Thank you for standing by. At this time, I would like to welcome everyone to the EQT Q2 2023 results conference call. All lines have been placed on mute to prevent any background noise. After the speaker's 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, again, press star one. Thank you. Cameron Horwitz, Managing Director, Investor Relations and Strategy, you may begin your conference. Good morning, thank you for joining our second quarter 2023 results conference call. With me today are Toby Rice, President and Chief Executive Officer, Jeremy Knop, newly appointed Chief Financial Officer, and David Khani, outgoing Chief Financial Officer. In a moment, the team 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 for 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 forward-looking statements. Today's call may also contain certain non-GAAP financial measures. Please refer to our most recent earnings release and investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. With that, I'll turn the call over to Toby. Thanks, Cam, and good morning, everyone. Before speaking to second quarter results, I want to say thank you again to Dave for being a great colleague and friend over the past three years. Your knowledge and experience during a unique time in EQT's history, combined with a thoughtful approach and heart, made you a favorite of all who had the pleasure of working alongside you. I want to thank you for your tremendous contributions to EQT, and we are excited to see your continued success into the next phase of your life. I also want to introduce Jeremy Knop, who is taking the reins from Dave as our new Chief Financial Officer. Jeremy joined EQT in 2021 as the EVP of Corporate Development and has extensive experience in strategic decision-making, investment management, capital allocation, M&A, and transaction execution from his time at EQT in previous roles at Blackstone and as an investment banker. Jeremy's strategic, value-oriented mindset and deep understanding of our business instills great confidence that he will continue to drive value creation, strengthen our balance sheet, and ensure the realization of our long-term vision. His exceptional leadership skills and unwavering focus on value creation make him the ideal candidate to steer EQT towards continued success. Jeremy's proven track record and dedication to leading purpose-driven teams make him an invaluable asset to our executive group, and we look forward to the meaningful impact and contributions he will undoubtedly make in his new role. Now, turning to Q2 results. Our operation teams built upon the momentum we achieved in the first quarter, with notable execution on both drilling and completions. As shown on slide six of our investor presentation, our drilling team recently set an EQT record by drilling 12,318 ft in 24 hours on our FGL-8H well in Greene County, and followed this up, setting a new world record by drilling 18,200 ft in 48 hours on the same run. This is not just one-off execution. However, as we recently ran a benchmarking exercise that shows EQT is consistently achieving best-in-class drilling results. Specifically, we found that EQT's recent Southwest Appalachia wells were drilled at a rate of penetration greater than 60% faster than peers, which means that even with materially longer laterals, our average spud to TD days are 20% less than nearby operators. To further put this point in context, one horizontal EQT rig can drill roughly 300,000 more lateral feet per year relative to our peer average, which is why we can maintain greater than 5 BCFE per day of net production, running just two to three horizontal rigs. A few contributing factors to this performance include diligent landing zone targeting, best-in-class geosteering, and innovative use of rotary steerable tools. It's all about people, planning, the right equipment, and execution. Turning to completion, slide seven shows our team replicated the solid efficiency gains achieved in Q1, with first half 2023 frack crew pumping hours up roughly 20% year-over-year and in line with peak levels experienced in early 2021. Not to be outdone by our drilling performance, our completions group set two records of their own in Q2. First, our team completed and drilled out 20,818 ft of lateral on our Michael 4H well, which at nearly 4 miles, is one of the longest completed laterals in the history of U.S. shale development and an internal EQT record. Our completion team also beat our previously set world record during the quarter by drilling out 262 frack plugs with a single roller cone bit, which was 90% above the prior peer record. I want to give a big shout-out to both our drilling and completion teams for the excellent performance and continuing to push the envelope when it comes to achieving peak performance. This stellar execution allowed us to achieve the midpoint of second quarter production guidance, even in the face of lower-than-expected liquids volumes from downtime at the Shell ethane cracker and fewer than expected non-operated tills, which negatively impacted our production by a combined 12 BCFE relative to our forecast. After a challenging 2022 environment where operations performance was plagued by third-party issues, our teams have resumed peak execution, driving best-in-class performance. Another highlight of the quarter was LOE, which came in at just $0.08 per Mcfe and averaged $0.07 per Mcfe in the first half of the year. A contributing factor to EQT's peer-leading LOE is our ability to efficiently handle water, which speaks to the benefits from the West Virginia water system that we've invested capital into building over the past several years. As a reminder, our West Virginia water system currently comprises 28 miles of installed water pipe and 250,000 bbl of water storage. Alongside the LOE benefits, our percentage of produced water recycled continues to climb as we target 90% this year, up from roughly 70% in 2020. Our West Virginia water system is an example of our ability to invest capital into projects that have strong risk-adjusted rates of return and add structural resiliency into our free cash flow generation. Specifically, we have invested $80 million into our West Virginia water system to date and have realized $20 million of associated annualized cost savings, implying this investment is generating a highly attractive 25% free cash flow yield. We are currently finalizing plans for similar projects that will facilitate water connectivity between our West Virginia and Pennsylvania assets, which should provide further resiliency and LOE reduction opportunities moving forward. Lastly, we retired $800 million of incremental debt during the second quarter, taking another material step forward towards achieving our balance sheet objectives. We have now retired a total of $1.9 billion of debt since initiating our shareholder return framework in late 2021, which has driven a meaningful reduction in our leverage and was a key enabler of achieving our investment-grade credit ratings. Moving forward, we will continue to prioritize debt paydown until achieving our leverage targets, as a bulletproof balance sheet ensures that EQT can maximize value creation through all parts of the commodity cycle and provide investors the best risk-adjusted exposure to natural gas. Turning to LNG, as highlighted in our press release, we recently signed an HOA with Lake Charles LNG to supply 1 million ton per annum, or 135 million cu ft per day, under a 15-year tolling agreement. This deal aligns with our strategy of allocating a portion of the 1.2 Bcf per day we have covered via FT to the Gulf, to international markets and gives us the flexibility to sell our gas directly to end users globally. We have spent the last year and a half studying the nuances of LNG export opportunities and believe the strategy we are pursuing provides the best combination of upside exposure with downside risk mitigation. Relative to the net-back structures that are commonly being signed, EQT is pursuing a more integrated approach with direct connectivity to end users of our gas. This strategy allows us to creatively structure deals with downside price protection, obtain visibility into global downstream markets, and interact with a wide array of potential customers. We plan to pursue signing one or more SPAs with prospective international buyers and have additional opportunities to increase our tolling exposure, though we will remain measured in our approach as we ensure the best risk-adjusted outcomes for EQT. As America's largest natural gas producer, we have played a critical role in providing energy security to the United States while driving significant emissions reductions via coal displacement. Our scale, peer-leading inventory depth, and environmental attributes uniquely position us to facilitate these objectives both domestically and abroad, and we are excited to begin unleashing EQT's reliable, low-emissions natural gas on the global stage. Turning to our recently released ESG report, we received multiple accolades highlighting our ESG leadership over the past year and made continued material progress toward our goal of net zero Scope 1 and Scope 2 emissions by 2025. Some of these accolades include being just 1 of 14 upstream companies globally to achieve the UN's OGMP 2.0 Gold Standard, receiving an A-grade rating from MiQ for our peer-leading methane intensity, increasing our MSCI rating to AA, reflecting our ESG risk mitigation actions, and being named one of the top workplaces in the US by Energage for the third consecutive year. Looking specifically at emissions, our 2022 Scope 1 and 2 production segment, GHG emissions totaled just 433,000 metric tons, which was 20% lower year-over-year and 50% below 2018 levels prior to new management taking over at EQT. It's worth noting that the bulk of our pneumatic device replacement was completed in the second half of 2022, so 2023 emissions should see a further benefit from this initiative. We expect the completion of our pneumatics replacement to further lower our methane intensity from 0.038% in 2022 to near our 2025 target of 0.02% this year, which is 90% below the ONE Future 2025 target and makes EQT one of the lowest methane intensity upstream producers on the planet. Between increasing operational efficiencies and replacing our pneumatics, we have now reduced our absolute emissions to essentially as low as possible under current technologies. From here, we are preparing multiple nature-based projects to generate our own carbon offsets that will leverage cutting-edge soil probe technology to ensure the quantification of these offsets is accurate and transparent. These projects will help offset our remaining emissions and 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 Scope 2 emissions. Turning to slide nine of our investor presentation, we commend the House and Senate for passing the Fiscal Responsibility Act, which included the approval of the Mountain Valley Pipeline and begins to address critical permitting reform components. We see the completion of MVP as imperative to addressing increasingly unaffordable and insufficient electricity in the Southeastern United States, while simultaneously allowing the region to achieve its climate goals. Its inclusion in this bill shows that permanent reform is not a political bargaining chip, but instead, a necessity recognized by a bipartisan government acting for the good of all Americans. While the recent stay from the Fourth Circuit Court creates some timing uncertainty, we still expect MVP to enter service by the first half of 2024. As it relates to EQT, our capacity on MVP has limited impact to our free cash flow in the near term, assuming current futures strip pricing. That said, the pipeline brings much needed breathing room to Appalachian infrastructure and should lower high line pressures in certain parts of the field that can in turn lessen the risk of system outages moving forward. Longer term, the completion of MVP should catalyze multiple southern expansion projects that 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. We believe this will in turn drive better price realizations and materially enhance the value that MVP brings to EQT over the coming years, while simultaneously lowering energy prices for consumers in the Southeast. I'll conclude with a few comments on our pending Tug Hill acquisition. The transaction has taken modestly longer than we anticipated to close, we continue to work constructively with the FTC and expect we will complete the transaction in Q3. As a reminder, Tug Hill and XcL Midstream bring low-risk, high-quality assets, offsetting our existing acreage that should drive an additional $0.15 decline in our corporate free cash flow break-even price, providing even greater resiliency to our business moving forward. I'll now turn the call over to Dave. Thanks, Toby. It's bittersweet to be on my final conference call after three and a half amazing years at EQT, and over 30 years on Wall Street and in the corporate world. I'm honored to have left my mark on this company, and I feel a deep sense of pride in all that we've accomplished in a relatively short period of time. Since I joined in January 2020, the stock has essentially quadrupled. We regained investment-grade credit status, and EQT was added to the S&P 500 Index. Even with this, EQT is truly a unique organization on a trajectory that I believe will create tremendous value for years to come, which is why I am excited to remain a long-term shareholder in this company. I'm also thrilled to see Jeremy appointed as EQT's next CFO. I've seen his exceptional execution capabilities firsthand, and I'm extremely confident he is the right person for the job. Jeremy and I have worked closely together on many aspects of the business, including financial policy, capital allocation, and hedging, which will ensure strategic continuity and a smooth transition of the role. With that, I'd like to say one final thank you to all our stakeholders for your support, and I'll now turn the call over to Jeremy. Thanks, Dave, and good morning, everyone. I'm extremely excited and grateful to take the reins from Dave as EQT's next Chief Financial Officer. Since joining the company in 2021, I've been continually impressed by the depth and quality of EQT's assets, the company's world-class execution capabilities, and the heart, trust, and teamwork that flows among our employees. I believe these attributes materially differentiate EQT in today's energy landscape and set the stage for us to drive meaningful value creation for our shareholders. Our high-level financial strategy will remain consistent with the execution you've come to expect from us over the past several years, with a focus on ensuring we always maintain a bulletproof balance sheet, continued execution of our value-oriented shareholder return framework, and thoughtfully investing capital in ways that structurally improve our business. I'm excited to make an even more impactful contribution to the organization and look forward to engaging in even more dialogue with our shareholders in my new role. Turning to second quarter results, sales volumes were 471 Bcfe, in line with the midpoint of our guidance range. As Toby highlighted, our drilling and completions team saw extremely strong field-level execution during the quarter, which allowed us to offset the negative impact of downtime at Shell's ethane cracker and lower non-operated tills associated with the broader slowdown in gas-directed activity, which combined reduced quarterly net production by 12 Bcfe relative to our forecast. Note that we have applied a greater risking to our ethane production forecast going forward to better account for continued operational issues at the cracker as Shell works to bring it fully online. Our per-unit adjusted operating revenues were $2.11 for Mcfe. Our total per-unit operating costs were toward the low end of our guidance range at $1.37, resulting in an operating margin of $0.75 per Mcfe. Capital expenditures, excluding non-controlling interests, were $470 million, in line with the midpoint of our guidance range. Adjusted operating cash flow and free cash flow were $341 million and -$129 million respectively. We also saw a $96 million working capital benefit, driven by declining accounts receivable and lower margin postings, which offset much of the total cash impact from negative free cash flow during the quarter. Turning to the balance sheet, a strong credit profile and ample liquidity remain core to our operating philosophy and will provide access to differentiated value creation opportunities for EQT shareholders moving forward. Our balance sheet remains very strong, with trailing 12-month net leverage exiting the quarter at 1.1x, down from 1.6 x a year ago. We exited the second quarter with $3.5 billion of net debt and $1.2 billion of cash on hand. As shown on slide 12 of our investor deck, we further built upon our track record of debt retirement, with $800 million of incremental debt retired during the second quarter. This was comprised of the $300 million tender offer for our 6 and 1/8% 2025 senior notes and the full redemption of our 5 and 5/8% 2025 senior notes. Since rolling out our shareholder return framework in 2021, we've now retired over $1.9 billion of total debt, which has eliminated nearly $90 million of annual interest expense. Despite the challenging natural gas macro environment this year, we expect our leverage to remain well in check as we forecast exiting 2023 with a net debt to EBITDA ratio of 1.3 x at current strip, excluding the pending Tug Hill acquisition. At the end of the quarter, liquidity stood at $4.9 billion, comprised of $1.2 billion of cash, $2.5 billion of availability under our credit facility, and the $1.25 billion term loan that we have in place for the pending Tug Hill acquisition. Moving to hedging. Second quarter results highlighted the beneficial position of our 2023 hedge book, as we realized $237 million of cash NYMEX hedge gains for the quarter, inclusive of deferred put premiums. In recent strip, we expect full year NYMEX cash hedge gains of approximately $440 million, net of deferred put premiums. Looking into 2024, we opportunistically added to our hedge position to de-risk a portion of our expected free cash flow and debt repayment goals. We currently have 30% of our 2024 production hedged, with a weighted average floor price of $3.64 per MMBtu and a weighted average ceiling of $4.14 per MMBtu. Note our hedge position is strategically tilted toward the first half of 2024, where we see the most potential downside risk should normal winter weather again not materialize. By protecting near term free cash flow and prioritizing our debt repayment goals, we are intentionally creating flexibility to maintain maximum upside price exposure in late 2024, 2025, and beyond, when the natural gas market looks increasingly tight and we believe pricing is asymmetrically skewed to the upside, while at the same time mitigating downside risk. As it relates to basis, Appalachian differentials have widened for the balance of 2023, driven by elevated eastern storage levels, a byproduct of the warm prior winter. The current M2 future strip implies more than a $1.50 per MMBtu differential to NYMEX this fall, which is a price level below cash costs for many producers. EQT is well positioned here, however, as we have roughly 90% of balanced 2023 local volumes covered with basis hedges that are solidly in the money relative to current strip. On MVP, we model a first half of 2024 in service date, though acknowledge there could be some risk to the timetable based on recent activity from the Fourth Circuit Court. When MVP does come online, higher transmission expense associated with our capacity should be largely offset by a combination of the immediate material step down in our gathering rate and better price realizations, resulting in a negligible impact to EQT's free cash flow in the near term. However, as Toby mentioned, we see significant opportunity to move production further into the Southeast U.S. over time as expansion projects are completed. This will occur at a time when Gulf Coast volumes supplying the area shift more towards satisfying LNG export demand, which will likely contribute to better price realizations and value for our MVP capacity over time. Turning to the natural gas macro landscape, fundamentals are largely playing out as we expected. As discussed on our last earnings call, we anticipated additional gas-directed activity cuts, given prices fell well below many producers' break-evens across the U.S. Activity reductions have played out, with 35 gas rigs laid down across the U.S. in the second quarter, 22 of which were in the high-cost Haynesville Play, a nearly 40% fall from the peak in a very short amount of time. We expect incremental gas rig drops for the rest of 2023, albeit at a much slower pace relative to the last few months. The large year-to-date reduction in drilling activity should moderate supply from current levels and help support prices for the balance of 2023 and as we head into 2024. We also note over 45 oil-directed rigs were laid down during the second quarter, and oil activity is now roughly 15% below highs set late last year. Further declines in oil-directed activity will likely result in associated gas growth underperforming relative to consensus. Lending additional structural support to natural gas prices in 2024 and 2025. Another area of significant market support has come from strong gas-fired power demand. Lower spot natural gas prices and materially weaker than expected wind generation drove approximately 3 Bcf a day of higher natural gas power generation during the second quarter. Specifically, wind generation underperformed expectations by a staggering 20 million megawatt hours. Most of this shortfall was met by natural gas generation, demonstrating the need and the value of reliable generation to compensate for inherent volatility of renewables. LNG performance during the quarter remained strong as Europe and China lifted U.S. cargoes to refill storage and meet demand from record-breaking heat realized in May and June. Some of this strength was offset by major maintenance at Sabine Pass in June, but this has since been completed. Looking ahead, we anticipate 6 Bcf a day of incremental nameplate LNG capacity online by year-end 2025, which should create a significant tailwind for natural gas fundamentals over the next several years. Turning to oilfield service pricing, the rate of change in inflationary pressure has slowed meaningfully over the past several months, and we're starting to see leading indicators of potential softening in certain areas. Recent indications suggest steel casing prices have declined 15%-20% relative to the recent peak. We should start to see the benefits of this beginning in late Q3 as we deplete our current inventory. For reference, steel associated with casing and wellheads makes up around 10% of our total well costs. In terms of drilling and completions, we are currently running two horizontal rigs and two to three frack spreads. Given our focus on consistent execution of our combo development strategy, we lock in the bulk of our rigs and frack spreads under long-term contracts. This strategy has paid dividends for us over the past several years, as our rates have been consistently below the spot market. The quantity needed is much lower than peers due to our higher efficiencies. We do see the opportunity for some modest downward pressure on big-ticket items. As our contracts roll off, we're exploring ways to improve our efficiencies that could translate into incremental downward pressure on well costs. While it's still too early to predict with precision, we preliminarily see the potential for our total well cost to decline by up to 5% year-over-year in 2024. Turning to guidance, we are reiterating our 2023 production outlook of 1,900 Bcfe-2,000 Bcfe, our 2023 capital budget of $1.7 billion-$1.9 billion, excluding the pending Tug Hill acquisition and our per-unit operating expense in differential ranges. On slide 33 of our investor deck, we provide adjusted EBITDA, operating cash flow, and free cash flow outlooks at various natural gas prices for the remainder of 2023. At recent strip pricing, 2023 adjusted EBITDA is expected to be approximately $2.8 billion, and 2023 free cash flow is anticipated to be roughly $900 million prior to the impact of our pending acquisition. As it relates to capital allocation, we are pleased with the execution of our shareholder return framework to date and will continue with our opportunistic, all-of-the-above construct moving forward. As a reminder, since initiating our framework in late 2021, we have retired more than $1.9 billion of debt, repurchased more than $600 million of stock, and pay an annual base dividend of $0.60 per share, which we grew 20% last year relative to our initial dividend. As it relates to our buyback execution, we believe our opportunistic strategy is generating superior results. As our current share price suggests, we have generated a weighted average return of 31% for our shareholders versus a -5% on average for the peer group. Looking ahead and consistent with our track record, investors should expect we will maintain a bias towards debt repayment until we achieve our target of 1 x leverage at $2.75 per MMBtu natural gas prices, which will ensure a bulletproof balance sheet through all parts of the commodity cycle. This will in turn minimize the downside while allowing us to limit the need to defensively hedge and cap what we expect to be unpredictable, asymmetric price movements to the upside in the years ahead. We will also continue to rigorously assess investment opportunities with strong risk-adjusted returns that improve the quality of our business while compounding cash flow, which is the foundation of sustainable shareholder value creation in any business. Similar to our West Virginia water system that Toby highlighted earlier, our buyback 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. Finally, sustainable long-term base dividend growth will remain a key pillar of our shareholder return strategy moving forward. I'll close by highlighting slide three of our investor presentation, which I think elegantly summarizes the value proposition at EQT. We believe our modern, data-driven operating model, significant scale, peer-leading inventory, quality and depth, ESG leadership, and low investment-grade cost of capital make EQT one of the most compelling investment opportunities in the market today. Despite these characteristics and strong relative stock performance recently, EQT trades at the highest five-year cumulative free cash flow yield as a% of enterprise value amongst the gas peers. Meaning, we could buy back more of our enterprise value with organically generated free cash flow at strip pricing. As illustrated on the left side of slide 11, thanks to our relentless focus on achieving the lowest free cash flow breakeven, at our current stock price, EQT shares simultaneously provide among the least downside in a long-term $3 gas price scenario, and the most upside in a $5 gas price scenario. When measured by the next five years of cumulative free cash flow relative to enterprise value. Whether investors fully appreciate this or not, as this cash flow is realized, it should drive our equity value higher by definition. We believe this will propel further share price outperformance. This signals to us the market is only scratching the surface of appreciating EQT's strategically advantaged position and high-quality assets. I look forward to helping identify and capture significant value for shareholders in my new role moving forward. 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: EQT's operational execution has been on point in 2023, with our drilling and completion teams setting multiple internal and world records during the quarter. Number two: we continue to successfully implement our value-oriented capital returns framework with an incremental $800 billion of debt retired in Q2, taking our cumulative debt retirement to more than $1.9 billion since late 2021. Number three: our recent HOA for tolling capacity at Lake Charles represents an initial step in progressing our LNG strategy, which seeks to diversify a portion of our production into international markets and achieve the best combination of upside exposure with downside risk mitigation. Four, we strategically added to our 2024 hedge position, which ensures the accelerated achievement of our debt retirement goals, while simultaneously providing shareholders maximum upside exposure to gas prices in late 2024, 2025, and beyond. Lastly, number five: our 2022 ESG report underscores our peer-leading environmental performance with a 20% year-over-year decline in EQT's production segment, Scope 1 and Scope 2 greenhouse gas emissions, moving us yet another step closer toward the realization of our ambitious 2025 net zero emissions goal. I'd now like to open the call to questions. To ask a question, please press star one. Please limit yourself to one question and one follow-up. Your first question is from Umang Choudhary of Goldman Sachs. Please go ahead. Your line is open. Thank you. Best of luck, Dave, and hope to stay in touch. My first question was around your plans of around improving your free cash flow breakeven. Wanted to get your thoughts on capital efficiency improvement heading into 2024, given you highlighted drilling completion efficiency gains and a 5% reduction from deflation. Also, if there's any update on the next gen well design, which you talked about earlier in the year. Sure. A couple of things that will take place in 2024. We'll see a little bit lower activity levels compared to 2023, and that's as a result of just the catch-up activity that we added in 2023. That will be helpful. On the operational efficiency side of things, that's great to see the progress that the teams have made there, but really, the focus is gonna be on service costs, inflation reductions that we see. We're being conservative with that low single digits, but we'll update that as the teams continue to procure bids. And obviously, stepping back, bigger picture, we've got Tug Hill, which will lower our cost structure. Also, as a reminder, we say it every quarter, the step down on gathering rates will be impactful as well. You know, pretty unique in the sense that EQT has some pretty big items that will lower our cost structure going forward. I think that's definitely unique and worth pointing out. As it relates to the Mach 3 science campaign that we run, we have completed all of the operational execution of that, and we are currently in monitoring mode for the impact there. You know, we have taken some best practices and incorporated that into our well design program, and, you know, with the monitoring that we've done, we have tightened up the controls and our assessment to take these different parameters and make sure that we are applying the best for market conditions. It's been some practices implemented, greater awareness on the knobs that we're turning, and we'll continue to monitor that. As we mentioned in the past, biggest focus for us, determining factor is really going to be where the service cost environment shakes out. We'll keep everybody updated on that front. Got you. That's very helpful. Thank you. My next question was on LNG strategy. You've obviously taken the first step towards executing your strategy by signing the HOA agreement with Lake Charles. Any update on what the end customers are looking for? Any color on the price exposure which they're willing to take and their willingness to sign collar contracts? At a very high level, what customers are looking for, they're looking for energy security. While you've seen customers around the world build out the infrastructure to receive LNG, that you've seen customers acquire supply to feed that infrastructure, but as long as the supply is tied to index pricing, it's hard to see that energy security, which only comes with cost controls and guardrails on pricing. This is something that we thought was incredibly important. We thought it was unique, and with this tolling structure that we put in place, we now have the flexibility to give that energy security to our customers with, you know, collared floors and ceilings type price controls on the LNG and energy that they're buying. We think there'll be tremendous interest, and now that we have this tolling capacity, we can really dial up the conversations, ultimately leading to a sales and purchase agreement with some of these customers. Thank you. Your next question is from Devin McDermott of Morgan Stanley. Please go ahead. Your line is open. Hey, good morning. Thanks for taking my question, and Dave, congrats again on the retirement. My first one is just on Tug Hill, and Toby, I'm not sure how much more you can say, but I was wondering if you could talk a little bit about just the high-level dialogue with the FTC, the reason for the slight delay here, and what gives you confidence in the ability to close this deal here in 3Q? Well, conversations have been constructive with the FTC over the past 12 months, I'd say. You know, I think we said that by the middle of this year, we'd have better insight on where this deal stands. I can tell you today that we have confidence that we will reach resolution within the next 30 days. Okay. Great. Separately, on MVP, the disclosure on it being roughly cash flow neutral, is helpful. I was wondering if you could elaborate a bit just on some of the moving pieces there. I know you've taken some cash payments upfront for the scheduled rate relief that comes along with that pipe entering service. What's the net remaining rate relief, and how should we think about the impact of that piece over the next few years? Yeah, there's a couple pieces to that. When that pipeline comes online and you think about the associated capacity that supports it, like Hammerhead, you'll see our rates step up on the transportation side. At the same time, that triggers a gathering rate reduction, and we'll access more premium markets. Net-net, as we've talked about before, that should really net the impact out. You know, I think as you look through the end of the decade, and you look at some of the expansion projects that are in play that Williams and others are talking about right now, our expectation is that that market we deliver to through MVP at Station 165, will start to trend to trade more like that Transco Zone 5 market. If you look at what Cal 25 looks like on the basis markets today, Station 165 trades about $0.40 back, and that Zone 5 market trades at about a $1 premium to NYMEX. It's gonna be an evolution of that market as those downstream projects are built out. That's what we're looking forward to really in the years ahead, and I think that capacity, the value of it will increase each year that goes by. Great. Thank you. Your next question is from Bertrand Donnes of Truist. Please go ahead. Your line is open. Hey, morning, guys. Just one of your peers is taking the approach that, you know, LNG exports will be about 15%-20% of U.S. volume, so they want to keep their contribution in that range. I just wanted to see if that matched kind of your internal strategy, or does the tolling agreement you have maybe let you pivot more easily, and so you maybe could go above that percentage? You know, the way we've talked about this historically is having that 1.2 Bcf a day, of supply into that Gulf Coast market today. You know, we will use a portion of that to sell into international markets, but, you know, we haven't necessarily set any sort of guidance range like you describe around it. I think we'll be opportunistic, depending on the facility, depending on what the market provides us. You know, long term, I think we'd like to increase capacity to the extent it makes sense, but within, you know, a proper risk-adjusted framework. Gotcha. My follow-up on the same topic is just kind of 2 smaller points. Does your ability to increase your capacity to the Gulf Coast have any impact on maybe the pace of additional LNG deals? The second part of that is just, with a 15-year term on your side, did you want to match the end user's agreements to that duration, or do you maybe want to do five years here and there, you know, and add up to that 15 years? Thanks, guys. Yeah. On the structure with the sales and purchases agreement, we would like to see parity with what we're doing on the tolling side. And I would say, just what's gonna govern the pace for us, given the fact that we have ample exposure to the Gulf Coast and LNG? The pace is really gonna be governed by the customers. If we can execute attractive, collar-type pricing that locks in some pretty favorable returns for us, then I think we'll look at continuing the pace and doing more. These are the conversations that we're gonna be having over the next 12 months, that we've already begun. That will come back and determine pace, and we'll update you guys along the way. Sounds good. I appreciate it. Your next question is from Arun Jayaram of JPMorgan Chase. Please go ahead. Your line is open. Yeah, good morning. Toby, I wanted to get a follow-up on your comments on your expectation that you could close the deal with Tug Hill in the next 30 days. I mean, do you contemplate any changes to the original agreement? Just want a sense is, if you close in 30 days, do you expect it to be consistent with the original terms signed with Tug Hill? We expect to be closing within 30 days, one of the guiding principles for us as we're going through this process, is to make sure that we preserve the economics of the deal that we signed up and feel like we're going to be able to deliver that. Also preserve the strategic flexibility going forward. It's been a long process, but we see the light at the end of the tunnel, and we're gonna achieve our original goals. Great. My follow-up, Toby, you started the call talking about a lot of efficiency gains on the drilling and completion side, and then obviously you have the Mach 3 program, which is underway. You know, excluding any kind of impacts from service cost tailwinds, next year, how should we be thinking about capital efficiency of next year's program, just given some of the benefits efficiency gains that you highlighted this morning? Yeah, Arun, you know, slide 22 for us, really puts the spotlight on CapEx efficiency over time, and we do anticipate there to be a tick down on our CapEx intensity. I think looking longer term, when you get the benefits of Tug Hill, you get the benefits of the lower gathering rates, overall corporate break even will continue to trend lower. Great. I also want to pass on my regards to Dave. Good luck in retirement. It's been great working with you all these years. Thank you. Your next question is from John Abbott of Bank of America. Please go ahead. Your line is open. Hey, thank you very much for taking our questions. Dave, the BofA team wishes you also the best of luck in your next adventures. Thank you. Toby, first question is really on West Virginia. You've mentioned other opportunities here for, like, improvements like water infrastructure between West Virginia and PA. Could you characterize, you know, the number of opportunities? Are we talking about two? How do you see potential costs versus the $80 million that you spent previously? I mean, there has been some sort of cost inflation. Just how quickly would you want to go after these types of opportunities? Are we looking at 2024? Do you want to see some deflation? How should we think about that? I think what's special about West Virginia is the terrain, and logistics become very important. To solve logistics constraints, you know, investing in infrastructure is the solution. You've seen the benefit from the water infrastructure investment that we've done in West Virginia. That will continue, and we've identified a synergy with the Tug Hill acquisition to combine the Tug Hill water system with our system. That not only is gonna expand our produced water network, but also freshwater delivery. We're excited about continuing the progress on the water side. We're also looking at sand infrastructure and really just getting some transloads closer to the well locations. That should hopefully not just alleviate bottlenecks, but also set the completions teams up to continue to knocking it out of the park and removing sand as being a bottleneck. That will be a constraint on them, just given their enhanced operating efficiencies that they've been demonstrating down there. John, I think, just to add to that from more of a financial perspective too, if you look at that water system we built out, we spent about $80 million doing that, and today, that's generating savings of about $20 million a year. Think about that as like a 25% free cash flow yield. That's something that, You know, it's not like a well that declines. It's durable. It's got longevity to it for the next 10-15 years. Some of the other projects we've looked at recently, one of which we highlighted when we announced that Tug Hill acquisition, what was, you know, additional pipeline connectivity throughout the basin. We're seeing similar sorts of returns on those projects. It's kind of a mid 20% free cash flow yield. You know, the more projects like that we can find to reinvest capital into, you know, the more value we think we can create, both through reinvesting and compounding, also just improving the base quality of the business. It's something we're focused on. We've got the operational teams, you know, looking around, trying to find more opportunities to reinvest cash flow like that. I mean, those are two examples just to make it a little more tangible. Appreciate it. The second question is on MVP. You know, assuming it comes online, you know, maybe the basin can't necessarily grow into it all at once. You know, when you sort of think about that capacity coming on, what are your thoughts about EQT growing into some of that capacity over time? Would you want to maintain market share? How do you think about it? Do you want to just stay flat? How do you think about that capacity? Certainly out of the gate, until some of the downstream expansion projects are completed, that really create more of that demand pull, at that delivered market, we just plan to reallocate volumes that are currently being sold in basin, to that MVP capacity. You know, where the basin sits today, and I think 2023 is a good example, where in-basin storage is about 100 Bcf a day above, not per day, 100 Bcf above normal. You know, there's not a lot of headroom. We think MVP coming online will take some of that froth out of storage and balance the market a little bit more. If additional infrastructure is built, we would love the opportunity to grow into it, but where we sit today, it's hard to see that being in the next one to two years. Appreciate it. Thank you very much for taking our questions. Your next question is from Scott Hanold of RBC Capital Markets. Please go ahead. Your line is open. Yeah, thanks. You know, hey, Toby, you obviously, you know, have some confidence in seeing the Tug Hill, you know, closing it sounds, you know, and, you know, with a lot of the, you know, economics and, you know, kind of, non-negotiables that you wanted. Can you talk about, more specifically, though, you know, your view on, you know, further consolidation, you know, within the basin and beyond that? I know that was a strategy, a few years ago to, you know, generate more shareholder value. Do you see any limitations based on, you know, your conversations, you know, with the FTC to do, you know, much beyond the Tug Hill deal? Scott, at this time, I think we'd just like to stay focused on getting the deal done with the FTC, and we'll look forward to updating you guys on path forward after we get through this. Okay, understand. Then on the LNG tolling agreement, you know, I think that you indicated some of the things that, you know, the buyers were interested in getting. Can you just give a high-level view on the way that you're structuring the agreements? Like, what, where, what do you see as certain terms of, you know, the benefit of reaching those international markets? What kind of bands are you looking at relative to what you could get in the U.S.? Does that also mitigate the need for you all to, you know, hedge those volumes when you, when you do have some collaring on the pricing? Yeah. Let me answer it this way. It getting these deals in place is a multi-step process. Signing the HOA is the first step in that. You know, as we look forward to the next steps, it comes down to getting a binding agreement in place based on those HOA terms, and then following up on that with that sales and purchase agreement. A collar structure is what comes into play as part of that sales and purchase agreement, so it's a little premature to give too much clarity around that at the time, but you're right, that is still our intention. Thank you. Your next question is from Michael Scialla of Stephens. Please go ahead. Your line is open. Yeah. Thank you, and congratulations to both David and Jeremy. Jeremy, you talked about the 24 hedges you added during the quarter that were weighted to the first half, I guess to take some winter risk off the table. I want to see how you guys are viewing the market in the second half of 2024 and into 2025. I guess it sounds like you would stay lightly hedged there, given the incremental LNG capacity. Is that fair? Yeah, there's a couple dynamics at play. When we look at the market going forward, we try to get a sense for. Well, it's hard to predict price exactly. We try to get a sense for where the skew is. When you look at where storage is today, heading into this winter in the first half of 2024, we feel like there's pretty equal upside, downside skew. That's why you've seen us lean a little bit more into swaps, even though it's something we're generally trying to de-emphasize in the past. Unless we see strong call skew in the options market, it's hard to feel good about leaning into those. But really near term, because that we would like to de-risk our debt repayment goals. As we get towards the back half of 2024 and into 2025, where that upside is just so much more asymmetrically skewed, but is not yet reflected in the options market or in the future strip, we wanna remain patient there, and hedging more near term allows us to do that. Look, it doesn't mean we're not gonna hedge 2025 at some point, but we think where the market sits today, it's far off from where really it should be. You know, as you think about how the market might trade as you get into 2024, you know, I think most market participants and analysts see that cal 2025, 2026 market is getting especially tight as you see that demand ramp, or at least ramp in nameplate capacity of LNG. The market obviously trades a season ahead. I think as you get towards next summer and the market starts looking at winter 2024, 2025, and a lot of that demand ramp, unless you have a step change, really increase in production at the same time, I think the market will look increasingly tight, and that'll probably start getting reflected next summer in probably a much more asymmetric way. You know, I think we're trying to be patient at this point in time and not be in a position where we need to really defensively hedge and take away that upside, which is what I think a lot of our investors are looking for in the market today. That makes sense. Thank you. I wanted to ask on if Tug Hill does close within the next 30 days, is it fair to assume that your second half activity that you've laid out on your legacy properties doesn't change? Looks like, I think they're running two rigs right now. Would you expect to just maintain those two rigs into the end of the year? Yeah. Operational cadence for EQT assets will remain the same. Our plan with Tug assets to continue to maintain activity levels. I think the high-grade opportunities would probably start seeing those hit the schedule maybe 12 months. It would just take some time for us to set those wheels in motion. Pretty much in summary, similar plans for the first 12 months, and then you can start seeing us optimize the asset base. Thank you, guys. Your next question is from Josh Silverstein of UBS. Please go ahead. Your line is open. Thanks. Good morning, guys. Congrats to Jeremy and David as well. Just on the LNG front, I know you were starting to sign some contracts here. Longer term, do you think this leads to a potential stake in an LNG facility, to help kind of have the vertical chain, so to speak, there? Yeah, Josh, we've always looked at investing in LNG facilities, you know. Does the world need EQT to do that right now? It seems like these projects are getting going. What the world needs is EQT supply. We're participating in that front. Our prize here is really getting exposure to international markets. If we can do anything on the East Coast, that would give us exposure to sustainable growth opportunities. That's the real value for us. We're not, you know, looking to make investments in LNG, but there could be opportunities where, from a risk mitigation perspective, it could make sense for us to make a small investment in an LNG facility, but that's sort of how we're viewing it right now. Gotcha. Yeah, I was just wondering if there's an investment to be made, maybe it pushes through the Lake Charles facility a little bit faster. I wasn't sure from that angle. No, I think just, you know, when we looked at the several facilities, early on, we weren't sure if we needed to make an equity investment to get international pricing, and after a lot of discussions, we found that we really don't need to do that. Got it. That's helpful. Jeremy, you mentioned the, you know, the free cash flow over the next five years and the ability to start returning capital to shareholders. You don't have a formal strategy in place right now. The share buybacks have gone up and down based on where the commodity prices has been. Once the Tug Hill transaction is closed, do you foresee kind of getting towards a, call it a, you know, a formal 50% kind of split between balance sheet reduction, shareholder returns? Do you want to hit a certain, you know, debt level before you kind of commit to that? I'm curious how you're thinking about the shareholder return profile going forward. You're right that really, while this deal has been pending, our focus has been to be opportunistic tactically, but really accumulate cash ahead of closing. Until closing happens, I think you can expect us to continue doing the same thing. After the acquisition closes, I think you should really expect until we meet our debt targets to really pursue the same strategy, which is weighted towards debt repayment. Then tactically, when we see dislocations in the market, lean into that buyback. You know, I think the concept of a formulaic, programmatic buyback is just a long-term strategy, is something you'll see us probably shy away from, at least near term. You know, I think we like to be more tactical in how we approach that, especially in an industry that is inherently always cyclical, both from a macro standpoint and even a weather-driven standpoint. We think there'll be, you know, continued opportunities to create outsized value for patients, just like we've done to date. Great. Thanks, guys. Your next question is from Paul Diamond at Citi. Please go ahead. Your line is open. Thank you. Good morning, all. Thanks for taking my call. Just a quick one, talking about, the completion efficiency is up 20% year- on- year, and you also had some pretty, strong drilling performance as of late, substantially. You know, it's kind of like breaking yourselves away from peers. I guess the first part of the question is, how much more on the bone do you see there? Is that something we should think as, like, step change in the future or more incremental? As far as, like, others catching you, is that, you keep running in place, or is that a gap you think you can really maintain? Yeah. The goal for us is to, you know, raise the bar. These records show what could happen and the potential we have, and the goal for the operating teams is to move that average performance up to peak performance. That's the games that we're playing, and we're removing any bottlenecks to achieving that peak performance along the way. Our attitude is that peers have the ability to keep up with us. This is the fire that keeps us continuing to evolve and look for ways to continue raising the bar. We're incredible. We're proud of where we're at, but we're always looking to get better. That's really... I'd say the one of the defining characteristics of our culture is just our ability and the drive to continually evolve our business. Understood. Thanks for the clarity. I'll leave it there. Your next question is from Jeoffrey Lambujon of TPH. Please go ahead. Your line is open. Good morning, everyone, and congrats to both Jeremy and Dave. I appreciate you all taking my questions. My first one is just a follow-up to the water infrastructure commentary that you mentioned. I think that was part of the synergies that you highlighted with the deal. Just wanted to get a sense for if any of the savings here from these opportunities would be incremental to that $0.15 break-even improvement that you all have highlighted in the past. That $0.15 that we talked about associated with the deal, that's all pre-synergies. Just kind of as a rule of thumb, we don't like to include synergies in just our base guidance. I think when we announced Tug Hill, we were talking about $80 million a year of total synergies. You know, we haven't been able to refine that just due to some gun-jumping laws around just this FTC process. You know, that's all incremental upside to the guidance we've given, that $0.15 and even that rate of return that we talked about on that existing West Virginia water system we already built. Okay, great. Then maybe going back to MVP and potential infrastructure downstream, I imagine D and E, in particular on that slide, will be relatively important from a pricing standpoint, but it'd be great to get any thoughts you can share just on the projects that you show there, and how you're thinking about the potential impacts to your marketing or regional mix as those get developed. Yeah. We see most of those projects as more of demand pull, back, rather than supply push. We don't anticipate needing to take out contracted capacity, but those are important for just the long-term development of that Station 165 market. Thank you all. Your next question is from Noel Parks of Tuohy Brothers. Please go ahead. Your line is open. Hi, good morning. I just wanted to go back to the project of swapping out the pneumatics. I just wondered, could you give a sense as to what sort of the scale of that overall cost was looking back? It's about $28 million, and when you think about it, normalized on a dollar per ton, it's less than $10 per ton to achieve the emissions reductions. Great. I guess just one thing, and I apologize if this has been touched on already, but with the FTC review, is the fact that in the technical transaction, you're also doing the infrastructure purchase, is that a factor that has made the overall review process go on a little longer, or is that sort of unrelated? I don't think there's any elements that are unique here or that stand out. I think this is just part of the process to review the deal and concept. I mean, I just remind everybody when the FTC issued their second request to us, it was back in November, and I think if you just remember what the gas market was like, there was a lot of concerns over natural gas, you know, what was happening with Europe and, you know, peak fear on gas shortages. I think the FTC took the opportunity to take a closer look, and that's the process that we're going through, and are happy that we're in a place where we're confident in getting this thing closed within the next 30 days. Great. Thanks a lot. Your next question i s from John Daniel of Daniel Energy Partners. Please go ahead. Your line is open. Hi, guys. Thank you for including me, and Dave, congrats. If you get bored, give me a call. Toby, you noted some of the drivers of the improved drilling performance, but how much of that improvement is due to an internal process versus third-party technology from one of the service providers? Well, I think on the internal side, I mean, look at the setup we're delivering to the operations teams. I mean, large scale, long lateral combo development certainly sets the teams up to knock it out of the park, and that definitely would be considered an internal improved thing that we do that is gonna be hard to replicate with other asset bases. You gotta go out there, and you gotta execute, and the teams are doing that. We have very close relationships with our service providers. You know, I think on this run here, that there's been a lot of improvements on bit design, that the teams have worked with our service providers. Really close relationship, and, you know, our success is really... Got it. ... gonna be based on the success of our partnerships, and we've got some great partners on the drilling front, and across the operational spectrum. I'd say, you know, probably half of it is internal, and the other half is the great working relationship we have with our service providers. Okay. Thank you. The second one for me is, you know, when you look at this, the drilling success, and assuming a portion of it can be copied into other basins, and just seeing the efficiencies that you've achieved, I mean, when you look at, you know, analysts such as myself, are we fooling ourselves when we prophesy a rising rig count in future years, or are we gonna see these efficiencies render that a not a reality? Well, John, yeah, I mean, when I step back, and you look at the, I mean, you, we've got sort of gotten past the step change in operational efficiencies. It's more of a slow grind. Yeah. It's the factors that are ultimately gonna be defining the success of the operation. We've sort of pushed past just what specifically we're doing on site at that operation. It's really external factors that are really influencing. Things like, do we have long laterals ready to drill? What's the land situation look like on the completion side, what's the logistics on water and sand? It's as much as the system that we're creating as it is the actual individual performance. I think industry has already made the move to recognize that long laterals are the key. Sure. ... how much of that they have, and the quality of inventory, I think, is gonna be defining characteristics on their efficiency going forward. Fair enough. What you reported seems like a step change better to me, so maybe I haven't been paying attention, but that's pretty impressive. Thanks. Thank you for including me for on the call. There are no further questions at this time. I will now turn the call over to Toby Rice for closing remarks. Thanks, everybody, for your time today. We look forward to continuing our strategy to make the energy we produce cheaper, more reliable, and cleaner, and we'll look forward to keeping you updated on our progress. Thank you. This concludes today's conference call. Thank you for your participation. You may now disconnect.