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spk00: Welcome to Range Resources first quarter 2022 earnings conference call. All lines have been placed on mute to prevent any background noise. Statements made during the conference call that are not historical are forward-looking statements. Such statements are subject to risk and uncertainty, which could cause actual results to differ materially from those in the forward-looking statements. After the speaker's remarks, there will be a question and answer session. At this time, I would like to turn the call over to Mr. Lace Sando, Vice President, Investor Relations at Range Resources. Please go ahead, sir.
spk09: Thank you, Operator. Good morning, everyone, and thank you for joining Range's first quarter earnings call. The speakers on today's call are Jeff Ventura, Chief Executive Officer, Dennis Degner, Chief Operating Officer, and Mark Skuki, 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'll also find our 10Q 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.
spk10: Thanks, Leith, and thanks, everyone, for joining us on this morning's call. Before discussing the successful first quarter range had, I wanted to spend a few minutes on the global energy challenges that we're all witnessing and working through. Since our year-end call in February, Commodity prices across the board have moved significantly higher as supply has struggled to meet demand for varying reasons, ranging from longer-term capital underinvestment to supply chain issues and infrastructure challenges, some of which are driven by policy decisions in the United States and abroad. The Russian invasion of Ukraine has resulted in the tragic loss of life and massive destruction of cities and infrastructure, and it has also exposed some of the flaws in energy policy that has miscalculated or ignored the physical realities of energy market fundamentals while trying to achieve ambitious longer-term environmental goals. Range pioneered the development of the Marcellus shale over 15 years ago, and it's been an exciting and humbling experience to watch Appalachian shale production from the Marcellus and Utica Point Pleasant grow from nothing to now producing over one-third of the nation's natural gas supplies, becoming the largest producing natural gas field in the world in making the US the largest natural gas producer in the world. The result is natural gas prices in the US are significantly lower than natural gas prices in Europe and Asia. Currently, US pricing is about 75% lower than prices abroad, creating a significant number of quality jobs, making US manufacturing more competitive, helping to keep the US utility bills lower than other countries, positively contributing to the US trade balance, generating tax revenues for governments, and providing energy security for our country. In addition, the U.S. has led the world in lowering CO2 emissions, primarily from the substitution of natural gas for coal and power generation, as natural gas has a 60% lower carbon footprint than coal. Despite this meaningful improvement in emissions by moving from coal to natural gas, we believe that much more can and should be done in the years ahead, both in our country and globally. As we look forward, we see a world that desperately needs access to ethical, safe, secure, reliable, and abundant fuel sources, while at the same time being mindful of and continuing to prioritize the global move towards a lower carbon future. There's no shortage of independent third-party experts that believe Appalachian natural gas and NGLs should be a growing part of that global solution. We believe that Appalachia will see increased in-basin demand in incremental takeaway projects in the years ahead. However, a more meaningful increase in natural gas supply will require the support from federal, state, and local governments to provide critical infrastructure in the form of pipelines, compression, and LNG terminals to get Appalachian natural gas to the end markets that need it. We believe that the Marcellus and Utica Point Pleasant shales have the ability to increase production meaningfully and to be part of the global call on added LNG supplies from the United States. But the industry is currently hindered by a lack of additional infrastructure due to permitting delays, policy decisions, and rhetoric that discourages long-term capital investment in natural gas and natural gas infrastructure. So where does that leave range today? We believe we have positioned the company for success in whatever commodity price and infrastructure scenario we find ourselves in this year, next year and for the foreseeable future. As the most capital-efficient operator in the largest natural gas field in the world, we believe we sit at the low end of the global cost curve for natural gas. Importantly, Range and other Appalachian producers also have an advantaged emissions intensity profile, given the prolific nature of the Marcellus, robust drilling standards, and a focus on operational efficiencies being applied on a daily basis. Longer term, We see ranges being differentiated amongst producers given our operational expertise, robust multi-decade core inventory, and access to markets outside of Appalachia. I believe the financial and operational results of the most recent quarter reflect those advantages as we've made steady progress on our key objectives for 2022. Enhancing margins through thoughtful marketing, hedging, and a focus on cost completing our drilling program safely within budget and with peer-leading capital efficiency, bolstering our balance sheet with absolute debt reduction, and returning capital to shareholders. Operationally, range successfully delivered on our first quarter development plans with production coming in slightly better than expected and capital spending of $117 million, or approximately 25% of the full-year budget, putting us on track with our full-year guidance of $460 to $480 million. Dennis will provide some additional details on the quarter in a minute, but we're off to a great start. Looking at margins, starting with price, Rains delivered a premium natural gas differential in the first quarter as we weathered daily price volatility with thoughtful marketing and balanced deliveries to multiple end markets. Range's natural gas liquids production also received a premium to Mont Bellevue equivalent price coming in at over $40 per barrel or greater than $6 per MCFE. Overall, Range received $5.63 per MCFE in the first quarter for its aggregate production. This represents a premium of over $0.74 over Henry Hub natural gas prices, something that's unique when compared to pure dry gas producers in Appalachia the Haynesville, and other natural gas plays. As a result, we realized the highest quarterly cash flow per share and free cash flow in company history, a trend we expect to continue throughout this year. This record free cash flow is being directed towards absolute debt reduction and capital returns we announced in February, including a base dividend to begin later this year and a $500 million share repurchase program. We were comfortable making an announcement in February when commodity prices were much lower because of our competitive cost structure and peer-leading maintenance capital requirements that provide us a solid foundation for generating truly sustainable free cash flow through the cycles. The meaningful improvement in commodity prices over the last two months has simply allowed us to accelerate our absolute debt reduction while simultaneously repurchasing shares of what we believe is a fraction of the underlying value of the business. particularly with long-term commodity prices re-rating higher as the call for U.S. natural gas becomes more evident globally. We have discussed our long-term balance sheet target of $1 to $1.5 billion in absolute debt. It now appears that we can achieve this financial objective by early next year at current strip pricing while simultaneously funding the base dividend and share repurchases. While Range's stock prices moved materially higher over the last two years, we believe the buyback program continues to represent a compelling investment of our capital as we still traded a substantial discount to the underlying value of our reserves and resource base under what we believe are conservative mid-cycle pricing assumptions and development plans. While we run various NAV scenarios in addressing company valuation, we can point to Range's approved reserve valuations at year-end 2021 as a proxy for the value of a portion of our inventory. At year-end 2021 strip pricing, the PV10 of Range's approved reserves was $12.7 billion. For context, after backing out year-end net debt balances, this PV10 equated to approximately $40 per share. Based on more recent strip pricing, that valuation is well north of $60 per share, And, as many of you are aware, the SEC definition of approved reserves only allows for five years of development. And beyond this five-year window, range has thousands of additional core Marcellus wells. Simply put, we don't believe this significant resource value is currently reflected in range's share price, presenting range the opportunity to create meaningful long-term per share value for our equity holders through our buyback program. Before turning it over to Mark and Dennis, I'll reiterate something I mentioned on our last call, which is that I truly believe range is in the best position in the company's history. As the world continues to move towards cleaner, more efficient fuels, natural gas and NGLs will be the affordable, reliable, and abundant supply that help to power our everyday lives, while also helping billions of others improve their standard of living and reducing their reliance on coal and other more carbon-intensive fuels. We believe Appalachian natural gas and natural gas liquids are well positioned to meet that current and future demand. And within Appalachia, Rains will be among those leading the charge on emissions intensity, capital efficiency, and transparency, which are all core to generating sustainable long-term value for shareholders. Rains has de-risked a massive inventory of high-quality wells in the Marcellus, measured in decades, and translated that into a business capable of generating free cash flow through the cycles. Underpinning this business is the low sustaining capital requirements that Range enjoys, reflected in our peer-leading, drill-and-complete spending per MCFE, which allows us to weather potential service cost inflation better than most and generate healthy margins. At the same time, Range's balance sheet is in the best shape in company history, with rapid improvements continuing in the coming months. With significantly lower absolute debt, range will be even more resilient when we see the next cycle. That said, with favorable fundamentals for natural gas and natural gas liquids today and for the foreseeable future, range is well positioned to generate healthy returns on and returns of capital to shareholders. I'll now ask Dennis to cover operations.
spk03: Thanks, Jeff. A little over two months ago during our prior earnings call, we kicked off the year by describing our 2022 plan with a continued focus on capital efficient operations, along with safety and environmental performance that work hand in glove to achieve our overall objectives this year. The results we'll discuss today clearly reflect that our program is off to a solid start and on track to deliver on this year's objectives. Focusing in on our first quarter operations, capital spending came in at $117 million, or approximately 25% of the 2022 program budget. We increased activity throughout the first quarter to a level consisting of three horizontal drilling rigs, two top hole rigs utilized to drill the shallower vertical section, and two frack crews. This level of activity is scheduled to continue during the second quarter before tapering off later this year and puts us on track with our capital guidance of $460 to $480 million for 2022. This front-loaded activity approach is consistent with the past several years and results in a higher number of wells turned to sales in late Q2 through the second half of this year, driving higher second-half production and putting us on track for our annual production guide of 2.12 to 2.16 BCF equivalent per day. In the first quarter production, it came in at 2.07 BCF equivalent per day, as strong field runtime helped offset some of the weather-related impacts associated with winter storm landed in early February. We expect production in the second quarter to be slightly lower than the first quarter average, given the planned midstream maintenance we talked about on our last earnings call. Though we plan to exit Q2 at approximately 2.15 BCF equivalent per day, and as mentioned, production is expected to increase further across the second half of the year, putting us on track to deliver our full-year production of 2.12 to 2.16 BCF equivalent per day. Shifting to our operational highlights, in Q1, 13 wells were drilled in our dry and wet acreage positions while returning to pads with existing production on three of the four pad sites. Of the 13 wells drilled, 12 of them were in southwest Pennsylvania, with one in northeast PA. The Q1 wells had an average lateral length of more than 13,200 feet, which is a 13% increase versus the same time period, 2021. This was driven by three wells with lateral lengths that averaged more than 18,000 feet, placing them in the top 15 longest laterals in Ranges Marcellus program history. We've touched on the importance of being repeatable on prior calls, and drilling along laterals is one of many components to this success factor. Drilling long laterals provides capital and operational efficiencies, particularly when using existing pads and infrastructure, while at the same time reducing our overall environmental footprint. This results in our continued leadership in capital efficiency in Appalachia, whether measured on drilling costs per foot or maintenance capital per MCFE. As an example, in the face of inflationary cost impacts during the first quarter, The efficiency gains from our long laterals drilled during this timeframe enabled the team to reduce drilling costs by 4% on a per put basis when compared to the first quarter of 2021. For completions, 15 wells were completed during the quarter. Overall, the team completed just under a thousand frac stages while setting a first quarter completions efficiency record by averaging over eight and a half frac stages per day. During our previous call, We mentioned an emerging step change in our efficiencies attributed to new surface equipment and procedures. As an update, in February of this year, the completions team pumped a record 16 stages in a day with a single frac crew while utilizing this new equipment and procedure. This type of improvement shows the team's creativity and commitment to improving our frac stages per day as we move forward, further reducing our program cycle time and reducing cost. This is just one of many examples where our teams continually look to implement new technologies and process improvements to achieve our higher operational and capital efficiencies. Recently, you may have seen an announcement regarding a contract extension for an electric frack fleet for future range activity. The extension was signed during the first quarter for the latest generation equipment configuration for deployment in Q4 of this year. The new fleet has a considerably smaller footprint, which will improve operations as we continue our strategy of returning to pads with existing production, a key component in our development plan. This fleet will also play a role in RAGE's continued ESG efforts by minimizing emissions, all while generating power from clean burning natural gas from RAGE's assets. We look forward to continuing our partnership and collaboration with our service partners to achieve our mutual long-term goals. Water operations continue to capture savings from our water recycling program during the first quarter. In excess of 1 million barrels of third-party produced water was utilized, which reduced overall completion costs for the quarter by nearly $3 million. The water logistics software deployed a year ago allowed RANGE to plan for reduced water tank levels in the field prior to winter storms and prevented unnecessary impacts to production. Cross-departmental communication Adaptive scheduling and technology-focused cost reduction efforts allowed range production to continue to flow uninterrupted and continue the trend from 2021, which saw range generate $13 million in water savings across the year. Again, further demonstrating the durable and repeatable nature of our operational and capital efficiencies, one of the many advantages of having a large blocky acreage position. And lastly, Lease operating expense for the first quarter finished at just under 11 cents per MCF equivalent, with winter operations putting us at the high end of guidance as expected. Before moving to marketing, I'd like to briefly touch on service costs. We continue to monitor changes to the global and domestic supply chains, making adjustments as needed. Although we've seen commodity cost increases in areas such as fuel, steel, and sand, we have mitigated our exposure where possible, by taking proactive steps such as securing our 2022 tubular goods and by entering into the previously discussed frack fleet contract extension, which will commence on November 1st. We will continue to watch the supply chain landscape and adjust our plan as necessary. I do think it's worth providing some context to the inflation discussion, though. As range is low base decline, and peer-leading well costs serve as a hedge against service cost inflation. For context, our maintenance capital program of $460 to $480 million for 2022 works out to approximately $0.60 per MCFE of production. This is the lowest in Appalachia and is a fraction of what you'll find in higher-cost, higher-decline basins such as the Haynesville. So to the extent that there are inflationary pressures that continue beyond this year, range is well positioned to manage through it and should be advantaged versus other E&P companies. Shifting over to marketing, ethane exports from the U.S. were strong in the first quarter and were estimated to be 27% above the five-year average, while domestic demand was 17% higher year on year. Together, these fundamentals helped push Mont Bellevue ethane prices 29% higher through the first quarter. This backdrop, coupled with Range's diverse portfolio of NGO contracts, drove a 74 cent per barrel premium to Mont Bellevue for the quarter, and Range's absolute pre-hedge NGO price increased to more than $40 per barrel. Additional domestic ethane demand, such as the Shell Cracker in Appalachia, is expected to come online this summer, while existing facilities will restart following maintenance. This growing demand is expected to support ethane price versus natural gas. Domestic propane inventory is at historic low levels, which coupled with several periods of cold weather, boosted Mont Bellevue propane prices nearly 28% during the first quarter. Butane price performance was similar. rising 21% across the quarter on strong domestic demand for gasoline blending plus export demand that was 70,000 barrels per day or 28% above the five-year average level. Looking ahead to the balance of 2022, range expects strong demand for U.S. LPG exports to European and Mediterranean markets as customers in those regions look to diversify their supply. Range is well positioned to meet this demand using our export capacity at the Marcus Hook Terminal near Philadelphia. The ongoing strength in export demand will present a challenge to domestic buyers as they work to refill storage levels from historically low levels, supporting Mont Bellevue pricing through the summer and setting up for another bullish winter for the 2022-2023 season. This continued strengthening of NGO outlook and price realizations further supports our 2022 NGO guidance range of $0 to $2 per barrel premium relative to the Montville View Index. For our natural gas marketing efforts, in Q1, range reported a natural gas premium of $0.03 above NYMEX, including basis hedging, and a $0.17 differential improvement versus the first quarter of 2021. Underpending ranges realized natural gas price of $4.92 with stable production levels across Appalachia, exports from LNG reaching 13 BCF per day, Mexican exports exceeding 6 BCF per day, and winter heating degree days within 2% of the 10-year average. This resulted in below average storage levels, Q1 daily pricing near $5 per MMBTU, and record cash margins for the company. Before turning it over to Mark, I'd like to briefly touch on our environmental and safety performance. For 2021, RANGE's greenhouse gas emissions equated to approximately 0.26 CO2 equivalent per MMCF equivalent, a level within 10% of the prior year, and placing RANGE at the low end of emissions intensity on a global basis. Looking at water recycling, Range once again recycled over 100% of our produced water while utilizing production water from other operations in the area. And for safety, we continue to see training and hazard identification pay dividends, with no Range employee OSHA incidents in the past six months and only one in the past two years. We look forward to sharing more details on these as well as other accomplishments in our upcoming Corporate Sustainability Reports. slated for release this summer. In summary, our operations and marketing updates today continue to reflect our dedication to efficient operations, capital discipline, and deployment of new technology to deliver on our most capital-efficient program. We look forward to future updates on these key areas in the future quarters ahead. I'll now turn it over to Mark to discuss the financials.
spk02: Thanks, Dennis. In the first quarter, the Range team delivered on stated objectives, pursuing our mission to realize the value of Range's world-class, world-scale asset base, paired with a balance sheet fit for purpose to consistently deliver value to shareholders over a multi-decade inventory life. It was a busy quarter with substantial progress across much of the business. Cash flow from operations reached $489 million, which funded net debt reduction, of approximately $250 million after early debt redemption costs, capital expenditures of roughly $117 million, and reinitiation of our share repurchase program, acquiring 600,000 shares in the month of March. We've been focused on absolute debt reduction for several years, and as of quarter end, we have reduced debt, net of cash, by over $1.7 billion since 2018. As noted on the year-end call, We believe that a prudent and competitive debt level for the company going forward will be in the $1 to $1.5 billion area, which is achievable at strip pricing in early 2023. With clear line of sight to target debt levels and quarter-end net debt to EBITDAX of 1.6 times with rapid additional deleveraging in coming quarters, we're able to execute both debt reduction and our return of capital program. These two objectives, a pristine balance sheet and competitive shareholder returns, are not mutually exclusive. They are integral parts of our overall capital allocation strategy and can be executed in tandem. We have consistently described a waterfall of our reinvestment of cash flow. First, maintenance capex in order to utilize infrastructure and maximize margins. Second, debt reduction towards target levels. Third, return of capital to shareholders. And fourth, growth capex when appropriate. It's important to note that this hierarchy entails flexibility to allocate based on highest overall returns to the company and its shareholders. With ranges leading full cycle costs, margins are strong, generating significant free cash flow that will support even greater flexibility in the use of free cash flow focused on risk-adjusted, returns-driven capital allocation. Taking a closer look at the first quarter results, cash flow of $489 million was driven by planned production levels, achieving strong pre-hedge realized prices of $5.63 per MCFE compared to $3.20 first quarter last year. This realized unit price is 74 cents above NYMEX Henry Hub, driven by improved natural gas, natural gas liquids, and condensate pricing. During the first quarter, NGL price per barrel pre-hedge reached just over $40 per barrel, or in excess of $6.60 on an MCFE basis. Range's diversified portfolio of transportation capacity and customer contracts supported differentials such that the total per unit price received by Range remains a premium to Henry Hub Natural Gas and Mont Bellevue NGLs. Hedged cash margins per unit of production expanded to $2.65, up 156% compared to first quarter last year. Ranges margins benefited from higher prices through a combination of careful hedging and continued focus on costs and efficiency. The change in total cash unit costs in the first quarter compared to the prior year primarily relates to processing costs, which are linked to NGL prices with minor variations in other line items offsetting. While line items such as LOE and GNA continue near multi-year lows, further savings in interest expense will result from continued absolute debt reduction and the refinancing transactions completed in the first quarter. The refinancing transaction executed in January reduces annualized interest expense by greater than $40 million, or 16 cents in cash flow per share, with further significant interest savings from retirement of upcoming debt maturities. Cash balances of $113 million at quarter end combined with continued free cash flow and an undrawn revolving credit facility provide ample liquidity to redeem at par senior notes maturing in 2022 and 2023. Additional balance sheet enhancements were completed in early April. with the execution of a new five-year revolving credit agreement. The elected borrowing base remains at $3 billion, with lender commitments of $1.5 billion, right-sizing the facility given range's expected cash flow, cash balances, and manageable debt maturity profile. Successful first quarter results, combined with a positive view of opportunities for range going forward, further support our confidence in the return of capital program announced on the last call. we continue to expect to reinitiate a cash dividend in the second half of this year at an annualized 32 cents per share. Further, we have already begun repurchasing shares under the current aggregate $500 million authorization. We continue to believe the repurchase program is an attractive investment opportunity given the significant gap between the value of range's inventory and production versus current share price. PV10 of proved reserves at recent strip pricing equates to over $60 per share net of debt. Using proved reserves in this rough valuation ignores the significant incremental value of inventory beyond SEC-proved reserves. We'll remain flexible and adapt to market conditions, project returns, and prudent reinvestment with this expanded repurchase program providing additional scale to a compelling option for use of free cash flow. Hard work, focus, and swift but precise adjustments to our business plan, without veering from our core objectives, are demonstrating the value of Range's portfolio and business. Patience and diligence allowed early returns of capital to come in the form of debt reduction and share repurchases. Now, continued returns of capital are planned as we work to narrow the gap between share price and intrinsic value of per-share exposure to what we believe is the largest portfolio of quality inventory in Appalachia. We seek to continue this trend of disciplined value creation for our shareholders. Jeff, back to you.
spk10: Operator, we'll be happy to answer questions.
spk01: Thank you, Mr. Ventura. The question and answer session will now begin. If you would like to ask the question, please indicate by pressing the star key, then 1. If you are on a speakerphone, please pick up the handset before asking your question. If you would like to withdraw your question, you may do so by pressing the pound key. Once again, please press star then 1 to ask the question. Our first question comes from the line of Josh Silverstein with Wolf Research. Your line is open.
spk04: JOSH SILVERSTEIN, Thanks. Good morning, guys. You're at about $2.5 billion of gross debt as of March 31st, and based on the forward outlook to be – or your target to be at $1 to $1.5 billion of gross debt. How are you utilizing the $1.4 billion of free cash flow strip? I imagine you're probably trying to take out the $750 of notes next year. But how do you look at the remainder of that cash balance?
spk02: Sure. Good morning, Josh. This is Mark. So you're right. Strong prices have taken what was a very compelling forecast of free cash flow earlier this year and bumped it by another billion plus over the next couple of years. So with that, we can achieve the balance sheet sooner than was previously forecasted. So in the near term, the 2022s will be redeemed in May at par. The 2023 notes can be redeemed at par in December. So as we roll forward, we are likely, I would say, to hit the absolute debt levels in early 2023. You know, sitting here at 1.6 times leverage today, clearly within a month or two, we're well within the relative leverage ratio we want to be in. But in absolute terms, easily, based on current strip pricing, able to achieve absolute debt levels in early 2023. So what that does is it gives us greater flexibility to in how we want to use that incremental free cash flow. You know, slide 14, we highlight the, what we're labeling excess free cash flow, optionality around executing our existing return of capital program and potentially the forms that may take in the future. But just to circle back, you know, this is, this return of capital program, the application of our free cash flow is really just a continuation of what we've been doing largely for the last four or five years in reducing debt, debt down in aggregate, 1.7 billion or more to date. We've bought back to date 10,600,000 shares. We've focused on improving the balance sheet while creating value for shareholders. So in the near term, cashflow easily meets debt maturities and gives us a lot of choices on the retarded capital program.
spk04: Got it. And just on the buyback as well, you know, obviously that's a pretty strong kind of 15, 20% free cashflow yield next year. Are you thinking about your yield at that level when thinking about the buyback? Or are you looking at prices at a lower level and then comparing that to what the stock is?
spk02: Yeah, I think we triangulate using a number of different valuations. We, of course, run NAV. We look at simplistically proved reserves and the value. I think that's a decent yardstick or at least a gut check on valuation. We look at relative value of other investment opportunities just in terms of overall market. But What it comes down to is that given the sheer scale of ranges inventory, there is what we believe to be such a significant gap that repurchasing shares is just such a compelling opportunity that that's the primary focus of the return on capital program.
spk04: Thanks for that. And then just the follow-up. There's obviously a lot of focus now to try to get incremental sales volumes into the international pricing. Can you just talk about the opportunity for you guys? You send volumes to the Gulf Coast now. How are those discussions going and what are the opportunities for you?
spk03: Good morning, Josh. This is Dennis. I think you touched on it, but I'll start with our portfolio configuration. Right now, from a net gas standpoint, 80% of our gas gets out of the basin. Of that, 50% gets to the Gulf and then we have Of that, another 30% that essentially gets to other, we'll call it non-northeast markets over to the Midwest as an example. So for the past several years, we've tried to take the approach, whether it's on our nat gas side and on our NGLs, which you've heard no doubt Alan and the rest of the team talk about, let's get our molecules to premium markets so that we can enhance our margins as much as possible. and have exposure to multiple indices and different contract structures, which I know, again, we've talked about. From the ethane perspective, it could be things like being exposed to, you know, European naphthic as an example instead of just being looking at a Montbelvi alone type index. As we go forward, you know, we fully expect that we're going to continue to have conversations as LNG-type infrastructure receives more and more support, hopefully, to develop. And when you look at I'll pick on LNG just particularly for one moment. When you look at the long runway of core inventory that range has, where we're at being on the low end of the cost curve and also being on the low end of the emissions curve, not only for the U.S., but also globally, we feel like that's going to position us well. to continue to basically move our gas on the pipes that we have to get to places like the Gulf as that infrastructure develops, and even in the Northeast if we see future LNG facilities come into play there. We feel like we're well poised for that. These are multi-decade decisions for this infrastructure to go into the ground. And so we feel like our inventory is going to feed well into that. And for those organizations who are going to want to build that infrastructure, they're going to be looking for a surety of supply. So We'll have ongoing conversations in the future. We want to get our molecules again to those premium markets. We've been playing in the LNG space for the past several years. We've got some volumes that are already going to those type infrastructure setups, and we'll continue to do so and look for those opportunities going forward.
spk04: Great. Thanks, guys.
spk03: Thanks, Josh.
spk01: Thanks. Our next question comes from the line of Michael Cielo with Staple. Your line is open.
spk12: Good morning, everybody. Mark, excuse me, Jeff, you said that you could grow when the market calls for it. You've had a pretty good handle on the macro outlook. I'm wondering, when do you anticipate the market will need either more production from rain specifically or even Appalachia? Does that get pushed out at all with higher gas prices, or how does that look right now in terms of when you would anticipate growth from either Appalachia or range?
spk10: Yeah, well, I think, you know, in terms of on the macro side, you know, we saw it even in Europe last summer, you know, with the hard push with Europeans towards wind and solar and the issues they had last summer. and basically needing more gas. And even if you roll back over the last decade, countries like Germany, you know, shutting down post-Fukushima, shutting down nuclear and moving away from coal and pushing into wind and solar and realizing, yeah, they had a big need for natural gas. And then, of course, with the tragedy in Ukraine, now having the source of your supply, an ethical source and a surety of supply and all those types of things are critical. So that, I think, really increases the call on gas from the U.S. for LNG. Fortunately, the U.S., as I mentioned in the call notes, U.S., with the discovery of the Marcellus Utica Point Pleasant, now has the largest producing gas field in the world, and we're by far the largest producer of gas globally. You know, it's not even close. So I think there would be a bigger call on U.S. gas, which will increase demand. The other thing, you know, you've seen is – Again, going back to the crisis in Europe, an increased call on U.S. coal. And then in the U.S., less coal to gas. They're switching away from gas to coal, coupled with higher pricing. So all that, I think, says, you know, more supply, more demand for U.S. gas. Fortunately, we're in the basin that has the largest gas field. We have the largest core inventory. So I think we're in a good position. And of course, you've seen the strip now increase price, not just the front month, but really for the next decade, gas prices move up. So we're in a good position as far as range for this year. Clearly, we're at maintenance capital, which said that, and we'll stick with that. And Mark talked about the waterfall of capital, one, maintenance capital, two, debt reduction, three, shareholder returns, and then, but the ability to grow. So, you know, when that's called for, and that'll then you get into the whole discussion of infrastructure and the timing and all those things, which we'll consider. And infrastructure, by the way, not just in the Marcellus, but you're seeing constraints potentially pop up, you know, within a year in the Hainesville and even widening of basis in the Permian on gas takeaway. So we think we're in a good position to call on U.S. demand higher. We have – largest core inventory, good relationships with international customers. We have contracts. We've been in discussions. So I think we're in a good spot.
spk12: Is it fair to say, given those things you laid out, especially the constraints, that you're probably not able to really grow much in 2023, or is there some possibility of grabbing market share that early?
spk10: Well, you know, we'll look at that as we get later in the year and lay out 2023. Even within the basin, it's different whether you're in the far northeast part of the Pennsylvania, per se, versus in the southwest part of the play. So where we are, we're in a better position. There is some takeaway capacity in the southwest part of the play. Currently, you know, through coal plant retirements, through the shell crafters will come on. They'll have a little incremental demand for gas and those types of things. So coupled with, you know, the discussion that everybody's, you know, focused on MVP, it's 95% done and there's a big call on it to be complete. So we'll see, you know, does that get completed in 2023? You know, and any of those things that takes gas out of the basin, you know, creates more space. And I think the other thing that you do see is limits to core inventory or tier one inventory, not for us, but for other people. So that could also create some space and some ability to take market share.
spk12: Thanks for that detail. And I just want to follow up on Project Canary, see where that stands today, and if there's any line of sight of getting to a premium price for responsibly sourced gas.
spk03: This is Dennis. Thanks for the question. At this point, we've been awfully pleased with the monitoring that we've had really across the program. I think we've mentioned it in the past. We've had four paths that essentially we've gone through the certification process with Project Canary. We continue to investigate other alternatives for monitoring and a lot of it so that we make sure that we're continuing to capture data. We know that that is really key to telling our story and further supporting missions numbers like we touched on today in our call notes for 2021. The RHG right now, the premium that we've been able to capture has more than covered the cost, but as you can imagine, that's still an emerging market and emerging space. So until that market, let's just say, further develops, we're continuing to collect data, we're continuing to investigate, you know, for the various certification pathways, what makes sense for range, and also our counterparties. We're having a lot of ongoing conversations between our marketing team and those that we're transacting with on a regular basis so that there's alignment there as well. And so I would fully expect to see us continue to play in this space as we move forward and further tell our story about our low emissions and where we stand.
spk12: Thank you, guys.
spk01: Thank you. Our next question comes from the line of Doug Leggett with Bank of America. Your line is open.
spk11: Good morning. This is John Abbott on for Doug Leggett. The first question that we have is on your transportation optionality. Specifically, we're looking at slide number 11, where you talk about gathering costs declining naturally over time, and then you have optionality with your transportation agreements. We have the option to redo or let them expire. Any color on those transportation agreements that could potentially expire? Just given where gas prices and commodity prices are at, does it make sense to let them expire at this point in time?
spk03: Yeah, good morning, John. This is Dennis. I'll tackle that first here. Mark may want to chime in. But ultimately, I think one of the reasons why we've always couched it as a decision point for us to retain, renew, or release, depending upon what's going on in the marketplace, is for the very question, I think, what you're asking here. I think as we look forward and we have conversations around infrastructure, you can make the argument that some of the portfolio it would make sense to retain. But we're going to evaluate each one of those as they get ready to expire from a cost perspective, not only cost, but what markets they get to. Clearly, if you take a pipe like MVP as an example, it starts to, yes, add takeaway, but it also changes some of the dynamics and maybe pricing at the different end markets that we could see. So from a diversification standpoint, I'll go back to maybe how we started visiting with Josh this morning. We will want to have some diversification in our portfolio because we see that as key both today, and it's been that way historically, and we expect it to be important as we move forward. But to specifically answer your question, would we let those expire? I think we'll no doubt evaluate each one of those as we get close, and we'll make the right decision for our program, whether it's more maintenance-type activity, other pipes get commissioned, or if we are looking at some low, modest growth-type profiles.
spk11: Appreciate it. And then our follow-up question is on cash taxes. You updated your long-term view, and you've suggested at least $1 billion of free cash flow per year in 2025 and beyond. Mark, we understand that you have the NOLs. You know, just assuming long-term $4 gas, at what point do you see yourselves as a full cash taxpayer?
spk02: Sure. So cash tax is clearly top of mind for everyone. It's a byproduct of higher commodity prices, so something the industry hasn't faced in a while. But fortunately for Range, sitting with about $2.9 billion in federal NOLs, we are starting from a very strong position. That's an asset, a deferral of cash taxes for our shareholders that, frankly, with higher prices gets realized sooner than just even a few months ago. I think it's important to note the composition of that NOL. When those are generated alters how they are utilized going forward. So for range of the total $2.9 billion in federal NOLs, about $1.2 billion of those are able to be used and offset up to 100% of your taxable income. After that, the remaining $1.7 billion or so, you're able to offset up to about 80%. of your taxable income. It just has to do with regulations and when those NOLs were generated. So what it means is for 22 certainly don't expect cash federal taxes for 2023 in the next few years you will be able to use that 1.7 billion bucket and offset the vast majority would expect some 80 percent or more based on that NOL as well as the deductions generated in those years. So suffice it to say that while cash taxes may be due in the next couple years, they will be largely mitigated and pushed out, and I think that's a very good relative position compared to peers. We also noted that we've got 860-some million NOLs at the state level in Pennsylvania. We commented on the year-end call that, again, within the state of Pennsylvania, you can offset up to about 80% of your taxable income very low effective rate, think 1% type area for state level taxes.
spk11: Appreciate it, Mark. Thank you for taking our questions. Thank you.
spk01: Thank you. Our next question comes from the line of David Deckelbaum with Carlin. Your line is open.
spk08: Thanks for taking my questions, everyone. I just wanted to ask a follow-up on the LMG side, if I might. As you think about the world kind of growing, you laid out in your slide deck certainly the demand of, call it like an incremental 20 BCF a day of projects. In a world where infrastructure isn't necessarily keeping up with that, beyond MVP, is there a, I know others have asked about this today, is Is there a general number that we could think about the incremental capacity that range would have to grow on a million cubic feet a day basis beyond the 400 that's coming up for recontract?
spk10: Wait, let me just at a high level. I mean, you know, we're saying 50% of it goes to the Gulf. So, you know, 50% of, you know, one-sixth. just the gas part, ignoring the NGOs, is $800 million a day. Then you can look at incremental growth beyond that, but let me flip it to Dennis.
spk03: Yeah, David, I think maybe I'll take a step back and maybe attack this a little bit differently. There's no doubt I think we're all seeing, as Jeff touched on in his comments this morning, the benefit of having additional infrastructure that goes into place for energy security, both here locally, but also when you think about it globally. is that infrastructure, as it reaches support and gets built and commissioned, in some ways I would say, you know, growth really becomes a part of the line of sight once you see that infrastructure to start to come into realization, if you will. But regardless whether range, you know, sends, you know, future growth molecules to an LNG facility or that frees up the ability to put, you know, gas into other local infrastructure, as Jeff pointed to, like the Shell Cracker facility or other outlets, it really provides optionality. And back to some of the diversification that we pointed to earlier in some of our comments around pipes expiring or renewing. So we see that as just really good optionality for us, much like in some regards our ethane optionality when you look at us having ethane molecules on three of the four main outlets out of the Northeast, just kind of as a tangent. I don't know that growth is necessarily going to be the driver in this, but we do see that that infrastructure comes into place. It provides good optionality, and whether we see the best premiums and margin enhancement through the LNG facilities or we take those molecules and put them into other infrastructure, we look to further improve our margins by doing so.
spk10: And I would just say globally, you know, if you look at commodities like oil or gold or wheat, U.S. commodities trade kind of like global commodities, except for natural gas. So as the natural gas export facilities expand and grow, U.S. gas should raise the price of U.S. gas. It should trade more like a global commodity. So we have the access to get to LNG facilities. And we're in discussions that we have good relationships on some of the international players, but even the other, just US gas in general, I think would come up as a trade more like a global commodity.
spk08: That's a great point, Jeff. And then, you know, my only follow-up would be, I know Josh asked about this earlier on how the contracting conversations are going. Do you think that there is sort of a high for fixed price that would be coming from demand contracts that would incentivize more offshoring of domestically produced gas that, you know, might sort of bridge this transition from gas trading as more of a domestic fuel versus a global commodity?
spk10: Yeah, I think as people bid more for U.S. gas, and again, as that, you know, ARB, you know, will decrease with time and compress. So the answer is yes.
spk08: Thank you, guys. Thank you.
spk01: Thank you. Our next question comes from the line of room. J.O. Ram with J.P. Morgan. Your line is open.
spk13: Yeah, good morning. I wanted to get some thoughts from the team on how you think the Russia-Ukraine conflict will impact NGL export fundamentals, you know, ethane and maybe the heavy end of the barrel. So quick thoughts on how you think the conflict and call it the rerouting of energy supplies to Europe could impact NGL fundamentals.
spk07: Yeah, thanks, Arun. This is Alan. I head up our liquids marketing business. Appreciate the question. It's a good question. The impact, I'll start with LPG. The impact on LPG is, it's rather small on a global basis, but kind of like with gas and crude, it's big with respect to Europe's imports. So Russia exports roughly, call it 40,000 barrels per day of LPG to the waterborne markets. and about 100,000 barrels per day via overland markets. So again, that represents 140,000 barrels per day. That's around 1% of total global LPG demand. But it's a much bigger portion of Europe's imports. And as a result of that, Europe is going to be tight, and that tightness If you have to replace those barrels, the best market to get them from is really from the U.S. We're best situated from a logistics standpoint. And in particular, Marcus Hook, where we have our exports out of, are best positioned to supply any shortfall in Europe due to Russian sanctions. That could, you know, just that 140,000 barrels per day or so, just to put into context, that's roughly equivalent to five extra VLGCs per month out of the U.S. Gulf Coast or out of Marcus Hook. So it's a significant amount. That's a direct impact on LPG. There's some indirect impacts as well. If we look at just NAFTA coming out of Russia, It is roughly four times more than what the LPG is. So the naphtha markets are tightening globally. And what that means indirectly for LPG is that the spread between propane and naphtha is going to widen in favor of propane actually becoming more preferred going into flexible ethylene steam crackers. And that could add a big chunk of demand And we're already seeing that starting to happen in Europe. And then finally, shortages of natural gas. As we've seen, TTF prices are high. They can obviously go higher. So anyone that can actually put LPG into fuel probably started doing that last fall. But if there's physical shortages of natural gas, there's going to be continued creativity people continue to be motivated to look for other ways to fuel LPG, whether it's at industrial complexes, refineries, or just spiking directly into natural gas. So we see a lot of indirect impacts that, you know, could almost double the call that we previously had on demand growth for LPG globally over the next couple of years. So what that means for propane, you know, right now it's trading down around, call it 53%, 55% of WTIs. Our view is still that it's going to be 60% to 70% of TI, and really it's only lagged recently because we've just gotten through the winter, and I think some of the fears of running out of supply this winter have kind of eased, and that's led things to ease a little bit. Also, crude itself is just really bullish right now, and so with both propane and crude bullish, with crude being much more liquid than propane, there's been some lag, let's say, in the price of propane, but fully expect that we'll see that relationship or that ratio increase in favor of propane as we go through the rest of the year. For the last part of your question, you asked about ethane, and really we don't have a lot of visibility on that. I don't think there's really much of an impact, except to say indirectly again, what we're seeing is that for international crackers that rely on naphtha or heavier feedstocks, the appetite for something like ethane out of the U.S., and in particular, out of Marcus Hook, has been really, really high, just because the advantage to cracking ethane is so far superior to that of the other feedstocks. So we've seen, and Dennis commented on this in his prepared remarks, we've seen ethane exports really high and continuing to increase. And given our forecast for this year with new ethane VLECs coming on the market. We only see that continue to increase as we go through the year. So I hope that answers your question.
spk13: No, that was great. And I just have a quick follow-up. You guys have takeaway capacity to move half your gas volumes to the Gulf Coast. You mentioned that you're selling 400,000 MMBTU a day to LNG exporters. I wondered if you could comment on what kind of pricing are you getting relative to those volumes? Are you getting any sort of premium relative to Henry Hub? And then as you think about potentially looking at, call it marketing agreements, maybe long-term supply agreements to LNG exporters, could you talk about what type of risk would a producer have in periods where, let's argue if you signed a 10-year agreement where in periods where the market may be, you know, have a temporary supply imbalance and where, you know, prices, you know, globally were weak. So I just want to talk about, you know, what kind of risk does a producer have in some of those long-term agreements?
spk03: Yeah, Ruth, this is Dennis. I'll start off with kind of the current and then move to the future. And from a current perspective, you know, the 400 a day that we've referenced that is already contracting in the LNG space, you know, I think if you were to look across the board, historically, a lot of those have been based on some kind of, we'll call it natural gas indices. And so it's pretty common, whether it's Range or others, I think, to have a similar structure. We don't typically, as you would imagine, disclose what those contract terms look like. But it's competitive in the portfolio. It's a good way of adding in some diversification to how we look at pricing and getting exposure to different environments. So it's very competitive within the portfolio that we have today. As we look at the go-forward, though, piece, I mean, we're open to those conversations, whether it's exposure to TTF or, you know, basing it on something more traditional, whether it's hub-based or something else. And I'll reference back to something we touched on earlier. As an example, we were the first to export ethane out of the U.S. And as a part of that, along with other ethane deals that we put in place, came different exposures to different indices and structures, like European NAPFA as an example. So we are very open to different exposures. We also want to make sure that we're aligning the risk with the rest of our program, though. And so that's where, you know, clearly, you know, Mark's input and the rest of the senior management team comes into play as well. We will make sure that that all aligns, coupled with that diversification. So we've been playing in that space for the past several years. We're open to it, but it also has to align with the risk of our organization.
spk13: All right, great. Thanks.
spk01: Thank you. We are nearing the end of today's conference. Ladies and gentlemen, we are nearing the end of today's conference. We'll go ahead and answer Noel Parks of TUI Brothers for our final question.
spk06: Hi, good morning. Good morning. You know, with the improvement we've seen in gas prices, of course, that does a lot for free cash flow upside. But I was wondering, I think since the last call, the two-year strip is up about $2 to $2.50 since then. And I'm just wondering, as far as how you look at your inventory and its definition as priorities, What's the maybe first or lowest hanging fruit benefit that you get from just that extra price flexibility? Does it have any implications for geography or for just drilling patterns? Does it give the ability to concentrate more in certain areas because the inventory is high-return inventory pool sort of expands if you sustain higher prices for a while?
spk02: Sure. No, this is Mark. I'll kick it off. So with Range's footprint, 250-plus pads across southwest Pennsylvania, existing pads and infrastructure in northeast Pennsylvania as well, and our practice over a number of years of adding wells to existing paths as well as building new paths, you've got what I'll call, at a very superficial level, a blended average to an extent of inventory within each program year. So a year's drilling program is not selected. Each individual well is not necessarily selected because it was economic only at $250, so we're going to drill this well. This well was economic at $4, so we're going to go drill this well. As we look at a program year, It's about the overall return of that program, the availability of infrastructure, be it the gathering system, the compression, and the ultimate destination and realized price and net back for that production. So the price is certainly beneficial, but it, I would say, has not significantly altered how we view the inventory in totality or the drilling program. With some 3,000 locations in the Marcellus, 2,000 of which are 2 PCF per 1,000 and greater, That hasn't altered. One question that's come up periodically is, are you drilling the Lycoming County, the northeast Pennsylvania, because prices are up and you're dipping into different inventory? The answer is no. The returns across all of our wells are highly competitive with the program. Drilling those wells is no different than drilling a selected pad in southwest Pennsylvania. It's a function of available transport, gathering, and so forth, and the returns on those wells is competitive. Long-winded to answer your question, I would say prices are clearly a positive, but it doesn't alter how we view the allocation of capital and wealth selection.
spk06: Great. Thanks a lot. And just my follow-up, given that you have achieved a smaller FRAC footprint, I was wondering if that also had any implications operationally in terms of just what you have to or can do as far as, you know, offset FRAC planning and so forth.
spk03: Yeah, Noel, I I would kind of frame the smaller footprint as benefit today, more benefit in the future, meaning we know that as we return to our pad sites. As I take a step back, we've got around approximately 250 pad sites. When you look at us having close to 1,200 producing wells across the field, you can kind of do the math. It's somewhere in the neighborhood of around five to six, kind of an average window of number of wells per pad. But as we move back to those pads with existing infrastructure, our ability to conduct simultaneous operations, produce wells safely, all of that plays a factor in how we're forward-looking around efficiencies, safety, and really continuing to develop our assets and harvest our reserves. So significant benefit in the near term. I'd say more benefit as we look in the future, and we're going back to those pad sites that then have 8, 10, or even a few more wells.
spk06: Great. Thanks a lot.
spk03: Thanks, Noel.
spk01: Thank you. This concludes today's question and answer session. I'd now like to turn the call back over to Mr. Ventura for his closing remarks.
spk10: Yeah, I just want to thank everybody for participating in the call this morning, and feel free to follow up with any additional questions you might have. Thank you.
spk01: Thank you for your participation in today's conference. You may now disconnect. Everyone have a wonderful day.
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