Hello and thank you for standing by. My name is Regina and I will be your conference operator today. At this time, I would like to welcome everyone to the EQT Fourth Quarter 2023 Quarterly Results Conference Call. I would now like to turn the conference over to Cameron Horwitz, Managing Director of Investor Relations and Strategy. Please go ahead.

Good morning and thank you for joining our fourth quarter and year end 2023 earnings results conference call. With me today are Toby Rice, President and Chief Executive Officer and Jeremy Knop, Chief Financial Officer. In a moment, Toby and Jeremy will present their prepared remarks with a question-and-answer session to follow. An updated investor presentation has been posted to the Investor Relations portion of our website and we will reference certain slides during today’s discussion. A replay of today’s call will be available on our website beginning this evening. I’d like to remind you that today’s call may contain forward-looking statements. Actual results and future events could materially differ from these forward-looking statements because of the factors described in yesterday’s earnings release, in our investor presentation, the Risk Factors section of our Form 10-K and in subsequent filings we make with the SEC. We do not undertake any duty to update any forward-looking statements. Today’s call also contains certain non-GAAP financial measures. Please refer to our most recent earnings release and investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. With that, I will turn the call over to Toby.

Thanks, Cam and good morning everyone. Coming into 2023, I sat down with our leadership team and we set our overarching corporate mission and goal for the year with two simple words: peak performance. I wanted our fourth year since the takeover of EQT to be our best one yet and the crew certainly came through in delivering on that mission. I want to take a few moments to briefly reflect on the incredible accomplishments from this organization that we achieved over the course of 2023. On the operations front, we set multiple drilling world records and achieved our highest completion efficiency pace ever, with 2023 monthly pumping hours per crew up more than 15% year-over-year. Importantly, this incredible operational pace came amid a 22% improvement in our 2023 EHS intensity, which was even better than our 15% target and underscores our unwavering commitment to safety at EQT. On the financial front, despite a challenging natural gas price environment, EQT generated nearly $880 million of free cash flow in 2023, retired north of $1.1 billion of debt and raised our base dividend by 5%. This financial performance is a clear demonstration of our advantaged position at the low end of the North American natural gas cost curve and highlights that EQT is poised to thrive regardless of where we are in the commodity cycle. On the M&A front, we closed on the strategic acquisition of Tug Hill and XcL Midstream and integrated the assets at a record pace. Our team has wasted no time driving material operational performance improvement on the assets, with the latest EQT operated Marcellus drilling costs coming in more than $200 per foot or nearly 55% lower than Tug Hill operated wells. This recent performance suggests the potential for even more upside than the $150 per foot of well cost savings we discussed last quarter, which as a reminder, is additive to $80 million of largely infrastructure-related synergies we originally announced with the deal. On the marketing front, EQT’s low-cost peer leading inventory depth and environmental attributes enabled us to sign the largest long-term physical supply deals ever executed in the North American natural gas market with some of the country’s leading utilities. With much stronger than expected power generation growth in many regions of the United States and natural gas providing the ideal low-carbon dispatchable complement to renewable generation, we expect gas-fired power demand will surprise the upside over the coming decade and EQT’s unique ability to meet this demand should result in additional margin capture opportunities moving forward. We also made material progress executing on our differentiated LNG strategy, leveraging our significant Gulf Coast firm transportation capacity to sign HOAs covering 2.5 million tons per annum of LNG tolling capacity or roughly 5% of our total natural gas production. Our more integrated approach to LNG exposure compared with peers gives us direct connectivity to end users of our gas globally and we have seen strong interest from prospective international buyers. While there has been some noise around LNG permitting of late, the outcome of COP28 demonstrates the world has spoken deeming natural gas as critical in facilitating the energy transition while ensuring energy security. It is abundantly clear that nations around the world currently powered by coal desperately want and need greater access to natural gas and ultimately political posturing will reconcile with this reality if we, as a society, are truly intent on achieving global climate goals. On the ESG front, we announced a first of its kind public-private forestry partnership with the state of West Virginia, which will create one of the highest quality most verifiable nature-based carbon sequestration projects anywhere around the globe. We have already seen solid momentum on this project to date and we are incrementally confident in EQT’s ability to become the first energy company of meaningful scale in the world to achieve net zero Scope 1 and 2 emissions. This impressive list of achievements is a showcase of what is possible when you combine a world-class asset base with an industry-leading digitally enabled team underpinned by a culture of excellence and teamwork. Turning to our reserve report. EQT’s 2023 proved reserves totaled 27.6 Tcfe, which was up 2.6 Tcfe relative to 2022, largely driven by additions from the Tug Hill acquisition. Importantly, even with the SEC price deck dropping from over $6 per million Btu at year-end 2022 to $2.64 at year-end 2023, EQT’s proved reserves prior to the impact of Tug Hill were slightly higher year-over-year, underscoring the economic resiliency of our world-class low-cost Appalachian reserve base. Within our proved undeveloped reserve category of roughly 8 Tcfe, we have just 417 gross locations booked or roughly 3 years of development, representing only 10% of our derisked inventory of nearly 4,000 gross locations. It’s also worth highlighting that we estimate an additional 2 Tcfe of reserves not captured in our bookings associated with our non-operated position in Northeast Pennsylvania as we book limited PUDs on this asset, given we only have timing visibility out 3 to 6 months. Additionally, we’ve taken a conservative stance with limited reserve bookings for Tug Hill’s go-forward Utica inventory in West Virginia, which should be a source of reserve upside over time. Using the year-end 2023 SEC price deck of just $2.64 per million BTU, the PV-10 of our proved reserves is approximately $12 billion. Assuming recent strip pricing, this value jumps to almost $23 billion. And again, this ascribes credit to just 3 years or 10% of our remaining inventory. I’d also note our reserve valuation is calculated prior to the impact of our firm transportation portfolio to the value accruing to EQT for marketing arrangements like the MVP firm sales contracts we announced last quarter are incremental to these PV-10 values. We see the consistency and economic resiliency reflected in our reserve report as an important channel check for investors that highlights EQT has among the highest quality, lowest cost natural gas asset base anywhere in the world. Looking to 2024, we are initiating 2024 production guidance of 2,200 to 2,300 Bcfe, which includes some flexibility to curtail volumes should natural gas prices remain weak. Our program contemplates running 2 to 3 rigs, 3 to 4 frac crews and turning in line 110 to 140 net wells. As shown on Slide 6 of our investor deck, this activity level juxtaposed against our large production base underscores the incredible capital efficiency and quality of our assets, as EQT is generating the most gross-operated production per rig of any natural gas operator in the United States by a wide margin. Looking at our spending profile, we are setting a 2024 maintenance capital budget of $1.95 billion to $2.05 billion, including maintenance, land and infrastructure spending. We have also tactically allocated $200 million to $300 million for strategic growth projects across water infrastructure, gas gathering and land that are opportunistic in nature and highly symbiotic with our upstream operations. Jeremy will give more details later on, but these projects generate the best risk-adjusted returns in our portfolio, derisk our upstream execution, allow us to replenish inventory at extremely attractive costs and facilitate the compounding of capital for shareholder value creation. At the midpoint of our maintenance capital and production guidance ranges, our implied 2024 maintenance capital efficiency equates to $0.89 per Mcfe and our unhedged maintenance NYMEX free cash flow breakeven is $2.50 to $2.60 per million Btu. With contractual gathering rate reductions, the shallowing of our base decline, improving basis from the firm sales arrangements we announced last quarter and reductions in interest expense, our all-in NYMEX free cash flow breakeven price should be on a glide path down towards $2.30 per million Btu over the next several years. We believe this economic profile is in a class of its own relative to the rest of the industry, where we expect to see upward pressure on cost structure over this period associated with operators shifting to lower quality inventory in both the Haynesville and parts of Appalachia. This differentiation is highlighted by the fact that we project EQT will generate cumulative free cash flow of almost $9 billion over the next 5 years at a natural gas strip that averages approximately $3.40 per million BTU over this period. This gas price is roughly equivalent to the fully loaded corporate marginal cost of supply in the U.S. required to simply breakeven from a free cash flow perspective, let alone to generate returns for shareholders. Said another way, higher cost natural gas producers will at best generate no shareholder value at the current strip over the next 5 years, while EQT is set to generate more than 40% of our enterprise value in free cash flow over the same timeframe. This stark contrast underscores why cost structure is our North Star at EQT and why we strive not to be the biggest, but to be the highest quality, most resilient company that can generate durable free cash flow both in up cycles and in down cycles. This is the essence of sustainability and value creation in a commodity business. And we believe our shareholders are uniquely positioned to reap the rewards of EQT’s unrivaled combination of scale, peer-leading low-cost inventory depths and best-in-class emissions profile. I will now turn the call over to Jeremy.

Thanks, Toby and good morning, everyone. I’ll start by summarizing our fourth quarter results, which highlight our operational momentum as we closed out the year. Sales volumes of 564 Bcfe was toward the high end of our guidance range, reflecting continued best-in-class execution from our drilling and completion teams, along with strong well performance. Our per unit adjusted operating revenues were $2.75 per Mcfe, and our total per unit operating costs were $1.27 per Mcfe, which were at the low end of our guidance range driven by lower-than-expected LOE and G&A expenses. It’s worth noting that we outperformed LOE expectations every quarter in 2023 with total absolute LOE coming in $40 million below our internal forecast, driven largely by more efficient water handling facilitated by the investments we’ve made in water infrastructure. Capital expenditures were $539 million, which were in the lower half of our guidance range, reflecting the operational efficiency gains Toby mentioned previously. Turning to the balance sheet. Last month, we completed several transactions that eliminated debt, reduced interest expense, simplified our balance sheet and established an important 10-year pricing reference point, which is the longest dated bond outstanding of our natural gas peers and underscores the market’s confidence in our inventory duration. First, we retired all outstanding convertible senior notes due in 2026, which eliminated more than $400 million of absolute debt. Recall, our fully diluted share count already included the shares associated with our convertible notes. We simultaneously liquidated the capped call that we had purchased in conjunction with the issuance of the convertible notes for cash proceeds of $93 million. Pro forma the convertible note retirement, our total debt outstanding is currently $5.5 billion, which equates to a 1.6x leverage when annualizing fourth quarter adjusted EBITDA. Following the convertible note settlement, we executed a highly successful $750 million 10-year bond offering last month, the proceeds of which we used to pay off 60% of the term loan that we borrowed in conjunction with the closing of the Tug Hill and XcL Midstream acquisitions. We saw extremely strong demand from the credit market with a peak order book of almost $6 billion and the bonds pricing at a tight 1.65% spread to comparable U.S. treasury rates, which is similar to credit spreads of many of the highest quality large-cap companies in the broader energy sector. In conjunction with the bond offering, we also extended the maturity of our remaining term loan from mid-2025 to mid-2026, providing ample flexibility for maturity management moving forward. In terms of capital allocation, we will continue to prioritize debt pay-down until we achieve our $3.5 billion gross debt target. Our capital allocation philosophy is underpinned by an unwavering focus on establishing a fortress balance sheet, countercyclical and opportunistic share repurchases and a steadily growing base dividend. This long-term focused value investing framework has received resounding support from our increasingly high-quality shareholder base, and we will continue to allocate capital in accordance with this first principles framework. Looking ahead to 2024, we are setting an annual production guidance range of 2,200 to 2,300 Bcfe, which is underpinned by a fully loaded maintenance capital program of $1.95 million to $2.05 billion. Additionally, we are investing $200 million to $300 million into several strategic growth projects in the form of midstream and water infrastructure and infill land capture this year. These opportunistic investments are significantly value enhancing, and I want to take a moment to highlight the merits of each of these. The acquisition of XcL Midstream last year created a full-service midstream platform within EQT. And through this platform, we are already sourcing proprietary opportunities that generate strong risk-adjusted returns and robust free cash flow yields, even superior to those of our core Marcellus wells, while at the same time derisking our upstream operations. As shown on Slide 10, we are investing in three Midstream growth projects this year, comprised of the Clarington Connector, the OakGate Pipeline and the Pacific Coast Compression project. The combined capital associated with these projects is approximately $115 million. And once fully operational, these projects should generate aggregate annual free cash flow of nearly $50 million in the form of superior price realizations. This implies these investments will generate an aggregate free cash flow yield of nearly 40%, which is extremely attractive given the absence of price risk and the annuity-like cash flow profile over a 20-year asset life. We forecast a total return on investment of roughly 8x and the aggregate net present value of these projects is estimated at $250 million, implying value creation for shareholders equivalent to roughly $0.60 per share. Despite only having this Midstream business for just 6 months, these initial projects provide a glimpse into the long-term opportunity we see for this new business line. Reinvestment opportunities of this quality only come about because of the symbiotic relationship between our midstream and upstream teams working in alignment together. We believe this approach to growing shareholder value is differentiated among peers, especially in a $2 gas world, and intend to cultivate this platform so that it becomes an even more impactful driver of shareholder value creation over time. Within our reserve development CapEx, we’ve also allocated $80 million to expand our existing water infrastructure assets in West Virginia. As shown on Slide 12 of our investor deck, we expect 2024 investments into our water infrastructure to drive annual savings of $20 million, implying a 25% free cash flow yield on our invested capital. Our EQT-owned water system has materially increased the amount of water produced that we can recycle, which is having a tangible impact on our cost structure as demonstrated by our LOE coming in below forecast every quarter last year, translating to $40 million more free cash flow than originally forecasted. Turning to land. We have roughly $100 million allocated to opportunistic infill leasehold growth in mineral acquisitions this year. As shown on Slide 13 of our investor presentation, opportunistic leasehold additions organically replenished 65% of the acreage that we developed over just the past year, which is a pace of replenishment that can materially expand our years of inventory when aggregated over time. We believe this ability to organically backfill developed inventory is a unique feature among U.S. shale plays that largely exists only within Southwest Appalachia due to the land configuration and historic development activity. We are seeing notable opportunities to add to our acreage position at extremely attractive prices this year given the low commodity price environment, which we were able to capture due to our strong financial position. To put into context, the value creation potential of deploying leasehold capital, we highlight a very tangible example on Slide 13 of our investor presentation. In 2022, we infilled leased acreage and increased our working interest by 18% in our Polecat North development located in Greene County, which we brought online last year. The incremental interest we added in this project through organic leasing is projected to generate a 90%-plus free cash flow yield in year 1 alone and nearly 55% of annual free cash flow yield over the first 5 years and a return on invested capital of roughly 7x at strip pricing. This example highlights why we see these tactical land expenditures as an extremely attractive reinvestment of capital while simultaneously extending inventory duration, which can, in turn, help facilitate additional strategic initiatives such as signing long-term supply agreements. A key point I want to leave you with on these growth projects is whether it’s land capital, infrastructure investments, our acquisition strategy, long-term agreements with utilities or our base upstream business, we are incredibly intentional about aligning these decisions to ensure they symbiotically work together to enhance each other and collectively result in optimal risk-adjusted compounding of shareholder capital in the decades ahead. In essence, this is the definition of terminal value. And through building a successful track record of these decisions, we expect this to be reflected in our stock price. Lastly, I want to quickly touch on our cost structure guidance given the moving pieces with the imminent startup of MVP. We are guiding full year transmission expense to $0.42 to $0.44 per Mcfe, which is up approximately $0.10 year-over-year driven by the costs associated with MVP. This is partly offset by an accompanying contractual step-down in our gathering rates, which we forecast to be in the $0.52 to $0.54 range for 2024, down from roughly $0.65 in 2023. Within our 2024 corporate differential guidance of $0.50 to $0.70, we conservatively assume EQT flows only a portion of our MVP capacity due to downstream limitations at Station 165. In the winter months, we should be able to flow at higher rates on MVP and realize a greater premium on downstream pricing. Thus, the cash flow uplift associated with MVP will be seasonal in nature until downstream expansion projects come online. It’s also worth highlighting that we have roughly 500 MMcf per day of our Station 165 pricing exposure hedged through financial instruments and firm physical sales through 2025, which provides downside protection should there be any further price pressure downstream of MVP over the next few years. With nearly 2.5 Bcf per day of upcoming project expansions at Station 165 and significant demand pull from the Southeast region, our ability to flow volumes on MVP and associated realized pricing should progressively improve over the coming years culminating in the commencement of our firm sales contracts in 2027 that are projected to improve our corporate-wide differential by $0.15 to $0.20, driving a $300 million-plus uplift in annual free cash flow generation. Turning to Slide 11 of our investor presentation. We announced the proposed acquisition of an additional 34% ownership in the EQT operated Seely and Warrensville gathering system in Northeast Pennsylvania for $205 million in cash, and we currently expect the transaction to close in late Q1 or early Q2. EQT currently owns 50% of this gathering system. So our pro forma ownership will increase to 84% based on terms agreed to in the purchase agreement, subject to the potential exercise of certain preferential purchase rights. Recall, this gathering system was part of the Alta acquisition we completed in 2021, which has been a significant source of value creation for EQT. The purchase price implies we are acquiring these assets for a double-digit free cash flow yield, underscoring how this deal allows us to reinvest capital into durable, long-lived infrastructure at an attractive rate of return with near zero execution risk, given we operate both the system and the upstream development underpinning the assets. Consistent with our broader strategy to reinvest capital into assets that improve our corporate cost structure, our greater ownership in the system will immediately lower our overall free cash flow breakeven price by more than $0.01 per Mcfe upon close. We are currently looking at ways we can shift even more development activity onto this system over the coming years, which could drive additional upside to the transaction. Moving to hedging. We tactically added to the front end of our 2024 hedge position earlier this year, leaning into the price spike that occurred ahead of the winter storm in January. We have now greater than 50% of our first quarter 2024 production volumes hedged with a weighted average floor price of $3.87 per MMBtu, which has derisked a significant portion of our free cash flow outlook for the year. We have nearly 50% of our second quarter production hedged with a weighted average floor of $3.39 per MMBtu. And roughly 40% of our Q3 production covered at a weighted average floor price of $3.42 per MMBtu. Additionally, we’ve recently added some 2024 winter hedges, taking our fourth quarter hedge coverage up to more than 20% with a weighted average floor price of $3.47 per MMBtu. Turning to Appalachian. Basis differentials were relatively wide during the fourth quarter, driven by an elevated Eastern storage level and rising production associated with multiple operators completing wells that were deferred from earlier in the year. Our strong basis hedge position again paid dividends this quarter, boosting our corporate-wide realized natural gas price by $0.08 per MMBtu. As it relates to the increase in Appalachian supply, after peaking at just under 37 Bcf per day in December, production in the basin has fallen by roughly 1.5 Bcf per day, and we anticipate further declines in the Appalachian supply through the second quarter. On the local demand side, it’s noteworthy that PJM recently doubled its 15-year annualized load growth forecast from 0.8% to 1.6%. This equates to nearly 7 gigawatts of additional power demand by 2027, in more than 10 gigawatts by 2030, which, if satisfied by natural gas, would translate to nearly 2 Bcf per day of additional local demand by the end of the decade. This trend of increasing local demand juxtaposed against a relatively flat basin supply and the commencement of MVP should provide a structural tailwind for local pricing over the coming years, which we do not believe is currently priced into the basis futures market. As it relates to Lower 48 supply, it’s worth highlighting that a prominent data vendor revised its year-to-date supply estimates downward by 1 to 2 Bcf per day this week. We had suspected certain data sources were overstating production, and this downward revision validated the market is not as oversupplied as many previously thought. Assuming production simply stays flat at the current revised level and weather is normal through the injection season, end of summer gas storage will be roughly in line with the 5-year average level. I’ll close by sharing a few philosophical thoughts on what we believe it takes to not only survive but to thrive as a natural gas producer and a macro backdrop that we expect will be characterized by unpredictable volatility for the foreseeable future. The real long-term winners in this business will not be the biggest companies that gain scale simply for the sake of scale, but will instead be the companies that have a corporate cost structure that is currently and in the future at the low end of the cost curve. A low-cost structure is the only competitive advantage one can have in a commodity-driven business, which is why it is our North Star and drives nearly all of our strategic decision-making. While we are believers that future natural gas prices will be higher on average, we do not believe that prices will be stable at the $4 to $5 level, like the prevailing consensus view. And building a business around this assumption of average prices is likely to end poorly. Until we return to a world where we can build necessary domestic infrastructure, we believe we are more likely to see prices either around the $2 level they are today to force high-cost producers to curtail production and activity or materially higher to curtail demand, as pricing becomes the only variable left to balance natural gas inventories. Said another way, we believe in an increasingly fat-tailed distribution of outcomes. That is a critical distinction, and we’re already seeing the manifestation of this dynamic with prompt month pricing at this moment. However, EQT is at the low end of the cost curve and will be moving even further down the cost curve over the next 5 years due to our contractual gathering rate reductions and long-term MVP firm sales agreements. This outcome is by design as our philosophy toward creating value in a cyclical, volatile commodity business has underpinned every one of our strategic decisions over the past several years. The culmination of these decisions has created a unique opportunity for investors to deploy capital into the preeminent natural gas platform that is positioned to generate peer-leading shareholder value through all parts of the commodity cycle over the long term. And with that, we will open the call to questions.

Our first question will come from the line of Arun Jayaram with JPMorgan. Please go ahead.

Yes. Good morning, team. I wanted to see on Slide 9, you highlight your views on maintenance CapEx and strategic growth CapEx and you compared it from 2024 relative to a 2025 to ‘28 outlook. Jeremy, I was wondering if you can maybe help us think about the trajectory of that spend? How does 2025 look versus ‘28? And maybe just some thoughts on midstream CapEx under this outlook because that was a clear focus of today some of the strategic midstream investments that EQT is making.

Yes, absolutely. So we’ve assumed in our go-forward forecast and our 5-year outlook, about $150 million per year, which is kind of a loose bucket we’ve assigned. I wouldn’t say it’s entirely defined through that forecast, but that’s our broad assumption, which is what’s reflected on that slide. There is a little bit of carryover on this Clarington Connector project into 2025, but I would say that expectation for spending is within that bucket. I mean look, I think these sort of spending projects, it’s not something that necessarily will be recurring. But look, if we see great opportunities that make our business better, sometimes it costs a little bit of money to invest and actually capture that price and that value. That’s what you’re seeing us do in 2024. There’ll be years, we probably don’t spend any of that capital and other years where we spend a little bit more.

That’s absolutely helpful. Second question. Give us some thoughts on the glide path on the $2 billion deleveraging target. There have been some recent press reports on EQT, potentially looking at selling your non-op piece in Northeast PA. I don’t know if this is a great environment to be selling assets. I was wondering if you could comment on maybe some inorganic opportunities to delever, call it, in a big bang type of approach.

Yes. Look, obviously, with the volatile commodity price environment, even a month ago, the outlook when the strip was at $3 is different than where the strip is today, closer to $40. So it’s, in many ways, organically, it will depend on just where the strip settles. We continue to be really bullish the next 6 to 9 months might be a little bit bumpy. But I think we continue to have the view, and I think you’re starting to see it from some of the earnings guidance already coming out this quarter. Really a curtailment in activity today is just going to really amplify the upside, I think, as we get into next year. So we remain well positioned to capture that. I think as much as really anybody. In terms of inorganic ways to de-lever, I mean, look, we – for the right price, we’re a seller of anything, right? I mean our focus and our North Star is really just creating shareholder value if there is an opportunity to do that. Certainly, I think when we started thinking about rationalizing the portfolio in Q4, we were looking at a $350 strip. So the process for executing on that might be maybe a little bit delayed. But I would say there is a renewed interest really across the market in non-operated assets, really from international players who have interest in having exposure to U.S. gas, and I think we’ve seen a little bit of this recently, but don’t want to actually have U.S. operations. So we really started exploring that because of inbounds we got. And I think a lot of those buyers are a little less price sensitive than some of the buyers domestically. So look, we – anything we do, it certainly is not defensive, it would be opportunistic. And I’d say we’ve seen some really good interest on the asset. I think it values that certainly do not reflect strip pricing. So we will remain opportunistic, but it’s something that could happen near-term. It could happen a year from now. But it’s just part of our continued effort to not necessarily just chase scale, but really chase quality and what creates the most value.

Great. I will turn it back. Thanks.

Your next question comes from the line of Sam Margolin with Wolfe Research. Please go ahead.

Hey, good morning, everybody. Thanks for taking the question.

Good morning.

Thanks for the detail on your activity plans for ‘24. As always, that’s a recurring slide. My question is the ranges of the number of wells that you drill and complete and turn to sales are the same range, but they are not necessarily aligned on either end. And so when you think about how you execute within those ranges, do they move together on a one-to-one basis? Or is there a scenario where you drill 120 wells, you complete 120 wells and you turn 120 wells in-line. And you have no change in sort of your DUC backlog or your deferred TILs?

Yes. So to provide some more color on the numbers we put out there, I mean there is a mix of wells that are – not all the numbers are the same for what we spud to what we horizontally drill, complete and what we ultimately turn in line. When we put those numbers out – when we have to pick a number, it’s typically the TIL. And so there will be a little bit of a range there to account for some flexibility. If we see a more compelling opportunity in ‘25, we could pause on some of the TIL activity.

Okay. That makes sense. And then, I mean, this is sort of a follow-up to those ranges. They are designed, I guess, to correspond to a number of different market outcomes. I mean what’s the market condition where you might materially change those ranges and bring down activity levels below where you’ve been running? Obviously, as you can imagine, that’s an inbound question I think all of us get from investors. Thanks.

Yes, Sam. It’s something that I think we, like every one of our peers, is probably thinking about every day right now. I mean you look at the prompt price in the $160s. The market is asking for not only production curtailments, but also activity reductions. And look, if you look at our – even our production guidance that we gave in that bond prospectus in mid-January, you’ll notice we’ve reduced that range by about 50 Bcfe. I would characterize that as a response to the price environment we’re in and wanting to make sure there is flexibility. So EQT can respond and make sure that if price gives a signal for lower activity and in lower production, we stand ready to respond.

Understood. Thank you so much.

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

Hey, good morning. And thank you for taking our questions. Our first question is really on your 5-year cumulative free cash flow outlook. You mentioned $9 billion. And that’s lower than you gave in the third quarter. Obviously, that’s part of lower commodity prices. But when you think about those two outlooks, has there anything really changed on the cost side in terms of assumptions? And anything particularly moved when you look at those two projections?

No, John, there have been no changes. I don’t think of any material consequence aside from pricing.

Alright. And then the other question here is really all related to your long-term gas differential. Where do you think your differential sort of – if you sort of look at strip pricing, where do you think it is from 2027? And then Jeremy, you sort of went out there and you suggested that in-basin demand should improve over time, and that’s not reflected in current differentials. Where do you think that could potentially move?

Yes. So if you look at just the EQT forecast, the midpoint of our range is that $0.60 level for differentials for this next year. If you look at where we end up in 2028 with the expansion projects in-line and just at current strip pricing, our realized differential will be about $0.50. So our differential on average drops about $0.10 from where we sit today to really the back end of that 5-year guidance range. I mean, look, when you think about the in-basin demand dynamics, I think what we’ve highlighted could add potentially up to 2 Bs a day of demand in-basin, some of that might be taken by renewables, so call it 1 to 2 Bs net to gas. And then the MVP downstream expansion projects come online, too. I mean that’s going to fully utilize MVP. And I actually think from conversations we’re having, there is probably likelihood MVP gets expanded by another half B a day. At EQT, we stand ready to really be a supplier of that to support that project. I think there is ample demand in that southeast market with data center build-outs really underpinned by the AI revolution right now and population growth in that area that’s really pulling on gas for just absolute power demand increases in addition to core retirement. So it’s power, I think, in our view, as you look towards the end of this decade is increasingly becoming, I think, as bullish of a thematic tailwind as really LNG, and we will probably take the torch from LNG in the coming years. And so I think that dynamic really – when you couple all those dynamics and themes together and I think you really see a really healthy backdrop for Appalachia. And I think certainly, as you see some operators start to run thin on inventory in the basin, I think it provides opportunity for companies like EQT to not only capture better in-basin pricing but actually really grow our own production into that and take a bigger share of the pie. So we – that’s really our expectation over the next couple of years. We stand ready to respond to it, but we see it really more as a tailwind than a headwind.

Very, very helpful. Thanks for taking our questions.

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

Good morning, guys. Thanks for taking my questions. I was hoping just to dig in a little bit more on just Arun’s question. I think you will highlight the lower implied maintenance CapEx going into ‘25 and beyond. I guess if we think about that delta of – I guess, $100 million, $200 million next year, is most of that just coming from continued synergies on the Tug Hill assets? Is it lower base decline? Is it implied cost savings? Is it less infrastructure spend? Or is it sort of all of the above? Or what’s driving the bulk of that?

Yes, I would say it would be all of the above. Teams are looking across all angles of the business, looking for ways to shave pennies off the program.

And then maybe just to talk a little bit about just the LOE side or production cost side. I think you’ve highlighted in the deck, especially on Slide 12, the benefits of the water system. The guidance, obviously, this year, I guess, now inclusive of the Tug Hill deal and some other moving parts, your LOE is moving higher. Are you including the expected benefits from the water system investments in your ‘24 guidance around LOE? Or is that something that would be additional upside?

You’re talking about the savings of $40 million that we referred to in the prepared remarks or what are you referring to?

Yes, the $40 million, and I guess like the completion of the systems in ‘24?

Yes. So those investments, I mean, you don’t get an instant response to the same year. I mean the time it takes to build those systems, you usually see that savings show up in the following year and the years after that. So like the water system investments, the additional $80 million we’re spending this year in interconnecting really the Chevron Water Systems, what we’ve built out the Tug Hill systems. I mean that’s really going to pay dividends for us, not only in completion costs over the coming years just through lower water cost and water recycling, but also through LOE. I expect more of that to show up in 2025 and beyond where you start seeing that move the needle.

Appreciate the color.

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

Hey, good morning. I had a couple of questions on the liquids production and pricing. The first question is, it looked like ethane production was lower than guidance for 4Q, while pricing for the other NGLs was higher than what we expected. Can you give some more detail on those two items and maybe remind us how your heavier NGLs are priced?

Yes. Look, I would say on the ethane side, it really just comes down to what’s going on with the Shell cracker both in terms of Q4 actuals and also the outlook for 2024. So that’s really going to be the main driver of that. I think in the guidance we gave – assumed that – our underlying assumption there is influenced by our expectation that, that cracker plant is not fully online really for another year. But that’s something that I think we and our peers around us in Southwest Appalachia are having a haircut a little bit just due to the continued startup delays on that facility.

And how are your NGLs priced?

Really just based on index in basin, I wouldn’t say there was anything that’s really changing as it relates to those dynamics.

Great. And looking at the forward guidance, it looks like liquids, excluding ethane, declines from 4Q volumes and then again from the 1Q volumes. What’s driving the decrease for the heavier liquids?

Yes. I would simply chalk it up to just – we have some pretty lumpy pads in the way we develop. It really just comes down to some of the liquids-rich pads that we acquired from Tug and how that alternates with some of the more of the Utica pads that get turned online or other Marcellus, just dry Marcellus activity. So it’s just kind of normal course lumpiness. But I wouldn’t expect any sort of long-term trend or change from what you’ve seen recently.

Your next question comes from the line of Ati Modak with Goldman Sachs. Please go ahead.

Hi, good morning, team. Thank you for taking the questions. You talked about the capital allocation priorities this year highlighted debt pay-down as the focus, maybe help us understand the thought process around how your view of the macro environment factors into that decision matrix between the different pieces and how we could expect that to evolve?

Yes, for sure. It actually is really driven by the macro in many ways. I think at a high level – I mean look, I think we are as bullish as anybody as it relates to the gas macro outlook as you get to kind of mid-‘25 into 2026. So really, what we have to weigh on our end is if we did – if we reallocated those dollars instead of debt pay down to something like a buyback and accelerating that right now, it would probably in turn cause us to want to go hedge more and protect the balance sheet in case you just had a bunch of macro factors not go according to plan in that time period. So, when it comes to opportunity costs for us, it’s really just a simple question of what’s the upside swing in the dollars buying the stock versus the upside, leaving that more unhedged. And I think with the asymmetric expectation we have to where pricing could go, certainly by the end of 2025 as you get into 2026 that – I mean that dwarfs any sort of return we can get just by buying back stock right now. And so for us, the question is what ultimately is going to create the most shareholder value. And so really, we would rather be patient on the hedging front and use our dollars near-term to just to de-risk the balance sheet. So, really by doing that, we think that actually gives investors more upside and exposure to gas prices. And if for some reason things don’t work out on our expectations on the macro, it provides more downside at the same time. So, that’s why we have allocated and plan to allocate the way I already explained.

Got it. Thank you for that. And then you mentioned the low-cost structure as an advantage. You mentioned a couple of drivers there as well, but I was wondering if you could provide some more color on those pieces and what drives it down further over the next few years?

Yes. I mean it’s a couple of kind of key things, and it’s really contractual. So, I mean our gathering rights, I mean you have seen our guidance with MVP coming online, the impact on just the full year is those rates stepping down at the same time MVP goes into service. Those further step down, as we have talked about before, into 2026, ‘27 really hit a bottom in 2028. And so really, those rates are Equitrans contract that last year were about $0.80 for just the gathering rate hit a bottom of $0.30 by the time you get to 2028. On a blended basis, I mean they don’t gather all of our production, so on a blended basis, it’s a little more muted. You don’t see that full $0.50 drop. But that is a contractual step down that is part of our longer-term forecast. And again, just a tailwind to us even if you have flat pricing and everything else in the environment doesn’t improve. And then the other piece of that, too, as we talked about last quarter, these supply deals that we signed downstream MVP, and so that’s going to also improve our realizations, our realized pricing by $0.15 to $0.20, which over our production base is that kind of rounded $300 million of free cash flow. So, it’s really the combination of the two. There are some offsetting factors in there, but around like compression adds and you have a tailwind as you pay down debt, your interest expense falls as well. But by the time you get to 2028, we see that breakeven cost structure about $2.30, down about $0.30 from where we sit right now. So, it’s a continued tailwind. And look, as we have talked about, I think over and over again, I think that is really unique to EQT. I think where you are in the shale revolution right now, a lot of that core inventory is depleted or rapidly getting depleted. I expect a lot of cost structures to be rising over that period. So, it’s really a unique differentiating characteristic of EQT and it’s really just further like share price upside, free cash flow upside relative to what you get anywhere else.

Thank you. I appreciate that. I will turn it over.

Your next question comes from the line of Scott Hanold with RBC Capital Markets. Please go ahead.

Yes. Hey. You all kind of indicated that your breakeven point this year is around $2.20. And how do you think about that with the gas cracker, if gas prices do, say, continue to trend on the direction they are related to weather, whatnot, I mean would you guys be willing to make changes to make sure that you guys generate positive free cash flow, like so. The bottom line question is like when you start getting around that $2.20 threshold, would you be willing to cut a little bit more to kind of preserve free cash flow rather than burn some cash?

Yes. Scott, I think there is two factors that we think about that would cause us to curtail. One is preserving the ability to not lose money. And so that certainly would look for us to curtail. And the other one is we are looking in 2025, where you see a $1 higher pricing, and that is even – that’s going to be further intensive for us to pinch back and deliver those molecules into a higher-priced market. So, yes, it’s something we are watching and thinking a lot about.

Yes. Scott, I would just underpin too. I mean you have to remember, I mean certainly for a business like EQT, where we are drilling 15 wells, 20 wells a pad, the CapEx we spend this year has no real impact on our production this year. It really has an impact on production next year. And so when we are thinking about that sort of rate of return and you save yourself $100 million this year, what’s the impact on free cash flow next year. Certainly, with where pricing even is today after pulling back and I think our expectation is probably significantly higher than the strip today. It’s really hard for us to justify that, especially just given the financial position we are in, the amount of liquidity we have in our credit ratings. We are just not under the same pressure that most of our peers are. So, that allows us to be a little stickier and plan for the long-term and not be as reactive. But look, we – as we have said before, our production guidance gives us flexibility to reduce as needed. But reducing CapEx activity this year is not – I mean it would be window addressing this year at the expense of next year, and it’s just not how we run the business.

Yes. And Toby, I appreciate the fact that, obviously looking at the forward curve, we do all see, obviously that improvement. But one could argue if we step back several months ago, I mean certainly, 2024 looked significantly better than it is right now. So, like as you step back and think about the macro, like what do you think the big risks are that this gas price trend remains what we have been seeing outside of, obviously weather. But more on, I guess the political front and everything else that’s out there? And then how do you react as a company of this persists into 2025?

Yes. It’s a great question. Listen, I think on the political front, I mean I think political force can override market forces for so long. And our job is to align with the market is to make sure the energy we produce is the cheapest, most reliable, cleanest form of energy that’s out there. And I think eventually, the demand for this product is going to overweigh, I think the political short-term gains that people are thinking that they are helping by doing this. So, I mean long-term, we feel even more optimistic about the large role natural gas will play in the commodity mix going forward. But yes, I mean in the short-term, we need to be sensitive to the market that we are in. Activity reduction is going to be a big thing. I mean a key part of our thinking is we positioned our business to be a low-cost operator in the U.S. I mean our breakevens are significantly lower than what we think is the marginal cost of production. And we are going to see if those marginal producers reduce activities. We have already seen that start to happen. But that’s something we are going to be monitoring and then it’s – eventually, we will have a normal winter. But even without that, with just normal weather, we should be balanced coming into 2025.

Yes. And Scott, with all the bearish narratives out there, I think it’s really important to remember that with these data revisions that came out of Genscape a week or so ago, I mean production levels were not at 107, pushing this bearish narrative, production levels today are like 104.5. And so if you look at where we are at today with normal weather, the market is actually balanced. And so the extra, call it, 275 Bcf that’s in storage right now is really just a result of, again, a really warm El Nino winter. If we had just had normal weather, the market would be balanced right now. So, I think this sort of overarching view of the market is just so out of balance, production is way too high. LNG is delayed. I think when you step back and kind of cut through the noise, it’s really not the case, which is I think why we are being a little more patient and disciplined here. And as it relates to a lot of the LNG headlines and some of the politics playing into that, I mean there is really no impact through – at least the end of 2026. So, as we look at the market today, we don’t really see any change in the LNG build-out timeline. I mean we expect in Q3, Q4, those facilities to start to come online. And again, I think that the work the market needs to do is just to clean up that excess overhang in storage coming out of winter. But the market is really not that far out of balance. I mean it’s a difference of 1% to 2% kind of change in your fundamental model. And it can flip back pretty quick too. So, I think if you are running a long-term business, you just have to keep that in focus. We are really not that far out of whack on the fundamentals.

Yes. I appreciate that.

And Toby, we all appreciate your – obviously, your insights into the political side. So, just kind of curious if I can extend the question. Like what are some of the major push-backs you are getting when you go to Washington and try to fight for kind of the gas companies? What is the main push-back, and how do you address it? Yes. I mean it’s really just asking people to step back and see. It seems like we are in violent disagreement – violent agreement here on what we want from our energy system in the future, like Republican and Democrat, everybody wants more affordable energy. Everybody wants more reliable energy. Everybody wants cleaner energy. And I think the work that we are doing is highlighting, I mean I would say the biggest difference that we are doing, the hump that we need to get people over is to understand that natural gas is a cleaner form of energy. And the good news is we don’t have to play with theories. We don’t have to rely on literature. We have case studies at big scale that show that natural gas is a decarbonizing force, whether that’s simply putting the spotlight in America and showcasing why we are the number one leader in lowering emissions in the world, it’s because of natural gas. And also, I would say the other narrative we need to address is the fact that some people think that America is the largest producer of oil and gas, the regulations or pipeline blockages can’t be that bad. But I think the simple response to that position is yes, we might be the largest producer of oil and gas in the country. We are the largest exporter of LNG in the world. But the question that needs to be asked is, is that enough, we have got ramp of inflation, wars in Ukraine, global emissions still skyrocketing, energy poverty is growing, energy security is crippled. Clearly, the United States needs to do a whole heck of a lot more because the world can only contain so much chaos before it starts spilling over and impacting Americans. So, the world security is our security. And these are simple points that we can make. It is a little bit of a different perspective that people haven’t thought too much about. You lay that common sense approach underneath the framework from climate leaders around the world that recently gathered at COP and came out with a very simple punch list of what needs to happen. Transition fuels are going to be necessary to meet the climate ambitions that we have. That’s a fancy word for natural gas is going to play a role. Carbon capture is going to be a part of those solutions. And then I think also the recognition that solar and wind as great as they can be, they are not the complete solution, and you need a heavyweight solution, and that is natural gas to meet the goal. So, we have got cover from the environmental front, but it’s really just getting this common sense message out, and that’s where we spend a lot of time working the megaphone.

Appreciate that.

Your next question comes from the line of Josh Silverstein with UBS. Please go ahead.

Yes. Thanks. Good morning guys. You mentioned previously that you think we are in an environment where natural gas could be $2 or it could be $4. How do you operate in that environment? Does your production stay relatively flat through all of this? Do you build DUCs when we are at $2? Do you release them when we are at $4? How are you kind of thinking about your development plans going forward in that kind of framework? Thank you.

Yes. I would say at a very high level, I mean keys to success is to have a low-cost structure so that we can weather the storm. And that also is going to position us to be opportunistic to play some of the volatility. Operate – and I will let Jeremy expand on that a little bit. But operationally, one of the things that we have looked to build into our business is the ability to bring some surge capacity. So, understand whether that’s choke management and pension volumes back so we can respond to higher price environments or in some cases, just holding back some TILs and building some DUCs. I think having a flexible program is going to be something that’s needed. But that’s going to be more around the edges. Having a low-cost structure is going to allow us to run consistent programs and be responsive, but not be completely whipsawed by the commodity price.

Yes. I mean I think one of the key things to remember as you think about how to actually manage the business in that environment comes down to like how do you see that distribution of outcomes. And so remember, our cost structure being – call it, mid-2s now headed towards low-2s. If we think about like what’s the worst that’s happened in the last couple of years, which was 2020, and you had gas settled at about $1.99, let’s call it $2. In an environment like that, even if we at EQT weren’t hedged and we have like a $2.30 breakeven, our free cash flow outflow would be in the – I don’t know, $500 million to $700 million range. So, a lot, and you can certainly hedge to protect that. But imagine being a producer in that environment and your breakeven is $3 and you are at scale, I mean you would have multiple billions of dollars of cash outflows, you just can’t survive for more than a year of that because your liquidity gets drained. So, for us, I think one of the things we have realized at scale is that one of the risks that is created is if you pair scale with a really volatile environment and your cost structure is too high, even if your balance sheet is clean, you can put yourself in a pretty precarious position pretty quick. So, that’s why we sort of – that’s why we focus so much on driving that cost structure down because for us, if our downside, call it, $0.50 and that’s pretty low, but if the upside is you have a year settling at $6, $7, $8, I mean you are talking about $10 billion type of cash flow to our business. So, we want to be in a position where we don’t have to hedge and inherently having a low cost structure like a structural hedge. And I think that really is what positions us to, again, not only just kind of survive in cruise through those down periods, but not have to defensively hedge so much of your production that you really missed out on the price. And the price is that sort of asymmetric upside. So, again, I think at a high level, you might – some people might say, well, it’s a little dilutive to just focus on cost structure so much near-term. I think that’s easy to see if you run a static model at like $3.50, $4 gas. Well, that doesn’t capture those is the element of volatility. And if you talk to any of the producers, any of our peers, I think the theme of volatility is well understood. I just – I think EQT is unique in how we position ourselves to, again, be structurally defensive towards that for long-term investors and then provide the best risk-adjusted upside to that theme and capture that every 3 years to 4 years when that sort of windfall period shows up. And again, I mean think about it, we had a little bit – you had a warm winter this year, you have an extra 275 Bs in storage. It could have gone the other way. And we will have winters that go the other way. You could have pricing at $5 just as quickly as you have pricing at $1.50. And that amount of cash flow at our scale is just an absolutely tremendous amount of value. So, we are trying to position ourselves to be able to capture it and not – again, like the last couple of years where we lost so much on hedging, continue to give that upside up. So, that’s again, why we just sort of philosophically focus on running the business the way we do.

Thanks. My last question was just on hedges. You mentioned a lot in there, but it looks like you didn’t add anything for 2025. I definitely get the constructive outlook that you guys have. But clearly there is the factor of weather, which you have mentioned as well that we just don’t know how that will play out. Why not at least look to add in something for 2025 at this point, just to have a base level in there? It looks like you added something for second half or fourth quarter for this year below where the strip is next year. So, I thought that would be great. Thanks.

Yes. So, I think we think about hedging going forward, just with our balance sheet and credit ratings where we are. I think you will see us start to hedge at a level that effectively drops our – I mean look, if you think about what hedging does in a low-price environment, it effectively synthetically drops your breakeven price. And so if our breakeven price, call it, is headed towards $2.30, we might long-term hedge between like 20% and 30%. And so if you do get that $2 a year on average, that’s kind of your free cash flow breakeven point on a hedged basis. We are kind of towards that with our hedging in 2024 right now. That’s that $2.20 level that we talked about. I think – look, we don’t plan to go into 2025 totally unhedged. I think we are just willing to be patient. And I think some of the bearish narrative in positioning in the commodity markets has really pushed pricing really below where it probably needs to be. So, look, we don’t need to hedge defensively right now. I think we are – we want to be opportunistic, and we just think there is so much asymmetric called SKU that should show up in that market in 2025. I think we are willing to be patient on that. But I mean look, we will take off risk at the right point in time, but we are going to continue to be patient on that.

Our last question will come from the line of Paul Diamond with Citi. Please go ahead.

Hi. Good morning. Thanks for taking my call. I just wanted to touch base real quickly on – you talked about LOE and some of the savings have been driven by water handling. I guess my question is how much more, I guess meat on the bone you think there is there? How much further do you think you can drive it lower?

Yes. I would say that we had a big step change. I think if you look at the water recycling rate, that’s a big driver on a large portion of our LOE. Obviously, water is the biggest portion. So, the goal for us is to stay in that 95% plus range on water recycling. I think the other benefits that the water system will come through just more efficient logistics to service our completions team and allow to give these guys the space to continue to run hard and continue to capture the operational efficiencies they are seeing there.

Understood. And then I have just kind of one final quick one. As the prop market sits right now on the curve, how should we think about kind of the operational cadence through the year with that 140 – or 110 to 140 TILs, should we think about that as pretty steady throughout the year, and more back half loaded, or how should we think about it as the market sits down?

Yes. Look, I would call it pretty steady throughout the year. I mean when you are running the size of spreads we are and the size of logistics operations, it’s not something you start to stop quickly or easily. The bar is pretty high for that. I think the range we give is just based on some shifts in timing that can happen. I think in terms of the macro environment, I mean look, we – the quickest thing that’s going to balance the market is not having operators in Appalachia, which have a pretty shallow base decline cutting activity and are drilling big pads that are hard to slow down. I mean that’s base load supply as we think about it. When we think about really the production that needs to come out of the market, the fastest way to balance the market, it’s taking Haynesville activity even further downward. They are drilling two wells to three wells at a time on the pads, becoming more and more infill wells and you have a 50% to 60% base decline. A cut in that activity would balance the market a lot faster. And that’s also the marginal producer today and will continue to be in the future. So, we expect that’s really where the volatility of production and variances and production cadence will show up and will continue to show up, I think in the backdrop of volatility that we have talked about.

Understood. Thanks for your time.

I will now hand the call back to Toby Rice for any closing remarks.

Thank you everybody for your time. We are looking forward to executing for you in 2024. Thanks a lot.

That does conclude today’s meeting. We thank you all for joining and you may now disconnect.