to two years ahead of the drill bit and make five to one 10 to one on that investment, we're going to do that every time.

David Deckelbaum: Um, if, if we see the opportunity to invest in long-term infrastructure and get a 20, 25% casual yield on that with virtually no risk, we're going to do that. Um, and so look, I think next year, it could be in the 100 to 200 million dollar range of that additional growth capital. Um, and, you know, what, I think what's true maintenance, if you want to think about that is, it's probably much closer to that $2 billion I appreciate it.

So there'll be some monitoring time observed there, but when you step back and think about.

These type of operational synergies that we will achieve that.

$150, a foot could translate to about $50 million of total spend which would translate to about call. It two to three.

Lower on our cost structure on top of the previously planned 15th so.

I hope that.

That adds some more color to your question.

That's helpful. Thank you.

And wanted to ask about the <unk>.

Your agreements.

The LNG.

In terms of.

Any comments there on the discussions youre, having with potential end users of LNG.

David Deckelbaum: If I could sneak in the housekeeping one. Is there a meaningful shift in your deferred tax assumptions for next year or cash tax as a percentage of overall burden? No, we don't see any material taxes paid in 2024. And then I think as you get into 2025 at least for stripers today, we're maybe looking at closer to like a 15% tax rate and then by the time you get to 2026, we're a full cash tax bear, kind of a low 20% cash tax rate. Appreciate it, I'll help. Thank you, guys. Thank you.

<unk>.

Any agreement there be contingent on converting your hoa's to binding agreements sort of what's the process of these play out there.

Yes, great question Theres actually been a lot of interest a lot of parties, reaching out to us about this so we've been really encouraged by that date.

In terms of sequencing, we do need to get those long term agreements signed on the supply side.

Before signing the ultimate SBA, but it's really a it's a parallel process and so we're working through that.

Michael Scialla: Your next question comes from the line of Michael Scialla with Stevens. Please go ahead. Morning, everybody. I want to see you talk about the potential for the 150 per foot of savings with the operational efficiencies that you're applying to the Tug Kill assets. What needs to happen for that to become reality? And I guess where are those relative costs based on what was completed there so far? Well, the cost savings that we had the 150 about half of that is operational efficiency, the other half is well designed.

In terms of timing, it's probably six to 12 months out before it kind of the whole package of those is done.

But look we've been we've been really encouraged by the progress to date.

Thank you guys.

Thank you. Your next question comes from the line of Kevin maturity with Pickering Energy Partners. Please go ahead.

Michael Scialla: So for that to materialize, we need to continue executing in the field and putting up some big numbers on drilling speeds and completion pace, obviously doing it as safely as possible to accomplish that. The other thing I'd say on the well designed side of things, that's probably going to take a little bit more time to materialize because we will take a more methodical pace on the science. We don't just run out and make all the changes at once.

Hey, good morning, the firm sales contracts you locked in starting in 2027 are very impressive.

With those margins de risked do you have any plans to grow into the volumes and is that baked into your 2024 to 2020, a free cash flow outlook.

We certainly have the option to.

We just got these deals signed a couple of weeks ago. So we have not made any long term plan adjustments, but that is an exciting option. That's really paired with this from a value creation standpoint, and something that we will evaluate in time, if the price environment.

Merits that level of activity.

Got you. So it is not not baked into that outlook at this time, the 60% free cash flow of BV.

Michael Scialla: So there'll be some monitoring time observed there. But when you step back and think about these types of operational synergies that will achieve, you know, that $150 a foot could translate to about $50 million a total spend, which would translate to about two to three cents lower on our cost structure on top of the previously planned 15 cents. So I hope that adds some more color to your question.

Right.

Great and then you mentioned the 55 cents off Nymex for 2024, I just wanted to get a little bit more clarity on whether that included basis hedges and any btu uplift.

Michael Scialla: That's helpful. Thank you.

Yes, that's right it's all in.

Great. Thank you.

Thank you. Your next question comes from the line of Jean Ann Salisbury with Bernstein. Please go ahead hi.

Good morning.

And then two MTA of HOS and do you have an ideal share of portfolio linked to global gas prices and what kind of your thinking that underpins that ideal share. If you if you did.

Michael Scialla: And one to ask about your agreements on the LNG. In terms of any comments there on the discussions you're having with potential end users of LNG and would any agreement there be contingent on converting your HOAs to binding agreements, sort of what's the process of these play out there? Yeah, great question. There's actually been a lot of interest, a lot of parties reaching out to us about this. So we've been really encouraged by that to date.

Yes, I think if you step back and said.

Looked at this purely from a market diversification perspective.

Somewhere around 10% exposed to international markets.

Feels balanced.

But.

This will ultimately depend on.

What type of netback, so we're able to achieve by connecting to that market and that will sort of.

Turn the knob on on where we sit with that but right now as it stands.

Michael Scialla: In terms of sequencing, we do need to get those long term agreements signed on the supply side before signing the ultimate SPA. But it's really a parallel process. And so we're working through that. In terms of timing, it's probably six to 12 months out before kind of the whole package of those is done. But look, we've been really encouraged by the progress to date. Thank you, guys.

This 2 million tonnes per annum for us is us putting our toes in the water.

A significant amount of volume to gas would provide a ton of energy security for customers around the world, but it's less than 5% of our total volume. So we're going to take a measured approach and accessing this market.

Great. That's all for me thanks.

Thank you. Your next question comes from the line of Paul Diamond with Citi. Please go ahead.

Hi, Good morning, Thanks for taking my call just a quick one you talked about the kind of a theoretical Max of 500 days versus the average of about 400. Currently just wanted to see if you guys could put a little bit of clarity around I.

Kevin MacCurdy: Thank you. The next question comes from the line of Kevin Maturdy with Pickering Energy Partners. Please go ahead.

Kevin MacCurdy: Hey, good morning. Um, the firm sales contract you locked in starting in 2027 are very impressive. With those margins de-risk, do you have any plans to grow into the volumes? And is that vacant until your 2024 to 2028 pre-catch law looked? We certainly have the option, too. We just got these deals signed a couple of weeks ago, so we've not made any long-term plan adjustments, but that is an exciting option that's really paired with this from a value creation standpoint, and something that we will evaluate in time if the price environment merits, you know, that level of activity.

I guess, how you see.

That gap like how close can you get to the 600 and over what timeframe.

Yes, so the theoretical Max is around 600 hours per month, and we set plans for 400 and hope to repeat the 500 hours per month listen the biggest thing is going to be.

The logistical support for these frac operations.

And that's all about getting as much water and sand to location as possible. We've spent a lot of time.

On the sand side, there could be some infrastructure investment opportunities for us on that pace to bring trans load facilities closer to the actual frac sites those opportunities are relatively small $8 million to $10 million upfront cost, but they can pay dividends over time.

Kevin MacCurdy: Gotcha. So it's not baked into that outlook at this time, the 60% pre-catch law of BB. That's right. Great. And then, um, you mentioned the 55 cents off 9x for 2024. I just wanted to get a little bit more clarity on whether that included basis hedges and any BTU uplift. Uh, yeah, that's right. It's all in. Great. Thank you. Your next question comes in line of gene and foulsbury with Bernstein. Please go ahead.

And then obviously, we understand that the benefits and economics behind water infrastructure.

One of the biggest benefits with EQT and one of the benefits of having a deep inventory in this area is we're going to be able to make these investments because we have so much inventory that's going to benefit from these investments and that certainly is a key differentiator.

Gene Foulbury: Hi, good morning. I just, um, I, on the 2MPA of HOAs, um, do you have an ideal share of portfolio linked to global gas prices and what kind of you're thinking that underpins that ideal share if you, if you do. Yeah, I think you've just stepped back and said, um, and looked at this purely from a market diversification perspective, um, you know, somewhere around 10% exposed to international markets, feels balanced. Um, but, you know, a, this will, will ultimately depend on what type of netbacks that we're able to achieve by connecting to that market and that will sort of turn the knob on, on where we sit with that.

To think about when you think about these opportunities present within EQT versus versus others.

Understood. Thank you and just one quick follow up you guys talked about the incorporation of <unk>.

BP and coal retirements, producing about four bcf of incremental demand out of Appalachia. Just wanted if you could get a bit of clarity around the timing of that is that over the next one year. Five years is how do you see that kind of development.

Yes, so half of that is obviously MVP at two Bcf a day and.

And the rest of it we kind of look at it over the next five years.

Gene Foulbury: But right now, as it stands, there's 2 million tons per annum for us as us putting our toes in the water. Um, I mean, it's a significant amount of volume to gas and provide a ton of energy security for, for customers around the world, but it's less than 5% of our total volume. So, um, we're going to take a measured approach in, in accessing this market. Great. That's all for me. Thanks. Thank you. Your next question comes from the line of Paul Diamond, Lucidie. Please go ahead.

Okay Chipping away, it's not it's not obviously in annual growth number, but we see over that timeframe that that demand showing up.

Through those different changes in the market.

Understood.

Thanks for your time.

Thank you. Your next question comes from the line of Noel Parks with tool. He brothers. Please go ahead.

Hi, good morning.

Gene Foulbury: Hi, good morning out. I've just taken my call. It's not quick one. You just talked about the, you're kind of that theoretical max is 500 days versus the average of about 400 currently. Just wanted to see if you could put a little bit clarity around, I guess how you see, you know, bridging that gap, like how close can you get to the 600 and over what time frame? Yeah. So, um, the theoretical max is around 600 hours per month.

Good morning.

One question I had was.

As you have.

Put together some of these longer term forecasts and projections.

And.

When you're making the infrastructure piece, yes.

Yes some.

The trends look really compelling.

As you look at different pricing scenarios do you picture and this of course, it would be a high class problem do you picture a gas price high enough, where a plausible senior kind of gets reintroduced of the industry over drilling again.

Gene Foulbury: And, you know, we set plans for 400 and, and hope to repeat the 500 hours per month. Listen, the biggest thing is going to be, um, the logistical support for these frack operations. And that's all about getting as much water and sand to location as possible. We've, we've spent a lot of time, um, on the sand side, there could be some infrastructure investment opportunities for us on that pace to bring trans low facilities closer to the actual fracksites.

I know is that sustained $6 $7 or something like that.

Yes.

I think our biggest thing that is going to be the biggest.

Gene Foulbury: Those opportunities are relatively small, you know, eight to 10 million dollars upfront cost, but they can pay dividends over time. And then obviously, we understand that the benefits and economics behind water[inaudible] Professor. You know, one of the biggest benefits with EQT and one of the benefits of our having a deep inventory in this area is we're going to be able to make these investments because we have so much inventory that's going to benefit from these investments and that certainly is a key differentiator to think about when you think about these opportunities present with an EQT versus others.

Driving force maybe on how people think about the dollars they spend towards drilling is really getting away from the half cycle wellhead returns and looking more.

At a holistic <unk>.

Cost of returns and gas price needed to actually not just generate free cash flow and cover your cost of supply but <unk>.

Actually create deliver.

Value to back toward shareholders in that.

Now scenario is showing us that even with current strip.

Is below the price level needed to.

To generate the cost of returns that investors are demanding right now so.

Gene Foulbury: Understood. Thank you. And I just want to quick follow up. You guys talked about the incorporation of MVP and co-retirement producing about full BCF. I think mental demand out of Appalachia. If you want to see if you get a bit of clarity around the timing of that, is that over the next one year, five years, is how do you see that kind of developing? Yeah. So, I mean, half of that is obviously MVP at 2 BCF a day.

Gene Foulbury: And the rest of it, you know, we kind of look at it over the next five years kind of shipping away. It's not, it's not obviously an annual growth number. But, you know, we see over that time frame that, that demand showing up kind of through those different changes in the market. Understood. It's all for me. Thanks for your time. Thank you. Your next question comes from the line of Noel Parks with two O.H. Brothers.

If you look at it from that perspective, I think you'd be a little bit more cautious over over activity levels.

We think the what's happened in this industry over the past few years and the sustainable shale era as operators I think are being much more holistic when they're making their investment decisions and thats going to lead to better more durable industry thats better to serve customers over the long term and also.

Keep investors.

Happy and satisfied with the returns that they're making.

I'd say another interesting caveat to that that's really important to remember I think a lot of people like to talk in terms of averages will talk about talking about future gas prices or commodity prices.

Ill review I think what's going to change a bit and the character of the gas market going forward is.

In a world, where there's less coal to switch to renewable Intermittency you have your days of demand covered dwindling for gas youre going to see a lot more volatility and so instead of a clear price signal so to speak of five or $6. As you suggested which would give you confidence to drill and grow I think you might see a year where gas is.

Noel Parks: Please go ahead. Hi, good morning. Morning. You know, one question I had was, as you have put together some of these longer-term forecasts and projections, and when you've taken the infrastructure piece, there, you know, some of the, the trends look really compelling. As you look at different pricing scenarios, do you picture, and this, of course, would be a high-class problem, do you picture a gas price high enough where a plausible C or a kind of gets reintroduced of the industry over drilling again?

Really high and another year of gas is really low that will average out to an attractive price in the middle but it does create a lot of volatility and I think from a planning perspective for companies.

That are just pure upstream producers it creates a lot more pause before saying we want to go invest an extra $1 billion in drilling in a given year.

If you want to look at a case study of that you can see what happened in the past 12 months, where that really seem to be all the rage in 2022 of prices were.

Noel Parks: And I mean, I don't know, is that sustained? $6 or $7 or something like that? Yeah, I mean, I think our biggest thing that is going to be the biggest driving force, maybe, on how people think about the dollars they spent towards drilling is really getting away from the, you know, half-cycle well-head returns, and looking more at a holistic cost of returns, and gas price needed to actually not just generate free cash, and cover your cost as a fly, but actually create, deliver value to back-tour shareholders.

High single digits, and all it took where a couple of events.

Events and prices fell as low as $2 now.

Now youre seeing the haynesville start to really decline so.

I think when you look ahead I think that's an important differentiation, but I think the net effect is youre going to see some aircrafts emerge of oversupply and under supply and that really underpins our focus on cost structure, because we don't want to be one of those producers that has to decline and has to ramp back up we'd love to be able to really produce durable cash flow and in return for investors through cycle.

And again, if you're worried about prices one year falling to $2 like we just saw this year and you have to hedge that but then you missed prices going back up materially higher over the long run you're not going to generate nearly as much value. So again that outlook is really informing how we scope the business, whether it's through just organic cost cutting so our hedging strategy are bad.

Noel Parks: And that right now scenario is showing us that even with current strip is below the price level needed to generate the cost of returns that investors are demanding right now. So if you look at it from that perspective, I think you'd be a little bit more cautious over activity levels. But, you know, we think that what happened in this industry over the past few years in this sustainable sale era is operators, I think, are being much more holistic when they're making their investment decisions, and that's going to lead to better a more durable industry that's better to serve customers over the long term, and also keep investors, and I'm just happy and satisfied with the returns that they're making.

<unk> sheet however.

How we think about future M&A.

That characteristic I think is an important caveat.

It will be a lot different in the next five years compared to the prior five years.

Great. Thanks, Thanks, a lot for being on the volatility angle into it and I also want to touch on the issue of coal replacement and.

I was just wondering are you.

As you see utilities doing there.

Longer term planning do you see any signs of the impact from some of the.

Noel Parks: Yeah, I'd say another interesting caveat to that that's really important to remember. I think a lot of people like to talk in terms of averages when talking about, talking about future gas prices or commodity prices. You know, in our view, I think what's going to change a bit in the character of the gas market going forward is in a world where there's less coal to switch to you have renewable intermitency. You have your days of demand covered dwindling for gas.

Advanced technology out there for example for <unk>.

Gas turbines.

Greater efficiency.

Lower emissions and so forth.

Is that in the equation as you as you see some of these core replacements on the horizon.

Well I think what you are seeing is energy security coming back into the headlines.

Noel Parks: You're going to see a lot more volatility. And so instead of a clear price signal, so to speak of five or six dollars as you suggested, which would give you confidence to drill and grow. I think you might see a year where gas is really high and another year of gas is really low. That will average out to an attractive price in the middle, but it does create a lot of volatility.

And the American grid add when you look at all a lot of the power generation capacity. That's been added over the last five years a lot of it has come from from <unk>.

Intermittent, albeit.

Lower carbon energy solutions like wind and solar.

Noel Parks: And I think from a planning perspective for companies that are just pure upstream producers. It creates a lot more pause before saying, you know, we want to go invest in extra billion dollars in drilling in a given year. And I think that, you know, if you want to look at case study of that, you can see what happened in the past 12 months where that really seemed to be all the rage in 2022.

And people are stepping back and saying do we have the reliability that we need and you see this across all.

All ISO as across the country, where your peak demand number is coming very close to your reliable electricity generation.

While you may have coverage from intermittent sources above that you realize that when that peak demand hits and youre pushing the red lining your reliable electricity power generation.

Noel Parks: Two prices were, you know, high single digits and all it took were a couple of events and events and prices, you know, fell as low as $2. Now you're seeing the haines, they'll start to really decline. So, you know, I think, you know, when you look ahead, I think that's an important differentiation. But I think the net effect is you're going to see some air gaps emerge of oversupply and under supply.

On your knees praying for the wind blow and the Sun to Shine and I think people are looking at this now and looking for more energy security and realizing that low carbon energy solutions like natural gas are going to be the solution that the world needs.

Noel Parks: And that really underpins our focus on cost structure because we don't want to be one of those producers that has to decline and has to ramp back up. We'd love to be able to really produce durable cash flow and return for investors through cycle. And again, if you're worried about prices, when you're falling to $2, like we just saw this year, and you have to hedge that, but then you miss prices going back up materially higher over the long run, you're not going to generate nearly as much value.

Great. Thanks, a lot.

Noel Parks: So again, that outlook is really informing how we sculpt the business, whether it's through just organic cost cuttings, our hedging strategy, our balance sheet, how we think about future M&A. But that characteristic, I think, is an important caveat. And it'll be a lot different in the, you know, next five years compared to the prior five years. Great. Thanks. Thanks a lot for bringing the volatility angle into it.

Thank you. Your final question comes from the line of <unk> with <unk>. Please go ahead.

Hey, Thanks Tobey.

Tobey I think you brought this up a few times.

The idea of downside protection when it comes to hedging and even your LNG strategy that I think provides us floor. It seems like youre more careful in protecting the downside risk versus some of your peers. So maybe just maybe that backs off a little bit once you hit your leverage target, but do you think this is just the nature of you guys being the biggest guy in the room.

Or are you looking longer term or where maybe you're just frankly have a different investor base that are asking different things that view, but just any thoughts there.

Well I think it's just prudent as an investor to think about protecting against the downside while also.

Noel Parks: And I also want to touch on the issue of coal replacement. And I was just wondering, are you, as you see utilities doing there, they're longer term planning. Do you see any signs of the impact from some of the advanced technology out there, for example, for gas turbines, you know, greater efficiency, lower emissions and so forth? Is that in the equation of you as you see some of these coal replacement on the horizon?

Providing exposure to what we think is going to be a really exciting natural gas market.

So I think one thing that's going to be the alternative is.

And we can play that with by hedging and caring about the floors and also caring about the ceilings are reported in our business. We can do that with some of the supply deals we structure.

Delivering floor as I cover our cost of capital allow us to generate the returns that.

Our investors are demanding while also providing ceilings that that prevents customers from experiencing price blowouts.

Noel Parks: Well, I think what you are seeing is energy security coming back into the headlines in the American grit. And when you look at all a lot of the power generation capacity that's been added over the last five years, a lot of it has come from from intermittent albeit, you know, lower carbon energy solutions like wind and solar. And people are now stepping back and saying, do we have the reliability that we need?

And at the end of the day, the integrated energy producer like EQT that has control over the cost to pull the gas out of the ground the contracts and move it through the pipelines and get it through.

The tailpipe of round two facility.

We can offer.

Pricing that ensures us to be able to generate our returns, but also gives the world what it really needs, which is guardrails on pricing.

Noel Parks: And you see this across all ISOs across the country where your peak demand number is coming very close to your reliable electricity generation. DeMission, while you may have coverage from intermittent sources above that, you realize that when that peak demand hits and you're pushing your redlining your reliable electricity power generation, you're on your knees praying for the winter blow and the sun to shine. And I think people are looking at this now and looking for more energy security realizing that low carbon energy solutions like natural gas are going to be the solution that the world needs. Great. Thanks a lot. Thank you.

And that has entered that will give them the energy security that ultimately is so desperately needed right now so.

Again, we think customers that are looking to play.

Play the spot market with this volatility, it's going to get pretty pretty exciting.

We can take away some of the volatility and still generate pretty great returns and create some really great win win scenarios for customers.

And let me add to that Bert I mean look I think we've moved from a world in the last couple of years, we were playing defense.

And very programmatically hedging 222 of our position being fully back to investment grade now with the low cost structure, one of the lowest amongst peers, where we can much more opportunistically say, where do we see risk on the curve, where do we see opportunity and again, that's why we keep trying to reemphasize, how how we're taking a more tactical approach to hedging at the mill.

Bert Donnes: Your final question comes from the line of Bert Donnes with tourists. Please go ahead. Hey, thank you guys. Toby, I think you brought this up a few times the, you know, the idea of downside protection. When it comes to hedging and, you know, even your LNG strategy that I think provides the floor. It seems like you're more careful in protecting the downside risk versus some of your peers. So, you know, maybe this, you know, maybe that backs off a little bit once you hit your leverage target.

So again, we've increasingly leaned into more hedges in the next 12 really nine to 12 months, because whether you know the biggest drivers winter during that time periods, whether that is a warm winter a cold winter a normal winter prices could be up 50 to one dollar of down 50 to $1.

Bert Donnes: But do you think the risk is just the nature of you guys being the biggest guy in the room, or are you looking longer term, or, or maybe you just have a different investor base that are, you know, asking different things of you, but just any thoughts there. Well, I think it's just prudent as an investor to think about protecting against the downside while also providing exposure to what we think is going to be a really exciting natural gas market.

I don't see it materially moving probably beyond that but that changes a lot as you get later into 2024 and into 2025 were relative to where the strip is right now and the other fundamental factors playing into it the declines in production, we expect to see start to really materialize in the haynesville.

In particular combined with the LNG the pickup in LNG demand, which by the end of 2025 were modeling it about five Bcf a day increase when you have another probably Bcf a day increase on top of that in the form of exports to Mexico.

Bert Donnes: So, I think one thing that's going to be the alternative is, and we can play that with my hedging and caring about the floors and also caring about the ceiling we're putting in our business. We can do that with some of the supply deals we structure delivering floors that cover our cost capital, allow us to generate the returns that our investors are demanding while also providing ceilings that prevent customers from experiencing price blowouts.

Other structural demand from things like industrial that market looks increasingly tight with a backdrop of low DUC inventory.

And actually Underinvestment and so when we see opportunities like that emerge we want to provide investors exposure to that.

But look at the end of the day, if I were to say you don't have a dynamic like that at play I think our focus and hedging will be protecting just the fixed cost structure of the business.

Bert Donnes: And at the end of the day, the integrated energy producer, like EQT that has control over the cost to pull the gas out of the ground, the contracts, move it through the pipelines and get it through the tailpipe of our new facility, we can offer pricing that ensures us to be able to generate returns but also gives the world what it really needs, which is guard rails on pricing. And that is that that will give them the energy security that ultimately is so desperately needed right now.

And take out some of the volatility associated with that and again in a world of high volatility as I explained a few minutes ago that we'd expect to see in the future. There will be really great years, and also some years that could be could be pretty pretty tough like we saw earlier this year and so we'd like to really take that volatility out and if you're thinking of.

The essence of what a lot of investors high quality investors in particular are looking for an energy right now is durable cash flow and yield and its price exposure right and so what we're trying to do through our hedging program is really try to scope that that exposure for those investors and provide that that long term runway, where they can have that in the next five.

Bert Donnes: So again, we're we think customers that are looking to play the spot market with this volatility, it's going to get pretty pretty exciting. And I think we can take away some of the volatility and still generates pretty great returns and creates some really great win-win scenarios for customers. Yeah, and let me add to that, Bert, I mean, look, I think we've moved from a world in the last couple of years, we're playing defense and very programmatically hedging to a position being fully back to investment grade now with the low cost structure, one of the lowest amongst peers, where we can much more opportunistically say, where do we see risk on the curve, where do we see opportunity.

Five to 10 years, we're not we're not trying to run a business that is just the highest volatility option on gas price, we're trying to run it like a real business.

So there are a lot of great point, Thanks, guys and then maybe shifting gears a little bit it looks like youre drilling slightly shorter laterals in <unk> versus <unk>, but youre still completing.

Turning in line, maybe some longer laterals. So could you talk a theres a strategy shift there or if that's just a quarterly blip and youre still targeting longer laterals.

Bert Donnes: And again, that's what we keep trying to re-emphasize how we're taking a more tactical approach to hedging at the moment. So again, we've increasingly leaned into more hedges in the next 12, really 9 to 12 months, because you know, whether, you know, biggest drivers winter during that time periods, whether that is a warm winter, a cold winter, a normal winter, you know, prices could be up 50 cents to $1 down 50 cents to $1.

Yes, we are still targeting longer laterals, there will be variances quarter to quarter and that sort of what you may be seeing here.

But the strategy has not changed the strategy to continue to leverage common development and unlock the scale of our asset base is still being top of mind and applied everyday.

Bert Donnes: We don't see it materially moving, probably beyond that, but that changes a lot as you get later into 2024 and into 2025, where relative to where the strip is right now and the other fundamental factors playing into it, that it climbs in production, we expect to see, start to really materialize in the Hainesville, in particular, combined with the LNG, you know, the pickup and LNG demand, which by the end of 2025, we're modeling it, you know, about a five BCF a day increase. We have another probably BCF a day increase on top of that and the form of exports to Mexico, another structural demand from things like industrial that market looks increasingly tight with a backdrop of low duck inventory and actually under investment.

That's perfect. Thanks, guys.

Thank you ladies and gentlemen, there are no further questions at this time I will now turn the call over to <unk>.

Toby rice for closing remarks.

Thanks, Eric this quarter marks another quarter.

Quarter, where we've demonstrated some pretty meaningful steps to make the energy we produce at EQT cheaper more reliable and cleaner for the world.

And also create value for shareholders.

What was really great to see this quarter is really talking about how the differentiating aspects of our business our low cost structure our scale.

Our deep inventory and environmental attributes are actually creating value and creating opportunities.

Bert Donnes: And so when we see opportunities like that emerge, we want to provide investors exposure to that. But look at the end of the day, if I were to say, you know, you don't have a dynamic like that at play, I think our focus in hedging will be protecting just the fixed cost structure of the business and taking out some of the volatility associated with that. And again, in a world of high volatility, as I explained a few minutes ago, that we'd expect, you know, to see in the future, there'll be really great years and also some years that could be pretty pretty tough, like we saw earlier this year.

For our for our business that we are.

Optimistic we will present, some really attractive investment opportunities for us in the future and we look forward to keeping you guys updated along the way.

Okay.

Ladies and gentlemen that concludes today's call. Thank you all for joining you may now disconnect.

Okay.

Bert Donnes: And so we'd like to really take that volatility out. And if you think about the essence of what a lot of investors, high quality investors in particular looking for an energy right now, it's durable cash flow and yield and its price exposure. And so what we're trying to do through our hedging program is really try to scope that exposure for those investors and provide that long term runway where they can have that in the next five to 10 years.

Bert Donnes: We're not trying to run a business that is just the highest volatility option on gas price for trying to run it like a real business, of this. Those are a lot of great points, thanks guys. And then the maybe shifting gears a little bit, it looks like you're drilling slightly shorter laterals in 4Q versus 3Q, but you're still, you know, completing or turning in line, maybe some longer laterals. So could you talk of there's a strategy shift there, or if that's just, you know, a quarterly blip and you're still targeting longer lateral. Yeah, we're still targeting longer laterals.

Okay.

Toby Rice: There will be variances quarter to quarter and that's sort of what you may be seeing here.

[inaudible] we've, we've,