EQT Corp Q1 FY2023 Earnings Call

Good morning or good afternoon, and welcome to the EQT Q1 Results Conference Call. My name is Adam, and I'll be your operator for today. Operator Instructions. I will now hand the floor over to Cameron Horwitz, Managing Director, Investor Relations and Strategy. Cameron, ready when you are.

Good morning, and thank you for joining our first quarter 2023 results conference call. With me today are Toby Rice, President and Chief Executive Officer; and David Khani, Chief Financial Officer. The replay for today's call will be available on our website beginning this evening. In a moment, Toby and Dave 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. 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 and our investor presentation, in 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 may also contain certain non-GAAP financial measures. Please refer to our most recent earnings release and investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. With that, I'll turn the call over to Toby.

Thanks, Cam, and good morning, everyone. While the current natural gas macro environment has created some headwinds for U.S. natural gas producers at large, the price pullback is reinforcing EQT's confidence in our corporate strategy and illuminating several facets of differentiation relative to our peers. A key pillar of distinction has been EQT's M&A strategy where we have taken a disciplined approach to acquisitions specifically focused on assets that lower our cost structure. The current gas price environment underscores the benefits of this strategy with enhanced free cash flow durability through the bottom parts of the commodity cycle allowing for accretive capital allocation decisions, resiliency in corporate returns and greater consistency and operational cadence. Our pending Tug Hill acquisition further builds on this M&A strategy as it is expected to drive an additional $0.15 decline in our corporate free cash flow breakeven price, providing even greater resiliency to our business moving forward. Another area where EQT is differentiating itself is through our evolved hedging strategy. While we no longer have financial needs requiring hedging, given material improvements in our balance sheet, we have evolved into opportunistic hedgers, predominantly using glide collars to derisk free cash flow at the bottom part of the cycle while maintaining material upside exposure to natural gas prices. This strategy is paying off in real time as EQT has among the best hedge books of any natural gas peer in 2023 with 62% of our production covered via floors with an average strike price of $3.38 per MMBtu. In conjunction with our M&A and cost reduction efforts, our hedge book is a key factor driving our full year 2023 corporate NYMEX free cash flow breakeven down to less than $1.65 per MMBtu. A third pillar of EQT's strategy driving distinction among peers is our opportunistic capital returns approach. When we rolled out our return framework in late 2021, we did so under the premise that we would look to maximize returns to shareholders via our capital allocation decisions, which requires a tactical and thoughtful approach to both debt repayment and equity repurchases. With more than a year under our belt of returning capital to shareholders, we believe our underlying approach and execution is generating superior results, which is exemplified by the fact that we have achieved the best return on our equity buybacks among our peer group and retired a material amount of debt at discounts to par as interest rates have risen. A fourth element of differentiation comes on the environmental front as EQT has taken material steps forward in achieving our peer-leading goal of net zero Scope 1 and 2 greenhouse gas emissions from production operations by 2025. We highlighted the material benefit of completing our pneumatic device replacement initiative a year ahead of schedule with our fourth quarter results. And we are building upon this momentum with recent announcements of strategic partnerships directed at advancing the development of low carbon intensity, natural gas products and generating verifiable carbon offsets. In short, we believe the key tenets of our corporate operating philosophy are laying the foundation for differentiated and sustainable long-term value creation for EQT, and you can expect continued execution upon our proven strategy going forward. Now turning to first quarter results. 2023 got off to a very strong start across the board at EQT. As shown on Slide 7 of our investor presentation, we replicated the solid efficiency gains we achieved late last year in the first quarter with frac crew pumping hours up 35% year-over-year as the third-party infrastructure constraints that slowed our operational pace in 2022 moved firmly into the rear view. These efficiency gains facilitated our first quarter production coming in 2% above the midpoint of guidance, while our CapEx came in 7% below the midpoint of our expectations. Our advantaged firm transportation portfolio allowed us to achieve an average differential of $0.16 above NYMEX. Operating expenses came in 2% below the midpoint of our guidance on lower-than-expected LOE, production taxes and G&A. Combined, these factors drove free cash flow of $774 million during the first quarter which is EQT's highest quarterly free cash flow and significantly derisks our free cash flow generation for the year. I want to personally thank all members of our crew for their hard work in facilitating this execution as we have made significant strides toward our goal of achieving peak performance this year. On the capital return front, we repurchased nearly 6 million shares or $200 million of stock during the first quarter at an average price of less than $34 per share. We also retired $210 million of debt principal during the quarter at an average cost of 96% of par. Even with these significant returns to shareholders, we exited the quarter with greater than $2.1 billion of cash on hand, up from $1.5 billion at year-end 2022. Our net debt at the end of the first quarter was approximately $3.3 billion compared with $4.2 billion at the end of 2022. Our net debt to trailing EBITDA currently stands at 0.9x, underscoring the tremendous balance sheet progress we have achieved over the past several years. In terms of full year guidance, we are reiterating our $1.7 billion to $1.9 billion capital budget, which excludes our pending Tug Hill acquisition. As a reminder, our 2023 budget includes $100-plus million of nonrecurring capital associated with third-party constraints that shifted roughly 30 turning-in-line wells into 2023 and assumes 10% to 15% year-over-year oilfield service cost inflation. As it relates to the latter, we are seeing a notable trend of flattening out in oilfield service costs as industry activity moderates and we believe the stage is set for some degree of softening in the second half of the year, which, if manifested, would provide upside to our current outlook. Our 2023 production guidance is unchanged and at 1,900 to 2,000 Bcfe, and we are operationally on track to get back to 500 Bcfe per quarter of run rate production by the middle of this year. That said, as we mentioned last quarter, the lower end of our guidance range contemplates scenarios where we slow our production cadence for the year should natural gas prices continue to deteriorate. And we have the flexibility to make game-time decisions on our cadence as the year progresses. On Slide 32 of our investor presentation, we've provided an updated range of 2023 adjusted EBITDA and operated cash flow and free cash flow outlooks at various natural gas prices for the remainder of the year. At recent strip pricing and factoring in first quarter actuals, we forecast 2023 adjusted EBITDA of approximately $2.9 billion and free cash flow of roughly $1 billion this year, implying a 9% free cash flow yield at the bottom part of the commodity cycle. As shown on Slide 5 of our presentation, our free cash flow generation has significant durability and duration with our internal forecast projecting cumulative free cash flow from 2023 to 2027 of greater than $12 billion at strip pricing and excluding the benefit of Tug Hill. This equates to more than 105% of our current market capitalization and greater than 80% of enterprise value, underscoring the significant value proposition embedded in EQT shares even after the recent decline in strip pricing. Our free cash flow outlook gives us tremendous confidence in being able to achieve our absolute debt target of $3.5 billion pro forma for the Tug Hill acquisition, while also being able to continue to opportunistically retiring our stock via our $2 billion share repurchase authorization. Turning to our environmental initiatives. We announced multiple key projects over the past few weeks. First, we entered into a strategic partnership with Context Labs to advance the development of verified low-carbon intensity natural gas products and carbon offsets. Through tracking, reporting and verification of critical emissions data, this strategic partnership will support us in achieving our industry-leading emissions reduction targets. With a focus on emissions quantification, operational analysis and the certification of natural gas production we plan to work with Context Labs to scale emissions mitigation across the full energy value chain. Context Labs will provide an enterprise-wide deployment across EQT's asset footprint with the goal of achieving full digital integration of our carbon intensity data. The resulting creation of certified low carbon intensity products will add another dimension to EQT's already robust and digitally enabled organization. We view the emissions profile of our natural gas as a strategic asset for our shareholders, and this partnership will further aid in illuminating the relative value of our product and ensure EQT's molecules remain among the most coveted in the world. Additionally, we announced EQT's first nature-based carbon offset initiative earlier this month. We partnered with the Wheeling Park Commission, a public park in West Virginia, Teralytic, a soil analytics company and Climate Smart Environmental Consulting to implement forest management projects with the goal of generating carbon offsets in our own backyard. These projects will span more than 1,000 acres of forest land and we will utilize Teralytic's soil probe technology to ensure the quantification of offsets is accurate and transparent. EQT has been an industry leader in reducing operational emissions, and our natural gas already has some of the lowest greenhouse gas intensity in the world. Nature-based projects like this, which are supported by cutting-edge technology that ensures accuracy and transparency, will offset our remaining emissions and be a key enabling factor for EQT to become the first energy company of meaningful scale to achieve verifiable net zero Scope 1 and 2 greenhouse gas emissions. As it relates to the pending Tug Hill acquisition, we have been constructively working with the FTC and believe we are on track to close the acquisition around midyear. Due to the relative value structure of the deal with a meaningful equity component and the interim free cash flow since the deal's effective date of July 1, 2022, we expect the price paid at closing to be roughly $2.3 billion of cash and approximately 48 million shares, which at a $33 per share price equates to a closing value of roughly $3.9 billion. We note this deal structure contrasts with other recent transactions in the industry, which were cash heavy and thus more levered to commodity prices. This consideration mix, along with Tug Hill's cost structure, have served as a hedge for EQT as gas prices have fallen as evidenced by the deal accretion more than doubling since announcement, all while leverage has stayed in check. In summary, our strong first quarter results underscore that the third-party infrastructure challenges we faced last year are in the rearview and EQT is back to peak performance. We generated our highest quarterly free cash flow, we repurchased a material amount of equity and debt and exited the quarter with an improved leverage position and over $2.1 billion of cash on hand. While the current natural gas macro environment does present challenges, it also illuminates the relative advantages of EQT's corporate strategy, underpinned by large-scale combo development, a disciplined M&A focus on low-cost assets, a risk-adjusted hedging strategy and opportunistic capital returns. This unique corporate profile has laid the foundation for significant value creation through all parts of the commodity cycle. And we look forward to building on our successful track record of execution on behalf of all of our stakeholders. I'll now turn the call over to Dave.

Thanks, Toby, and good morning, everyone. I'll briefly summarize our first quarter results before discussing our balance sheet, the macro landscape, hedging, 2023 guidance and use of our free cash flow. Sales volumes for the first quarter were 459 Bcfe or 2% above the midpoint of our guidance range. Our per unit adjusted operating revenues were $4.11 per Mcfe and our total per unit operating costs were $1.34, resulting in an operating margin of $2.70 per Mcfe. Capital expenditures, excluding noncontrolling interests were $464 million or 7% below the midpoint of our guidance range as operational efficiencies exceeded expectations. Adjusted operating cash flow and free cash flow were $1.24 billion and $774 million, respectively. We also had a $426 million working capital tailwind during the quarter, largely driven by declining accounts receivable from decreasing prices with a further tailwind expected in Q2 and Q3. Our capital efficiency for the quarter came in at $1.01 per Mcfe, which was approximately 10% better than what was implied by the midpoint of our guidance ranges, driven by outperformance on both production and capital spending. Note that as we complete the excess wells that were shifted from last year, our second half capital efficiency should improve by double digits relative to the first half. Turning to the balance sheet. Our strong credit profile and ample liquidity remain a core tenet, underpinning our operating philosophy and will provide differentiated value opportunities for EQT moving forward. Our balance sheet position continued improving with trailing 12-month net leverage exiting the quarter at 0.9x, down from 1.2x last quarter and 1.9x a year ago. We exited the first quarter with $3.3 billion of net debt and $2.1 billion of cash on hand, inclusive of the $1 billion in proceeds from our notes offering. This week, we extended our $1.25 billion term loan to the end of 2023, which aligns with the timing of the amended purchase agreement and provides timing flexibility. The bank term loan, along with our cash balance, gives us the flexibility and confidence to fund the cash portion of the Tug Hill deal independent of any bond proceeds that we raised last fall. As Toby mentioned, we continue to actively progress our debt retirement initiatives. We retired $210 million of senior notes principal in the first quarter primarily via open market purchases at an average price of 96% of par. Since unveiling our capital returns framework, we have retired more than $1.1 billion of debt principal, which has eliminated nearly $40 million of annual interest expense. Our commitment to a bullet-proof balance sheet is being recognized by the credit rating agencies. S&P and Fitch reaffirmed our investment-grade credit ratings over the past several weeks with stable outlooks at both agencies, even as natural gas prices have temporarily receded. As we further execute our objective of achieving $3.5 billion of gross debt pro forma for the pending Tug Hill acquisition, we believe additional credit rating upgrades are possible. I'd like to also briefly highlight Slide 10 of our investor presentation, which shows our track record of materially growing our asset base while lowering our net debt. At year-end 2019, our net debt was $5.3 billion. Our proved reserves were 17.5 Tcfe and our net production was 4.1 Bcfe per day. Fast forward to 2022, we increased our proved reserves to 25 Tcfe and our production to 5.3 Bcfe per day through the Chevron and Alta acquisitions and organic reserve growth, all while decreasing our net debt to $3.3 billion through the end of the first quarter. Said another way, we have grown our asset base by 30% to 40%, while simultaneously lowering our net debt by a comparable percentage over the three years and our plan for additional debt reduction post closing the Tug Hill acquisition should more acutely highlight this track record. Turning to a few brief thoughts on the gas macro landscape. The combination of warm winter weather and the Freeport outage left roughly 400 Bcf of excess natural gas in storage this winter. The market is in process of rationing this excess gas with the balancing items likely to be split between low production and increased gas-fired power demand. On the former, declines in gas-directed activity has accelerated as of late with pricing falling well below many producer breakevens across the U.S., and we believe additional gas-directed activity declines in the coming months to moderate the pace of storage injections by roughly 200 Bcf. As it relates to power generation, over 7,000 megawatts of U.S. coal generation is set to be retired in 2023 and we are seeing gas take further share from coal in the power stack to the tune of roughly 2 Bcf per day this year. With the average cost of coal rising materially in 2022, the coal to natural gas switching floor has increased by 50% or more and we believe this is a structural shift given the massive underinvestment in coal capacity. There are several avenues of upside potential that could drive additional market tightening above our current base case expectation, including higher sustained LNG exports, greater industrial demand, and reduced imports from Canada, given a tight Canadian storage market. We expect continued volatility in natural gas prices as gas and coal activity moderates and storage overall is an inadequate buffer relative to peak demand. Moving to hedging. Our 2023 hedge book underscores our evolved hedging philosophy that seeks to provide investors with the best risk-adjusted exposure to natural gas prices. We have 62% of our 2023 production covered with floors at an average weighted price of $3.38 per MMBtu, which provides significant cash flow protection in downside pricing scenarios while maintaining upside exposure. We also have 10% of our 2024 volumes hedged at a weighted average floor price of $4.20 per MMBtu and a weighted average ceiling of $5.40 per MMBtu. Given our expectation of improving natural gas macro fundamentals as the year progresses, we will opportunistically look to add to our 2024 hedge position at the appropriate time. As it relates to basis, we are seeing a material benefit from our expanded firm transportation portfolio, which was reflected in our first quarter differential coming in at a $0.16 premium to NYMEX as we captured favorable pricing spreads during the quarter. We continue to expect additional opportunities to expand our FT position as other Appalachian operators release existing firm transportation capacity. As it relates to MVP, Slide 8 of our investor presentation illustrates the project's impact on EQT's cumulative free cash flow. While the benefit of MVP is interrelated with the spread between NYMEX and local Appalachian prices, the current future strips suggest MVP has an immaterial impact on our cumulative free cash flow as higher price realizations are largely offset by higher transportation expense. That said, we continue to be staunch supporters of the MVP as the project is necessary to ensure energy security for the Southeastern region of the United States while achieving its carbon reduction goals via the phaseout of coal-fired generation. We were encouraged to see Energy Secretary Granholm show her support for MVP and broader energy infrastructure this week with notable comments on how these projects will deliver dependable energy to Americans while supporting the reliability of the electric grid. For reference, our model assumes MVP starts up in the second half of 2024 and we will adjust assumptions if needed. Importantly, gathering rates contractually begin declining in 2025 independent of MVP success, providing a further tailwind to free cash flow as margins widen by $0.15 from current levels, adding approximately $300 million of annual pretax free cash flow by 2028. Turning to guidance. We are reiterating our 2023 production outlook of 1.9 to 2.0 Tcfe. This range provides significant flexibility to respond to evolving macro conditions with the low end of our production guidance a potential outcome of moderating activity should natural gas prices continue to decline. We are currently running 2 operating horizontal rigs and thus not contemplating reducing rig activity, but we have flexibility around our completion cadence as well as our choke management program. We are also reiterating our 2023 capital budget of $1.7 billion to $1.9 billion, excluding the pending Tug Hill acquisition, which embeds 10% to 15% year-over-year oil field service inflation. As it relates to leading edge inflation trends, we are experiencing a flattening out of steel costs and starting to see long-haul logistics prices softening. We believe this is a signaling of some degree of price relief on local logistics such as sand and water hauling and could enable further completion efficiencies. While still too early to predict with precision, we believe this backdrop could set up for some degree of net price relief for EQT by the fall and upside potential to our free cash flow outlook later in 2023 and into 2024. As a reminder, $100-plus million of our budget is associated with turning in line wells that slipped from 2022 into 2023 due to third-party constraints and thus is not anticipated to carry forward into future periods. This dynamic, along with the shallowing of our base PDP decline, is anticipated to drive 5% to 10% improvement in our capital efficiency in 2024 and beyond, independent of any oil field service cost relief. Our per unit operating expense range is 2% per Mcfe lower at the midpoint driven by lower production taxes and G&A. We're also lowering the range of our average differential forecast for the year to negative $0.35 to negative $0.60 per Mcfe, driven by narrowing local basis and the benefits from our firm transportation portfolio. On Slide 32 of our investor deck, we provide adjusted EBITDA, operating cash flow and free cash flow outlooks at various natural gas prices for the remainder of 2023. At recent strip pricing, 2023 adjusted EBITDA is expected to be approximately $2.9 billion and 2023 free cash flow is anticipated to be roughly $1 billion implying a free cash flow yield of 9% at the bottom part of the cycle. As it relates to cash taxes, we continue to expect our remaining federal NOLs to offset the bulk of our 2023 taxes. Our 2024 cash tax rate would be approximately 5% to 7% of operating income or $120 million to $170 million at current strip pricing, increasing to the low 20% range in 2025 and beyond which is fully captured in our cumulative free cash flow outlook. Turning to capital allocation. We repurchased almost 6 million shares during the first quarter and have retired a total of more than 20 million shares under our buyback authorization at an average price of roughly $30 per share. Our buyback strategy is opportunistic in nature as we seek to maximize the return generated for investors, and we are pleased with our execution to date as we have generated the best buyback return among the gas peer group. We've also retired $210 million of debt principal during the quarter at an average price of 96% of par taking our total debt principal retired to $1.1 billion since initiating our capital return framework. This focus on debt retirement has driven our net leverage down a full turn over the past year highlighting our commitment to a bulletproof balance sheet. Looking ahead, our cash position affords us tremendous flexibility as it relates to financing the cash portion of the pending Tug Hill acquisition. As we work constructively with the FTC and approach deal closing, we plan to maintain cash on hand to effectively prefund a portion of our expected debt paydown post deal close. We will also look for opportunities to buy back additional stock post deal close, especially in light of the value accretion and the cost structure improvements that Tug Hill and XL assets will bring to EQT. As Toby mentioned, we see greater than $12 billion of cumulative free cash flow from 2023 through 2027 at today's lower strip even before factoring the benefits of the pending Tug Hill acquisition, leaving us with plenty of firepower to fully achieve and exceed our debt retirement goal and our equity buyback authorization. I'll now turn the call back over to Toby for some concluding remarks.

Thanks, Dave. To conclude today's prepared remarks, I want to reiterate a few key points: One, first quarter results were robust across the board at EQT, underscored by strong operational efficiencies and lower-than-expected capital spending and higher price realizations from our advantaged firm transportation portfolio; two, the solid performance facilitated $774 million of free cash flow, underscoring our cash generation potential even in a lower natural gas price environment; three, we built upon our track record of thoughtful opportunistic capital returns during the quarter with nearly $550 million of returns via share repurchases, debt retirement and our base dividend; four, our commitment to a bulletproof balance sheet is evident as net debt declined by roughly $900 million during the quarter, and we exited Q1 with over $2.1 billion of cash on hand; and finally, the current natural gas macro environment is giving us even greater confidence in our differentiated corporate strategy underpinned by efficient large-scale combo development, a disciplined M&A focus on low-cost assets, a risk-adjusted hedging strategy and opportunistic capital returns. I'd now like to open the call to questions.

Operator Instructions. Our first question comes from Arun Jayaram from JPMorgan.

My first question regards the differential guide. You guys reduced your full year differential guide relative to the 4Q press release by about $0.15 per Mcfe, which obviously is nearly $300 million tailwind to cash flow. So I was wondering if you could talk about what actions you've taken to support the lower or the narrower differentials? We did see that you have a little bit more takeaway to the Midwest and Gulf Coast. And maybe help us think about how much of that lower differential is related to the FT versus maybe some basis hedges that you've set up? And what is the potential impact beyond this year as we think about longer-term differentials for EQT?

Yes. So it's a great question, Arun. So we've added about 500 million a day of FT capacity over the last 18 months, mostly to the Midwest and some to the Gulf Coast. These are definitely higher value regions that give us exposure to improved realization. We continue to expect to add more this year and make that better. So that was definitely a piece of it. The other piece of it was our hedging strategy and how we had certain areas and left certain areas open. M3 was a very strong region for us this quarter. As a nuclear facility in New York went offline, we're seeing higher and higher values up in that M3 area as winter showed up. So winter is a very positive M3 area. The third piece is, as natural gas NYMEX prices come down, our local basis narrows as the correlation is about 80% to 85%. So when NYMEX goes up, our basis widens; when NYMEX comes down, basis narrows. Those are the three impacts, of which I'd say the first two will probably be long-lasting, and we'll continue doing it. The last one is, of course, subject to what NYMEX prices do.

Great. And my follow-up is for Toby. Toby, it's been just a little bit over a year. I think you announced your Unleash LNG initiative at CERAWeek last year. But I was wondering if you could maybe talk about some of the wins that you think you've had, maybe some of the things that haven't developed as quickly as you'd like. I mean, we do note that we do have now 10 Bcf a day or so of projects, which have been FID-ed. So there is going to be a lot more demand for feed gas for LNG. But I wonder if you could give us a sense, after a year, some of your thoughts on just the overall initiative.

Yes, Arun, let's look at where people's heads are at around the world when they're thinking about energy. I think there's a couple of classes where people's sets are at. We've got some people that still have their heads in the sand, thinking that just focusing on the United States and fixing emissions here is going to somehow solve the global emissions issue that they're concerned about. They need to pick their head up. We've got other people that have their heads in the clouds and thinking that some of these solutions that are being proposed are only addressing one part of the energy ecosystem, and they may be a little bit too optimistic. What we need is people to have a level head talking about deploying proven, scalable, truly sustainable solutions like Unleash U.S. LNG that will have the biggest impact on lowering global emissions and will have the biggest impact on providing more energy security to the world. Now I'm excited about where the world has moved. We've moved away from a world that is a sum-of-the-above approach towards energy, only solar only wind. We've seen that strategy play out in Europe and the world has taken notice that that may not be the best solution, and it may not be a capable solution. So the world has moved back towards a more realistic and more practical approach — an all-of-the-above approach towards energy. That's where Unleash U.S. LNG sits. But if we want to meet the environmental ambitions and the timeline needed to get there, if we want to accelerate pulling the 3 billion people around the world that live in energy poverty, if we want to protect the 60% of Americans who live paycheck to paycheck, we need to move from an all-of-the-above approach to a best-of-the-above approach towards energy. And while the world certainly, I think, isn't capable right now on determining what is the best source of energy, one of the things that we're excited about over the last year is we've been successful in defining the criteria at which energy will be graded upon. Those criteria are cheap, reliable and clean. And that seems to be universally accepted as the three main criteria. We're seeing actions with the administration — Secretary Granholm supporting pipelines, supporting MVP and in the closing paragraph of her letter says that energy needs to be affordable, reliable and clean. So we are very excited about the progress we've made. There's still a lot of work left to do. I think permit reform is inevitable. Our energy ecosystem is maxed out. Pipelines are full. Refineries are running at maximum capacity. And without that extra flexibility, we are at risk of a major event throwing us back into another energy crisis. That event can be weather — we see utilities in New England writing letters to the President saying that they're concerned if they experience a mild cold winter how they will deal with that. It could be a cyber event. We saw what happened with Colonial Pipeline. It could be another geopolitical event. In my opinion, it's not if one of these events happens, it's when. We need to build up our industrial energy capacity so that we can deal with these events when they take place. That's one of the reasons why I believe permit reform is inevitable. I think people understand where we're at and what we need to do, and we're excited about helping lead the conversation going forward.

Operator Instructions. The next question comes from Umang Choudhary from Goldman Sachs.

My first question was on the outlook. I mean, you articulated your thoughts around the natural gas macro outlook. I was wondering if you can give any color in terms of like what levels would you look to adjust your completion activity? And any color you can provide on your choke management plans.

So we'll continue to measure the current commodity price. I think the default plan for EQT is to continue a steady pace operationally even given what we see in the commodity outlook. We have the luxury of keeping a steadier plan because of the fact that we are the low-cost operator. And so we'll be able to capture some of the efficiencies that come along with that steady activity plan. As far as production is concerned, if we see local prices get below the cost it takes for us to produce, then you're going to see us curtail volumes. So that will be a game-time decision and we'll watch how the setup continues to evolve and operate our business accordingly.

Yes. And I'd just add, due to the water line issue last year, our production is below maintenance levels normally by, we'll call it, 2% to 3% already. So we've actually contributed, I would say, our share a little bit of the reduction in gas to help balance the market as well.

Operator Instructions. The next question comes from John Abbott from Bank of America.

Apologies for the sirens in the background here. It sounds like something is going on. Our first question is related again to the Tug Hill and Excel Midstream acquisition. It looks like you're still suggesting those are going to close around midyear. It sounds at that time, we'll have potentially some sort of update to guidance. Just sort of thinking about that, could you remind us what is included in the $80-plus million of synergies that you had initially suggested? And at this point in time, where do you see potential upside versus that?

Sure. So the $80 million in synergies that we identified primarily came from some midstream synergies, connecting our infrastructure — building some pipelines that would connect our asset base from Ohio, West Virginia and Pennsylvania. Another synergy that's fairly large is connecting our water systems. There will be a synergy there. When we look at the synergies, we tried to be really practical in outlining what those are. Those will be additive to the accretion numbers that we put out. Given the fact that these are largely infrastructure related, they're typically lower risk in nature. Some of the upsides that we look at: we have a track record of improving operations on the assets that we ultimately inherit. Our drilling team is a really great example. Look at the drilling performance uplift we've seen on the Alta acquisition — we do think there is an opportunity for us to repeat that. We've got a very strong drilling team. So those will be some of the upsides to that. When we look at that $80 million of synergies, how does that compare to the $0.15 that the Tug Hill transaction will impact by lowering our free cash flow breakevens? These $80 million would be an additional $0.04 on top of that $0.15 — it just shows you the impact of adding this asset under our belt will be very impactful in lowering our costs.

So just to be clear, does combo development factor into those synergies?

Combo development does factor into the synergies. Dual development will also take place. The only other logistical impact that will present itself is the frac activity that's taking place on the Tug Hill assets will become another location for our water team to use for recycling. And water recycling is a big needle mover on efficiency gains. Our water recycling rates have gone from 80% to over 90%, and we're going to continue to focus on increasing our water recycle rates — the Tug Hill assets will give us a little bit more flexibility on how to achieve that.

Operator Instructions. The next question comes from David Deckelbaum from Cowen.

Perhaps I just wanted to go back on a couple of points that you had already made. But if you could provide any color on what your expectation is in terms of crews and rigs perhaps leaving Appalachia if you give us a sense of magnitude and timing when we might expect to see some incremental softening around the service side as you think about getting into the back half of '23 here?

Sure. Just to level set what we've seen, we've seen a 10% reduction in rigs that were focused on gas — about 17 rigs have come off. We expect that trend to continue down and we're also looking at some of the commentary. The big focus really needs to be on the completion activity — and from the earnings with Halliburton and Liberty, they are signaling that they're seeing a mobilization of frac crews moving away from gas towards oil. So that will be something else that we're looking at throughout the course of the year in addition to the rig reductions.

Yes. And I'd just say logistics items like sand, falling steel costs, those are things that we're looking at probably in the second half of the year to soften — but we obviously didn't put that into our numbers because we need to see it happen before we make that move.

You brought up, I think, if there are some ongoing headwinds here before we get to a lot of the LNG egress that comes on in — and obviously, the coal retirements looking for some displaced gas there. How do you think about managing a short-term curtailment profile? And you highlight at a corporate level now your free cash breakeven this year is $1.65 with the benefit of the hedge book. Do you think about curtailing things at a corporate level? Or is this still calculated at a field level of sort of an individual area or a bad basis?

We look at it at a field level. We look at it both, but when we want to do a broader, larger curtailment, then we'll look at the overall rates of return. We'll look at the forward curve and make a decision about whether we can create value by moving gas into the future as opposed to keeping it producing today. We've shut in production in 2020 a couple of times, and we also shut in production in 2021 that we didn't really talk much about. Those were shorter-term in nature. So we'll do it both field and corporate.

I appreciate that, David. And if I could just ask a little bit more on Umang's question earlier around the hedge book. The curve for 2024 is kind of sitting in and around the area where you guys had hedged out for 2023. You don't have much hedge volumes in 2024 now. I guess how do you think about that dynamic just given the fact that your realizations could look pretty attractive if you hedged out 24 at this point? Is that more a sort of a commentary or reflection on your confidence in hitting deleveraging goals this year and requiring less of a hedge profile next year? Or is that more of taking this wait-and-see into what ultimately might be a volatile spike for the 2024 curve?

When we hedge and we use collars, we like to see skew in the market. The best times to add collars is when you have an uptick in gas. If we wanted to do swaps, which we could do and lock in some of this and protect some of the 2024 picture, we could. But what we're also seeing is activity slowing on the gas side, activity starting to slow on the coal side, and we're heading into the summer months here, which is a catalyst. We're also seeing some incremental LNG come on in the first quarter of next year with Golden Pass. So I think the worries about storage levels getting to 4 Tcf or 4.1 Tcf — one, we don't think it's going to get there. I think you'll see it come in short of that. And then even at 4 Tcf, that's basically 30 days of cover, which, to provide a meaningful buffer in a peak demand period, you really need about 60 days. So we see if you get a normal winter, you could see a spike in gas and you really need about 400 Bcf of incremental storage in 2024 to be able to support the incremental LNG that's coming online in 2024. I think we're seeing a very positive setup here. The big negative could be if summer doesn't show up and we do underperform on summer demand. That's why we like to hedge: to manage those risks. We're going to try to figure out the right time to jump in and add those hedges and try to derisk it. But we see a lot of moving parts, both positive and negative, and we're trying to make sure we time hedging right.

The next question is from an analyst. Your line is open. Please go ahead.

You touched on the takeaway capacity, could you talk about your current volumes that were able to get down to the Gulf Coast? I see the 28% you have on Slide 20. But I wasn't sure if some of that was financial exposure and maybe not actual volumes. And then maybe how you're thinking about your options to increase takeaway specifically to the Gulf Coast? Are you looking to do something similar to that $200 million you picked up last year? Or are you comfortable with your mix? Or are you looking at M&A or midstream partnerships?

Yes. So the volumes down to the Gulf, that's all physical. That's not financial. And so we are looking to add more over time, and there are more pieces that will come up over time. It's very episodic, as you can imagine. So we will look to continue to grow the FT position to all the higher-valued areas, including the Gulf. I think it's important to note that as you see a lot of volume growth down in that area, it's important to have hedging; hedging will play more of a role in the Gulf Coast as Haynesville tries to grow and Permian tries to grow. So you need to have Gulf Coast and hedging as a strategy now. Once you get tied up into the LNG market, that will actually alleviate some of the need to hedge basis down there, too. So there's a lot of things that you need to do to manage the complexity down there.

Got you. Very helpful. And then maybe could you talk about the allocation of free cash flow in future periods. If we see a significant call on gas prices from LNG demand, do buybacks compete with acceleration? Do you look at them independently? Or do you compare them on kind of an IRR level? Or is it maybe you guys have an internal NAV on your company? And if your shares trade below or above, is that how you decide what activity level to do?

Well, right now, until we have all East Coast LNG offline, we're going to be running in a maintenance-of-capital perspective. So right now, the buybacks are competing probably more with our debt retirement and maybe a little bit on the margin with the dividend. If we were to get access to East Coast LNG and be able to grow — which we're talking several years into the future — then it will be a rate-of-return exercise, and we'll have a view of what we think our NAV is at a mid-cycle price, and then we'll compare it against the value we can get to lock in that growth with LNG pricing.

The next question comes from Harry Matti from Barclays.

Circling back to Tug Hill, the bonds you issued last year had some M&A conditions in them linked to a deal closing by June 30. And I appreciate you still think you're on track to close by midyear, but clearly, it's going to be a little bit closer to that date than you originally envisioned. Dave, maybe you can talk a bit about how you're thinking through those mechanics and what your contingency is if you don't close by June 30.

Yes. So I think if you listen to the comments we made, we purposely made the comment that we're sitting with a lot of cash and we have the term loan extension that we just did. We effectively don't need any of the bonds if we cross over past June 30.

Got it. Okay. And then my follow-up there is just, I mean, given the strong start to free cash flow this year, would your preference actually be to have even more short-term prepayable bank debt in the financing mix you originally envisioned just to provide even more short-term debt reduction runway?

We'll think about that. That's more of a maturity management exercise. So that's something we'll think about as we get closer to midyear.

The next question is from Paul Diamond from Citi.

Just a quick circle back. Given the structural takeaway constraints, how do you guys think about opportunities for in-basin growth, whether that's through industrial or other means?

Are you talking about demand growth? Or are you talking about us growing production?

Demand growth in-basin.

You'll have coal retirements as part of that. As you know, the Shell cracker has come on as well. I'd say probably in the neighborhood of 1 to maybe 2 Bcf per day over the next several years is probably a good sort of ballpark number.

Understood. And just kind of a more 30,000-foot question. As you look beyond Tug Hill on the M&A front, should we think about your potential use of any cash flow in the longer term still focusing on costs? Or will any of those goals shift, whether it's to inventory or filling production? How do you guys think about that beyond 2023 and into 2024 and beyond?

On an M&A basis, our strategy will stay the same. Obviously, a commitment to making sure the financial accretion is there. But the differentiating aspect is looking for opportunities that will lower our cost structure. The new dynamic is really the competition is competing with the value from buying back our own stock. Ultimately that may change where we allocate some dollars given where our stock trades, but we're going to stay committed to the disciplined strategy that we've laid out. We think it's created a lot of value and we'll stay disciplined.

The next question comes from Noel Parks from Tuohy Brothers.

I just wanted to talk a bit about when we're thinking about expansion of natural gas into industrial uses, microgrids and so forth. I have in mind your project with Bloom Energy that has been underway for a while now. In a lot of these installations, what becomes evident pretty quickly is the whole grid integration type of issues that can come up, especially when you're looking to resiliency-type applications. I was just wondering, in the energy management system and energy management software market, I'm hearing more and more about that being a focus as people look at projects. Is that something you could potentially see yourself making an investment in, sort of the software and energy integration software? Is that something you could picture yourself doing under the EQT umbrella?

For us, we are very big supporters of electrifying the world. Doing that is going to present a lot of challenges that you mentioned, the resiliency of the grids — are they capable of handling extra load — that presents some serious problems. I think you look at what happened with California where they moved to restrict some internal combustion engines and then later told citizens to not plug in their electric vehicles to charge in certain conditions. This is going to present some big changes but also big opportunities. One of the investments that we've made on our New Ventures front has been an investment in a company that is addressing behind-the-grid power generation — a fuel cell that runs off natural gas and generates power for the size of a microwave that can power your house. These are the types of solutions that are going to strengthen our grid — decentralized, smaller-scale opportunities at price points retail consumers can access. That's the sort of thing we're looking at and it falls into promoting natural gas demand while supporting the electrification theme that's taking place.

Great. Not something I've heard of before, so it's interesting. And just taking another stab at the macro picture, given this incredibly volatile year we've had spurred off by Russia-Ukraine and then the downward move you saw on weather: do you think we are headed towards maybe a permanent level of this sort of volatility? I looked back over the past year, there's maybe only one or two months that haven't seemed to have a $2 swing intra-month on pricing. Is this the new norm we'll get used to? Or do you look at the past year as being more an aberration that will get smoothed out by LNG and export demand?

We're in a world where natural gas is becoming a global commodity and what happens in the world will influence prices here in America. That could introduce more volatility, but we have the opportunity to reduce the volatility and provide more stable, lower prices for Americans and for the world. Our ability to export natural gas is a huge lever. Our production potential supports significant export capacity — we estimate the U.S. has the production potential to support up to roughly 60 Bcf per day of exports over time. That amount of energy is equivalent to adding a very large source of clean energy to the world stage. That's going to be a decarbonizing force and exports mean surplus and surplus means less volatility. Storage levels will stay fuller and the commodities will be underpinned by participants in LNG markets being set with long-term contracts. So we think it's a tremendous opportunity. The world will have volatility; we do not need to accept it. We can respond in America, and energy producers like EQT are key to reducing the volatility.

Yes. And I'd just say we need more storage capacity and we need more pipelines to be able to do it because if you keep taking coal-fired generation, which is baseload, offline and don't replace it with the ability to add more baseload fuel, you're going to increase volatility.

The next question comes from Josh Silverstein from UBS.

You guys mentioned some flexibility in the program for this year, obviously, depending on price. Can you just elaborate a little bit more what that might mean? Would you reduce rigs? Would you just build up DUCs for next year or thoughts and any shut-ins. Just curious what you guys would think about as far as flexing activity.

The simple way to think about it is EQT is going to continue building our production capacity. Whether we deliver that production capacity into the market will be determined by the price that we're receiving for the product. So that means rigs are going to continue to roll forward the development plans, same thing with frac crews, but whether we put that production into the market will be something that we determine at the time when those decisions need to be made.

I mean we're not running 15 rigs; we're running 2. Put in perspective — we don't have a lot of cutting that would be meaningful by reducing rigs dramatically. We can manage production in other ways if we have to.

Got you. Yes. And you guys had rolled some 2022 capital into this year as well, so I wasn't sure. And then just another question on free cash flow allocation. You extended thoughts on debt reduction and buybacks. Relative to your targets, you have about $2.9 billion left in debt reduction and $1.4 billion left in buybacks. So kind of a 2:1 ratio there. How do you think about the allocation to hit those targets, and obviously, depending on the deal, how you're planning to tackle both of those?

We are actually further along on the debt reduction side given the amount of free cash flow that we generate. I think we could see ourselves getting to our target somewhere around midyear next year. That gives us flexibility to buy back stock as well in that timeframe. Once we hit our debt targets, we could then effectively change that ratio to be much more equity-focused, assuming we're being opportunistic. We have a lot of flexibility. Beyond that, we've only allocated about one-third of our free cash flow. So you think about that as a longer-term question of how to deploy capital, and that will be a strategic decision for management over time.

And Dave, the next person in this role will be leveraging the capital allocation framework and the modern hedging strategy we've put in place, so there will be a lot of continuity in the strategic decisions that are made in this organization.

I'll hand back to the management team for concluding remarks.

Thanks for joining our call today. We are in a world that is struggling with energy security. It's been compromised and the ambitions to lower global emissions has never been stronger. Fortunately, EQT is a company that provides energy security to Americans and the world and has the capability of significantly lowering global emissions by using our natural gas to replace coal. We're excited about the opportunity set in front of us, and we will keep our heads down executing on our business. Thank you.

This concludes today's call. Thank you very much for your attendance. You may now disconnect your lines.