EQT Corporation (NYSE:EQT) Q1 2024 Earnings Call Transcript

EQT Corporation (NYSE:EQT) Q1 2024 Earnings Call Transcript April 24, 2024

EQT Corporation isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good morning. My name is Brianna and I will be your conference operator today. At this time, I would like to welcome everyone to the EQT First Quarter 2024 Results Conference Call. [Operator Instructions] After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] I would now like to turn the conference over to Cameron Horwitz, Managing Director, Investor Relations and Strategy. Please go ahead.

Cameron Horwitz: Good morning and thank you for joining our first quarter 2024 earnings results conference call. With me today are Toby Rice, President and Chief Executive Officer; and Jeremy Knop, Chief Financial Officer. In a moment, Toby and Jeremy will present their prepared remarks with a question-and-answer session to follow. An updated investor presentation has been posted to the Investor Relations portion of our website and we will reference certain slides during today’s discussion. A replay of today’s call will be available on our website beginning this evening. I’d like to remind you that today’s call may contain forward-looking statements. Actual results and future events could materially differ from these forward-looking statements because of the factors described in yesterday’s earnings release, in our investor presentation, the Risk Factors section of our Form 10-K and in subsequent filings we make with the SEC.

We do not undertake any duty to update any forward-looking statements. Today’s call also contains certain non-GAAP financial measures. Please refer to our most recent earnings release and investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. With that, I will turn the call over to Toby.

Toby Rice: Thanks Cam and good morning, everyone. Last month, we announced our agreement to acquire Equitrans Midstream, a transaction that will transform EQT into America’s first vertically integrated large-scale natural gas business. As we described in our conference call last month, this deal catapults EQT to the absolute low end of the North American natural gas cost curve, providing free cash flow durability in the low parts of the commodity cycle, while simultaneously unlocking unmatched price upside by mitigating defensive hedging needs, thus providing investors with peer-leading risk-adjusted exposure to natural gas prices. This combination is anticipated to drive our long-term, free cash flow breakeven price to approximately $2 per million Btu, which is $0.75 below the peer average and $1.50 below the marginal cost of supply in the Haynesville.

This gap between EQT and both average and marginal natural gas producers is a sustainable advantage, which is rare to find among any commodity business and ensures EQT is best positioned to create through-cycle value for shareholders, while other producers are forced to either chase commodity prices with the drill bit in a similar fashion to what has led to historical industry value destruction or defensively hedge a significant amount of production, thus limiting the ability to capture value in the upcycle. Along with the material cost-structured vantage, the combination of EQT and Equitrans will also create an integrated well-to-watt solution that will help enable and power growing demand associated with the data center and artificial intelligence booms that are burgeoning across the Southeast and Mid-Atlantic regions of the United States.

Our base case view suggests the proliferation of data centers, along with growth in other electricity-intensive markets, such as electric vehicles, to drive an incremental 10 Bcf per day of natural gas demand by 2030, while there is a plausible upside case that could take this number up to 18 Bcf per day. This means growth in the power generation segment could exceed LNG exports as a bullish demand catalyst for the natural gas market this decade, and this structural base-low demand growth story resides at the doorstep of our asset base. Our 1.2 Bcf per day of capacity on MVP, along with the long-term firm sales arrangements we announced with investment grade utilities last year, means EQT’s low emissions natural gas will be a key facilitator of the data center buildout occurring in the Southeastern United States and will give us significant exposure to premium Transco Zones 4 and 5 price points.

Due to the confluence of LNG facilities pulling gas south on Transco and power demand growth in the Southeast, we expect this region will become even more desirable than the Gulf Coast later this decade. As a result, we intend to pursue an expansion of MVP through additional compression to increase capacity from 2 to 2.5 Bcf per day, which will provide additional affordable, reliable, and clean Appalachian natural gas to our downstream utility customers. On top of the tremendous opportunity to serve as customers in the Southeast, where we already have first mover advantage through our record-sized physical gas supply deals with utilities we announced last fall, EQT is ideally situated to meet significant growth in power demand within PJM as well.

Our analysis suggests the combination of data center buildouts and additional coal retirements could generate up to 6 Bcf a day of incremental natural gas power demand in our own backyard by 2030. Whether it’s in the Southeast or at the doorstep of our asset base in Appalachia, EQT is well-positioned to capture this thematic tailwind through our material inventory depth and integrated business model that will create a one-stop shop to provide clean, reliable, and affordable natural gas that will be foundational to meeting America’s power needs as we embark on what will be a transformational journey into the age of AI. Turning briefly to first quarter results. The significant operational momentum we achieved last year has carried into 2024, which facilitated better-than-expected results across our drilling and completion teams in Q1.

The continuation of highly efficient operational execution, along with strong well performance and lower-than-expected LOE associated with our water infrastructure investments, drove outperformance relative to consensus expectations across every major financial metric during the first quarter. We continue to find new innovative ways to push the envelope of what is possible, and I want to thank our entire crew for their relentless pursuit of operational excellence. Shifting gears, last week we announced an agreement with Equinor to sell a 40% undivided interest in our non-operated natural gas assets in Northeast Pennsylvania. Consideration is comprised of $500 million of cash and upstream and midstream assets worth more than $600 million, implying EQT is receiving total value north of $1.1 billion in this transaction.

For perspective, we attributed approximately $1.1 billion of value to 100% of the Northeast PA non-op assets when we originally acquired them as part of our Alta acquisition, and the assets have already generated free cash flow in excess of that amount in the past two years. So this transaction marks an incredibly successful outcome for shareholders and a strong start to our deleveraging plan. The upstream assets we are receiving include approximately 26,000 net acres in Monroe County, Ohio, directly offsetting EQT operated existing core acreage in West Virginia. We are also receiving an average working interest of 14% in more than 200 producing wells that EQT currently operates in Lycoming County, Pennsylvania, along with a 16.25% interest in the EQT-operated Seely and Warrensville gathering systems servicing this acreage.

Following the closing of this transaction, EQT will own 100% of the Seely and Warrensville gathering systems which aligns with our strategy of lowering cost structure via vertical integration. I’d also note, our teams have identified significant operational synergy potential across the operated assets as well as longer term upside associated with the liquids-rich Marcellus in Monroe County. The non-operated assets we are selling have forecasted 2025 net production of approximately 225 million cubic feet per day, while the operated assets we are receiving have forecasted 2025 net production of approximately 150 million cubic feet per day. Comparing to $1.1 billion of total value to the 225 million cubic feet per day of total production we are selling, implies a roughly $4,900 per Mcf flowing production multiple.

While looking at metrics using net divested production and comparing this to the $500 million of cash consideration equates to roughly 6,700 for flowing Mcfd production multiple. We believe these attractive transaction metrics speak to the value of the high-quality natural gas assets, which are increasingly being coveted by international buyers looking to get exposure to the U.S. natural gas market. This transaction highlights that we are wasting no time jump starting the deleveraging plan we laid out with the Equitrans announcement and creating additional shareholder value in the process. The sale of our remaining 60% interest in these non-operated upstream assets and the option to monetize regulated or non-core midstream assets at Equitrans gives us tremendous confidence in our ability to achieve our debt repayment goals, and we look forward to updating the market as we make additional progress on this front.

To sum up, first quarter results demonstrate a continuation of peak performance at EQT. Our announcement of the Equitrans acquisition is a once-in-a-lifetime opportunity to vertically integrate one of the highest quality natural gas resource bases in the world, creating a one-stop shop to provide natural gas that will meet the growing data center and power generation needs at the doorstep of our asset base. And our recent transaction with Equinor illuminates significant hidden value embedded in our non-operated natural gas assets and gets us off to an extremely strong start towards achieving our deleveraging goals. I’ll now turn the call over to Jeremy.

Jeremy Knop: Thanks Toby, and good morning, everyone. I’ll start by summarizing our first quarter results beginning with sales volumes, which totaled 534 Bcfe. As previously announced, we curtailed 1 Bcf per day of gross production beginning in late February and through all of March in response to the low natural gas price environment resulting from warm winter weather. Along with non-operated curtailments, we estimate the total impact was 30 to 35 Bcfe during the quarter. Thus, normalized for curtailments, first quarter production would have been toward the high-end of our guidance range, underscoring strong operational efficiency and well performance during the quarter. Despite the curtailments during the quarter, our per unit operating costs still came in at the midpoint of our guidance range at $1.36 per Mcfe.

A significant contributor to this was the outperformance on LOE, which came in below the low-end of our guidance range. This LOE beat represents a continuation of the trend of LOE outperformance we highlighted throughout 2023, as our strategic investments in water infrastructure continue to drive tangible cost structure reductions. Turning to the balance sheet. Recall, we retired all of our outstanding convertible notes, which eliminated $400 million of absolute debt over the past two quarters. We also liquidated the capped call that we had purchased in conjunction with issuing the convertible notes for cash proceeds of $93 million. Additionally, we issued a $750 million 10-year bond and use the proceeds to reduce our term loan balance from $1.25 billion to $500 million, while extending the maturity by 12 months to June 2026.

We exited the first quarter with total debt of approximately $5.5 billion and roughly $650 million of cash on the balance sheet, leaving a net debt position of approximately $4.9 billion at the end of the quarter, down from $5.7 billion at the end of 2023. Subsequent to quarter-end, we used $205 million of our cash balance to fund the previously announced buyout of a minority equity partner in EQT operated gathering systems in Lycoming County, Pennsylvania, which closed earlier this month. This acquisition is expected to add approximately $30 million to our 2025 free cash flow outlook, highlighting an attractive free cash flow yield on assets that are annuity-like and have near zero execution risk due to EQT’s existing operatorship of both upstream development and the midstream system.

We intend to apply the remainder of our cash balance, along with the $500 million of cash proceeds from the Equinor deal towards debt reduction, which will allow us to make swift and significant progress toward the deleveraging goals that we laid out with the Equitrans announcement. We also recently added to our Q4 2024 and first half 2025 hedge book to further derisk our deleveraging plans. We are now between 40% and 50% hedged for the remainder of 2024 with an average floor price of approximately $3.40 per MMBtu. We are also approximately 40% hedged in Q1 and Q2 of 2025 with average floor prices ranging from roughly $3.05 to $3.30 per MMBtu. Upon closing the Equitrans acquisition and achieving our debt targets, we anticipate limiting defensive programmatic hedging to less than 20% of our production in a given year.

Going forward, our $2 Henry Hub free cash flow breakeven price provides a structural hedge as the Equitrans acquisition strips out the operating leverage from our business, limiting our need to financially hedge. This unique dynamic provides EQT’s investors differentiated upside torque to natural gas prices and peer-leading downside protection simultaneously. Turning to the 2024 outlook we issued, second quarter guidance and updated our full year production outlook to reflect voluntary production curtailments in response to the current low natural gas price environment. Our second quarter production outlook and per unit metrics embed the expectation that we will continue to curtail 1 Bcf per day of gross operated production through the end of May.

Our updated full year production guidance also captures this assumption and embeds additional optionality for further curtailments this fall should natural gas prices remain low. We believe our strategy of near-term curtailments while maintaining steady operations is the right approach to this market for EQT. In contrast to high cost producers who need to cut activity to reduce CapEx in hopes of remaining free cash flow positive. It is also important to remember that production is fungible between old wells and new wells so it makes little sense to defer new well TILs versus simply turning off production today. Our production today is a product of our investments in the last two to three years, and our CapEx investments today have little impact on the volume this year, but rather drive volumes in 2025 and 2026, when the futures market suggests gas prices will be higher than they are today.

EQT is positioned to take this approach as a result of our low-cost structure and strong balance sheet. And this is a good reminder of why we refer to a low-cost structure as our strategic North Star. We also embedded a June startup for MVP and our updated outlook on the heels of Equitrans’ filing for in-service with the FERC this week. This represents a meaningful milestone as MVPs in-service is a contractual condition precedent to closing the Equitrans acquisition and will finally allow EQT to provide much-needed natural gas to consumers in the Southeast region to meet growing power demand, displace coal and improve grid reliability. As Toby mentioned, upon closing of the Equitrans acquisition, we intend to pursue expanding MVP from 2 Bcf per day to 2.5 Bcf per day to meet additional demand growth expected in the Southeast region.

This expansion will be achieved through the addition of compression to the existing pipe rather than laying new steel and thus has a low execution and regulatory risk profile and high returns with an estimated build multiple of just four to five times EBITDA. Turning to slide seven of our investor presentation, we provided more granular details on how the Equitrans transaction is expected to impact EQT’s pro forma cost structure. While we are still working through some of the nuances of exactly how the transaction will be accounted for in our financial statements, this cost walk should give investors a good framework for thinking about the pro forma impacts of the transaction. In summary, we expect the transaction to drive a pro forma unlevered cost structure improvement of approximately $0.50 per Mcfe.

Base synergies equate to approximately $0.12 per Mcfe and upside synergies provide a further $0.08 improvement. So the cost structure benefits to EQT from the Equitrans deal could total approximately $0.70 per Mcfe over time. That is a monumental impact. The advantage arising from this cost structure improvement is evident on slide 10 of our investor deck, where we show cumulative 2025 to 2029 free cash flow for pro forma EQT and natural gas peers at gas prices ranging from $2.75 to $5 per MMBtu. EQT’s pro forma free cash flow durability is peer-leading at $2.75 natural gas prices as we project approximately $8 billion of cumulative free cash flow versus most peers to our free cash flow negative at this price deck. At the same time, free cash flow and an upside price environment, pro forma cumulative free cash flow generation of a staggering $26 billion.

And importantly, most peers will actually have much less upside than shown here as they are likely to defensively and programmatically hedge away much of the commodity price upside to protect the downside risk resulting from high operating leverage. This underscores how the Equitrans acquisition drives free cash flow durability and down cycles, while unlocking the ability to capture asymmetric upside in high priced environments, given limited financial hedging needs. I want to close by sharing a few observations from the more than 100 meetings we’ve had with EQT and Equitrans shareholders in the wake of our acquisition announcement. While we have already experienced a high grading of our shareholder base over the past several years, the Equitrans transaction has further accelerated this trend as the merits of pairing the characteristics of a major integrated company with the superior long-term demand profile of natural gas is resonating extremely well, and we have been encouraged by the near unanimous support for the transaction from some of the world’s largest, most thoughtful long-term fund managers, including shareholders of Equitrans who have expressed excitement in owning significant stakes in the new EQT.

We think our easy-to-own business model will be increasingly coveted by long-term coffee can style investors who are structurally bullish natural gas long-term. and we look forward to demonstrating this differentiated value proposition for shareholders as we navigate the volatile world ahead. And with that, we’d now like to open up the call to questions.

See also 15 Best Places in Minnesota For A Couple To Live On Only Social Security and 20 Biggest Precious Metals and Minerals Companies in Australia in 2024.

Q&A Session

Operator: Thank you. We will now begin the question-and-answer session. [Operator Instructions] Your first question comes from the line of Neil Mehta with Goldman Sachs.

Atidrip Modak: Hey, this is Ati on for Neil. Guys, I’d be curious on the non-operated asset sales in the pipeline, how are you thinking about the portion that’s remaining? How the conversations are going with potential buyers? And what should we expect in terms of the structure of those deals? Should it be similar to what you’ve announced, or is it going to be a little bit more cash-oriented?

Jeremy Knop: Yeah. So we’re continuing to have some really constructive conversations there and have a lot of great momentum. And I think what we’re seeing is the announcement of the deal with Equinor a couple of weeks ago is actually really catalyzing those to move forward even more swiftly. So we have a ton of confidence in getting that done and a lot of great dialogue that’s ongoing. Look, I think the deal with Equinor was a little bit unique because they had other strategic objectives in their exit from U.S. onshore. That’s why we structured that deal way we did, but I’d anticipate the remaining sale of that interest to be in the — in cash consideration as opposed to a more complex kind of mix of assets and cash.

Atidrip Modak: Got it. Appreciate that. And then as you think about the supply/demand macro for natural gas in the U.S. right now, you did mention that you will extend the cuts, how are you seeing the response — the production response that you’re seeing from the latest numbers? Is that — is there an element of sufficiency there? Do you think there’s additional cuts required? And how should we think about your philosophy as you think of bringing the cadence back online?

Toby Rice: Yeah. We think that you’re going to continue to see cuts and discipline from other operators. But I think a lot of eyeballs are focused on what’s going to happen with some weather with a normal summer, that could bring the — that could tighten up some of the storage overhang we have. And then also these low gas prices are going to more power demand. So, I mean, we think there’s a couple of catalysts here. But in the meantime, until those hit, I think you could continue to see more patients from operators.

Jeremy Knop: Yeah. At a high level, when you think about the macro outlook, you added about 400 Bcf a day into storage in excess from the winter weather, another 200 on top of that from production being higher than we all forecasted. So you have an overhang of about 600 Bcf that has to get worked out by, call it, October. And that will happen — the market mechanism forces that to happen both through curtailments to limitations and supply but also increases in demand from coal to gas switching. And as Toby said, certainly constructive summer weather can give that a boost as well. But look, I think to maintain that market rebalance through the summer, you probably maintain low prices. It probably can’t rise all that much. But once you get through that October period, you see the inflection of LNG demand really start to pick up. we think that market starts to change pretty swiftly.

Atidrip Modak: Awesome. Appreciate the answer to that. Thank you.

Operator: Your next question comes from Arun Jayaram with J.P. Morgan. Please go ahead.

Arun Jayaram: Good morning. Gentlemen, wanted to get your thoughts on — obviously, the data center demand. You highlighted in your deck how you think that this could create kind of a premium opportunity for gas that’s sold on the Transco Zones 4 and 5 South lines. I was wondering if you could give us — just your general thoughts on how different may play out in the Appalachia Basin over time and specifically highlight your leverage to these two zones.

Jeremy Knop: Yeah, Arun. So, look, I’d start with going back to those physical gas sales deals that we announced in Q3, Q4 last year. And if you look at the way that was structured, we tranche that out across those markets. And so, those were sold in tranches ranging from M2 plus $1.15, all the way up to Henry Hub plus $0.50, right? So we gave you guys the blended pricing for how that impacts the company. But to us, that sort of keyed us off to a lot of the demand and the tailwinds that are really coming that the utilities are seeing. And effectively, the premium being paid is to lock-in reliability of supply. And so I think that’s a good proxy for where that market moves in time. And if you think about what’s happening between just electrification of everything, now adding data centers into that and think about the way the Transco pipeline, where it supplies gas across the country, you’re going to see the LNG facilities pull gas south on that pipeline and create an even bigger deficit in that Southeast market.

So we think that market really in time becomes the most premium market in the country, because you have a combination of LNG pulling gas away and a deeper deficit from all these other factors we’re talking about, whether it’s retirement of coal, whether it’s data center growth. And so that’s why the utilities, I think, are willing to pay the prices that they did to lock up reliable gas supply. That’s the reason we’re so excited about expanding MVP and adding additional capacity because we think — I mean, there’s a big demand sync being created in that market from both themes, but it’s really the confluence of both of those big demand themes that’s going to drive that market where it is. That’s why we’re so excited about MVP and also where our asset sits adjacent to that market.

Arun Jayaram: And just I have a follow-up. We had been liaising with a couple of utilities and they mentioned how Governor Shapiro in Pennsylvania was somewhat focused on trying to keep grow demand within the state. And so, I just wondered, Toby, give your perspective on some of the thoughts because Pennsylvania, as you know, exports electricity and gas. Thoughts about some of that data center demand coming within the state of Pennsylvania as well as any latest views on East Coast LNG.