Range Resources Corp Q1 FY2023 Earnings Call

Welcome to the Range Resources First Quarter 2023 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. Statements made during this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties which could cause actual results to differ materially from those in the forward-looking statements. After the speakers’ remarks, there will be a question-and-answer period. At this time, I would like to turn the call over to Mr. Laith Sando, Vice President, Investor Relations at Range Resources. Please go ahead, sir.

Thank you, operator. Good morning, everyone, and thank you for joining Range’s 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. We may reference certain 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. We’ve also posted supplemental tables on our website that include realized pricing details by product along with calculations of EBITDAX, cash margins and other non-GAAP measures. With that, let me turn the call over to Jeff.

Thanks, Laith, and thanks, everyone, for joining us on this morning’s call. Range continued to deliver on our key strategic objectives in the first quarter, operating safely and efficiently to deliver a production plan that consistently generates free cash flow. Dennis and Mark will walk through the quarter, further demonstrating the resilience of Range’s program and assets even in today’s commodity price environment. As was announced last month, after 20 years with Range, I’m retiring, and this will be my last earnings call. I have to say I couldn’t be more proud of the work the Range team has done to position the company where it is today. Range is in the best operational and financial shape in company history and is poised to generate substantial free cash flow and competitive returns long-term, given our multi-decade inventory, efficient operations, and access to diversified markets. For the Marcellus, the future is bright as we sit at the very low end of the global cost curve with one of the lowest emissions intensities of any play. Given the size and potential of the Marcellus, it has the ability to help supply the U.S. and our allies for decades. I strongly believe the products we produce are going to remain in high demand as natural gas and natural gas liquids provide products needed for our everyday lives. Natural gas has many important uses, from generating electricity to making plastics. It’s a key ingredient in the manufacture of fertilizer for agriculture. It’s a key source of industrial heat for making steel and cement, and it’s used for heating and cooking, just to name a few. Given the importance of the Marcellus and Range’s sizable core position, I believe Range is in a desirable position to continue delivering competitive returns and creating sustainable long-term value for shareholders. Before turning it over, I’d just like to say that I’ll be forever grateful to the Range team for their dedication, creativity, and hard work. We pioneered what I believe is the best and largest producing natural gas field in the world and have developed it in a way that we can all be proud of as good citizens of the communities with industry-leading environmental practices. The discovery of the Marcellus in 2004 was a game changer for energy markets. This resulted in Range becoming one of the largest natural gas and natural gas liquids producers in our country, and the U.S. becoming by far the largest natural gas producing country in the world. The positive impacts have been many. Natural gas prices in the U.S. are more affordable than Europe and Asia, which helps direct the industry back to the U.S., creates hundreds of thousands of jobs, helps with national security, and improves the trade balance. In addition, the free market substitution of coal with natural gas has been the major driver behind the U.S. leading the world in CO2 emissions reductions. I thank God for blessing me with an opportunity to be part of the team that has not only unlocked these resources but has also been innovative in successfully producing and marketing the vast resources over the last two decades. I’ve said this on past calls, the team and Board we have in place today is the strongest it’s ever been. I look forward to seeing Dennis, Mark, and the entire Range team continue to move the company forward, generating significant long-term value for shareholders and making Range even stronger and more resilient. Thank you to my colleagues and friends. I’m so proud of what we were able to accomplish as a team. I’ll now turn it over to Dennis for his remarks.

Thanks, Jeff. It’s an exciting time to be a part of the Range team, and I’m humbled by the opportunity to lead the company in the years ahead as we remain focused on translating our world-class resource base into long-term shareholder value. Like Jeff said, the company is in a great position today, and we aim to continue working to make Range even stronger in the future. In the first quarter, Range continued to successfully deliver on our stated objectives. By completing our operational plans safely and with peer-leading efficiencies, generating free cash flow, further strengthening our financial position, and returning capital to shareholders in the form of share buybacks and a base dividend. Looking at operations, I’m pleased to report that our program is off to a solid start and is on track to deliver this year’s plan with a continued focus on capital-efficient operations, safety, and environmental performance. Our front-end loaded drilling activity for the year resulted in utilizing two top hole rigs and three horizontal rigs during most of the first quarter. We will maintain this level of drilling activity through the end of Q2 before tapering off in the second half of the year. Completions activity will remain relatively steady with one frac crew operating through 2023, while a second crew is activated later this year. This drill and complete cadence is consistent with previous year’s maintenance level programs, which generates turn-in lines and a production profile weighted towards the back half of the year. Capital spend for the first quarter was $152 million, which represents roughly 26% of our 2023 program budget. This is in line with the level of operational activity conducted during the quarter and puts us firmly on track with our capital guidance of $570 million to $650 million for the year. Production for the quarter came in at 2.14 Bcf equivalent per day and was underpinned by consistent field run time and strong well performance. We expect daily production in the second quarter to be approximately 100 million equivalent lower than Q1 as we have moved up planned annual midstream maintenance and turn-in lines are weighted towards the end of the quarter. Fields picked up in the second half of the year, making the fourth quarter our highest production, putting us on track to deliver a full year production of 2.12 to 2.16 Bcf equivalent per day. This back half weighted production profile fits well with the current shape of the natural gas curve. Shifting to operational highlights, our drilling team exceeded Range Prior’s record for fastest day drilling in the lateral section and then broke their own record two more times during the quarter. During the quarter, 13 wells were drilled that averaged daily horizontal footages greater than 1 mile per day. By comparison, only four wells achieved this level of efficiency in all of last year. These records, along with other strong days drilling in the lateral, drove a 42% increase in the average daily horizontal footage drilled per rig. The drilling team also successfully added three wells to the top 10 longest laterals drilled for Range, with all three laterals exceeding 18,800 feet. After drilling over 1,500 wells in the Marcellus, this is the type of incremental improvement that has become a cornerstone of our program, supporting our peer-leading capital efficiency. Completions placed just over 600 frac stages on three pads located across our dry, wet, and super-rich areas while utilizing our contracted electric frac fleet. Efficiencies remained in line with prior quarters, with the team averaging eight stages per day while varying completion designs based on well mix. Completion efficiencies continued to improve in late Q1 and into Q2 by averaging in excess of nine stages per day. As a byproduct, a pad currently being completed is setting a new standard for our overall operational efficiencies and is projected to be one of our most efficient pads in Range’s history. We look forward to providing more details on a future call. On the last call, we provided some context on inflation and how Range’s low base decline and peer-leading well costs serve as a hedge against service cost inflation. Year-to-date in 2023, we have seen the price of rigs and pumping crews start to show signs of receding slightly. Next-generation pumping crews continue to be in high demand, but the availability of traditional spot crews and drilling rigs has increased. Additionally, commodities and raw materials like tubular goods and sand are also starting to show signs of increased availability. It is possible this could translate into slight one-off savings later this year, with broader savings more likely to occur in 2024. Range remains in a leadership position on capital intensity, given our low base decline, strong well productivity, and our blocky acreage position, which lends itself to efficient operations and peer-leading well costs. Shifting over to marketing and looking at the NGL macro. U.S. LPG exports set an all-time monthly record of 2.1 million barrels per day in March, driving a quarterly record of over 1.9 million barrels per day. This level of export activity represents an increase of approximately 19% above the same time period last year, keeping domestic propane stocks within the five-year range, despite the unusually warm winter. Looking ahead to the balance of 2023, Range expects continued growth in the demand for U.S. LPG exports in order to satisfy ongoing strong demand in European and Mediterranean markets, as well as PDH demand in China that continues to recover with the addition of new capacity and due to the loosening of zero COVID policies. Range’s diverse NGL marketing agreements drove $1.63 per barrel premium to Mont Belvieu for the quarter, with an absolute NGL price of $27.60 per barrel. And our NGL pricing equated to $4.60 per Mcf equivalent, which was $1.14 premium to the average Henry Hub natural gas price. Liquids optionality is a key differentiator in our resilient free cash flow versus other natural gas producers. This becomes more evident when natural gas prices are challenged like they have been to start 2023. The ongoing strength in the NGL outlook and price realizations support our 2023 NGL guidance range of $1 per barrel discount to $1 per barrel premium relative to the Mont Belvieu index. For our natural gas, in Q1, Range reported a natural gas differential of $0.14 below NYMEX, including basis hedging with our realized natural gas price closing out at $3.58 per Mcf. Freeport LNG returning to full service and early signals of rig activity reductions should help storage levels normalize as we work through injection season and look toward next winter. Lastly, our team’s strong safety and environmental culture was on display as we reflect on both last year and Q1’s performance. Starting from an already low level, we continue to see further improvements in our safety performance in the field while capturing emissions reduction as a result of initiatives discussed on prior calls. We look forward to sharing more details on these accomplishments in our upcoming corporate sustainability report slated for release this summer. In summary, this year’s program is off to a solid start, and this is an exciting time to be a part of Range and our industry. Our low capital intensity, liquids optionality and our leading hedge program all come together to provide Range with one of the lowest breakevens amongst natural gas producers. I believe the resilience of Range’s business is being demonstrated in today’s challenging price environment, as we’re still delivering on stated objectives and generating free cash flow. I look forward to our future calls together as we continue to demonstrate our dedication to safe, efficient operations and consistently generating competitive returns to shareholders. I’ll now turn it over to Mark to discuss the financials.

Thanks, Dennis. The first quarter was successful operationally and financially, with solid execution across the business. Cash flow from operations totaled $475 million, funding net debt reduction of approximately $250 million, capital expenditures of roughly $152 million, the first quarter dividend, as well as 400,000 shares repurchased. Two objectives helping drive value are a durable balance sheet and competitive shareholder returns. These are not mutually exclusive. They are integral parts of our overall capital allocation strategy. We’ve consistently described a waterfall of our cash flow reinvestment. First, maintenance CapEx in order to utilize infrastructure and maximize margins; second, debt reduction towards target debt levels; third, return of capital to shareholders; and fourth, growth CapEx when appropriate. It’s important to note that this waterfall entails flexibility to allocate based on highest overall returns to the company and its shareholders. With Range’s leading full cycle costs, margins are resilient, generating free cash flow even at reduced commodity prices that support risk-adjusted returns-driven capital allocation. We’ve been focused on absolute debt reduction for several years. As of quarter-end, we have reduced debt net of cash by nearly $2.5 billion since it peaked in 2018. Debt reduction achieved to date places us close to entering our target range of $1 billion to $1.5 billion net debt. With current leverage of 0.8 times debt to EBITDAX and close proximity to our debt targets, we believe the company is in great shape to continue value creation on a stable financial base throughout business cycles. Taking a closer look at first quarter results, cash flow from operations of $475 million was driven by planned production levels, achieving strong pre-hedge realized prices of $3.82 per Mcfe. This realized unit price is $0.36 above NYMEX Henry Hub, driven by Range’s diverse sales outlets for natural gas, combined with the pricing uplift from natural gas liquids and condensate. During the first quarter, Range’s NGL price realized was approximately $28 per barrel or $4.60 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. Hedged cash margins per unit of production remained strong at $2.06. Range’s margins benefit from thoughtful hedging and continued focus on cost and efficiency. Total cash unit costs improved by $0.16 versus the prior year. The change compared to the prior year primarily relates to savings in processing costs, which are linked to NGL prices, with variations in other line items related to labor cost inflation or the timing of planned workover projects. Cash interest expense declined by $14 million for the quarter compared to Q1 last year, on reduced debt balances, equating to $0.08 per Mcfe savings. These improvements more than offset slightly higher LOE as mild weather allowed the team to pull some workover activity into the first quarter that would typically have been completed in Q2 and Q3. Range’s rightsized hedging program supported realized prices for the first quarter with $32 million in realized NYMEX hedging gains. Looking forward, Range’s natural gas is approximately 55% hedged at $3.50 for the balance of 2023, providing further support to Range’s free cash flow profile. Cash balances of $228 million at quarter-end, combined with future free cash flow and an undrawn revolving credit facility, provide ample liquidity to efficiently operate our business and execute efficient debt retirement. Successful first quarter results, combined with a positive industry backdrop for Range going forward, support our confidence in the return of capital program discussed on previous calls. We believe a stable, reliable fixed cash dividend is appropriate at this time and in this market, while remaining opportunistic in our share repurchases with capacity available totaling $1.1 billion, alongside our primary objective of reaching target debt levels. We will remain flexible and adapt to market conditions, project returns, and prudent reinvestment. Range’s story for a long time has been about innovation, translated into reality through dedicated teamwork, hard work, focus, and swift but precise adjustments to our business plan without trending from our core objectives or demonstrating the value of Range’s portfolio and business. This focus and dedication will continue as Range’s business is in the best shape in company history and primed for impending demand growth domestically and internationally for natural gas and natural gas liquids. With a strong financial foundation and 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.

Operator, we’ll be happy to take questions.

Thank you, Mr. Ventura. The question-and-answer session will now begin. Our first question will come from Michael Scialla of Stephens.com. Your line is open.

Yes. Good morning, everybody. Jeff, I wanted to offer my congratulations on a great career. Not too many folks can make claims about taking a big hand in a huge discovery like Marcellus. Congrats. And Dennis, congrats to you on your promotion, well-deserved. I want to ask first...

Thanks for the comments. Kind of you to say that, and much appreciated.

Absolutely. I wanted to ask about the decision to keep cash on the balance sheet. Mark, you mentioned your priorities for cash use and noted there’s some flexibility. Given that gas prices fell this winter, I was wondering about your thoughts on this, especially since you repurchased a significant amount of shares last year, totaling $400 million. Can you provide some insight into the choice to maintain cash on the balance sheet for now?

Good morning, Michael. There are several factors to consider here. We are continually assessing risks and returns, which is part of our capital allocation strategy. Since the beginning, we have repurchased over 14 million shares, including $400 million last year. This year, in the first quarter, we encountered the usual blackout period during our earnings preparation, and we also had the announcement regarding retirement and succession planning, all while dealing with fluctuating commodity prices. As we navigated through the early months and prioritized our options, we decided to retain that cash due to the potential benefits it offers. Looking ahead, we are nearing our debt targets, maintaining a few hundred million in cash, and our net debt is aligning with our target levels. This flexibility is advantageous as we progress through the year.

Very good. Dennis mentioned that you see storage returning to normal this summer. Could you provide a bit more detail on that? I know you are asked every quarter about your macro views, and you’ve been quite accurate regarding the gas macro. How do you foresee that developing? What factors contribute to the return to normal storage levels? Additionally, how does this connect with your thoughts on your cash priorities?

Yes, good morning, Michael. If we take a moment to reflect on the gas market, both in the near term and in the coming years, it’s clear we are beginning to see the shift from mere speculation to actual data reflected in the numbers. On the supply side, rig activity has started to decline, which has been evident over the past few months. For instance, in Appalachia, we are now in the third year of a maintenance level program that optimizes the gathering system's utilization and enhances our cost efficiency. When we combine our maintenance strategy with reductions in rig activity from other Appalachia producers, alongside the observable year-over-year well performance decline affecting production profiles, it suggests potential relief from an oversupplied market. This could be supported by looking at days of supply. As we approach the end of this injection season, inventory levels are projected to be around 3.9 or possibly 4 trillion cubic feet. When this is considered alongside the factors I mentioned, and the increasing demand we've seen in recent years—specifically from the industrial sector and LNG, particularly with Freeport ramping up to full capacity and upcoming infrastructure expected to launch in 2024—it leads us to estimate around 42 days of supply by season's end. This compares to the five-year average of 43 days and the 41 days we recorded in October 2022. The current commodity price environment is significantly different from what it was last October. Therefore, one could argue that the market may not be as oversupplied as suggested solely by the storage figures. On the demand front, LNG presents a unique scenario. Looking into 2024, we anticipate that Golden Pass Train 1 could be operational by midyear, which would have a meaningful impact as we head into the next injection season, putting everything in a favorable position. We plan to maintain our current level of operations, which we believe will align well with our transportation strategy and enable us to navigate through various market cycles.

And our next question will come from Doug Leggate of Bank of America.

Jeff, let me add my congratulations. You’ve been around for a very long time making some of us feel pretty old. So, I hope you enjoy the next stage of your endeavors.

Thanks, Doug.

So guys, I got a couple of questions. I guess my first one is for Mark. Mark, obviously, the stock and therefore, the market capitalization moves around quite a bit, we at least see the equity value as what’s left from enterprise value minus net debt. So, when you see the market failing to recognize a forward curve, which is 50% above a year ago, there’s two things you can do. You can buy back shares or you can reduce net debt to force market recognition of value. So, my question is, why is $1 billion to $1.5 billion the right number in a volatile commodity environment? Why not go tighter than that? You’ve seen some of your oil peers go to net debt zero. Why not?

That’s a fair question, Doug. So, as we’ve laid out our debt targets over the last couple of years, we began with what is the most conversational debt metric and easiest for everyone to understand that debt-to-EBITDAX ratio. Fundamentally, we believe the absolute debt number is what’s really important, given commodity price fluctuations and EBITDA fluctuations that naturally occur in the space, either cyclically or seasonally. So starting with a leverage ratio that investors and we believe are prudent levels, we set out some targets and thinking through a commodity price cycle, we said at the depth of the cycle, we want to be at or better than 2 times in mid-cycle. You might think around 1.5 times at a strong market, you want to be better than 1 times leverage. Those were not hard and fast. They were indicative levels we laid out. Actually, it’s on a proxy from a year before last. When you pressure test those levels against a variety of commodity prices, both for natural gas, oil, and NGLs, you can get to a $1 billion to $1.5 billion level at our current production levels. So that’s the genesis of the framework and those levels. They are indications indicative of what we think creates a solid financial foundation. That’s not to say that we can’t be opportunistic in strong environments and pay that down. That’s also by design to have a strong balance sheet to use that balance sheet appropriately when opportunities arise, whether that’s buying back shares, whether that’s putting cash on the balance sheet, and paying off debt opportunistically. So, again, those are guidelines just intended to make sure that Range from a financial standpoint has the wherewithal to capitalize and monetize this huge inventory we have over the long haul.

Fair. I’ll keep pressing on the 5% money. I wonder if that influences the decision a little, but we can discuss that later. My follow-up question is to congratulate Dennis and to lead into a two-part question. Dennis, the press release about your promotion to CEO mentioned something intriguing about the company’s sole operational area. My first question is strategic: with Jeff's retirement and your new role, should we expect any changes in strategy? Additionally, considering the speculation around the time of Jeff’s retirement regarding potential M&A for Range, have there been any discussions in recent months about other strategic alternatives that might have been considered for Range that could have fueled that speculation? I’ll leave it there. Thank you.

Yes. Thanks for the comments and the questions this morning, Doug. I’ll take a step back and really kind of start with the change of strategy piece, and then I’ll end up with your second question. I think you heard it from all three of us this morning and you’ve probably heard it from us on prior calls, but the company is in the best position it’s ever been in the history of the organization. When you look across the multiple facets that we report on, whether it’s financial, operational, safety, environmental, Range continues to really chip away at continuous progress. So, from our position, the company is in a great position today. We’re drilling some of our longest laterals, our fastest wells. Even after 1,500 horizontal wells being drilled in the basin, we’re still continuing to make that incremental progress, which we kind of see generating our highest return wells and being really resilient and durable through the cycles. We’ve got the best team in the business. I think when you look at some of the early on wells that we drilled with the RINs discovery well in the mid-2000s, there’s many of those team members are still with us today. That is difficult to put a dollar value on because their commitment level is tremendous. So, you’re in a lot of ways, Doug, you’re not going to see a lot of change from Range. It’s going to be staying the course, continuing to block and tackle in the aspects that we’re really strong and talented at, and that is really continuing to develop our assets, drill our best wells, and really generate competitive returns for our shareholders and generating free cash flow through the cycles. We see the world needs our clean-burning energy that we supply. And we stand ready to participate in that year in and year out with our program. As far as your follow-up question about any other considerations, I think ultimately, we’re prepared to go it alone. Again, when you look at the asset base we have and the quality of the inventory, now on our 15th year of a positive reserves revision, we stand poised to continue to, again, just continue to chip away at what we do best, incrementally improving our well performance, efficiencies and other aspects of our business. So no other considerations from our end.

And our next question comes from Bertrand Donnes of Truist.

Good morning, team. And thanks for everything over the years, Jeff, and congratulations, Dennis. Kind of piggybacking on Doug’s question. I know that debt reduction and buybacks are the current focus. But in the future, does the shareholder return program change? It seems like you’ll have the ability to accelerate production when the market asks for it. Is that what we should expect almost all cash flows to go to, or if you ramped your spending levels into a strong gas pricing environment, would that be accompanied by a balance of buybacks and dividends?

Yes, that's a relevant question. There are two points I'd like to address. First, looking at our activity levels from the previous year, our capital allocation strategies are implemented simultaneously and can vary in focus depending on our progress toward target debt levels, cash flow projections, and market conditions including stock prices. For instance, we've allocated 75% of cash flow in a quarter towards debt reduction and the majority towards share repurchases in another quarter. This allocation can shift based on the state of our balance sheet, stock prices, and cash flow expectations. Assuming we maintain our target debt levels, the next consideration is the demand for natural gas. Growth is a key factor; we need to assess the demand for our gas and our capacity to deliver to end customers. We believe this is more about timing rather than opportunity. We have sufficient capacity, with half of our gas directed to the Gulf Coast and the rest distributed to the Midwest and Northeast. Over 90% of our revenue comes from sales outside of our primary basin, which positions us well. Given the depth of our inventory, we can grow either by utilizing existing capacity, responding to increased in-basin demand, or expanding through new or existing facilities. We have various avenues for success, and our capital allocation will adjust based on the demand for our offerings and the economic viability of share buybacks in relation to incremental growth.

That’s great color. And then, on the capital allocation side, I think the strength in your NGL pricing kind of outperformed Street estimates, maybe even internal estimates. Are there any plans to switch where your activity levels are to maybe focus on the liquids-rich areas versus the dry gas area? And maybe would that be temporary until there’s kind of a call on gas when you guys to accelerate and then maybe switch back to dry gas, but just any thoughts there? Thanks.

Thank you for the question. When we examine our program year after year, you'll notice that we typically allocate around 30% to 40% of our efforts towards the dry gas segment, while the remaining 60% to 70% focuses on the liquid segment, including both wet and super-rich categories. This year's plan aligns with that approach. We intentionally include some flexibility in our program, allowing us to optimize our schedule throughout the year in response to operational efficiencies or market changes. Our ability to adapt is largely due to our capacity to return to pads with existing production, which generally accounts for about 50% of our annual activity. This agility enables us to react quickly and present our best program each year. However, we prefer not to make drastic changes. Recent commodity price trends highlight the risks associated with significant adjustments, as they could lead to miscalculations. In a maintenance scenario, we aim to keep our gathering system operating at full capacity, adding another layer to our operational strategy. We do maintain some flexibility. Currently, we are significantly focused on the NGL side, which we believe is advantageous given the NGL pricing we reported in the first quarter. Lastly, since our program is heavily weighted towards early activity and we expect production to increase in the latter half of the year, we feel this also aligns well with the commodity outlook for the second half and into the winter of 2024.

And our next question will come from Jacob Roberts of TPH & Company.

Just to start out, has there been any discussion internally about the ideal pace for utilizing the remaining $1.1 billion on the repurchase, and is there any urgency regarding that amount?

I guess the short answer to the question is no. There is no pace on it. We’ll be opportunistic and balance the priorities. So, we intentionally have not given out a hard and fast formulaic approach. We have to balance market conditions and our priorities and returns and cash flows. So, that’s the optionality and the intentional flexibility building the program.

Fair enough. I was hoping you could discuss the ethane dynamics that Range experienced this quarter and how you envision that developing over the year. Dennis, you outlined the NGL macro perspective. I’m just curious about how we should consider any potential impacts on the premium to Mont Belvieu, possibly in 2024 and beyond.

Thanks for the question, Jacob. I’m going to start off and then I’m going to pitch over to Alan to let him provide some thoughts on this question that you’ve raised. I think when you look at the production profile for this year, quarter in and quarter out, you can expect to see some fluctuations in let’s just say the gas that we report on and that production profile or on the NGLs, just depending upon the turn-in lines, and again, that activity cadence. But by and large, we would expect our NGL production to basically be relatively consistent and flat throughout the balance of the year. A lot of that goes back to some comments I made earlier, we’re still under a maintenance-level program where, again, we’re keeping the system at a high level of utilization and maintaining a flat level of production. But from an ethane perspective, I’ll put over to Alan at this point and let him provide some additional color on the DIF and other long-term outlook.

Hey Jacob, this is Alan Engberg. I oversee our liquids business. I want to discuss the overall NGL premium we experienced in the first quarter. As mentioned previously, Range has had a strong start to the year. The liquids business serves as a hedge against low natural gas prices. Generally, NGLs track crude oil prices more closely than natural gas does. Although ethane correlates with gas, its pricing is affected by other NGLs that align more with crude. The international markets have a strong correlation with crude as well. When natural gas prices are weak, the gap between gas and crude widens, allowing NGLs to perform better. Range has significant flexibility in our operations, and given the lower demand due to weak winter weather, we shifted our focus to the export markets, which performed very well for us. Market-reported index values at the export dock compared to the Mont Belvieu index averaged about $0.08 to $0.085 per gallon in the first quarter, reflecting a 35% year-on-year increase. Our premium benefited not just from the market spread between gas and crude but also from our ability to pivot to higher-value markets. This is somewhat seasonal; winter typically offers more opportunities than summer. Thus, we are maintaining our guidance for that premium at around $1. Now, regarding ethane fundamentals, the price has dropped significantly since the fourth quarter and is currently weak, primarily due to lower natural gas prices affecting ethane. Additionally, there has been destocking in the chemical sector, which has softened demand. Nonetheless, ethane inventories, particularly when viewed as days of supply, remain at five-year lows. The recent EIA report indicated that ethane stocks, in terms of days remaining for distribution, are at the bottom of the five-year range for this year and next. Historically, we have not seen lower levels since 2011 in terms of days of disposition. We are observing improvements in operating rates within the chemical industry during the first quarter. There is potential for another 250,000 barrels per day of ethane demand to bounce back, returning us to last July's levels, along with an additional 200,000 barrels per day of new domestic and international demand. Given the strong fundamentals and the upcoming demand, we anticipate that ethane prices relative to gas will improve for the remainder of the year and could potentially double in value compared to gas. Due to our strategic position as an industry leader, with production at the Houston MarkWest facility—the main hub for moving ethane to Mont Belvieu, Canada, and international markets—we are optimistic about our ability to extract strong values from ethane and the rest of the NGLs throughout the year.

Our next question will come from Subhasish Chandra of Benchmark Company.

Thank you. And ditto, Jeff, on all the words said here for a long and storied career. Couple of line item questions. First, I guess, on lifting costs, I think, in the 10-Q kind of cited water hauling cost. Just wondering if that is a temporary issue or a structural issue of any kind and the abandonment cost, which is not a huge number, but if that was specific to any particular part of your acreage.

Yes. Good morning, Subhasish. I’ll go ahead and tackle these. From a water hauling perspective, we have seen some fluctuations that are kind of short-term in nature from a cost perspective. As you can imagine, as demand goes up for, let’s just say, the start of the program at the beginning of the year, coupled with winter operations and fuel cost. We can see some of those being needle movers, if you will, at times with our quarterly water hauling cost. We would expect, though, all of that to still normalize throughout the year, and we’re on track for our lease operating expense guidance that we provided this past call for $0.11 to $0.13. So, all of that is still intact. From a workovers perspective, any given quarter, I think, is really tough to assess whether it’s a workover that’s unique or an abandonment operation because each one has its own unique cost exposure. We did pull several projects forward into Q1. As you can imagine, in the Northeast, we try and push some of those projects into the middle part of the year when the weather is a little bit nicer. But with the mild winter conditions that we had in the first quarter, the team became very proactive to pull some of those projects forward. So, we could see some benefit throughout the year with further production stabilization. We would expect to see, just like when we talk about turn-in lines or other operational cadence, we expect to see some quarter-over-quarter variance, but everything is still on track for the guidance that we provided this past quarter.

I have a question about MVP. It seems like the conditions are better than ever to get that pipeline up and running. We've discussed this before, and I'm curious if you have an opinion on whether you expect to see 2 Bcf a day of fresh gas in the basin, or if a significant portion of it would just be rerouted.

That’s a great question. Historically, with large greenfield projects, there has typically been a gradual increase in capacity. However, in the current environment, it's likely that there will be more of a redistribution of production, allowing capacity to open up on other pipelines. This would create demand from customers who will utilize that specific infrastructure. As a result, we might see production shifted from other sources towards the MVP. It seems that a combination of these two approaches could emerge.

And our next question will come from Paul Diamond of Citi.

I would echo everyone’s commentary here. Congratulations, Jeff. Well deserved. And good luck in the next efforts.

Well, thank you very much. I appreciate it.

Just circling back a little bit. You mentioned that you are beginning to observe some weaknesses in the inflationary trends we've experienced over the past years and are focusing more on the latter half of this year and likely 2024. Could you provide more insight on this and share if there's anything specific you believe might change first or offer additional details?

Yes. Good morning, Paul. This is Dennis. It’s difficult to predict exactly where we’ll see changes at this point. We are noticing some availability of rigs on a one-off basis and some openings in schedules for spot frac crews that may be needed for specific projects throughout the year. Pricing hasn’t shifted significantly yet, and we are still observing high utilization of specialty equipment, especially high-spec drilling rigs and electric frac fleets. There are also indications of relief in the availability of tubular goods and some consumable products like frac sand, which could lead to unique savings toward the end of the year. However, we believe that any savings realized will primarily manifest in 2024. Regarding inflation dynamics, I’d like to reference our incremental cost per Mcf. Last year, we recorded $0.64 per M, influenced by our low base decline and overall capital efficiency. This year, despite some increases from 2022 to 2023, we are still in the mid-$0.70 range, which is considerably lower than what we see compared to peers in other basins. Regardless of how things unfold, we believe we will maintain a leading position in the industry.

And just one quick follow-up. I know we’ve talked a lot about the takeaway constraints and the concern for in-basin growth, at least in the near term. How do you guys think about the opportunity for more organic growth in-basin, whether it’s through industrial demand or commercial or residential? How do you guys think about that going forward?

Yes. I believe there are a couple of options when we look at the M&A activity from the past few years. We've noticed a shift in capital allocation for some producers, directing their efforts towards the assets involved in those transactions, sometimes moving away from Appalachia. Additionally, there has been a decline in well performance year-over-year, which presents challenges for peers making capital allocation decisions. However, we haven't experienced that on our end. This situation positions us advantageously to utilize infrastructure that may be underutilized in the future. We believe we have a long runway of inventory that puts us in a strong position. There are specific projects we have identified for when the demand for Appalachia gas increases. We expect that demand will come; it’s a matter of when, not if. For now, we are maintaining our focus and we know that we can add inventory to our growth strategy, supported by both macro trends and the fundamentals of the basin. There are growing discussions about in-basin demand sources, such as the Shell cracker, which is projected to use around 100,000 barrels of ethane along with fuel gas, nearly reaching a quarter of a billion a day from that facility alone. Combined cycle facilities have also shown interest in the area due to the ample supply and inventory available for a company like Range. Therefore, we recognize that there are more elements to consider beyond just pipelines; there will be in-basin demand that could develop further. There are certainly future growth opportunities ahead.

And our next question will come from Scott Hanold of RBC Capital Markets.

Yes. Thanks. Jeff, Dennis, again, my congrats to both of you. Maybe my first question is to kind of layer on to that conversation. But when you think about the market right now, it is a little bit loose in the gas market. I know there are a lot of folks calling for the need for some gas producers to further reduce activity. Can you just give us a high-level sense that, is there any point where it makes sense for Range to back off on its maintenance plan, or is there an overriding just kind of efficiency benefit to maintaining maintenance?

Yes. Scott, this is Dennis again. We’re very comfortable with the maintenance program that we have laid out. I mean, again, by the time we get to the mid-year point, we’ll be down to one drilling rig and one frac crew. So, this is what I would say a very comfortable low-end position for our program. It’s very capital and operationally efficient for us. It allows us to continue to check all the right boxes from a lower cost structure perspective, high-end utilization of the gathering system. Even through the balance of the last couple of years when we started to see fluctuation in commodity prices, we didn’t grow. Instead, we stayed the course. And we did what we said we were going to do and remain focused on our balance sheet objectives. So, from our perspective, we never grew, and we stayed the course. Again, we’ll stay at this level until the fundamentals suggest we should do otherwise.

So, would there be any consideration to curtail production rather than change your drilling program but to curtail during periods of more extreme weakness?

Yes, it's a good question. We evaluate this on an as-needed basis within the organization. Looking back at previous periods with similar commodity prices, we showed a willingness to shut in some of our gas when cost reductions were associated with it. However, it's a more complex decision than simply shutting in gas due to the liquids component we discussed today. The incremental benefit to our realized price from overall liquids production gives us an advantage compared to our natural gas peers, who may be more negatively impacted by NYMEX prices. In the past quarter, we exceeded $1 over Henry Hub, specifically at $1.14. Maintenance makes sense for us, utilizing our existing infrastructure. NGL exposure significantly contributes to our cash flow, representing about 30% of our production profile and up to 40% to 45% from a cash flow perspective. Overall, we are aware of these factors and regularly analyze them based on commodity prices, as NGLs are important for us and yield meaningful returns.

And we are nearing the end of today’s conference. We will go to Umang Choudhary of Goldman Sachs for our final question.

Jeff, thank you so much for your leadership and contribution, and good luck on your time. Dennis, congratulations on the promotion. My first question was around deflation. You talked about seeing some signs of deflation. Can you give any more details around it? What do you think is the impact on capital spending this year and potentially next year?

Yes. I would really point to having a very minimal impact to this year’s program. I think for a couple of reasons. One, you’re still trying to see the rig reductions materialize and what that means for where the market is truly heading. Secondly, our program is front-end loaded for the year. The deeper you get into the year does take us down to the one rig, one frac crew type environment. By nature of that, your speedometer has been reduced by the time you get to the remaining quarters in the second half of the year at that point. More materially, we see this being an opportunity for 2024. We know that we have a long-running history and relationship with many of our service providers. Those service partners want to align with companies that are efficient and will execute a program that they've communicated and everyone's made commitments around. We think that'll be more results we'll be seeing through the 2024 process than later this year.

Going back to the options for growth, what would you like to see in terms of local demand or cash basis to indicate a need to expand more in-basin? In other words, considering your desired growth areas and the evolution of your gas marketing portfolio, are there any specific end markets where you would like to increase your exposure?

That's a good question. I'll take a step back on this, Umang. We'll approach the situation similarly to how we've handled our NGLs and current gas portfolio. As Mark mentioned earlier, 80% of our gas is transported out of the basin, and from that overall portfolio, 50% reaches the Gulf. We are already involved in the LNG market, so we will keep looking for opportunities in both NGLs and gas that offer the most competitive returns, regardless of the end market. We anticipate more opportunities within the basin in the future, but that will require time to develop and establish the necessary infrastructure. Additionally, we need to compete with our capacity to transport gas to the Gulf versus having it in the basin. We'll consider all options. Our marketing team is highly skilled, and historically, we have shown our ability to innovate, such as being the first producer to export ethane in a way that aligns with global indices. This has contributed to the returns we've discussed today. The team will stay focused and continue exploring all available options, ensuring they compete with our current portfolio.

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

I just want to thank everybody for participating on our call today. And thanks for all the kind comments for Dennis and me on our path forward. If you have any questions, please follow up with the team. Thank you.

Thank you for your participation in today's conference. You may now disconnect.