EQT Corporation (NYSE:EQT) Q3 2023 Earnings Call Transcript

EQT Corporation (NYSE:EQT) Q3 2023 Earnings Call Transcript October 26, 2023

Operator: 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. [Operator Instructions] Thank you. I would now like to turn the call over to Cameron Horwitz, Director of Investor Relations and Strategy. Please go ahead.

Cameron Horwitz: 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 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.

An aerial view of an energy refinery, with massive tanks and piping defining the landscape.

We do not undertake any duty to update any forward-looking statements. Today’s call also contains certain non-GAAP financial measures. Please refer to our most recent earnings release and investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. With that, I’ll turn the call over to Toby.

Toby Rice: 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 XcL Midstream in late August. As shown on Slide 5 of our investor deck, with roughly 60 days under our belt post closing, we currently have 74% of total integration milestones actions completed. To 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. The successive 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.

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 XcL 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-designed and operational efficiencies. As it relates to operational efficiencies, I want to first talk about third quarter performance for stand-alone EQT and then provide some stats on what the teams have already achieved on the Tug Hill assets. As shown on Slide 7 of our investor deck, after posting stellar second quarter operational performance, both our drilling and completions again set new internal and world records in 3Q.

Recall last quarter, we highlighted EQT’s world record of drilling over 18,200 feet in 48 hours on the same run. This record lasted a mere 60 days as our team bested that effort by drilling 18,264 feet in 48 hours on our Denver 5H 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 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 6 of our investor deck, our teams are wasting no time unleashing EQT’s industry-leading operational progress as we’ve taken over the assets. To 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 optimize water handling and sand logistics across the asset base.

On the drilling front, since taking over operations, our team has already improved horizontal drilling speeds by 50% relative to legacy Tug Hill 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 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-design changes on the Tug Hill assets, including cluster spacing, clusters per stage, proppant loading, proppant type and casing weight, to name a few. While it’s still early to quantify the full impact of efficiency gains and operational synergies on the Tug Hill assets, we preliminarily see the potential for up to $150 per foot of well cost savings associated with these efforts.

The potential impact from optimizing well design 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, 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 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 forma free cash flow in 2024 and cumulative free cash flow of approximately $14 billion from 2024 to 2028.

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. Shifting gears 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.

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 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 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. 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 Southeast region. 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 debottlenecked and our pricing exposure will shift to a blend of premium demand areas, including Henry Hub and Transco Zones 4 and 5 South. 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 the same time, the debottlenecking of EQT 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. 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 tons per annum of LNG under a 15-year tolling agreement. This comes on the heel of a prior HOA with Lake Charles LNG and upon completion of definitive agreements 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 1.2 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 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 and superior downside protection. We are currently pursuing signing SPAs 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 covet EQT’s molecules as a long-duration secure supply source that can drive meaningful emissions reductions via coal displacement, similar to the precedent we are setting in the U.S. Southeast market with our newly announced firm sales agreements directly with utilities. 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 forced 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 Appalachia’s position as a premier world partner in decarbonization.

We plan to deploy advanced soil probe technology from our partners at Teralytic, 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 effort. Operational efficacy of these projects will be assured and audited by West Virginia University’s 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. 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 1 and 2 GHG emissions.

Turning to 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 is a collaboration initiated by EQT, the state of West Virginia, Batel, GTI Energy and Allegheny Science and Technology. 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. Along with the decarbonization impact, ARCH2 is anticipated to facilitate various community benefits, including the potential to create more than 21,000 high-paying jobs. The selection of ARCH2 deeply reinforces the critical role natural gas, particularly Appalachia 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.

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-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 CO2 sequestration. 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’ll now turn the call over to Jeremy.

Jeremy Knop: 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 XcL assets. Sales volumes in the third quarter were 523 Bcfe comprised of 491 Bcf of natural gas and 5.2 million barrels of liquids. We note third quarter production volumes included roughly 5 Bcfe of curtailment principally in response to weak local demand and approximately 8 Bcfe associated with lower-than-expected non-operated turn-in lines and curtailments. 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 Tug Hill’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 stand-alone 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 were $443 million and negative $2 million, respectively. It’s worth noting, however, free cash flow was negatively impacted by $28 million of non-recurring expenses from the Tug Hill 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 Tug Hill and XcL 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 stand-alone GP&T in the second quarter, which underscores the cost structure accretion from the low breakeven Tug Hill and XcL assets. I’d also note our fourth quarter production outlook embeds expectations of curtailments in the first half of the quarter, given elevated Eastern storage and seasonal demand weakness. While we are 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 2.3 Tcfe. 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 at 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 to peers. Turning to the balance sheet. Recall, we funded the cash consideration of the Tug Hill and XcL acquisition upon close in August with $1 billion of cash on hand and $1.25 billion of term loan borrowings. We exited the third quarter with $5.9 billion of total debt, including $400 million related to equity-light convertible notes, which equates to an LTM leverage of 2.1x, though we note this figure includes the full impact of financing the Tug Hill and XcL acquisitions with just 39 days of EBITDA contribution.

For reference, excluding Tug Hill and XcL impacts, we estimate LTM net debt-to-EBITDA would have been approximately 1.25x 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 Baa3 by Moody’s shortly after we closed the Tug Hill 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, an 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 we will continue with our opportunistic all-the-above strategy with our North Star being the countercyclical 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 1x leverage target at $2.75 per MMBtu natural gas pricing, which 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 XcL Midstream team now part of EQT, we are actively exploring opportunities to deploy capital into differentiated infrastructure investments that 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.

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 the roughly $600 million of share repurchases 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. And finally, sustainable long-term base dividend growth is a key pillar of our shareholder return strategy, and to this end, we recently raised our dividend by 5% to $0.63 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 a corporate free cash flow breakeven price that is amongst the lowest in North America.

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 to 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.

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 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 as the investment case for coal weakens further, with the market increasingly turning to cleaner burning natural gas. We expect coal production to drop by over 20% year-over-year in 2024 as 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.

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 Hill’s volumes with a weighted average core price of approximately $3.60 per MMBtu and a weighted average ceiling of $4.10 per MMBtu. 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 when 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. Our strong basis hedge position paid dividends this quarter, boosting our corporate-wide realized natural gas price by $0.12 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. Over the medium to long-term, we see several factors that could lend structural support to Appalachian bases, including the commencement of MVP and additional coal-fired power retirements in the PJM market, creating incremental demand upward of 4 Bcf per day.

As it relates to MVP timing, we’re encouraged by the recent Equitrans and PHMSA consent order and continue to model the first quarter of 2024 in-service date. The outlook for MVP increasingly derisks 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. 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 debottlenecking of downstream markets and directly link EQT’s volumes to a market price at 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 $0.18 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 sustainable utility demand, dynamics which could drive an even greater uplift to long-term free cash flow over time. Importantly, these contracts and debottleneckings occur around the same time our gathering rates with Equitrans complete the contractual step down from $0.80 today to $0.30 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 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’s shareholders in the form of free cash flow growth and value creation. 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 are not simply due to scale but underpinned by EQT’s world-class assets, coupled with a culture and teams that are relentless in their pursuit of excellence as the operator of choice and driven to maximize value for shareholders.

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 tenet of shareholder value creation. We believe the days of wellhead IRRs driving activity levels amongst U.S. gas producers are in the rearview mirror as this behavior related to the destruction of hundreds of billions of dollars of capital in the last decade. Put very simply, wellhead IRRs 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 beholden 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 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 MMBtu to even begin generating cash flow in maintenance mode, meaning below this price, no shareholder value is being created and 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 MMBtu based on current market valuations. On the other hand, EQT shares are pricing in a level embedding a mid-$3 gap 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’ll now turn the call back over to Toby for some concluding remarks.

Toby Rice: 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 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 preeminent low-cost producer of natural gas on the global stage. Second, integration of the Tug Hill and XcL 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.

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. 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 peer-leading scale, low cost structure, inventory depth and environmental attributes. And finally, sixth, our first-of-its-kind public-private forced 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, I’d now like to open the call to questions.

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Q&A Session

Operator: Thank you. [Operator Instructions] Your first question comes from the line of Umang Choudhary with Goldman Sachs. Please go ahead.

Umang Choudhary: 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 cost positioning, which I assume is not completely reflected on Slide number 12. So a couple of questions here. Like 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.

Toby Rice: Hi, Umang. This is Toby. Let me just put 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. Over the last 10 years, we’ve seen natural gas demand grow about 50% in this country. During that period of time, the pipeline capacity that’s 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. Jeremy, do you want to cover some of the more detailed points about this transaction, how it came together?

Jeremy Knop: Yes, 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 a 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 NYMEX minus $0.40 type differential when you take into account the premium in-market pricing we’re getting and the cost to transport it there on MVP. That gets you to that, call it, $0.15 to $0.20 of all-in company-wide differential improvement in 2028 and beyond. And that’s what gets that $300 million just in total of annual cash flow uplift.

Umang Choudhary: 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?

Jeremy Knop: Yes. It’s a good question. You know what, we think the risk is relatively low because the contracts were structured in different tranches. In many ways, we’re actually linked to NYMEX pricing and Gulf Coast pricing. And so any change in NYMEX or just from the pull on the LNG market in 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 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 – I think it’s evidence we’re 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 these firm sales deals, there might be, near-term, a little bit of downside to cash flow. But think about it, the AMA that we restructured here is maybe a couple of 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 10:1 investment return is really how we look at it as we’re really trying to build long-term value.

Umang Choudhary: That’s very helpful. Thank you.

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

John Abbott: 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 companies. How do you think about industry consolidation from here and how do you see EQT’s potential role in that?

Toby Rice: Well, my view hasn’t changed. We think consolidation is 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 Tug Hill acquisition, we are focused on lowering our cost structure. Those assets have lowered our cost structure by about $0.15 pre-synergies. 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. 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 stand-alone 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.

John Abbott: Appreciate that. And then for our follow-up question, appreciate the free cash flow guidance that you 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, true long-term maintenance CapEx without taking into account potential debottlenecking opportunities, how do you think of that at this point in time from a spend perspective to hold maybe 2.3 Tcfe flat?

Jeremy Knop: Yes, let me take that one. So let’s use next year as a proxy. So we expect, while we’re still working through the budget, we expect a low $2 billion type all-in CapEx number. But 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-risk, strong return opportunities, so things like the West Virginia water system that we invested in talked about last quarter, good example of that. We’re looking at a couple of other infrastructure projects through our XcL platform now to debottleneck volumes, to realize better pricing.

We’re also seeing opportunities 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 worth $5 million to $10 million when drilled. So we have a pretty active program replacing about 80% of our lateral footage developed each year, which sort of perpetually extends our inventory. And so on a rate of return basis, we see those as, call it, 5:1, 10:1 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 about $2 billion. And we don’t see that changing materially in the really five-year forecast at least.

John Abbott: Very, very helpful. Thank you for taking our questions.

Operator: Thank you. Your next question comes from the line of Arun Jayaram with JPMorgan. Please go ahead.

Arun Jayaram: Yes. Good morning. Toby, the crown jewel of the Tug Hill deal was the XcL Midstream system. I wanted to get your thoughts on value creation opportunities from integrating the midstream further in terms of internal and third-party opportunities. Obviously, it is going to help your cost structure as you highlighted as well.

Toby Rice: Yes. Arun, 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’d say as we’re looking for more investment opportunities that will generate pretty attractive low-risk returns that we’re looking for, we’re going to continue to just keep pushing the ball along and capturing those synergies that we identified. That Clarington 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 be – continue to be a big focus there on that front. And hopefully 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, 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. But one of the things with a really large contiguous acreage 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.

Arun Jayaram: Great. And just maybe a follow-up on the 2024 outlook where you’ve highlighted $1.7 billion of free cash flow potential. It sounds like CapEx will be in the low $2 billion range. Can you give us a sense on your thoughts on differentials for next year?

Jeremy Knop: Yes. I’d say on a – kind of what’s embedded in that is on an all-in company basis like a $0.55 to $0.60 kind of all-in differential. I mean, 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.

Arun Jayaram: Great. Thanks a lot.

Operator: Thank you. Your next question comes from the line of Nitin Kumar with Mizuho. Please go ahead.

Nitin Kumar: Hi. Good morning guys, and thanks for taking my questions. I kind of want to start on this new firm sales contract. I think, Jeremy, you mentioned that there’s an impact of about $100 million to $200 million 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. What’s the restructuring of the AMA costing you?

Jeremy Knop: Yes. So that AMA 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’s saying is that’s probably $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 is about $300 million, 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 million is about 10:1. So again, we think about it more from an investment perspective, it’s a near-term investment for a pretty material long-term value uplift.

Nitin Kumar: Got it. That makes sense. And then just maybe a quick question around service costs. You mentioned the 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 capital savings from operating efficiencies on Tug Hill, $150 per foot. How much of that is baked in or what are your thoughts on the service cost environment right now?

Toby Rice: So at a very high level, we’re expecting, I’d say, single-digit service cost deflation. Biggest driver there 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’s sort of underpinning our budget in this upcoming year is assuming a 400 hour per month frac pace. And as we’ve seen with the teams, 500 hours 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 high watermark. And those will translate to probably more significant cost savings than what we’re seeing on the service side.

Nitin Kumar: Okay. Thanks guys.

Operator: Thank you. Your next question comes from the line of David Deckelbaum with TD Cowen. Please go ahead.

David Deckelbaum: Hey guys. Thanks for the questions. I wanted to ask just that you provided the 2024 outlook. I assume that at this point, it sounds like that’s the original budget of the $1.7 billion base for EQT and then $300 million-plus or so for Tug Hill. So 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?

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

David Deckelbaum: Well, maybe like if you could expand on that a bit because I think that’s helpful. As we think about improvements into the business from an efficiency standpoint into 2025, could you sort of quantify some of like the maybe front-loaded opportunistic investments around infrastructure and lands that would be in 2024? Does that extend through 2025, 2026? Is this a multi-year integration and investment process? Or is this more of an upfront 2024 situation?

Jeremy Knop: Look, I think it’s just opportunistic. It’s based on when we see opportunities come about. And obviously, they have to meet our pretty stringent criteria to justify investment. But again, 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 5:1, 10:1 on that investment, we’re going to do that every time. If we see the opportunity to invest in long-term infrastructure and get a 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. And I think what’s true maintenance, if you want to think about that, is probably much closer to that $2 billion number.

David Deckelbaum: Appreciate it. If I could sneak in the housekeeping one. Is there a meaningful shift in your deferred tax assumptions for next year, cash tax as a percentage of overall burden?

Jeremy Knop: 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, 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 taxpayer, kind of a low 20% cash tax rate.

David Deckelbaum: Appreciate a little help. Thank you guys.

Operator: Thank you. Your next question comes from the line of Michael Scialla with Stephens. Please go ahead.

Michael Scialla: Good morning, everybody. Wanted to see, you talked about the potential for the $150 per foot of savings with the operational efficiencies that you’re applying to the Tug Hill assets, what needs to happen for that to become a reality? And I guess where are those relative costs based on the wells completed there so far?

Toby Rice: Well, the cost savings that we had, the $150, about half of that is operational efficiency, the other half is well design. 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 design 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. So there’ll be some monitoring time observed there. But when you step back and think about these type of operational synergies that we’ll achieve, the $150 a foot could translate to about $50 million of total spend, which would translate to about, call it, $0.02 to $0.03 lower on our cost structure on top of the previously planned $0.15. So I hope that adds some more color to your question.

Michael Scialla: That’s helpful. Thank you. And I wanted to ask about the – your agreements with 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 that needs to play out there?

Jeremy Knop: Yes. 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. 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 – it’s a parallel process and so we are 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.

Michael Scialla: Thank you, guys.

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

Kevin MacCurdy: Hey, good morning. The firm sales contracts you locked in starting in 2027 are very impressive. With those margins derisked, do you have any plans to grow into the volumes? And is that baked into your 2024 to 2028 free cash flow outlook?

Jeremy Knop: We certainly have the option to. 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 that level of activity.

Kevin MacCurdy: Got it. So it’s not baked into that outlook at this time, the 60% free cash flow of BV?

Jeremy Knop: That’s right.

Kevin MacCurdy: Great. And then you mentioned the $0.55 of NYMEX for 2024. I just wanted to get a little bit more clarity on whether that included basis hedges and any Btu uplift?

Jeremy Knop: Yes, that’s right. It’s all in.

Kevin MacCurdy: Great. Thank you.

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

Jean Ann Salisbury: Hi. Good morning. I just – on the 2 MPA of HOAs, do you have an ideal share of portfolio linked to global gas prices? And what’s kind of your thinking that underpins that ideal share if you do?

Toby Rice: Yes. I think if you step back and said and 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 netbacks that we’re able to achieve by connecting to that market, and that will sort of turn the knob on where we sit with that. But right now, as it stands, this 2 million tons per annum for us is us putting our toes in the water. I mean, it’s a significant amount of volume of the gas and 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 in accessing this market.

Jean Ann Salisbury: Great. That’s all for me. Thanks.

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

Paul Diamond: Good morning and thanks for taking my call. Just a quick one. You guys talked about the kind of that theoretical max is 500 days versus the average of about 400 currently. I just wanted to see if you guys could put a little bit of clarity around, I guess, how you see bridging that gap. Like how close can you get to the 600 and over what timeframe?

Toby Rice: Yes. So the theoretic 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 transload 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. And then obviously, we understand the benefits and economics behind water infrastructure. 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 within EQT versus others.

Paul Diamond: Understood. Thank you. And just one quick follow-up. You guys talked about the incorporation of MVP and coal retirements producing about 4 Bcf of incremental demand out of Appalachia. Just want to see if you could give a bit of clarity around the timing of that. Is that over the next one year, five years? Just how do you see that kind of developing?

Jeremy Knop: Yes. So I mean, half of that is obviously MVP at 2 Bcf a day. And the rest of it, we kind of look at it over the next five years kind of chipping away. It’s not obviously an annual growth number, but we see over that timeframe that demand showing up kind of through those different changes in the market.

Paul Diamond: Understood. That’s all for me. Thanks for your time.

Operator: Thank you. Your next question comes from the line of Noel Parks with Tuohy Brothers. Please go ahead.

Noel Parks: Hi. Good morning.

Toby Rice: Good morning.

Noel Parks: One question I had was as you have put together some of these longer-term forecasts and projections, and when you make the infrastructure piece, some of 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 feeder kind of gets reintroduced of the industry overdrilling again? I mean, I know is that sustained $6, $7 or something like that?

Toby Rice: Yes. 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 spend towards drilling is really getting away from the half-cycle wellhead returns and looking more at a holistic cost of returns and gas price needed to actually not just generate free cash flow and cover your cost of supply, but actually create, deliver value back towards shareholders. 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 we think the – what’s happened in this industry over the past few years in this sustainable shale 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 happy and satisfied with the returns that they’re making.

Jeremy Knop: 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 future gas prices or commodity prices. 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 intermittency, you have your days of demand covered dwindling for gas. You’re going to see a lot more volatility. And so instead of a clear price signal, so to speak, of $5 or $6, 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 where gas is really low. That will average out to an attractive price to 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. And I think that if you want to look at a 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 of prices were high single digits. And all it took were a couple of events and prices fell as low as $2. Now you’re 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 you’re going to see some air gaps emerge of oversupply and undersupply. 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 the 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, it’s our hedging strategy, our balance sheet, how we think about future M&A. But that characteristic, I think, is an important caveat and it will be a lot different in the next five years compared to the prior five years.

Noel Parks: Great. Thanks a lot for bringing 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 their longer-term planning, do you see any signs of the impact from some of the advanced technology out there, for example, for gas turbines, greater efficiency, lower emissions and so forth? Is that in the equation as you see some of these coal replacements on the horizon?

Toby Rice: Well, I think what you are seeing is energy security coming back into the headlines in the American grid. And when you look at a lot of the power generation capacity that’s been added, over the last five years, a lot of it has come from intermittent, albeit 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 you see this across all ISOs 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 you’re pushing them, your red lining, your reliable electricity power generation, you’re on your knees praying for the wind to 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: Great. Thanks a lot.

Operator: Thank you. Your final question comes from the line of Bert Donnes with Truist. Please go ahead.

Bertrand Donnes: Hey, thanks guys. Toby, 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 a floor. It seems like you’re more careful in protecting the downside risk versus some of your peers. So 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 maybe you just currently have a different investor base that are asking different things of you. But just any thoughts there?

Toby Rice: 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. 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 we’re putting in our business, we can do that with some of the supply deals, we structure delivering floors that cover our cost of capital, allow us to generate the returns that our investors are demanding while also providing ceilings that prevent customers from experiencing price blowouts. 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 to move it through the pipeline and get it through the tailpipe of LNG 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 guardrails on pricing.

And that is – 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 the spot market with this volatility, it’s going to get pretty exciting. And I think we can take away some of the volatility and still generates pretty great returns and create some really great win-win scenarios for customers.

Jeremy Knop: Yes. 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? And again, that’s why we keep trying to reemphasize 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 nine to 12 months because whether the biggest driver’s winter during that time period, or whether that is a warm winter, a cold winter, a normal winter, prices could be up $0.50 to $1 or down $0.50 to $1.

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, the declines in production we expect to see start to really materialize in the Haynesville, in particular, combined with the pickup in LNG demand, which by the end of 2025, we’re modeling at about a 5 Bcf a day increase, and you have another probably 1 Bcf a day increase on top of that in the form of exports to Mexico. Another structural demand from things like industrial. That market looks increasingly tight with a backdrop of low DUC inventory and actually under-investment. 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 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 to see in the future, there’ll be really great years and also some years that could be pretty tough like we saw earlier this year. 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, are looking for an energy right now, is durable cash flow and yield and price exposure, right? 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.

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.

Bertrand Donnes: Those are a lot of great points. Thanks, guys. And then maybe shifting gears a little bit. It looks like you’re drilling slightly shorter laterals in 4Q versus 3Q, but you’re still completing or turning in line maybe some longer laterals. So could you talk if there’s a strategy shift there or if that’s just a quarterly blip and you’re still targeting longer laterals?

Toby Rice: Yes. We’re still targeting longer laterals. There will be variances quarter-to-quarter and that’s sort of what you maybe 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 every day.

Bertrand Donnes: That’s perfect. Thanks, guys.

Operator: Thank you. Ladies and gentlemen, there are no further questions at this time. I will now turn the call over to Toby Rice for closing remarks.

Toby Rice: Thanks, Eric. This quarter marks another 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 for our business that we are optimistic will present some really attractive investment opportunities for us in the future, and we look forward to keeping you guys updated along the way.

Operator: Ladies and gentlemen, that concludes today’s call. Thank you all for joining. You may now disconnect.