EQT Corporation (NYSE:EQT) Q1 2023 Earnings Call Transcript

EQT Corporation (NYSE:EQT) Q1 2023 Earnings Call Transcript April 27, 2023

EQT Corporation beats earnings expectations. Reported EPS is $1.7, expectations were $1.27.

Operator: 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. . I will now hand the floor over to Cameron Horwitz, Manging Director of IR and Strategy. Cameron, ready when you are.

Cameron Horwitz: 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.

Toby Rice: 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 and 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 college 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. While 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 the $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 TILs into 2023 and and assumes 10% to 15% of 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 and 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 Teralytics 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 in the world 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 added $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 purchased a material amount of equity and debt and exited the quarter with an improved leverage position in 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.

David Khani: 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 pills 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 for 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 ’19, our net debt was $5.3 billion. Our proved reserves were 17.5 Tcfe our production — 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 3 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 timing above our current base case expectation, including higher sustained LNG exports, greater industrial demand, and reduce 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 and downside pricing scenarios while maintaining upside exposure. We also have 10% of our 24 volumes hedged at a weighted average floor price of $4.20 per MMBtu and a weighted average ceiling of $5.40 per MMB2. 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 interlated 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 Grand Home show of 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 and we will adjust assumptions if needed. Importantly, gathering rates contractually begin declining in 2025 independent of MVP success, providing a further tailwind to to free cash flow as margins widened by $0.15 from current levels, adding approximately $300 million of annual pretax free cash flow by 2028. Turning to guidance. We are reading our 2023 production outlook of 1.9 to 2 Tcfe. This range provides significant flexibility to respond to evolving macro conditions with the low end of our production guidance of product’s 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.

Toby Rice: 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 Advantage 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.

Q&A Session

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

Arun Jayaram: 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?

David Khani: Yes. So it’s a great question, Arun. So we’ve added about 500 Bcf — I’m sorry, $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 improve realization. So — and 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 leave 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 shows up. So winter is a very positive M3 area. And then like the third piece is, as natural gas NYMEX prices come down, our local basis narrows as the correlation is about 80% to 85%.

So NYMEX goes up. Our basis widens NIM has come down or basis narrows. So those are the 3 impacts of which I’d say the first 2 will probably long-lasting, and we’ll improve — keep doing it. And the last one is going to be obviously subject to what NYMEX prices do.

Arun Jayaram: 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 Serra week 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.

Toby Rice: 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 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, the 5 physics and are only addressing 1 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 that 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 capable solution. So the world has moved back towards a more realistic and more practical approach in 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 time line 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 energy 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. And those criteria are cheap, reliable and clean. And one of the — that seems to be universally accepted as the 3 main criteria. And we’re seeing actions with the administration Secretary Grand Home 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 to throw 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 — a 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. It’s not — in my opinion, it’s not if one of these events happen, it’s when. And we need to build up our industrial energy capacity so that we can deal with these events when they take place. And that’s 1 of the reasons why we believe Perma 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: The next question comes from Umang Chaudhry from Goldman Sachs.

Umang Choudhary: My first question was on the — on your plans. On the outlook, I mean, you appreciate 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.

Toby Rice: 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 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.

David Khani: Yes. And I’d just add, due to the water line issue last year, our production has not — 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.

Umang Choudhary: Got you. That make sense. And then I guess, more for a longer-term question. As you highlighted in Slide 29, we are probably going to be in a volatile gas price environment going forward given you have not built up our gas storage capacity here in the U.S., even as demand has grown. Would love to revisit your thoughts around around the optimal long-term leverage and also on your hedging levels, acknowledging that obviously, your free cash flow breakeven is low, and it’s probably going to even reduce going forward.

David Khani: Yes, it’s a great question because you’re right, with lack of coal-fired generation as baseload with some nuclear coming offline and then replacing it with gas and renewables, you’re going to have more and more volatility going forward. And so as a producer, how do you handle that One, you have to have a very, very strong balance sheet. So having investment grade, having onetime leverage. Maybe over time, we’ll build up cash as well. So our net leverage might even below that 1x. The second is you have to have the low-cost structure, right? So if you notice, we’ve taken our cost structure down from from we’ll call it, $2.85 to $2.90 down into the 220s, right, over time. So very important to be a low-cost producer in a commodity business.

And then third is we’re using our hedging strategy with collars. If we do something on the LNG front, we’ll do stuff with collar. So we’ll try to manage that volatility. And so I think that’s the 3 ways we’ll do it. And I’d say the fourth way is probably also to have very low to no emissions because that means the end market demand will stay very strong for your product on a relative basis.

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

John Abbott: 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?

Toby Rice: Sure. So the $80 million in synergies that we identified primarily came from some midstream synergies, connecting our — 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. So there will be a synergy there. I’d say all these things, 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. And 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 that we ultimately inherit.

Our drilling team is a really great example. Look at the drilling performance that we — the uplift we’ve seen in performance 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. And when we look at that $80 million of synergies, how does that compare to the $0.15 that the Tog Hill transaction will impact by lowering our free cash flow breakevens, these $80 million would be an additional $0.04 and on top of that $0.15 just shows you the impact of adding this asset under our belt will be very impactful in lowering our costs.

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

Toby Rice: Combo development does factor into the synergies the dual development also will take place. I’d say the only other logistical impact that will present itself is — the frac activity that’s taking place on the Tolko 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 team is — 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 in the Tuck Hill assets will give us a little bit more flexibility on how to achieve that.

John Abbott: Appreciate it. And then I want to go back to Arun’s earlier question on differentials. So Dave, it sounds — as you said, you’ve had about $500 million of FT over the last 18 months. How do you describe the opportunity set sort of going forward to improve on realizations going forward at this point? What is — how do you think about available FT coming up? What is the opportunity set there for you to improve realizations at this point?

David Khani: Yes. So I would just say there are other producers in the basin that are letting FT go. And so as that comes available, we’ll pick it off I don’t want to get too specific because, obviously, we want to execute on first and then we’ll talk about it. But there — I’d just say there are pieces out there over time that we will pick up and continue to grow that number. And I’d just say as producers have less and less inventory in the basin, those opportunities just grow.

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

David Deckelbaum: 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?

Toby Rice: Sure. Just to level set what we’ve seen, we’ve seen a 10% reduction in rigs that were focused on gas. It’s 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 next year 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. .

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

David Deckelbaum: 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 like short-term curtailment profile? And you highlight at a corporate level now your free cash breakeven this year are $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? .

David Khani: Yes. We look at it at a field level. We look at it both, but — and we could tell things, I’d say, at moments in time, we don’t really talk about it much. So there might be a weekend here, we can there — but when we want to do like a broader, larger, then we’ll look at the overall rates of return. We’ll look at the forward curve. And make a decision about are we — can we create value by moving gas into the, future as opposed to keeping it producing today. So — you know we’ve shut in production in 2020 a couple of times, but we also shut in production in ’21 that we didn’t really talk much about. Those are shorter term in nature. So we’ll do it both field and corporate.

David Deckelbaum: I appreciate that, David. And if I could just ask a little bit more on just Umang’s question earlier around the hedge book. The curve for ’24 is kind of sitting in and around the area where you guys had hedged out for ’23. You don’t have much hedge volumes in ’24 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 ’24 curve?

David Khani: Well, when we hedge and we use collars, okay, we like to see SKU in the — when we do that. And so the best times to add collars is when you have an upper movement 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. But what we’re also seeing is we’re seeing activity slowing on the gas side. We’re seeing activity starting to slow on the coal side, and we’re heading into the summer months here, which is a catalyst. And 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’re going to see it come in short of that.

And then the second is, if you think about storage, even at 4 Tcf, that’s basically 30 days of cover which if you understand the commodity business, I know you do, you really need 60 days to really provide any buffer in a peak demand period. So we see if you get normal winter, you could see spike in gas and you really need about 400 Bcf of incremental storage in 2024 to be able to support that incremental LNG that’s coming online in ’24. So I think we’re seeing a very positive setup here. The big negative could be if summer doesn’t show up and we do on show up. And that’s why we like to hedge is to manage those risks. So 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 trying to make sure that we get from a timing perspective and how we hedge right.

Operator: The next question comes from . Your line is open. Please go ahead.

Unidentified Analyst: You touched on the , 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 there — are you comfortable with your mix? Or are you looking at M&A or midstream partnerships?

David Khani: Yes. So the volumes down to the Gulf, that’s all physical. That’s not financial. And so — and we are looking to add more over time, and there is 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. And 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 will play more of a role in the Gulf Coast as Haynesville tries to grow and Permian tries to growth. So you need to have Gulf Coast and hedging as a strategy now. Once you get tied up into the LNG market, then 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.

Unidentified Analyst: 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, that’s how you decide what activity level to do?

David Khani: Well, right now, until we have all LNG off the East Coast, 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 dividend. If we were to get access to East Coast LNG and be able to grow, which we’re talking — we’ll call it 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 at a, we’ll call it mid-cycle price, and then we’ll compare it against the value we can get to lock in that growth with LNG pricing.

Operator: The next question comes from Harry Matti from Barclays.

Unidentified Analyst: Circling back to Tug Hill, the bonds you issued last year had some SMR 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 of closing so last June.

David Khani: 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 into past June 30.

Unidentified Analyst: 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 and the financing mix. you originally envisioned just to provide even more short-term debt reduction runway?

David Khani: We’ll think about that. That’s more of a, I’ll call it, maturity management exercise. So that’s something we’ll think about as we get closer to midyear.

Operator: The next question is from Paul Diamond from Citi.

Paul Diamond: Just a quick circle back. I mean given the — kind of looking beyond 2023 and given structural takeaway constraints, — how do you guys think about opportunities for in-basin growth, whether that’s through industrial or other means?

David Khani: Are you talking about the demand growth? Or you’re talking about us growing production?

Paul Diamond: Demand growth in basin.

David Khani: Yes. So you’ll have coal retirements as part of that. As you know, the Shell cracker has come on as well. And — and I would 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.

Paul Diamond: Understood. And just kind of a more 30,000-foot question. As you look kind of beyond Tug Hill on the M&A front, — should we think about your guys’ potential use of any cash flow in a longer term, still focusing on costs? Or will any of those — any of those goals kind of shift, whether it’s to inventory or filling production? Or how do you guys think about that kind of beyond in ’24 and beyond. .

Toby Rice: 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. And the new dynamic is really the competition is competing with the value from buying back our own stock. So I mean, that ultimately is going to be the thing that changes given where our stock trades, but we’re going to stay committed with this strategy that we’ve laid out. We think it’s created a lot of value and we’ll stay disciplined.

Operator: The next question comes from Noel Parks from Tuohy Brothers.

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

Toby Rice: For us, we do — are very big supporters of electrify 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 presents some serious problems. I think you look at — see what happened with California where the are going to ban ICE engines and then a week later tell their citizens to not plug in their electric vehicles and the to charge them. This going to present some big changes but they’re also going to present some big opportunities. One of the investments that we’ve made on our new ventures front has been an investment in a company that is going to address the behind the grid power generation company called what fuel cells is creating basically a fuel cell that runs off natural gas and generates power for the size of a microwave can power your house.

These are the type of solutions that are going to strengthen our grid but it’s going to be the decentralized smaller scale opportunities that will exist and at price points that retail consumers can get into. So that’s sort of what we’re looking at and that falls into our promoting natural gas demand while supporting the electrification theme that’s taking place.

Noel Parks: Great. Not something I’ve heard of before. So it’s interesting. And just taking another stab at sort of the macro picture. If we look at sort of this incredibly volatile year we’ve had sort of spurred off by Russia, Ukraine and then sort of the downward move you saw on weather. Do you think that we are I mean the software a long time was that LNG and that export demand, if anything, might sort of contain volatility a bit. But I’m wondering if it may be — the reality is that we’re going to see from geopolitical pressures and seasonal variances. Is it conceivable you think that we’re headed towards maybe a permanent level of this sort of volatility I mean, I looked back over the past year, there’s maybe only 1 or 2 months that haven’t seemed to then like a $2 swing intra month on pricing.

So yes, I guess I just interested in your thoughts on is — is this the new norm we’re going to get used to? Or do you look at the past year as being more an aberration that will indeed get smoothed out by.

Toby Rice: Yes. So 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. So that could introduce more volatility, but we have the opportunity to reduce the volatility and provide more stable, lower prices for Americans and also for the world. Our ability to export natural gas, our potential is here in this country is 60 Bcf a day is what we think we have the production potential to put that amount to bring that amount of energy into the world, put it on the water and provide energy security for the world. that amount of energy is equivalent to 10 million barrels a day. It’s equivalent to adding a Saudi Arabia of clean energy to the world stage. That’s going to be a decarbonizing force and exports mean surplus and surplus means less volatility.

Stores levels will stay fuller and the commodities, I think, ultimately will be underpinned in the economics to the people participating in LNG will be set with long-term contracts. So the certainty on pricing and the economics of the investments that we’re making will be shored up. So we think it’s a tremendous opportunity. The world will be volatility. We do not need to accept it. We can respond in America and energy producers like EQT are the key to reducing the volatility.

David Khani: 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 kind of fuel. You’re going to increase volatility.

Operator: The next question comes from Josh Silverstein from UBS.

Josh Silverstein: Great. SP249079218’s 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. . Josh, the simple way to think about it is EQT is.

Toby Rice: Going to continue building our production capacity. Whether we deliver that production capacity into the market will be — at what levels will be determined by the price that we’re receiving for the product. So that means rigs are going to continue to roll roll forward the development plans, same thing with frac crews, but whether we put that production into the market will be something that we determined at the time where those — where that decision will be made.

David Khani: Yes. I mean we’re not running 15 rigs we’re running 2 put in perspective — so we don’t have a lot of cutting 50% of our rigs would be more damaging to us. We can manage the production in other ways if we have to. .

Josh Silverstein: Got you. Yes. And you guys had rolled some 2022 capital into into this year as well, so I wasn’t sure. And then just another question on free cash flow allocation. Europe you extended the thoughts on debt reduction and buyback out, obviously, because of the delay in closing the Tokyo transaction. But relative to your targets, you have about $2.9 billion left in debt reduction, $1.4 billion left in the buyback. So pkind of a 2:1 ratio there. How do you think about the allocation of and hit those targets, and obviously, depending on the deal, but just as far as how you’re thinking about the — wanting to tackle both of those.

David Khani: Yes. So we are — we’re actually further along on the debt buyback is the amount of free cash flow that we generate. And so I think we could see ourselves getting to a target somewhere around midyear next year. That gives us flexibility to buy back stock as well in that. So I’d say Q1 is probably still a good ratio. And then once we hit our debt targets, we could then effectively change that ratio be much more equity if you want to, assuming we’re going to be opportunistic, right? But we have — we’ll have a lot of flexibility. And then just beyond that, you think about it, we really only allocated about 1/3 of our free cash flow. So you think about that as a longer term — how do we deploy that capital. And again, that will be and the next guy sitting in my seat role to figure out how to allocate capital properly.

Toby Rice: And Dave, the next guy is going to be leveraging the capital allocation framework that you put in place, the modern hedging strategy put in place. So there’ll be a lot of continuity in the strategic decisions that are made in this organization.

Operator: So I’ll hand back to the management team for concluding remarks.

Toby Rice: Thanks for joining our call today. thanks for joining the 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. So we’re excited about the opportunity set in front of us, and we will keep our heads down executing on our business. Thank you.

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