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Presentation

Operator: 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 speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. Cameron Horwitz, Managing Director, Investor Relations and Strategy, you may begin your conference.

Cameron Horwitz: Good morning, and 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.

Toby Rice: 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 contribution 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 toward 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 operations teams built upon the momentum we achieved in the first quarter with notable execution on both drilling and completions.

As shown on Slide 6 of our investor presentation, our drilling team recently set an EQT record by drilling 12,318 feet in 24 hours on our SGL 8H well in Green County and followed this up setting a new world record by drilling 18,200 feet 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 geo-steering and innovative use of rotary steerable tools. It’s all about people, planning, the right equipment and execution. Turning to completions. Slide 7 shows our team replicated the solid efficiency gains achieved in Q1, with first half 2023 frac 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 feet of lateral on our Michael 4H well, which at nearly four 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 frac 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 TILs, 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 barrels of water storage. Alongside the LOE benefit, 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 returns 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 to 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 cubic feet 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 guests directly to end users globally. We have spent the last 1.5 years 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 netback 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 U.S. 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 a verifiable net zero Scope 1 and 2 emissions. Turning to Slide 9 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 permitting 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 future 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. While 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 breakeven price providing even greater resiliency to our business moving forward. I’ll now turn the call over to Dave.

David Khani: Thanks, Toby. It’s bittersweet to be on my final conference call after three and 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 have accomplished in a relatively short period of time. Since I joined in January of 2020, the stock is 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’m 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 first hand, 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.

Jeremy Knop: 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 bullet proof 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 TILs 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 as a cracker as Shell works to bring it fully online.

Our pre unit adjusted operating revenues were $2.11 per Mcfe and 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 negative $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 1.6x 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 retiring with $800 million of incremental debt retired during the second quarter. This was comprised of the $300 million tender offer for our sixth 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 1.3x 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 a $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. The 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 towards 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 [MQ] future strip implies more than $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 balance 2023 local volumes covered with basis hedges that are solidly in the money relative to current strip. On MVP, we modeled a first half of 2024 in service date to acknowledge there could be some risk to the timetable based on the 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 supply in 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 mini producers breakeven 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, blending 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 listed 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% to 20% relative to the recent peak, and we should start to see the benefits of this beginning in late Q3 as we deplete our current inventory. For reference, deal 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 frac spreads. Given our focus on consistent execution of our combo development strategy, we lock in the bulk of our rigs and frac 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. And 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 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 to 2,000 Bcfe. Our 2023 capital budget of $1.7 billion to $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 outlook 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 was 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 we’ll 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 negative 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 1x 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 movement 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 that points in the cycle where we see favorable risk reward potential for generating returns well in excess of our weighted average cost of capital. And 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 3 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. However, despite these characteristics and strong relative stock performance recently, EQT trades at the highest five-year cumulative free cash flow yield as a percentage 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. Interestingly and 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, again, when measured by the next five years of cumulative free cash flow relative to enterprise value.

Whether investors fully appreciate this or not, is this cash flow is realized, it should drive our equity value higher by definition. And 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, and 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.

Toby Rice: 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 million 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.

And 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. And 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 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.

Operator: [Operator Instructions] Your first question is from Umang Choudhary of Goldman Sachs. Please go ahead. Your line is open.

Umang Choudhary: Thank you. And 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. I wanted to get your thoughts on capital efficiency improvement heading into 2024, given you recently – 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 early in the year?

Toby Rice: Sure. So a couple of things that will take place in 2024. We’ll see a little bit lower activity levels compared to 23%, and that’s as a result of just the catch-up activity that we added in 2023. So that would 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 going to be on service cost inflation reductions that we see. So we’re being conservative with that low single digits, but we’ll update that as the teams continue to procure bids. And obviously, at a stepping back, bigger picture, we’ve got Tug Hill, which will lower our cost structure. And then also, as a reminder, we say it every quarter, the step down in gathering rates will be impactful as well.

So 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 MACH3 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. We have taken some best practices and incorporated that into our well design program. And with the monitoring that we’ve done, we have tightened up the controls in our assessment to take these different parameters and make sure that we are applying the best for market conditions. So it’s been some practice 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. So we’ll keep everybody updated on that front.

Umang Choudhary: Got you. That’s very helpful. And 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?

Toby Rice: Yes. So at a very high level, what customers are looking for, they’re looking for energy security. And 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 this supply is tied to index pricing, it’s hard to see that energy security which only comes with cost controls and guardrails on pricing. So 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 fixed price collared floors and ceilings type price controls on the LNG and energy that they’re buying. So 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.

Umang Choudhary: Thank you.

Operator: Your next question is from Devin McDermott of Morgan Stanley. Please go ahead. Your line is open.

Devin McDermott: Hey. Good morning. Thanks for taking my question. And Dave, congrats again on the retirement. So 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?

Toby Rice: Well, conversations have been constructive with the FTC over the past 12 months, I’d say. But I think we said that – by the middle of this year, we’d have better insight on where this deal stands. And I can tell you today that we have confidence that we will reach resolution within the next 30 days.

Devin McDermott: Okay. Great. And then separately, on MVP, that disclosure on it being roughly cash flow neutral is helpful. But 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?

Jeremy Knop: Yes. There’s a couple of pieces to that. So 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. But at the same time, that triggers a gathering rate reduction and we’ll access more premium markets. And so net-net, as we’ve talked about before, that should really net the impact out. 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 65 will start to trade more like that Transco Zone 5 market. So if you look at what Cal 25 looks like in the basis markets today, Station 165 trades about $0.40 back and that Zone 5 market trades at a better about $1 premium to NYMEX.

And so it’s going to be an evolution of that market as those downstream projects are built out, but 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.

Devin McDermott: Great. Thank you.

Operator: Your next question is from Bertrand Donnes of Truist. Please go ahead. Your line is open.

Bertrand Donnes: Hey. Good morning guys. Just one of your peers have taken the approach that LNG exports will be about 15% to 20% of U.S. volumes, so they want to keep their contribution in that range. I just want to see if that matched kind of your internal strategy or does the tolling agreement if you have maybe let you pivot more easily and so you maybe could go above that percentage.

Jeremy Knop: The way we’ve talked about this historically is having that 1.2 Bcf a day of supply into that Gulf Coast market today. We will use a portion of that to sell into international markets, but we haven’t necessarily set any sort of guidance range like you described around it. I think we’ll be opportunistic depending on the facility depending on what the market provides us. Long term, I think we’d like to increase capacity to the extent it makes sense, but within a proper risk-adjusted framework.

Bertrand Donnes: Got you. And then my follow-up on the same topic is just kind of two smaller points. Does your ability to increase your capacity to the Gulf Coast have any impact on maybe the pace of additional LNG deals? And then the second part of that is just with a 15-year term on your side, did you want to match the end users agreements to that duration? Or do you maybe want to do five years here and there and add up to that 15 years? Thanks, guys.

Toby Rice: Yes. On the structure with the sales and purchase agreement, we would like to see parity with what we’re doing on the tolling side. And I would say just what’s going to govern the pace for us given the fact that we have ample exposure to the Gulf Coast and LNG, the pace is really going to be covered by the customers. And 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. So these are the conversations that we’re going to be having over the next 12 months that we’ve already begun, and that will come back and determine pace, and we’ll update you guys along the way.

Bertrand Donnes: Sounds good. I appreciate it.

Operator: Your next question is from Arun Jayaram of JPMorgan Chase. Please go ahead, your line is open.

Arun Jayaram: Yes. 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. And so I just wanted a sense is if you close in 30 days, do you expect it to be consistent with the original terms signed with Tug Hill.

Toby Rice: Yes. We expect to be closing within 30 days. And 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 and also preserve the strategic flexibility going forward. So it’s been a long process, but we see the light at the end of the tunnel, and we’re going to achieve our original goals.

Arun Jayaram: 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 MACH3 program, which is underway, 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.

Toby Rice: Yes, Arun, 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. And I think looking longer term, when you get the benefits of Tug Hill, you get the benefits of the lower gathering rates, overall corporate breakeven will continue to trend lower.

Arun Jayaram: Great. And I also want to pass on my regards to Dave, good luck in retirement. Great working with you over these years.

Toby Rice: Thank you.

Operator: Your next question is from John Abbott of Bank of America. Please go ahead, your line is open.

John Abbott: Hey. Thank you very much for taking our questions. And Dave, the BofA team wishes you also at the best of luck in your next adventures. Toby, like just – Toby, first question is really on West Virginia, you’ve mentioned other opportunities here for like improvements like water infrastructure between West Virginia and PPA. Could you characterize the number of opportunities are we talking about, too, how do you see potential cost versus the $80 million that you spent previously, maybe there has been some sort of cost inflation? And just how quickly would you want to be go after these types of opportunities? Are we looking at 2024, do you want to see some deflation? How should we think about that?

Toby Rice: Well, I think what’s special about West Virginia is the terrain and logistics become very important. And so to solve logistics constraints, investing in infrastructure is the solution. And so 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 going to expand our produced water network, but also freshwater delivery. So we’re excited about continuing with the progress on the water side.

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Jeremy Knop: 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. So think about that as like a 25% free cash flow yield. And that’s something that – it’s not like a well that declines, it’s durable. It’s got longevity to it for the next 10 to 15 years. Some of the other projects we’ve looked at recently, one of which we highlighted when we announced that Tug Hill acquisition, was additional pipeline connectivity throughout the basin. We’re seeing similar sorts of returns on those projects at kind of a mid-20% free cash flow yield. The more projects like that we can find to reinvest capital into the more value we think we can create both through reinvesting and compounding but also just improving the base quality of the business.

So it’s something we’re focused on. We’ve got the operational teams looking around trying to find more opportunities to reinvest cash flow like that. But I mean, those are two examples just to make it a little more tangible.

John Abbott: Appreciate it. And the second question is on MVP. Assuming it comes online, maybe you can’t – maybe if the basin can’t necessarily grow into all at once. But 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 that you want to just stay flat? How do you think about that capacity?

Toby Rice: Yes, 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. 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. There’s not a lot of headroom, we think MVP coming online. We’ll 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.

John Abbott: Appreciate it. Thank you very much for taking our questions.

Operator: Your next question is from Scott Hanold of RBC Capital Markets. Please go ahead, your line is open.

Scott Hanold: Yes. Thanks. Hey, Toby. You obviously have some confidence in seeing the Tug Hill closing it sounds with a lot of the economics and kind of non-negotiables that you wanted. Can you talk about more specifically though, your view on further consolidation within the basin beyond that? Because I know that was the strategy a few years ago to generate more shareholder value. Do you see any limitations based on your conversations with the FTC to do much beyond the Tug Hill deal?

Toby Rice: 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.

Scott Hanold: Okay. Understand. And then on the LNG tolling agreement, I think that you indicated some of the things that 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 do you see as in terms of 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.? And does that also mitigate the need for you all to hedge those volumes when you do have some coloring on the pricing?

Jeremy Knop: Yes. So let me answer it this way. Getting these deals in place is a multi-step process. Signing the HOA is the first step in that. 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, that is still our intention.

Scott Hanold: Thank you.

Operator: Your next question is from Michael Scialla of Stephens. Please go ahead. Your line is open.

Michael Scialla: Yes. 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. But I want to see how you guys are viewing the market in the second half 2024 and into 2025. I guess it sounds like you would stay lightly hedged there given the incremental LNG capacity. Is that fair?

Jeremy Knop: Yes. So there’s a couple of dynamics at play. And 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 SKU is. And so 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 SKU. And so that’s why you’ve seen us lean a little bit more into swaps, even though it’s something we’re generally trying to deemphasize in the past. Unless we see strong cost SKU in the options market, it’s hard to feel good about leaning into those. But really near-term because that we would like to derisk our debt repayment goals and so 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 want to remain patient there and hedging more near-term allows us to do that. So look, it doesn’t mean we’re not going to hedge 2025 at some point, but we think where the market sits today, it’s far off from where really it should be. And as you think about how the market might trade as you get into 2024, I think most market participants and analysts see that how 2025, 2026 market is getting especially tight as you see that demand ramp for at least – ramp in nameplate capacity of LNG, but the market obviously trades the season ahead. And so 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 will probably start getting reflected next summer and probably a much more asymmetric way. And so 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.

Michael Scialla: That makes sense. Thank you. And 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. And 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?

Toby Rice: Yes. 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 just take some time for us to set those wheels in motion. But pretty much in summary, similar plans for the first 12 months and then you could start seeing us optimize the asset base.

Michael Scialla: Thank you, guys.

Operator: Your next question is from Josh Silverstein of UBS. Please go ahead. Your line is open.

Josh Silverstein: Yes. Thanks. Good morning. Congrats to Jeremy and David as well. Just on the LNG front, I know you’re 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 kind of vertical change, so to speak, there?

Toby Rice: Yes, Josh, we’ve always looked at investing in LNG facilities does the world need it to do that right now? It seems like these projects are getting going, what the world needs is EQT supply, so we’re participating in that front. So our price 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. So we’re not 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 LNG facility, but that’s sort of how we’re viewing it right now.

Josh Silverstein: Got you. Yes. I was just wondering if there’s an investment to be made, maybe it pushes through the Lake Charles facility a little bit faster. So it was referring from that angle.

Toby Rice: No. I think just when we looked at 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.

Josh Silverstein: Got it. That’s helpful. And then, Jeremy, you mentioned 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 you kind of getting towards, call it, a formal 50% kind of split between balance sheet reduction, shareholder returns? Do you want to hit a certain debt level before you kind of commit to that? So I’m curious how you’re thinking about the shareholder return profile going forward?

Jeremy Knop: Yes. So 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. So 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. And then tactically, when we see dislocations in the market lean into that buyback. But I think the concept of a formulaic programmatic buyback. It’s just a long-term strategy. It’s something you’ll see us probably shy away from at least near-term. 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 continued opportunities to create outsized value for patients just like we’ve done to date.

Josh Silverstein: Great. Thanks, guys.

Operator: Your next question is from Paul Diamond of Citi. Please go ahead. Your line is open.

Paul Diamond: Thank you. Good morning, everyone. Thanks for taking the 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. 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 a step change in the future or more incremental? And also as far as like others catching you, is that to keep running in place? Or is that a gap you think you can really maintain.

Toby Rice: Yes. The goal for us is to 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. So that’s the game 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. And this is the fire that keeps us continuing to evolve and look for ways to continue raising the bar. So we’re proud of where we’re at, but we’re always looking to get better. And that’s really – I’d say one of the defining characteristics of our culture is just our ability and the drive to continually evolve our business.

Paul Diamond: Understood. Thanks.

Operator: Your next question is from Jeoffrey Lambujon of TPH. Please go ahead. Your line is open.

Jeoffrey Lambujon: 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, but just wanted to get a sense for if any of the savings here from these opportunities would be incremental to that $0.15 breakeven improvement that you all have highlighted in the past.

Jeremy Knop: Yes. So that $0.15 that we talked about associated with the deal. That’s all pre-synergies. This kind of as a rule of thumb. We don’t like to include synergies and just our base guidance. So think when we announced Tug Hill, we were talking about $80 million a year of total synergies. We haven’t been able to refine that just due to some gun jumping laws around just this FTC process. But 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.

Jeoffrey Lambujon: Okay. Great. And then maybe going back to MVP and potential infrastructure downstream. I imagine D&E in particular on that slide will be relatively important from a pricing standpoint. But be great to get any thoughts that you can share just on the projects that we show there and how you’re thinking about the potential impacts to your marketing or regional mix as those get developed?

Jeremy Knop: Yes. We see most of those projects as more demand pull back rather than supply push. So 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.

Jeoffrey Lambujon: Thank you all.

Operator: Your next question is from Noel Parks of Tuohy Brothers. Please go ahead. Your line is open.

Noel Parks: Hi. Good morning. I just wanted to go back to the project swapping out the pneumatics. And I just wondered, could you give us a sense as to what sort of the scale of that overall cost was looking back?

Toby Rice: It is about $28 million. And when you think about it, normalize on a dollar per ton, it’s less than $10 per ton to achieve the emissions reductions.

Noel Parks: Great. And 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 Tug Hill 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?

Toby Rice: I don’t think there’s any elements that are unique here that stand out. I think this is just part of the process to review the deal and concept. I mean, I’d just remind everybody when the FTC issued their second request to us who was back in November. And I think if you just remember what the gas market was like, there was a lot of concerns over a natural gas, what was happening with Europe and peak fear on gas shortages. So I think we 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 in close within the next 30 days.

Noel Parks: Great. Thanks a lot.

Operator: Your next question is from John Daniel of Daniel Energy Partners. Please go ahead. Your line is open.

John Daniel: 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?

Toby Rice: 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 going to be hard to replicate with other asset bases. But you got to go out there and you got to execute and the teams are doing that. We have very close relationships with our service providers. I think on this run here, there’s been a lot of improvements on bit design that the teams have worked with our service providers. So really close relationship and our success is really going to be based on the success of our partnerships, and we’ve got some great partners on the drilling front and across the operational spectrum. So I’d say probably half of it is internal, and the other half is the great working relationship we have with our service providers.

John Daniel: Okay. Thank you. And then the second one for me is 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 analysts such as myself, are we fooling ourselves when we propose a rising rig count in future years? Are we going to see these efficiencies render data a lot of reality…

Toby Rice: Yes. I mean when I step back and you look at the – I mean we’ve sort of gotten past the step change in operational efficiencies. It’s more of a slow grind and the factors that are ultimately going to be defining the success of the operation, we sort of pushed past just what specifically we’re doing on site at that operation, and 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? And on the completion side, what’s the logistics on water and sand. So it’s as much as the system that we’re creating as it is the actual individual performance. And I think industry has already made the move to recognize that long laterals are the key and how much of that they have and the quality of inventory, I think, is going to be defining characteristics on their efficiency going forward.

John Daniel: Fair enough. But what you reported, it seems like a step change better to me. So maybe I haven’t been paying attention, but that’s pretty impressive. Thank you for including me on the call.

Operator: There are no further questions at this time. I will now turn the call over to Toby Rice for closing remarks.

Toby Rice: 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.

Operator: This concludes today’s conference call. Thank you for your participation. You may now disconnect.