Range Resources Corporation (RRC) Q1 2022 Earnings Report, Transcript and Summary

Welcome to Range Resources’ First Quarter 2022 Earnings Conference Call. [Operator Instructions] At this time, I would like to turn the call over to Laith Sando, Vice President of Investor Relations at Range Resources. Please go, ahead sir.

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 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. Hopefully, you’ve had a chance to review the press release and updated investor presentation that we posted on our website. We may reference certain of those slides on the call this morning. You will also find our 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. 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 under investment 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 and making the U.S. the largest natural gas producer in the world. The result is natural gas prices in the U.S. are significantly lower than natural gas prices in Europe and Asia. Currently U.S. pricing is about 75% lower than prices abroad, creating a significant number of quality jobs, making U.S. manufacturing more competitive, helping to keep the U.S. utility bills lower than other countries, positively contributing to the U.S. 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 is 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 Range is 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 unexpected 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 million 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, Range 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 liquid production also received a premium to Mont Belvieu 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 cashflow 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 be again 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 what we believe is a fraction of the underlying value of the business, particularly with long-term commodity prices rerating higher as a call for U.S. natural gas becomes more evident globally. We have discussed our long-term balance sheet target of $1 billion 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 move 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 and company valuation, we can point to Range’s proved 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 proved reserves was $12.7 billion. For context, after backing out yearend 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 you’re aware, the SEC definition of proved 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 has 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’s 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, 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 in current and future demand. And within Appalachia, Range 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. Range’s de-risk 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 low sustaining capital requirements that Range enjoys reflected in our peer leading drill and complete spending per mcfe, which allows us to whether potential service cost inflation better than most and generate healthy margins. At the same time, Range’s balance sheet is in the best shape and 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 in returns of capital to shareholders. I’ll now ask Dennis to cover operations.

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 to top hole rigs utilized to drill the shallow vertical section and two frac 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 million 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 plan 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 length that averaged more than 18,000 feet placing them in the top 15 longest laterals in Range’s 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 along 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 cost 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 drill during this timeframe enable the team to reduce drilling costs by 4% on a per foot 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 1,000 frac stages while setting a first quarter completions efficiency record by averaging over 8.5 frac stages per day. During our previous call, we mentioned an emerging step change in our efficiencies and 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 frac 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 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 ranges continued ESG efforts by minimizing emissions, all while generating power from clean burning natural gas from Range’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 cost for the quarter by nearly $3 million. Our 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 block acreage position. And lastly, lease operating expense for the first quarter finished it just under $0.11 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 frac fleet contract extension, which will commence on November 1. 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 as low based decline and peer leading well cost service a hedge against service cost inflation. For context, our maintenance capital program of $460 million to $480 million for 2022 works out to approximately $0.60 cents 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 we’re estimated to be 27% above the five-year average, while domestic demand was 17% higher year-on-year. Together, these fundamentals helped push Mont Belvieu ethane prices 29% higher through the first quarter. This backdrop coupled with ranges diverse portfolio of NGL contracts drove a $0.74 barrel premium to Mont Belvieu for the quarter and Range’s absolute pre-hedge NGL price increased to more than $40 per barrel. Additional domestic ethane demand such as the shale 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 historic low levels, which coupled with several periods of cold weather boosted Mont Belvieu 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 expect 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 and export demand will present a challenge to domestic buyers as they work to refill storage levels from historically low levels, supporting Mont Belvieu pricing through the summer and setting up for another bullish winter for the 2022, 2023 season. This continued strengthening of NGL outlook and price realizations further supports our 2022 NGL guidance range of 0 to $2 per barrel premium relative to the Mont Belvieu 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. Underpinning Range’s realized natural gas price of $4.92 was 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 [indiscernible] 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 report, 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.

Thanks Dennis. In the first quarter, the Range team delivered on stated objectives, pursuing our 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 re-initiation of our share purchase 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 billion to $1.5 billion area, which is achieve 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 de-leveraging in coming quarters, we're able to execute both debt reduction and our return of capital program. These two objectives of 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 $5.53 per mcfe compared to $3.20 first quarter last year. This realized unit price is $0.74 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 a mcfe basis. Range's diversified portfolio of transportation capacity and customer contracts support differentials such that the total per unit price received by range remains a premium to Henry Hub natural gas and Mont Belvieu NGLs. Hedged cash margins per unit of production expanded to $2.65 up 156% compared to first quarter last year. Range's 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 G&A continued near multiyear 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 $0.16 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 liquidated 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 ranges 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 $0.32 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 ranges, 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 varying from our core objectives or demonstrating the value of ranges portfolio and business. Patients 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 and Appalachia. We seek to continue this trend of disciplined value creation for our shareholders. Jeff, back to you.

Operator we will be happy to answer questions.

Thank you, Mr. Ventura. [Operator Instructions] Our first question comes from the line of Josh Silverstein with Wolfe Research. Your line is open.

Hey, thanks. Good morning, guys. You're about $2.5 billion of gross debt as March 31st and based on the forward outlook to be or your target to be at $1 billion to $1.5 billion of gross debt. How are you utilizing the $1.4 billion of free cash strip? I imagine you're probably trying to take out the 750 of nodes next year, but how do you look at the remainder of that cash balance?

Sure. Good morning, Josh. This is Mark. So, you you're right. Our strong prices have taken what was very compelling forecast to free cash flow earlier this year and bumped it by another $1 billion plus over the next couple 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. 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 in how we want to use that incremental free cash flow. 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 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, that 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 balance sheet while creating value for shareholders. So, in the near-term cash flow easily needs debt maturities, and gives us a lot of choices on retard capital program.

Got it. And just on the buyback as well, obviously that's a pretty strong kind of 15%, 20% free cash yield that strip 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 the stock is?

Yes. I think we triangulate using a number of different valuations. We of course run NAV. We look at simplistically proved reserves in the value; I think that's a decent yard sticker, 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 re-purchasing shares is just such a compelling opportunity that, that's the primary focus of the returner capital program.

Thanks for that. And then just the follow up, there's obviously a lot of focus now to try to get incremental sales volume into international pricing. Can you just talk about the opportunity for you guys? You send volume to the Gulf Coast now. How are those discussions going and what are the opportunities for you?

Yes, good morning, Josh. This is Dennis. I think when you touched on it, but I'll start with our portfolio configuration. I mean, right now from net gas standpoint, 80% of our gas gets out of the basin. So, 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 net gas side and on our NGLs, which you've heard, no down 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 at different contract structures, which I know, again we've talked about. From the ethane perspective, it could be things like being exposed to European asset, as an example, instead of just being looking at a Mont Belvieu alone type index. As we go forward, 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 on the low cost – of 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 our pipes that – 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. So, 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 steady 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 volume that are already going to those type of infrastructure setups, and we'll continue to do so and look for those opportunities going forward.

Great. Thanks guys.

Thanks Josh.

Thanks. Our next question comes from the line of Michael Scialla with Stifel. Your line is open.

Yes. 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 need either more production from rain specifically or even Appalachia? And does that get pushed out at all with higher gas prices or how does that – how does that look right now in terms of when you would anticipate growth from either Appalachia or Range?

Yes. Well, I think in terms of on the macro side we saw it even in Europe last summer. With the hard push with Europeans towards the wind and solar and the issues I had last summer and basically needing more gas, and even if you roll back over the last decade countries like Germany shutting that post Fukushima shutting down nuclear and moving away from coal and pushing in the wind and solar and realizing, yes, 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 shortage 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'm mentioned in the call notes, U.S. with the discovery of the Marcellus Utica/Point Pleasant is now has the largest producing gas field in the world and whereby far the largest producer of gas globally. 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 I'd – you've seen is again going back to the crisis in Europe and increased call on U.S. coal, and then in the U.S. less coal to gas or switching away from gas to coal coupled with higher pricing. So, all that I think says more supply, more demand for U.S. gas. Fortunately, we're in the basin that has the largest gas bill. 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 we've 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, 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 in infrastructure by the way, not just in the Marcellus but you're seeing constraints potentially pop up, within a year in the Haynesville and even widening of basins in the Permian on gas takeaway. So, we think we're in a good position call on U.S. demand higher, we have largest core inventory, good relationships with international customers we have contracts, we’ve been in discussion. So, I think we're in a good spot.

Is it fair to say given those things you laid out, especially the constraints that you are probably not able to really grow much in 2023, or is there some possibility of grabbing market share that early?

Well, 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, through coal plant retirements, through the shale cracker will come on with capital incremental demand for gas and those types of things coupled with the discussion that everybody is focused on NBP, it's 95% done, and there's a big follow-on it to be complete. So, we'll see, does that get completed in 2023? And any of those things that takes gas out of the basin creates more space. And then, I think, the other thing that you do see is limits to core inventory or Tier 1 inventory, not for us, but for other people. So that could also create some space and some ability to take market share.

Thanks for the detail. And just want to follow-up on Project Canary, see where that stands today and if there is any line of sight of getting to premium price for responsibly sourced gas.

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, where we've had four pads that essentially, we've gone through the certification process with Project Canary. We continue to investigate other alternatives for monitoring. And [indiscernible] 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 emissions numbers like we touched on today in our call notes for 2021. The RSG right now, the premium that we've been able to capture has more than covered the cost that as you would 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, with the various certification pathways, what makes sense for Range and also our counterparties. We're having a lot of ongoing conversations with, between marketing team and those that were transacting with on a regular basis, so that there is 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 of where we stand.

Thank you, guys.

Thank you. Our next question comes from the line of Doug Leggate with Bank of America. Your line is open.

Good morning. This is John Abbot on for Doug Leggate. 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. I'll let them expire. Any color on those transportation agreements that could potentially expire just given where gas price and commodity prices are at, does it make sense to let them expire at this point in time?

Yes, 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 asked here. And I think as we look forward, and we had 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 in NBP, 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 on our portfolio because we see that is 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 when 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 profile.

I 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 in that you have the NOLs. Assuming long-term $4 gas, at what point do you see yourselves as a full cash tax there?

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, altered 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 a 100% of your taxable income. After that, the remaining $1.7 billion or so you are 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 2022, 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% 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 of 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 the state level taxes.

Appreciate it, Mark. Thank you for taking our questions.

Thank you.

Thank you. Our next question comes from the line of David Deckelbaum with Cowen. Your line is open.

Thanks for taking my questions, everyone. I just wanted to ask a of follow-up on the LNG 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 the world where infrastructure isn't necessarily keeping up with that, beyond MVP, is there a – I know others have asked about this today, 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 re-contract?

Wait, let me just at a high level, I mean we’re saying 50% of it goes to the Gulf. So, 50% of 16, just the gas part ignoring the NGLs is 800 million a day. Then you can look at incremental growth beyond that but let me flip it to Dennis.

Yes, 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 commission built in commission in some ways I would say growth really becomes a part of the a line of sight. Once you see that infrastructure to start to come into realization if you will, but regardless whether Range sends future growth molecules to an LNG facility or that frees up the ability to put gas into other local infrastructure as Jeff pointed to like the show cracker or other outlets it really provides optionality. In fact, 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. So, I don’t know that 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…

Yes, I would just say globally, 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 – it should raise the price of U.S. gas that should trade more like a global commodity. So, we have the access to get to LNG facilities and we’re in discussions and we have good relationships on some of the international players, but even the other just U.S. gas in general I think would come up as it trades more like a global commodity.

That’s a great point, Jeff. And then 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 might sort of bridge this transition from gas trading as more of a domestic fuel versus a global commodity?

Yes. I think as people bid more for U.S. gas, and again as that – or will decrease with time and compressed. So, the answer is yes.

Thank you, guys.

Thank you.

Thank you. Our next question comes from the line of Arun Jayaram with J.P. Morgan. Your line is open.

Yes, good morning. I wanted to get some thoughts from the team on how you think the Russia, Ukraine conflict will impact NGL export fundamentals, 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.

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 a 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 is some 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 our best position to supply any shortfall out of in Europe due to Russian sanctions. That could just that 140,000 barrels per day or so just put into context that’s roughly equivalent to five extra VLGC 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 naphtha coming out of Russia, it is roughly 4 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 it’s 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 ETF 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 and natural gas, there’s going to be continued creativity, people continuing 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 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, we – right now it’s trading down around call it 53%, 55% of WTI. Our view is still that it’s going to be 60% to 70% of WTI 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 why things to ease a little bit also crude itself is just really bullish right now. And so, with both propane and crude bullish and with crude being much more liquid than propane, there’s been some lag let’s say and other 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, 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 the for international crackers that rely on naphtha or heavier feed stocks, 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 feedstock. 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 forecasts for this year with new ethane VLECs coming on the market, we only see that continuing to increase as we go through the year. So, I hope that answers the question.

No, that was great. And I just had 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’m wondering if you could comment, are – 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 have a temporary supply imbalance and where prices globally were weak. So, I just want to talk about what kind of risk does the producer have in some of those long-term agreements?

Yes. Arun, this is Dennis. I’ll start off with kind of the current then move to the future. And from a current perspective, the 400 a day that we’ve referenced that is already contracting in the LNG space. 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 basing it on something more traditional, whether its 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 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 naphtha as an example. So, we’re very open to different exposures. We also want to make sure that we’re aligning the risk with the risk of our program though. And so that’s where clearly, Mark’s input and the risk of senior management team comes into play as well. We want to 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.

All right. Great. Thanks.

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 Tuohy Brothers for our final question.

Hi, good morning.

Good morning.

With the improvement we see in the 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 out about – 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 is 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, give the ability to concentrate more in certain areas, because the inventory – high return inventory pool sort of expands with, if you sustain higher prices for a while.

Sure. Noel, this is Mark. I’ll kick it off. So, with ranges 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 pads, as well as building new pads. 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 become 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 Marcellus, 2,000 of which are TTF 1,000 and greater. That hasn’t altered. One question that’s come up periodically is, are you drilling the Lycoming County in 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, that is 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. So longwinded 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 well selection.

Great. Thanks a lot. And just my follow-up given that you have achieved this 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 offset frac planning and so forth.

Yes. Noel, 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 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, we’re going back to those pad sites that then have 8, 10 or even a few more wells.

Great. Thanks a lot.

Thanks, Noel.

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.

Yes. 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.

Thank you for your participation in today’s conference. You may now disconnect. Everyone, have a wonderful day.