Title

Presentation

Operator: Good morning, and thank you for attending today’s EQT Q4 2022 Quarterly Results Conference Call. My name is Jason, and I’ll be the moderator for today’s call. All lines will be muted during the presentation portion of the call and opportunity of question and answers at the end. I would now like to pass the conference over to our host, Cameron Horwitz Managing Director, Investor Relations & Strategy. You may begin.

Cameron Horwitz: Good morning, and thank you for joining our fourth quarter and year-end 2022 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, in 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 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. 2022 proved to be a year marked by tremendous geopolitical and natural gas price volatility. That said, through the ups and downs, EQT never took its eye off the ball in our relentless drive towards improving efficiency, lowering our cost structure, reducing our emissions intensity and generating meaningful value for our shareholders. I am extremely proud of the positive milestones we achieved last year and want to briefly reflect on our accomplishments. On the financial side of our business, we generated almost $2 billion of free cash flow, achieved investment-grade credit ratings. EQT stock was added to the S&P 500 Index and we executed our capital return strategy with $1.7 billion of shareholder returns via debt retirement, a base dividend and share repurchases.

On the operations front, despite a challenging oil field service and infrastructure environment, we successfully implemented sand hauling and flowback initiatives that will structurally improve cycle times achieved meaningful completion efficiency gains in the latter part of the year that have continued into early 2023, eclipsed the basin record for drill out performance by a factor of almost 2 times and reduced top hole drilling costs on our Northeast Appalachia position by 30%, leveraging lessons learned from Southwest Appalachia. On the M&A front, we announced the accretive acquisitions of Tug Hill and XcL Midstream which checks all of the boxes of our guiding M&A principles, including accretion on free cash flow and NAV per share while strengthening the free cash flow durability of our business through a material reduction in our cost structure and improved operational control through midstream integration.

As it relates to the positive social impact of our business, EQT paid out over $1.8 billion in royalties last year to roughly 39,000 mineral owners in nearly every state in the country. Our organization also made almost $5 million in childhood donations last year, and our employees volunteered over 13,000 hours during 2022. Building on our leadership among decarbonization efforts, we completed our pneumatic device replacement initiative, a full year ahead of schedule, received a gold standard rating from the Oil and Gas Methane Partnership, or OGMP bear headed the launch of the partnership to address global emissions in the Appalachian methane initiative, and we announced the collaboration to form the Appalachian Regional Clean Hydrogen Hub or ARCH2.

Our 2022 achievements represent yet another positive step of the journey we’ve been on since taking over the helm of GT in 2019. Over this period, our team has improved asset productivity, strengthened our balance sheet, evolved our hedging strategy and added to our successful M&A track record, creating a durable free cash flow focused business model that will thrive in all natural gas price scenarios. These efforts will inevitably show through in 2023 and beyond and position EQT to create differentiated through-cycle value for all of our stakeholders. As previously mentioned, 2022 marked a significant milestone on our path to net 0 emissions as we eliminated 100% of our nearly 9,000 natural gas powered pneumatic devices from our production operations.

The impact of this effort is substantial as we reduced our methane emissions by 70% compared to 2021 levels and lowered our annual carbon footprint by roughly 305,000 metric tons of CO2 equivalent which is equivalent to taking over 66,000 passenger vehicles off the road. The coordinated effort covering 3,000 wells in nearly 550 pad sites is another testament to EQT’s ability to efficiently engineer and execute projects at scale. Our team completed this effort a full year ahead of schedule at a cost of $28 million. This equates to a carbon abatement cost of just $6 per ton, highlighting our position at the lowest end of the carbon abatement cost curve globally. The successful execution of our pneumatic device replacement program materially derisks our path to net zero by 2025.

And at which point, EQT will be the first energy company in the world of meaningful scale to achieve net zero GHG emissions on a scope 1 and 2 basis. We view the emissions profile of our natural gas as a strategic asset for our shareholders ensuring that EQT’s molecules will remain among the most coveted in the world for decades to come. In addition to our individual emissions reduction success, we also recently spearheaded the launch of the Appalachia Methane initiative, or AMI, to further enhance methane monitoring throughout the Appalachian Basin. AMI will promote greater efficiency in the identification and remedy of potential fugitive methane emissions to a coordinated satellite and aerial surveys with monitored results through transparent publicly available reporting.

This basin-wide sector agnostic approach to methane monitoring will not only allow accountability for methane emissions from all emitters, we believe it will eliminate any doubt that Appalachian natural gas is the cleanest form of traditional energy in the world. Turning to our reserve report. When taking the range of EQT in 2019, our team implemented multiple initiatives aimed at creating consistent, predictable well performance in systematically minimizing parent-child impacts via large-scale combo development. These initiatives have laid the foundation for our team to generate a solid track record of forecasting accuracy with well performance projections regularly within accuracy. This consistency is reflected in our 2022 reserve report as our proved reserves were up modestly year-over-year to more than 25 Tcfe Included in this number is more than 350 Bcfe of positive performance revisions, underscoring the strong productivity trends we have achieved over the past several years and a long-term repeatability from our deep core inventory.

We also note the core Lower Marcellus formation accounts for 99% of our proved undeveloped reserves, meaning we have essentially no future bookings associated with secondary targets. At the year-end 2022, SEC NYMEX price deck of $6.36 per million Btu, our after-tax proved reserve value is $40.1 billion, which equates to $100 per share after subtracting our current net debt. As shown on Slide 6 of our investor presentation, after-tax proved reserve value ranges from $14 billion at $3.50 gas to $41 billion at 650 Gas, which equates to $28 to $101 per share after deducting net debt. We believe this underscores the extremely favorable risk/reward setup for EQT stock as our proved reserves ascribe value to just 300 net locations or roughly 15% of our risk inventory of greater than 1,800 and core remaining locations.

Looking to 2023, we are setting a capital budget of $1.7 billion to $1.9 billion this year, excluding our pending Tug Hill acquisition. This contemplates turning in line 110 to 150 net wells, which is up from 74 in 2022 as third-party constraints shifted roughly 30 kills into 2023. Reserve development accounts for approximately 82% of our 2023 spending forecast. Land and lease is 7% in other, including facilities, midstream and capitalized items comprises 11%. Our budget assumes 10% to 15% of year-over-year oilfield service inflation includes $100-plus million for TIs that have shifted from 2022 into 2023 and approximately $50 million for new well design science, $40 million for midstream and roughly $15 million for new ventures. Our 2023 production guidance is 1.9 to 2 Tcf which is consistent with our prior commentary of getting back to the 500 Bcfe per quarter of run rate production by the middle of this year.

We’ve seen solid completion efficiency trends in Q4 and throughout January giving us confidence in our operational execution early in the year. That said, the low end of our guidance range contemplates a scenario where we slow our production cadence for the year should natural gas prices continue to deteriorate. At the midpoint of our guidance ranges, our implied all-in 2023 capital efficiency equates to approximately $0.90 per Mcfe. Given the catch-up capital associated with kills shifting from 2022 into 2023 will be nonrecurring on a go-forward basis, we expect our capital efficiency to improve by 5% to 10% in 2024 and beyond, as our till count normalizes and CapEx declines to run rate levels. On Slide 31 of our investor presentation, we provided a range of 2023 adjusted EBITDA, operating cash flow and free cash flow outlooks at various natural gas prices.

We project adjusted EBITDA will range from roughly $2.9 billion at $3 gas to $3.9 billion at $4 gas and free cash flow from roughly $900 million to $2 billion at a similar price range, implying a free cash flow yield range of 8% to 17%. Recall our hedge book provides significant downside cash flow protection this year as we have 62% of our 2023 production hedged with a weighted average floor price of approximately $3.37 per million Btu. As highlighted on Slide 10 of our presentation, EQT offers the most compelling risk-adjusted exposure to natural gas with the highest 2023 free cash flow generation among the GACE peers across all reasonable commodity price scenarios. With the reductions in our corporate cost structure and our well-positioned hedge book, EQT’s free cash flow breakeven price in 2023 is approximately $1.65 per million Btu, which is roughly 40% below the peer average and among the lowest of all natural gas producers in the country.

I’d also note this number assumes no impact from the low-cost Tug Hill and XcL midstream assets, which is expected to further lower our breakeven threshold. Even with the recent decline in near-term natural gas pricing, our cumulative free cash flow generation from 2022 to 2027, at strip is forecasted at greater than $12 billion, excluding Tug Hill which equates to approximately 110% of our current market capitalization and underscores the significant value proposition embedded in EQT shares. The resiliency of our free cash flow generation positions us to generate value countercyclically for our shareholders, and we will continue to opportunistically do so via our share repurchase and debt repayment programs. We are capitalizing on the current environment as we have repurchased nearly 6 million shares or $200 million of stock since the beginning of the year at an average price of less than $34 per share.

Since initiating our buyback program in late 2021, we have retired 20.4 million shares at an average price of approximately $30 per share. Along with the 5.7 million shares we retired via convertible note repurchases, we have reduced our fully diluted shares outstanding by more than 6% in a little over a year. Along with the equity repurchases, we have also retired an incremental $283 million of debt principal since our last update at an average cost of 95% of par. This takes our total debt retirement to more than $1.1 billion since the beginning of 2022 and underscores our commitment to a bulletproof balance sheet. Looking ahead, our game plan for shareholder returns remains consistent as we will methodically progress towards our goal of achieving 1 times to 1.5 times leverage at a conservative $2.75 gas price and we will opportunistically lean into equity repurchases to maximize returns for shareholders.

As we mentioned previously, we project greater than $12 billion of free cash flow through 2027 at current strip, so we have material firepower for shareholder returns above and beyond our current equity and debt repurchase authorizations. As it relates to the pending Tug Hill acquisition, we are currently in the process of responding to the FTC’s second request and remain committed to closing the acquisition. Recall, as we highlighted with the announcement the deal structure in Tug Hill’s low-cost assets generate greater free cash flow per share accretion to EQT shareholders at lower natural gas prices. Our latest analysis shows the Tug Hill deal is more than 10% free cash flow per share accretive and in 24 through 2025 before factoring in synergies compared with approximately 5% at the time of announcement demonstrating the importance of EGT’s focus on acquiring the lowest cost most durable free cash flow through well-structured transactions.

We also note with the renegotiation of the purchase agreement late last year, Tug Hill layered on hedges covering roughly half of its 2023 gas volumes with floors at $5 per million Btu. The benefit of which will flow through to EQT via the purchase price adjustment at closing. We plan to update the market with more details around timing of closing the transaction as we approach midyear and will provide full pro forma guidance upon closing. To sum up, I am extremely proud of our 2022 accomplishments as we made significant progress in our pursuit to become the lowest cost, most reliable and cleanest energy producer in the world. Our operational and financial and acquisition efforts over the past several years have deliberately sculpted our business such that it can thrive through the ups and downs of all parts of the commodity price cycle.

Notwithstanding the recent natural gas price pullback, we have never been as bullish on the future of natural gas and the value proposition of EQT as we are today, and we will continue our relentless efforts to crystallize this value for our stakeholders. Before turning the call over to Dave, as you may have seen earlier this week, we announced Dave will be transitioning out of EQT later this year. Dave has been an integral part of our team since 2020, and we are grateful for his contributions to our company. Dave came into EQT at a pivotal time and had clear objectives to help us turn around EQT and he delivered. We successfully positioned the company with a promising future through many efforts, include designing and executing a debt repayment strategy, improving our credit ratings and facilitating our capital allocation plans.

Dave tackled these projects with heart and urgency and his leadership contributed to our company moving from a challenging balance sheet position back to investment grade in record time. He not only achieved his goals but did so with professionalism and thoughtfulness. I’m immensely thankful for him as a colleague and a friend and I’m excited to see him move on to the next phase in his life. I’ll now turn the call over to you, guys.

David Khani: Thanks, Toby. It has been an honor having spent the last three years working with you and the EQT team. I’ve been amazed at how much this organization has accomplished in such a short period of time, and I am grateful to have been part of that evolution. EQT is truly a unique company with a world-class asset base and exceptional culture, a proven development model and a strong balance sheet. I am proud to have left my mark on this company and will be leaving we can see on the trajectory that will create shareholder value for years to come. As mentioned in the announcement this week, I will stay fully engaged with APP for the next several months as I help facilitate a smooth transition, and I look forward to seeing many of you at upcoming investor events.

Now turning to results. I’ll briefly summarize our fourth quarter and full year numbers before discussing our balance sheet hedging and 2023 guidance. Sales volumes for the fourth quarter were 459 Bcfe, roughly in line with the midpoint of our guidance range despite weather-related impact of approximately 10 Bcfe. Our adjusted operating revenues for the quarter were $1.32 billion or $2.87 per Mcfe, and our total per unit operating costs were $1.39 and resulting in an operating margin of $1.48 per Mcfe. Capital expenditures, excluding noncontrolling interests were $396 million in the fourth quarter, slightly below the midpoint of our guidance range. Full 2022 capital expenditures came in at $1.43 billion, excluding acquisitions, in line with the midpoint of our $1.4 billion to $1.475 billion guidance range.

Fourth quarter adjusted operating cash flow was $622 million, and free cash flow was $226 million, which takes our total 2022 free cash flow generation to approximately $1.94 billion. We also saw a $442 million working capital tailwind during the quarter, which was driven by a receipt of our cash election option from E-Train, declining accounts receivables from decreasing prices and lower margin requirements. Our capital efficiency for the quarter came in at $0.86 per Mcfe, up from $0.72 per Mcfe in the third quarter driven by lower production. This was expected due to third-party infrastructure limitations earlier in the year that negatively impacted our 2022 TIL count. For the full year 2022 our capital efficiency averaged approximately $0.74 per Mcfe, which is roughly 30% below the gas peer group average despite the just noted third-party issues impacting production last year.

Turning over to the balance sheet. A core tenet to our company’s operating philosophy is to have a strong credit profile and ample liquidity. We believe this will create differentiated value opportunities for GT moving forward. Recall, we saw several positive balance sheet milestones last year, including achieving investment-grade credit ratings. Our balance sheet improvements to continue in the fourth quarter with trailing 12-month net leverage exiting the year at 1.2 times and down from 2.3 times a year ago. We exited 2022 with $4.2 billion of net debt and $1.46 billion of cash on hand inclusive of the $1 billion in proceeds from the notes offering in the fourth quarter that will be used to help fund the cash portion of our pending Tug Hill acquisition.

As Toby mentioned, we continue actively progress towards our debt retirement initiatives. We’ve retired an incremental $283 million of senior note principal since our last update via open market purchases at an average price of $0.95 at par. Since unveiling our capital returns framework, we have now retired more than $1.1 billion of debt principal, which has eliminated nearly $40 million of annual interest expense. Moving to hedging. Our 2023 hedge book underscores our evolving hedge philosophy that seeks to provide investors with the best risk-adjusted exposure to natural gas prices. We currently have 62% of our 2023 gas production covered with 4s, an average weighted price of $3.37 per MMBtu, which provides significant cash flow protection and downside pricing scenarios while maintaining our private exposure.

Since our last update, we have also added to our 2024 hedge position with 10% of our 24 volumes now hedged at a weighted average floor price of $4.20 per MMBtu and a weighted average ceiling of $5.40 per MMBtu. As it relates to basis, we have nearly 90% of our 2023 Appalachian production covered via basis hedges, providing significant protection against any potential material widening of differentials. Over the medium to long term, we see reasons for structural optimism as it relates to local basis, most notably driven by incremental power demand growth in PJM and coal-fired power retirements. We have also benefited from expanding firm transportation portfolio as we’ve been able to ship gas further west and capture associated favorite pricing dynamics.

Recall, we have added an incremental $300 million a day to our FT portfolio last year, including $200 million to the Gulf Coast and $100 million to the Midwest. Looking ahead, we expect additional opportunities to expand our FT position as our peer-leading inventory depth allows us to capitalize on the trend we’ve seen of other Appalachian operators releasing existing firm transportation capacity. For 2023, our market mix is expected to be roughly 37% local 28% Gulf Coast, 20% Midwest and 15% eased. Note we now model an MDP start-up in the second half of 2024, which at the midpoint will take our local basin exposure to approximately 30%. As a reminder, our gathering rates contractually begin declining in 2025 independent of MPC’s success, providing a further tailwind to free cash flow as our margins wide.

Turning to guidance. We expect 2023 production volumes to range from 1.9 Ts to 2.0 Ts with the midpoint roughly flat compared with 2022. As we bring online the incremental pills that were delayed last year, we expect sequential growth in the second quarter and production achieving our 500 Bcfe quarterly maintenance run rate by midyear. Note that we contemplate a variety of scenarios in our 2023 planning with the low end of our production lines tied to the potential of moderating activity should natural gas prices continue to decline. We are setting the 2023 capital budget of $1.7 billion to $1.9 billion, excluding the pending Tug Hill acquisition. Our budget in beds, 10% to 15% year-over-year oil service inflation, with our supply chain contracting strategy, providing strong access and cost position.

With the likely decline of gas-directed drilling activity this year, we see the opportunity for some price relief in the second half of 2023. This has not been factored into our outlook. As Toby mentioned, $100-plus million of our budget is associated with turning in line wells that slipped from 2022 into 2023 to third-party constraints and thus we not anticipate to carry forward into 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. On Slide 31 of our investor deck, we provided adjusted EBITDA, operating cash flow and free cash flow outlook for 2023 at various NYMEX natural gas prices. Aided by insulation from our hedge book and material cost improvements we have achieved over the past several years, our projected 2023 free cash flow ranges from approximately $900 million at $3 gas to $2 billion at $4 gas implying a free cash flow yield of 8% to 17%.

As it relates to cash taxes, we had roughly $1 billion of federal NOLs as of the end of 2022 and at current strip pricing, we expect these NOLs to offset the bulk of our 2023 cash taxes. Our 2024 cash tax rate would be approximately 7% to 9% of operating income or $150 million to $200 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 have now retired over 20 million shares of our buyback authorization at an average price of $30 per share. Recall that we have eliminated additional 5.7 million shares via convertible note repurchases last year. So in total, we’ve lowered our fully diluted share count by more than 6% since beginning of 2022.

We still have significant firepower to retire shares with $1.4 billion remaining under our current $2 billion authorization. As mentioned previously, we’ve also made significant progress to our debt retirement with $1.1 billion of debt principal retired since initiating our capital return framework. We continue to target absolute debt of $3.5 billion pro forma for the tug acquisition, which will further bulletproof our balance sheet by taking our debt-to-EBITDA to 1 times to 1.5 times, assuming a $2.75 NYMEX gas price. Looking ahead, our low-cost structure and hedge book provide differentiated downside protection for 2023 free cash flow, which we will allocate towards our base dividend further debt retirement and opportunistic equity buybacks with an anticipated greater than $12 million of cumulative free cash flow from 2022 through 2027 and we have plenty of firepower to achieve and exceed our debt retirement goal and equity buyback authorizations.

I’ll conclude by highlighting Slide 11 of our investor deck, which underscores the economic impact of the cost structure improvements of EQT has achieved over the past several years from 2019 to 2021, we generated an average ROCE of negative 8% at an average realized natural gas price of approximately $2.50 per MMBtu, inclusive of hedging. Over this period, we’ve reduced annual costs by roughly $700 million, with spring loads our corporate return profile into an improving natural gas price environment. This was exemplified in 2022 as our ROCE jumped to roughly 17% with just a $0.50 improvement in realized natural gas prices at $3 per MMBtu. At current strip pricing, our ROCE should improve over the coming years, highlighting the sustainability of our operating model and the value creation potential of our business.

I’ll now turn the call back to Toby for some concluding remarks.

Toby Rice: Thanks, Dave. To conclude today’s prepared remarks, I want to reiterate a few points. One, through our relentless cost reduction efforts, balanced hedging strategy and execution on accretive M&A opportunities, we have purposely positioned EQT to thrive in all natural gas price scenarios; two, EQT is on track to become the first energy producer of meaningful scale to achieve net 0 Scope 1 and to GHG emissions, and we believe the market is only scratching the surface of recognizing the strategic value of the emissions profile of our natural gas. Three, our 2022 reserve report underscores the consistency of our combo development strategy positive well performance trends and the tremendous value inherent in our proved reserve base with significant upside based on our peer-leading inventory depth.

Our opportunistic capital return strategy has positioned us well to capitalize on temporary gas price weakness ahead of a structurally bullish natural gas outlook over the coming decades. And lastly, EQT offers among the best risk-adjusted exposure to natural gas prices and as 1 of the lowest 2023 free cash flow breakeven NYMEX prices of all U.S. natural gas producers, which underscores the sustainability of our business through all parts of the commodity cycle. I’d now like to open the call to questions.

See also 11 High Growth IT Stocks to Buy and 10 Largest Economies in Europe.

Operator: Our first question is from Umang Choudhary with Goldman Sachs. Your line is now open.

Umang Choudhary : First, Dave, thank you for everything and wish you the best as we begin the next after release, and hope to stay in touch and also look forward to engaging within the next quarter. I guess for the first question, given your low free cash flow breakeven this year, and you have some options. So how would you think about cash flow allocation opportunities between share repurchase and debt reduction?

Toby Rice: Yes. Great question. So I think you’ll see us continue our approach towards our capital allocation plans. What you’ve seen in the past has been a prioritization of debt paydown. That’s going to shift asset value into the hands of our equity holders. And then you’ll see us continue to be opportunistic with the buybacks. And obviously, the fixed dividend that we put in place is durable and will be a story that will continue to look to grow that over time.

David Khani: Yes. And I’d just add to that as we hit our debt targets, you could see the percentage of our free cash flow increasing towards equity time.

Umang Choudhary : And then would love your latest thoughts on the natural gas outlook. On the — what are you expecting from a supply response, how are you thinking the market is shaping up and then how does that change the way you approach your strategy around hedging? And then any update on the — any thoughts around M&A to the extent you can you can prosecute it given the — given what’s going on with age.

David Khani: Yes. So gas volatility has tripled since early 2021. And so we think that’s going to continue. And so our hedging strategy — our Edge 2.0 strategy really encapsulates that volatility. So everybody has to remember, volatility moves in both directions. And so that’s why we put our kind of the risk-adjusted upside in the way we structure our hedges with white collars. As far as gas right now, gas is right now oversupplied, and we kind of anticipated that and why we put as much of a hedge in place and got a little more aggressive mid-year we obviously see the higher cost producers starting to cut back on activity. It’s going to take a little while to get there. You’re also seeing coal burn coming down and absorbing some of this as well.

We’ll see some industrial demand pick back up as the chemical industry destocking and that will start to pick up and absorb some of the ethane that’s in the system as well as well as increasing some of the power demand as well. So it’s going to probably set the stage where it’s going to take some time to get through this year to get to that balanced market. But I think if we anticipate producers reacting the way we do, we should get to kind of a more balanced market and set the stage for a better 2024.

Toby Rice: Yes. And specifically, in regards to our strategy, I think Dave’s comments on our hedging strategy is designed to give us the downside protection while also giving us great exposure to commodity prices. So you’ll see us continue to execute that approach. As it relates to our activity levels, what you’re seeing with us this year is putting a plan in place that will get our production capacity back to 500 Bcf per quarter run rate. We feel like that’s prudent to get that capacity back. But that will give us the ability to respond in more real time if we continue to see gas prices decline or we’ll be happy to have that production capacity if gas prices move back to our view of where we think prices will be in the future.

So on an M&A basis, we’re going to continue. You’ll see no change on the approach there. One of the key characteristics of our M&A approach hasn’t just been on making sure we see the financial accretion on deals with cash flow per share NAV per share. But the other factor, which is really showing up is our commitment to buying low-cost, high-quality assets and in a low cost low price environment today, you’re seeing the benefits of that. And so we’ll continue to reinforce that element of our M&A strategy.

Operator: Our next question comes from Sam Margolin with Wolfe Research. Your line is now open.

Sam Margolin: I wanted to ask about the remark on Slide 12 about looking at new well designs. And maybe just talk a little bit about like some specific outcomes you’re going for with this approach, whether it’s like a PDP extension type of outcome or if it’s to manage declines? Or what exactly is going on with that comment?

Toby Rice: Yes. I mean the ultimate approach in any of the science work we do is improve the economics of the projects that we’re developing. The science that we’re doing is going to have the effect of lowering our F&D through increasing the performance on an EUR per foot basis, but that does come with some associated increase in costs. So for us to make a full determination on the economics that we’ll receive with this well design, we really need to continue through the monitoring period of the signs that we have in the ground right now. And also, we’ll pair that up with service cost inflation expectations and make a decision. Insight date for that is towards the middle part of this year. So we’ll come back to you with an update as we get this information.

Sam Margolin: And then just as a follow-up that you just mentioned with respect to inflation. And you mentioned you thought that the current market would drive some activity levels lower. And I wonder if you could just characterize a little more of your outlook here, if it’s just — do you think that sort of unit cost on the service side are nearing a plateau or if maybe the activity levels were so overheated, that we could actually see services kind of give back some price right now just because of the severity of the market conditions?

Toby Rice: Yes, it’s been a hot market the last 6 months, specifically. But I think with the pullback in commodity prices, we do anticipate to see some activity reductions. You’re already seeing it from what we consider the marginal producer here in the U.S. and the Haynesville. So I think in the next — over the next few weeks, we’ll have a better view on activity levels and how they’re coming down. And ultimately, that should translate to lower service costs in the future, and we’ll be monitoring that closely.

Operator: Our next question is from David Deckelbaum with Cowen. Your line is now open.

David Deckelbaum: Congrats, David, best of luck in the next chapter. I was hoping to just ask when you thought about 2023 planning, you obviously envision a large ramp in the back half of the year, which I suppose is just a function of the timing of TILs. I’d like a little bit of color how you’re thinking about the risks around that ramp. But also just curious how the closing timing of Tug Hills sort of informs what you’re doing this year on sort of legacy EQT or core EQT, where there might have been incremental activity that would have otherwise maybe been allocated towards West Virginia.

Toby Rice: Yes. As it relates to our hitting our production capacity targets by Q3, the thing we’re really looking at is completion efficiencies and really stages per day footage completed per day. And one of the slides we showed how we’ve gotten back to sort of historical performance levels there. So we’ll be watching that, and that will really be the guiding factor on the pace of reaching that target. As it relates to the activity levels relative to toil acquisitions, we were always planning on running this activity level, and we weren’t planning on changing our activities with the Tug Hill transaction that was probably going to be something that would be incorporated in ’24. So we’re executing sort of as we planned, and we’ll adjust when that deal gets closed.

David Deckelbaum: And is the expectation on everything you’re seeing that if this were to close, let’s say, in the end of the year, is $800 million a day, still the right production level. And I assume if it’s not, there would be a purchase price adjustment?

David Khani: Well, yes. So the purchase price was set at midyear last year. And so any change in free cash flow effectively will lower the price each month that will — that this takes to close. So if they change — if they decide to change activity and the response to this marketplace, then whatever impacts to free cash flow that will benefit to us. But we don’t know that they’re changing activity. We do know that they did add hedges at $5 on half of their gas production to lock in that a good portion of the free cash flow. So — and our expectation right now is that this will close midyear.

David Deckelbaum: And just a quick one. Just to confirm, the only difference between your 165 corporate level breakeven this year, and your 30 view just for EQT only longer term or through, I guess, the next several years, is just the benefit of the hedges in ’23, right?

David Khani: Correct, yes, we’re just trying to show that we and a much lower gas price before we don’t generate free cash flow.

Operator: Our next question comes from Neal Dingmann with Truist. Your line is now open.

Neal Dingmann: First, Dave, thanks for all the time, definitely been a great help. And probably my first question is on cost, specifically. What’s your comfort level with — when you see inflation and other potential incremental pressures this year — and just really wondering how sensitive is that to your D&C plan? You mentioned how you potentially would change D&C based on what gas prices. But I’m just wondering how does that relate to what you’re thinking on costs as well.

Toby Rice: Yes. When you look at the sensitivity that you got to look at is what percentage of services we have locked in and what exposure do we have to the spot market. Looking at the big picture items from rigs and frac crews, those are locked in. We have about 100 frac days that would show up in the back half of this year that we’re looking to procure. So there’s a little bit of exposure there to spot, but we’re planning for it — and we’ve got some time to see how the market shakes out before that. On steel, which is another big item for us, we’re pretty good from a procurement perspective through the first half of this year. And we think that the steel markets hopefully are showing some signs of loosening there on price.

So I feel like we’re positioned there to procure the rest and hopefully, a better service price environment for steel. And then as far as sand and water is concerned, those are largely locked in and feel good. One thing I’d say about sand, that’s important to note because that’s something that has really been backers in other parts of the country. Appalachia, the large part of the sand that we procure is not is it a different market than what people are seeing in basin sand in the Permian. A lot of the sand that we’re getting is coming from Wisconsin, Northern White. So it’s a little bit it’s not — hasn’t been as exposed as much service price inflation as other places in the country. So that’s sort of how we see the service cost sensitivities and feel like we’re in a good position and can be flexible and hopefully take advantage of a better service cost environment in the second half of this year.

Neal Dingmann: Yes, definitely, it seems like the applicant guys are in better price or better area there. And just maybe lastly, just on housekeeping. I’m just wondering — you mentioned about the $50 million adjustment per month color on the purchase price for the adjusted to included in Tug Hill. I’m just wondering, is that included in the Tug Hill hedges? Or is that incremental?

David Khani: The $50 million, is that what you just said?

Neal Dingmann: Yes. You mentioned about isn’t there — with that, you mentioned that $50 million per month regarding the purchase price adjustment, I’m just wondering, is that included in the Tug Hill hedges? Or is that incremental?

David Khani: Well, so I think in the first 6 months of last — so last year, we basically believe it was probably generate about $300 million to $350 million of excess free cash flow that would lower the purchase price. Roughly half of it goes to cash. Half of it goes to reducing the share count. And so with their hedges, if you thought the free cash flow still trends along that same pace, you might have, we’ll call somewhere in that same vicinity in the second half of the year. So you could — maybe you talk about 600 plus of purchase price adjustments that will help lower that purchase price. So the hedges will just solidify that.

Operator: The next question comes from Roger Read of Wells Fargo. Your line is now open.

Roger Read: Yes. Just one quick question probably for you, Toby. Just on — as you think about gas prices, do you think in the end, it’s more about the absolute decline risk in gas prices? Or do you think it’s going to be more about duration of, let’s just say, something below the average breakevens out there that ultimately forces activity and production lower and then maybe creates a little headroom for you on service costs by the latter part of this year.

Toby Rice: Yes. I think there’s a couple of things that are happening from an activity level, as these mature basins — or the shale plays continue to mature, the amount of activity levels will lower over time that should have an impact on lowering service costs. But also the other thing that’s taking place is the breakevens in the United States is rising as operators are moving to Tier 2 geology and both in geography and also in the zones that they’re completing. That will have the impact of increasing the marginal breakeven price of gas. That will help solidify price. The other thing I’d say is, as far as duration is concerned, I mean the one thing that we’re seeing is the call for cheap reliable clean energy. And if we learned one thing in 2022, looking what happened in Ukraine and Russia, the lesson learned there is energy security matters.

And without energy security, you cannot transition. Europe has gone backwards on their emissions targets because of the lack of energy security. And the most important takeaway from all of this is where did Europe turn for energy security. They turn to natural gas. And so we think that the call for this product is only going to strengthen over time because natural gas is the key to providing energy security to Americans in the world.

Operator: Our next question is from John Abbott with Bank of America. Your line is now open.

John Abbott: Dave, thanks for all of the entire Bank of America team who wants to echo best your best wishes in your next chapter. Our first question is going to be on the Tug Hill and XcL Midstream acquisitions. So when you look at — so the guidance that you provided back in September of last year and when you sort of think about these acquisitions potentially closing in the middle of this year. First, is the midstream spend that you laid out in September still on track at XcL? And then second, how does your current thoughts on the potential impact of the breakeven include updated thoughts on inflation heading into this year.

David Khani: So you take the second. I’ll take the first. Okay. Go ahead.

Toby Rice: So as far as — what was the second part of the question there?

David Khani: Inflation into our breakeven.

Toby Rice: Yes. So I mean, the key thing with Tug Hill and the reason why those assets had such a low breakeven cost, was really due to the fact that they own their midstream and also the liquids percentage of their program that they’re running there. So yes, they’re going to be pay with inflation like every other operator and we’ll recast what that looks like from a CapEx perspective. The one thing I’d say is these are pretty high-quality assets. So the activity levels needed to maintain production will mitigate some of the service cost inflation effects. But hopefully, by the time we take over, we’ve seen a little bit more balance come from service costs.

David Khani: Yes. And then even incorporate — if you look at our long-term breakevens that we give you, that does incorporate some inflation embedded in there. So that does — and then as far as the midstream projects are concerned, some of those projects we were working on together were this M&A and some of those projects will absolutely continue through. As far as the rest, I think we’d have to wait and see until this closes to get an update from Tod on that.

John Abbott: And then our second question is sort of on the natural gas macro. Despite spot weakness, the forward curve is about 50% above year-ago levels with former storage, albeit after losing Freeport exports. What do you think is going on?

David Khani: I mean you have basically an oversupplied market heading into €˜23 in and I’ll call very modest oversupply in ’24. And then you’ve literally had Freeport and weather not show up, knocking the front end of the curve down and caused the modest oversupply increase. And so it’s basically sending a signal to the producers start to cut production because pricing is forcing your activity off-line. So and it’s also going to send demand up. And so it’s going to create a reaction to try to get to that balanced market, which you’re going to see from a combination of supply coming off or supply growth slowing, which will probably end up being about B a day of impact. You’ll also see about an incremental B plus of demand being forced back into the system between power from coal going away in the stack and then also industrial demand coming online.

So those will be the things that will balance the market and if it doesn’t happen sooner, it will happen, it will take longer. That means that the rest of the ’23 curve will come down some, and that will cause quicker reaction, the later action. So it will get there, and that’s what the pricing signal always does.

Operator: Our next question comes from Noel Parks with Tuohy. Your line is now open.

Noel Parks: A few things. Wondering, in the reserves, did you experience any upward revisions on type curves, either just from general efficiency or anything you’d be able to see from your redesign?

Toby Rice: Yes. So the type curve revisions resulted in an increase of about 350 Bcf and that’s sort of what we’re referring to when we said performance revisions. So we have seen an increase to performance didn’t bake in anything on the science work that we’re doing. It’s just too early to factor that in.

David Khani: Yes. You need to have more historical information for Netherlands tool to be comfortable with us booking any uplift in type person. That’s probably more of a, we’ll call it, ’24 and beyond kind of benefit.

Toby Rice: Yes. And I hope that investors look at this with a theme that you’re starting to see around this industry where well performance is sort of degrading across industry to be assured to see that high-quality assets are translating to dependable performance, and you’re seeing positive improvements in the well results that we’re putting out, I think, is — should be very reassuring for investors.

Noel Parks: Great. And I just wanted to, at this point, looking ahead to services, of course, totally curious about what the service response is going to be if we do see activity continuing to head down. But just sort of as a reference point, when is your next significant renegotiation ahead either on the rig side or the frac side?

Toby Rice: Yes. So rigs were good through the end of the year with the frac crews, 2 out of the 3 frac crews or — sorry, we have 2 out of 3 factories locked up. We’ve got a frac crew that will be joining sort of middle part of this year that we’re currently under negotiations for right now. So I’d say probably that’s the biggest big resource we have that we’re working on. And as I mentioned, steel is the other big factor, which we’ll cover through the first half of this year, and we’ll continue to work through that. pressure for the second half.

Noel Parks: And just one more. Thinking about the Tug Hill acquisition, once that closes, can you just give a rough sense of maybe how many quarters of sort of deal-related onetime impact we might have on G&A and when G&A might get back to more of a steady state on a unit basis after the close.

David Khani: Sure. So right now, we’re dealing with extra G&A tied to the FTC and it will pull an unclosed process. So if we were to effectively close by midyear, I would say probably the last of what we would deal with is most likely all hitting at the end of the second quarter. It could some hit in the third quarter. But I would say that’s probably your best bet from what we know right now.

Operator: Our next question is from Paul Diamond with Citi. Your line is now open.

Paul Diamond: Perfect just a quick question for you on 2023 guidance. The numbers give you some optionality around some growth versus some reductions just wanted to kind of get you guys sensed on the strategy. And should we be thinking about that in yearly with pricing? Or is it more — or is there kind of on the high side and then it will step change if pricing drops below a certain level?

David Khani: Yes. So it will be a combination of pricing and duration and thinking about when we spend money and start to produce it’s not going to all come out in one quarter. It’s going to be over probably a 2-, 3-year period that ad matters from a returns perspective. So we’ll look at the forward curve and we’ll look at the drop and we’ll try to anticipate what we think the impact will be. And so we’ll model out. And so it will be a game-time decision. We’re not going to make a decision today, but it’s going to be price and duration that will drive it.

Paul Diamond: And just one quick follow-up. As we kind of move to a more long-term supportive fundamentals of $24 million and $25 million has there been any shift in kind of your priorities from Southwest PA versus the Northeast versus West Virginia? Or is that still kind of Southwest PA still pretty much the kind of the front runner as far as priorities go.

Toby Rice: Yes. I mean, our schedule is designed to develop the best rate of returns sooner. So that mix is sort of set. And what you see here for this year is probably going to continue into the future. So that’s sort of how we have our schedule laid out. And also the surface impacts and where we can do combos, longer lateral lengths, more wells per combo is another factor that could move to factor into the schedule.

Operator: There are no further questions. I’ll pass the call back over to the management team for closing remarks.

Toby Rice: Thanks, everybody, for your time today. Certainly, a lot of volatility in these environments. I think it’s a really good time for people to look at the differentiation that exists within the energy space. And I think the work that we’ve done at EQT really is showing up here, even in a downside scenario, we built a business that still is going to generate double-digit free cash flow yields. And with our low cost structure, we’ll be able to and look to a very promising future for natural gas and EQT. So we’ll continue to work and our employees here at EQT are going to be really focused on delivering peak performance in 2023. So thanks for your time.

Operator: That concludes the conference call. Thank you for your participation. You may now disconnect your lines.