Welcome to the Range Resources Third Quarter 2022 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. Statements made during this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties which could cause actual results to differ materially from those in the forward-looking statements. After the speakers' remarks, there will be a question-and-answer period. At this time, I would like to turn the call over to Mr. Laith Sando, Vice President, Investor Relations at Range Resources. Please go ahead, sir.

Thank you, operator. Good morning, everyone, and thank you for joining Range's third quarter earnings call. The speakers on today's call are Jeff Ventura, Chief Executive Officer; Dennis Degner, Chief Operating Officer; and Mark Scucchi, Chief Financial Officer. Hopefully, you've had a chance to review the press release and updated investor presentation that we've posted on our website. We may reference certain of those slides on the call this morning. You will also find our latest 10-Q on Range's website under the Investors tab or you can access it using the SEC's EDGAR system. Please note, we'll be referencing certain non-GAAP measures on today's call. Our press release provides reconciliations of these to the most comparable GAAP figures. For additional information, we've posted supplemental tables on our website to assist in the calculation of EBITDAX, cash margins and other non-GAAP measures. With that, let me turn the call over to Jeff.

Thanks, Laith, and thanks, everyone, for joining us on this morning's call. Range delivered a successful third quarter and realized record free cash flow and cash flow per share, both the highest in company's history. We're returning this free cash flow to shareholders through various means. Last week, the Range Board authorized a significant $1 billion increase to the company's share repurchase program. In September, we paid $0.08 per share in quarterly dividends, and we're rapidly approaching our long-term debt targets, which we expect to hit early next year at current strip pricing while simultaneously funding the base dividend and additional share repurchases. Year-to-date, Range has invested over $300 million in share repurchases or approximately 4.5% of shares outstanding, acquiring our own production and reserves of what we believe are very attractive and accretive levels. As of today, Range has approximately 242 million shares outstanding and $1.2 billion of availability on our updated share repurchase program. The buyback program represents a compelling investment of our capital as we traded a substantial discount to the underlying value of our reserves and resource base. While we run various NAV scenarios and assessing company valuation, we can point to Range's proved reserve valuation that's well north of $60 per share as a proxy for the value of a portion of our inventory. And as many of you are aware, the SEC definition of proved reserves only allows for 5 years of development. And beyond this 5-year window, Range has thousands of additional core Marcellus wells. Beyond that, we have what many consider to be core Utica and Upper Devonian as well. Simply put, we do not believe the significant resource value is reflected in Range's share price, presenting the opportunity to create meaningful long-term per share value for equity holders through our buyback…

Thanks, Jeff. Third quarter capital came in at $138 million, with drilling and completion spending totaling approximately $134 million. Capital spending for the first three quarters of the year totaled $382 million or approximately 80% of our annual plan. As communicated last quarter, we expect to complete our 2022 activity plan in line with the upper end of our original capital guidance of approximately $480 million. Production for the third quarter came in at 2.13 Bcf equivalent per day, adding an average of approximately 60 million cubic feet per day versus the prior quarter. Unplanned third-party midstream maintenance that impacted the third and fourth quarter will place us at the low end of our annual guidance range of 2.12 Bcf to 2.16 Bcf per day for the year. Despite these maintenance impacts, production is currently running approximately 2.2 Bcf equivalent per day. Looking at some of our operational highlights. We turned to sales 18 new wells during the third quarter. 12 of these wells are located in our dry and wet acreage positions in Southwest Pennsylvania, with 6 wells located in our Northeast PA footprint. As has become a hallmark of our operation, approximately half of the wells are located on pads with existing production, supporting Range's cost-efficient development plans. Turning to drilling. We are now running 1 horizontal rig, which drilled 7 wells during Q3. For completions, the team completed 22 wells during the third quarter across Southwest and Northeast Pennsylvania. Completion efficiencies averaged 7.8 frac stages per day, while executing just under 1,000 stages during the quarter. This is the largest number of frac stages pumped in a quarter for range since the second quarter of 2021 and represents approximately 30% of our fracturing activity for this year. The water operations and logistics group continued to build on…

Thanks, Dennis. Third quarter financial results continued to deliver against Range’s, stated goals at an accelerating pace. The Range team delivered on all fronts with operational results meeting guidance, driving strong financial results that were directly translated into shareholder value through continued debt reduction and growing returns of capital. Third quarter progress on balance sheet objectives while accelerating shareholder returns, demonstrate the immense progress made in positioning the business so that Range can consistently deliver tangible returns over the long term. Our mission is to deliver the value of Range's world-class world-scale asset base to shareholders, underpinned by a balance sheet fit for purpose to consistently drive the business over a multi-decade inventory life. Third quarter cash flow reached $550 million, which funded net debt reduction through the accumulation of $157 million in cash, share repurchases of $176 million, payment of a quarterly cash dividend totaling approximately $20 million after capital expenditures of $138 million. Net debt quickly moving toward target levels, combined with growing earnings, drove leverage down to a company low of 1 time debt to EBITDA. Current cash balances and expected fourth quarter cash flow are planned to redeem notes callable in December totaling $529 million. As net debt continues to decline toward our absolute target range of $1 billion to $1.5 billion, cash flow that can be allocated to shareholder returns continues to grow. To that point, this year, we have invested a total of $326 million in repurchasing Range shares or 65% of the previously authorized amount. Given year-to-date net debt reduction better than $500 million and the pace of further planned debt reduction, driven by strong forecasted cash flow as well as what we believe is a significant disconnect in Range's asset value compared to stock price, Range's Board has approved a $1 billion…

Operator, we'll be happy to answer questions.

[Operator Instructions] And today's first question will come from Scott Hanold with RBC Capital Markets. Please go ahead.

I was hoping to delve into 2023 a little bit. And correct me if I'm wrong, I guess if I'm reading into your commentary, it feels like somewhere in that $550 million to $575 million is at least an early kind of range that makes sense for a CapEx budget. But correct me if I'm wrong there, but -- and then talking into like how you look at the trajectory in terms of production, you're actually running about 2.2 Bcf a day if you sort of average that pace, that's still -- that's a nice 3% to 4% growth rate. Is that a reasonable way to kind of look at next year? Or do you see sort of a shape of a curve, which may make it a little bit more flattish? So what are your thoughts on that production trajectory in the next year as well as the capital range that I mentioned? .

Scott, this is Dennis. I'll start with the production side. I think if you look over the last couple of years, we've been on pace to deliver maintenance programs, keeping our production flat year-over-year. But we also front-end load our programs. So as you tie production back to an activity cadence, it's not uncommon for us to see potentially variations throughout the program year where we may be lower or higher, just depending upon when the turn in line start to kind of kick out of that process of drilling and completions activity. So we'd expect Q3 and Q4 to be a little bit higher this year versus the first half of the year. I think we've tried to touch on that a little bit through prior calls just again, because of turn-in-line cadence. 30% of our activity we touched on earlier in the call of our fracturing activity was done in Q3 as an example. So you'll see that translate into more production here in Q4 that 2.2% level. So we would expect to be somewhere in a very similar maintenance level production profile for 2023. So I think something in a similar guide of maybe a 2.12 to 2.16 type level. We'll better define that as we get into the next call and we finalize our budget and our plans for the upcoming year, but it's fair to say to expect a similar year-over-year flat type production profile. From a capital perspective, what we're seeing right now is the RFP process has been launched. We launched that a little bit earlier than what we have in prior years to try and work with our service partners to give them more lead time, more time to discuss with us, securing consumables of labor and just other equipment that would…

And I'll just tack on to what Dennis said. You take that cost, but then you have to couple it with the fact that we have the lowest base decline of any peer, which those two things together then lead to class leading capital efficiency and then put that together with the largest Tier 1 inventory and we think we're in a good place. .

And you all completed I think half a dozen wells in Northeast PA. Can you talk about what you saw from those wells? And how do those compete versus what you're doing in the Southwest Appalachia? Is that something where it makes sense to continue a modest development program into next year?

Yes, Scott, we're -- it's early on, but so far, so good. We really like the performance we're seeing out of those wells. I would say, just given Range's historical development in that area, it gave us a high end others we've seen a high degree of confidence in the type curves that we put together in that area, much like in Southwest PA. So the wells that we've drilled and completed up there have only been on for a few months. So still early on in the cleanup phase, but they're right in line with expectations. And we're still evaluating how future Northeast PA activity could find its way into future development programs. We like the rock quality there. We really like the results we're seeing. But we're still finalizing what kind of future activity would be in that area. The economics compete. And that's another thing that's really encouraging for us is as we look at our dry gas inventory in the southwest part of the state, those economics clearly compete across the program for us now. So still working on that, but fully expect that we'll continue to look at ways to bring our most capital-efficient wells into the program year-over-year.

Could you remind me what the EURs that you generally use up there what the type curves look like?

Yes. It's fair to, Scott, to look at those wells at being somewhere in kind of like a 2 to 2.5 Bcf per 1,000 range. Clearly, there are portions of the field that exceed that level as well. But that's a fair way to look at it. And again, if you look at some of the materials that we have in our slide deck, you can see why those economics can compete.

That will come from the line of Doug Leggate with Bank of America. Please go ahead.

I wonder if I could go to Slide 12 and just ask you particularly the 2025 outlook. I know it's a long way off, but I'm trying to understand where you are on cash taxes currently and whether you fully loaded this latest guidance for your expectations for capital inflation that you discussed and the transition to full cash tax, just to want to understand if they're fully embedded in these numbers?

Doug, it's Mark. Happy to take that question. So as a backdrop, the background information to your question is really where we're starting from in terms of net operating loss that we can use to help deferred taxes and minimize near-term cash tax payments. Range has roughly $2.9 billion in federal NOLs. So that largely will take care of taxable income for this year and will provide a substantial offset for 2023 as well. We have to dig into the details just a bit to understand the timing of cash tax payments. The NOLs come in two vintages. The first bucket, if you will, of roughly $1.2 billion allows you to offset up to 100% of your taxable income at the federal level. The remaining, the balance of $1.7 billion or so, you can use to offset up to 80% and of your taxable income at the federal level. So what that means is, again, federal tax is largely offset for 2022. 2023, they will be largely mitigated, but some cash taxes at the full level will begin -- and after 2023, you have effectively or very nearly fully utilize those NOLs. So as you head into 2024 and thereafter, your federal payments do begin to increase. At the state level, we do have NOLs as well, in the Commonwealth of Pennsylvania. Those can offset a portion of your taxable income. So you'll see modest think very low single digits, like maybe 1% effective rate. to the corporation this year and next year. So as you go forward into year '24 and beyond to your question, yes, there will be cash taxes we fully expect. That's a happy byproduct of strong profitability of the company. And yes, those estimates are baked into these numbers, we reflected here on Page 12.

My follow-up is kind of, I guess, it's like a's quasi takeaway question. But I'm going to ask it like this, our understanding is that some of your smaller, let's say, private peers don't have the same inventory debt or longevity that you guys do, and we're starting to see some larger space opening up in some of the pipes. I wonder if you could confirm if that's what you're seeing regionally? And if so, if that plays into whether a range would look to fill or be able to fill some of that space in the context of your flat production or maintenance capital comments earlier. I'll leave it there.

Yes, Doug, this is Dennis. I'll take that question. our marketing team in PA is always looking at the most creative ways to move our gas production on a regular basis. We monitor the pipes. We understand what's flowing on them pretty well. And I would say at this point, it's not unlikely to see some of that infrastructure as we go forward, be underutilized because of core exhaustion capital allocation, maybe for some companies that have gone to other basins as you look at some of the M&A transactions that have occurred over the past 12 to 24 months. But when you look at the way our core position is put together, it really allows us to really be ready and able to take advantage of whether it's processing capacity that goes underutilized. We monitor that as well or being able to take advantage of nat gas or NGL capacity that comes available on different portions of the infrastructure. So is there some capacity, I would say, year -- as we look over the past year, there's been points on an annualized basis across the year between local demand and capacity somewhere around approximately 1 Bcf of capacity. So there is room to put some gas in the system there. But on the -- there are times of the year, which you can imagine it is tighter than others.

So does that change -- would that change meaningfully Range's sort of ex growth sustaining capital guidance that you've obviously spoken to for some time?

So I'll start first and my means if Jeff or Mark want to jump in, please do. But I think as we think about 2023, we still lead toward a maintenance level type program, stay in the course and again, seeing stay dedicated to our financial objectives that we have. But again, as we start to look at 2024 and beyond, and you start to see core exhaustion limits in inventory and the quality of the inventory potentially for peers in the basin, we think that really tees up the opportunity for a different outlook in the event that we want to [Audio Gap] consider some kind of low growth profile. Again, we're a ways from that. We like a maintenance level type program for 2023 we feel like we're poised and ready with our long runway of inventory and our ability and history to execute in the basin. With over 1,200 producing wells, we feel like we really understand Appalachia well, and we're set up on the first cut of the fair way to be able to step in and actually add some additional production win the basin economics and also fundamentals call for it.

And that will come from the line of Jake Roberts with Tudor, Pickering, Holt. Please go ahead.

Just curious if we could dig into Q4 a little bit, some of the moving pieces there. I know you guys are messaging high end of the full year guide. Just curious what's going on there for the similar turn in line quarter-over-quarter for a bit less money. And then also as part of that, is the current rig running going to be with you for the reminder of the year into 2023? And is that part of what's been secured for 2023?

Yes. Jake, I'll -- this is Dennis. I mean as we look at our activity cadence for Q4, we have the 1 frac crew and the 1 drilling rig that's operating. If you look back on Q3, we had 2 frac crews that were operating. The second 1 was really focused on our Northeast PA activity that we touched on just a few minutes ago. And of course, then a second rig was being released early on in Q3, kind of late Q2 type time frame. So as you think about capital as we go from Q3 into Q4, and our kind of our cost distribution, it's about 70-30. When you start to look at the cost and the capital that we spend with the frac crew versus on the capital -- on the completion side versus the drilling rig side. So as we kind of finish out Q4, the lower pace of activity, those 2 frac crews -- sorry, the frac crew and the drilling rig will then go into 2023 for us. And there will be the frac crew for all of '23, along with that drilling rig. We typically front-end load our programs. So it would be also reasonable to expect us to see an increase in drilling activity in Q1 to then properly shape our program for 2023. But the turn-in-lines that you'll see in Q4 will mirror the activity that is a byproduct of those 1,000 frac stages that we pumped in Q3 it will be certainly a little bit less, but certainly be a byproduct of that as well.

And then 2024, I can see roughly 30% hedged. And I know you guys have spoken about as that comes out of the system. You don't need to have such a strong hedge profile as you perhaps much did. Is 30% a good range to be thinking about in that time frame once that does hit those target levels? Or should we expect some incremental adds there as we progress through 2023?

Jake, it's Mark. I'll start off responding to that question. So I think that's a good starting place as we look a year or two out, really our fundamental strategy and the purpose of hedging hasn't changed over the years. It's really a risk management exercise. Years ago, given the date of maturity of the business capturing the inventory drilling to hold drilling to prove up the inventory, a higher hedge percentage was required to protect the balance sheet, protect cash flow, protect the capital program necessary to capture this inventory. Today, given dramatically reduced debt balance extremely low leverage, the lowest in the company's history. We are looking conceptually to essentially cover a good portion of the fixed costs in the business to help mitigate the downside risk while still participating in a strong market, a market that has rerated and continues to be rate both in terms of natural gas and natural gas liquids. So as you look ahead to 2024, that roughly 30% hedged on the natural gas side. That equates to about 25% of revenue. That's a good level to cover the vast majority of fixed costs. But there may be some minor fluctuations above that. If you can generate extremely strong rates of return far beyond any other industrial sector, we might consider a bit more as well. But fundamentally, it's a risk management exercise designed to cover the fixed costs.

That will come from the line of Noel Parks with Tuohy Brothers Investment Research. Please go ahead.

I was wondering, thinking about the infrastructure situation. I was wondering, we, of course, know the federal opposition to pipeline growth as been pretty long standing now. I was wondering if there are any signs of reduced state or local opposition to pipelines? Or even if you could even see any signs of less opposition to LNG infrastructure going forward? .

Yes, this is Jeff. I would just say within the state, the good news is the natural gas industry pulls well -- so you can see in the elections, whether it's this current one, midterm or last one. The candidates that are running on either side, both support and talk about the natural gas industry because it pulls well with the citizens. The trade unions in the state are supportive of the industry. And the industry generates a lot of revenue for the states, whether it's taxes, jobs, all the things like that. In terms of -- so I think your -- there's constructive things there. In terms of LNG, I think there's a meeting actually later this week in Philadelphia and the states has a group of legislators who are looking to get together to talk about LNG and the opportunities in the southeast part of the state for LNG export. Clearly, it would be advantaged given all the need for energy in Europe, it's closer. Transportation to Europe would make a lot of sense, it would create a lot of jobs. And certainly, there's plenty of brownfield sites in that area. So I think all in all, it's positive.

I was wondering if anything as far as the adjacent states that aren't producers, I'm just thinking with what we might see with energy costs in New England and the Northeast this winter, whether there might be some reading of the writing on the wall as far as the need for more infrastructure.

Yes. I mean you've heard not that evolving it, but you hear in the New York gubernatorial race, the Republican candidate said that if he gets elected, that's one of the things that he's going to do is promote natural gas industry for New York in the pipeline. Clearly, it would be a plus New England's getting LNG imported was from Russia, Algeria different places. At a significantly higher price. I think earlier this year, if I remember exactly, don't quote me, but I think in January and February, they paid about $30 per 1,000 cubic feet or per MMBtu, whereas you could have bought it from Pennsylvania to Marcellus for a significantly lesser price. So that would be the common sense solution. And then importantly, too, from an environmental perspective, not only is at lower cost, but from an environmental perspective, the Appalachian Basin has the lowest emissions of any basin really on the globe. And within Appalachia, Range is basically the head of the class. So it's more cost effective. environmentally, it's better. . Clearly, it's more environmentally effective to move that by pipeline than it is to move it by ship from Asia to Northeast U.S. when the U.S. has such an abundant resource in natural gas. So it is the answer. But short-term and long-term answer, I think, for the country. And take that one step further, even in terms of manufacturing now, it's the U.S. is going to have a tremendous advantage from a feedstock point of view or an energy cost point of view. When you look at the price of natural gas in the U.S. versus Europe or Asia, it literally trades for plus or minus 70% less in the U.S., 75% less than it is in Europe or Asia. So that's an advantage from a manufacturing point of view as well as from a consumer point of view.

Right. And I did want to take a minute to think about longer-term, more optimistic scenario for gas. And thinking about with your current level of reactivity, could you just refresh my memory, what Range’s peak Appalachian rig count has been in the past? And I guess I'm thinking about a scenario in which maybe a multi-basin player decided to divest out of Appalachia. With your current overhead how much bigger an activity slate do you envision you could support?

Well, it's a great question. It's a bit of an apples-and-oranges question. If you go back to peak number of rigs that we ran, in the past when we were delineating drilling this developing might have been 10 to 12 rigs or maybe a tick higher. But back in that time, the lateral length of those wells were extremely small. So Range discovered the play, kicked it off. The early laterals were plus or minus 3,000 feet where today, our average wells 11, 12 and the longest '18 to '19. So a lot's changed, and the team has got better and more efficient year after year after year from a variety of things, not just longer laterals, I won't go into all those. But I think we have a great team operation. I think we know the state well. We know the marketing. We know how to move natural gas and NGLs in the basin. So there may be opportunities with time to do more. The good news is we have a great inventory, and we're in good shape. So we don't need to do anything. We can continue to execute the plan but to the extent there's something that makes sense for us to do, we'll be open to it. And ultimately, if there's capacity and it's the right time to grow, we'd also consider that. We have the inventory to do that.

We will go to Umang Chaudhry with Goldman Sachs for our final question.

My question is on NGLs. I wanted to get your thoughts around the near-term outlook for NGL, specifically on propane and ethane, especially given the current chemical demand weakness we are seeing Wanted to get your thoughts around when -- what is seeing which can get you more optimistic around the demand side of the equation? And how are you thinking about hedging the NGL molecule?

Yes. This is Dennis. I'm going to kind of open up here and then pitch over to Alan to provide some additional color. But -- as you look back on Q3 and where we've been from a pricing perspective, we had some unique things clearly take place. You look at ongoing lockdowns from a coding perspective, certainly providing an impact to really petrochemical facilities and their run rates. And so the reduction of what we've seen over the past quarter has been certainly unique. When you look at what's going on from an increase in naphtha inventories also that's been going on in abroad. That's also been impactful to Range’s pricing given that we've got some of our contracts that have an exposure to European naphtha. It's been a diverse portion of our portfolio, but something that also has created a lot of benefit to us over time. And as you look kind of in the go-forward part, really, we kind of see Q3 as being the low point from a guide perspective, and we see opportunity for that to further improve, thus in the updated guide that we've provided. When you look at days of disposition, you touched on propane as an example. We continue to remain at very low levels, below the 5-year average. We don't really see that changing as you get into 2023. When you look at exports, they've continued to also remain incredibly strong over the course of time. And certainly, you've got to think that there's going to be a point where COVID lockdowns are going to improve in some of the foreign countries that clearly we're all reading about these days and seeing those impacts. And I think we're seeing early on signs of that. Of course, last thing, winter is ahead, right? And so we know that demand is going to look differently for a significant portion of the NGL barrel as we start to get into our winter demand season as well. When you look into 2023, the last thing we see further optimism around is when you just think about the realized price that we could capture associated with strip pricing and getting that much closer to a Mont Belvieu outlook. And so from that, a lot of optimism for us, and I'm going to turn it over to Alan to let him add some additional color.

Actually, I'll just jump in on the hedging side. Among your question is a good one around the hedging of NGLs. First, that NGL derivative market is somewhat more limited. Historically, we use kind of a 3- to 6-month rolling forward type of window that we will layer on hedges. That said, we're constructive for all the reasons that Dennis just laid out. So we've been somewhat more limited on the hedges. But as you step back and look at where our delivery points are and how our NGL business is constructed, Range is running a global book of business here. . We deliver NGLs, ethane and other NGL components of the barrel down to the Gulf Coast to Canada and export out of market. So we export ethane, propane, butane to a variety of different price points. We have the ability in the underlying contracts linked to natural gas prices and/or propane -- international propane indices or other commodity indices as prudent for our own book of business and for our customers. So through the diversity of our delivery points and the pricing points, combined with some modest hedging we manage that risk. But all the fundamental reasons Dennis laid out, we're constructive about the NGL market ethane, propane and the other units going forward.

Thank you. This concludes today's question-and-answer session. I'd like to turn the call back over to Mr. Ventura for his concluding remarks.

I just want to thank everybody for taking the time to join us on this morning's call, and feel free to follow up with any additional questions that you may have. Thank you.

Thank you for participating in today's conference. You may disconnect at this time.