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spk00: Welcome to the Range Resources fourth quarter 2020 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 risk and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. After the speaker's remarks, there will be a question and answer period. At this time, I would like to turn the call over to Mr. Leith Sandow, Vice President, Investor Relations at Range Resources. Please go ahead, sir.
spk02: Thank you, operator. Good morning, everyone, and thank you for joining Range's year-end earnings call. The speakers on today's call are Jeff Ventura, Chief Executive Officer, Dennis Degner, Chief Operating Officer, and Mark Skuki, Chief Financial Officer. Hopefully, you've had a chance to review the press release and updated investor presentation that we've posted on our website. You will also find our 10-K 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.
spk05: Thanks, Leif, and thanks, everyone, for joining us on this morning's call. Looking back at 2020, Range made steady progress on key objectives. We enhanced margins through cost improvements and thoughtful marketing, strengthened our balance sheet by reducing debt for the third consecutive year, completed our 2020 drilling program safely and efficiently, and lowered the capital intensity of our business with the peer-leading maintenance capital program. Range also continued to advance on key environmental fronts, becoming the first North American producer to set a goal of net zero direct emissions. We believe each of these accomplishments show continued progress towards positioning the company to return capital to shareholders. Looking first at margins, we can discuss unit costs. Range reduced cash unit costs by about 10 percent last year compared to average 2019 costs. Mark will touch on the improvements in more detail, but it's important to point out that these unit cost reductions drive lasting enhancements to margins and cash flow that don't require change in commodity price. While we made improvements in 2020 on gathering and transportation expenses, LOE and G&A, we remain focused on becoming even more efficient in the years ahead. On the pricing side of the margin equation, I believe our mix of production and delivery of NGLs into the international markets provides range in unappreciated advantage in terms of pricing. For context, if we look at pricing for 2021 NGLs, we expect an unhedged realized price comfortably above $20 per NGL barrel for range, approaching $4 per MCF equivalent based on today's STRIP. Our ability to sell Purity NGL products into the international markets paired with improved NGL fundamentals helps support Range's strong free cash flow at strip pricing. Turning to the balance sheet, Range made significant progress bolstering our financial position over the last couple of years. Not only have we improved our cost structure and streamlined our operations, we have reduced debt by over $1 billion strengthened our maturity profile, and improved liquidity while reducing share count. This reflects our commitment to thoughtful, disciplined capital allocation. Looking forward, we expect free cash flow at strip pricing to further strengthen our position and move us towards our longer-term financial targets. Operationally, the team continues to innovate and reduce normalized well cost. As a result of efficient operations, coordinated planning and a laser focus on capital discipline, the team was able to deliver the 2020 operational plan for $19 million less than budgeted in March of last year. This is the third consecutive year Range has achieved these types of savings, spending less than budgeted, which is a reflection of our cost leadership and disciplined capital spending. Range has been a leader in well cost per foot amongst Appalachian producers since discovering the Marcellus. As Dennis will discuss, the operational plan that we've laid out for 2021 shows a continuation of efficient operations with average well costs below $600 per lateral foot, which is the best amongst peers. Ranges class-leading D and C costs, coupled with our shallow base decline and our substantial core inventory, all come together to support a very low and sustainable maintenance capital. Range's base decline entering 2021 is approximately 19%, allowing for maintenance capital in the low $400 million range. This low capital intensity that is unmatched among small and mid-cap E&P companies provides us a solid foundation for generating significant free cash flow. Importantly, this maintenance capital figure is sustainable for a couple of important reasons. First, the lateral footage in Range's drilling completing and turning in line for this year is all very similar to what we've accomplished in 2020, leaving us well-positioned to continue in the 2022 and beyond with equal or better capital efficiencies. This is unlike what we've seen from the industry, more broadly, which has relied on duct drawdowns or massive outspends to provide a short-lived boost to efficiencies. That is not the case for range. And second, range has a core inventory of wells measured in decades. which provides us a long runway of consistent, repeatable results in efficient capital deployment. These positive differentiators on sustaining capital bear out in the reported results. Taking a simple look at relative efficiency using actual DNC capital per unit of production range-led all Appalachian producers in 2020, and we expect similar results going forward. As others exhaust their core inventories in the years ahead, Range will remain well-positioned with multiple decades of inventory. A portion of the value of our inventory can be found in our year-end reserve report. At 275 natural gas and $50 oil, the PV10 of Range's approved reserves was $8.6 billion. For context, after backing out our year-end debt balances, this equates to over $22 per share. But as many of you know, the SEC definition of approved reserves only allows for five years of development. And beyond this five-year window, range has thousands of additional core Marcellus wells not included. Before turning it over to Mark and Dennis, I'll reiterate that I think range has made great progress in 2020 in the face of a difficult commodity environment. Looking forward, as prices are set to improve in 2021 and 2022 on improving fundamentals, we see range generating significant free cash flow, putting us on the path towards reaching our long-term leverage targets in the not-too-distant future, as debt reduction and strip pricing is the expectation. Our focus will remain on safe, efficient, and environmentally sound operations, prudent capital development, and generating sustainable returns to shareholders. Importantly, these are all reflected in our updated compensation metrics. Our latest slide deck shows a summary of the short-term and long-term incentives that will be reflected in our next proxy report, aligning our incentive programs with shareholders as we seek to continue our steady progress against key initiatives. Over to you, Dennis.
spk07: Thanks, Jeff. As we entered our 2020 program a year ago, our operational focus was clear. Deliver a maintenance-level production plan anchored by improvements in capital efficiencies. and in doing so, align our operational cash flow with annual capital spending. Our 2020 operational cadence, cost control, and production levels were consistent with these objectives, and our capital spending below budget for the third consecutive year speaks to the commitment of our team in achieving them. Our operational program was executed while coming in $109 million, or 20%, below our average capital plan of $520 million set at the beginning of January, and was also $19 million below our revised capital plan of $430 million that was adjusted in March. The program resulted in 67 wells turned to sales for the year, with approximately half of the activity focused in our dry gas acreage positions. Maintaining production levels while spending significantly less capital was a notable achievement by our operations, technical, and support teams. The initiatives that underpinned these results were driven by calculated scheduling adjustments made with a new multidisciplinary asset development software tool, continued improvements to operational efficiencies for both drilling and completions, the use of innovative and emissions-reducing technologies such as using an electric fracturing fleet, and a focus on reducing service costs throughout the year. As we look forward into 2021, our capital spending will be approximately $425 million, with 95% of the capital directed towards drilling and completions-related activity, which is consistent with last year's budget. Also consistent with prior years, our activity and capital cadence will be weighted towards the first half of the year, with approximately 60% of the capital allocated across the first and second quarters, with the remaining 40% covering the second half of the year. The capital plan for 2021 is projected to maintain production at approximately 2.15 BCF equivalent per day and maintains ample inventory and momentum to sustain capital efficiencies into future years. Production for the first quarter is projected at 2.06 BCF equivalent per day. This is below the full year average, as Q4 turn-in line counts and scheduled maintenance on portions of the dry gas gathering system are affecting Q1. Drilling and completions activity in the first half of the year is expected to result in building average daily production in subsequent quarters, delivering maintenance-level production for 2021. A key to our success in 2020 and for the year ahead is our peer-leading well cost. Our goal at the beginning of 2020 was to beat a $610 per foot target, and several drivers resulted in range eclipsing this goal. An optimized development plan was deployed for the year, utilizing a new collaborative digital platform previously mentioned. Along with a strategic focus on inventory planning, which resulted in substantial improvements in this metric. In addition to this, the team successfully drilled more lateral foot per day than planned and completed more frac stages per day versus prior years. Enhanced levels of diesel fuel displacement in our operations were also achieved with increased utilization of our natural gas dual fuel drilling rigs and electric frac fleet, further reducing cost and emissions. The direct sourcing of sand for our completions, along with our record setting water savings and volume handled, also benefited our well cost efforts. In aggregate, these operational actions resulted in a reduced normalized well cost in excess of 10% across all areas. As we look forward into 2021, our program will consist of 59 wells being completed and turned to sales. Approximately 60% of our turn-in lines are expected to be in our wet and super-rich acreage, with the remaining 40% located in our southwest drag gas position. Our planned average horizontal length per well for 2021 is projected to be similar to last year, with our turn-in line averaging approximately 12,000 feet. In the year ahead, we will continue to capitalize on the efficient practice of returning to pads with existing production. with approximately two-thirds of 2021's turn in lines scheduled on existing pad sites. Moving back to pads with existing production has become a fundamental and repeatable part of our program year in and year out, allowing us to reduce cost, maximize infrastructure utilization, and is complemented by our use of dual fuel drilling rigs and an electric fracturing fleet. To put color around this, Our contracted electric frac fleet pumped over 2,000 frac stages in 2020 and displaced over 3.8 million gallons of diesel fuel while running on 100% of Ranges' fuel gas. Couple this effort with Ranges' large, contiguous acreage position, and this translates into approximately $4.5 million in savings for the year, while significantly reducing emissions for those operations. Extended lateral links highlighted Range's 2020 drilling performance with almost half of our wells exceeding 14,000 feet in horizontal length, including the three longest wells in Range's Marcellus program history, each exceeding 19,000 feet. This resulted into a corresponding 12% reduction in drilling costs per lateral foot drilled, which fell below $200 per foot for the year. On the completion side, A 10% improvement in fracturing crew pumping efficiency was also realized, setting a performance record for range resulting in averaging over seven frac stages per day for the year. These improved operational efficiencies, the benefits of using range-supplied natural gas for the electric frac fleet, and an expanded ability to self-source sand for completions continues to drive down our peer-leading well cost. In 2020, the water operations team focused on expanding and improving the reuse program and reducing water logistics costs. Through creative initiatives by the operations and technical teams, a record low for cost per barrel of water was realized, with a 36% reduction compared to the prior year. For example, the volume of water reused from range flowback operations and producing wells along with third-party sources, represented 60% of all water used in 2020. That compares to 43% in 2019. The savings associated with the water reuse program not only exceeded the plan, but it also matched the cost savings seen in 2019, all while under maintenance production activity levels. Rage's water reuse program provides for lower operating costs and is a key component of our broader ESG efforts. reducing the volume needed from area freshwater sources. Lastly, similar progress was captured by reducing the cost associated with water transportation, resulting in a 75% reduction in freshwater transported by truck. Reduced trucking not only lowers cost, it also means less roast maintenance, reduced emissions, and fewer trips for our service partner drivers. This year, we project additional advancements in our water program logistics and cost structure as we've implemented a new customized water tracking and collaborative software tool. This smart software will allow greater visibility of our water logistics at any given moment, reducing unnecessary movements, wasted time, and associated cost. This will allow our logistics and operations team to make informed, real-time decisions. about water movements throughout the field, creating an even safer, low-cost program. Before turning to marketing, I'd like to give a special mention to our production and facilities teams. In 2020, the team was able to further reduce LOE produced water cost in excess of $2 million. They worked closely with our midstream partners to increase field runtime and translated this into a record low lease operating expense of $0.08 per MCFE for Q4. We see this LOE level as durable and repeatable as we continue our focus on enhancing high-field runtime while further optimizing flowback operations and produced water management. Ranges made significant progress toward reducing cash unit costs over the past few years, the largest of which has been the 17-cent improvement we've made to transport and gathering since the end of 2018. This expense is expected to move up slightly in 2021 as we move more of our existing NGO production to Marcus Hook for export and also as processing costs follow the direction of improving NGO prices. However, both are expected to be more than offset with higher NGO revenue this year. Beyond 2021, we expect transportation and gathering expense to decline in absolute terms, assuming continued maintenance of existing production levels. By 2025, annual gathering expense relative to 2021 is expected to decline by approximately $70 million, and by over $100 million by 2030. These are large and significant cost reductions, and importantly, they are simply an output of existing arrangements, not targeted dollar amounts or goals we are setting for ourselves. In addition, Range will have elections on multiple firm transport projects over the several years ahead where we can decide to retain or let capacity expire depending on market conditions. These elections, relative to 2021, represent over an additional $175 million by 2030. Regional basis in the third and fourth quarter was impacted by a Tetco capacity reduction, maintenance at Cove Point, and infrastructure upsets associated with seasonal hurricane storms. By the end of Q4, the upset infrastructure was returned to service, with TEDCO adding back approximately 1 BCF per day of capacity to their system. The impact of normalizing weather and return of capacity is represented in the improvement to ranges differential, from $0.57 in the fourth quarter to an expected $0.20 to $0.25 under NYMEX, in the first quarter of 2021. As we look forward with operations at flat production scenarios, strong LNG exports, infrastructure return to service, along with the gas demand needed to achieve go-forward storage levels. And we expect Appalachian gas pricing to experience meaningful improvements year over year. On propane fundamentals, historical high LPG exports have made the ongoing winter propane drawdown season one for the record books. Thus far, this winter's storage drawdowns have been twice that of last winter, and 65% greater than the five-year average, driving propane stocks to a reduced level versus the prior two years, and 10% below the five-year average. This low storage level, combined with bullish demand forecasts associated with cold weather across the U.S. Midwest and Northeast in February, has elevated propane prices by 70% versus the third quarter of 2020, and improving our expected pre-hedge NGO price above $25 per barrel for Q1 2021. Continued European and Asian LPG demand should support international prices and U.S. export economics in the coming quarters. As we've outlined on prior calls, Range is strongly positioned to continuously capture the best value for its LPG production through the flexibility of Marcus Hook exports. Starting in April, Range will access an additional 5,000 barrels per day of NGL transportation capacity on Mariner East, as we continue to expect near-term and long-term benefits of NGL exports out of the Northeast, with continued international demand growth for NGL products. we will have the capability to export over 80% of ranges propane and butane in 2021, leading to strong year-over-year improvements in NGO pricing and margins. As we wrap up operations and marketing, I'd like to congratulate our team for all they've accomplished in 2020 and for delivering on our operational, safety, and environmental goals, all during a very unique year. I'll now turn it over to Mark to discuss the financials. Mark?
spk06: Thank you, Dennis. As we all know, it would be an understatement to simply call 2020 an eventful year. Nevertheless, for Range, it was an extremely constructive eventful year during which the team successfully executed on key financial objectives during some unusual global events. The main themes discussed on the third quarter call continued through year end and into 2021, including cost reduction, debt reduction, improving the debt maturity profile, and enhancing liquidity, all of which were achieved while maintaining best-in-basin capital efficiency and doing so in a responsible, safe manner, one of our core values. Results for the fourth quarter and full year reflect Range's ability to navigate fluid market conditions, maintain focus on shareholder returns, and deliver on financial and operating objectives. Starting the financial discussion today, I want to ensure the recently announced accounting corrections are transparent and well understood. In the 10-K, we corrected a deferred tax error reported in the 2020 quarterly statements that was identified while preparing year-end financials. This mistake resulted from a misinterpretation of how the CARES Act modified future utilization of net operating losses. As you know, accounting rules provide a strict framework of how deferred tax assets and liabilities are quantified. and the misinterpretation led to incorrect non-cash deferred taxes reported. The correction, which we set forth in detail in the 10-K, is likewise non-cash, and there is no change in the NOL balance range holds for future use against taxable income. Changes in policies and procedures are already underway to prevent an issue like this from recurring. Moving to financial results. Underlying the financial foundation of any E&P is capital efficiency. Full cycle costs, operating costs plus sustaining CapEx dictate repeatable returns and cash flow. The quality of Range's inventory and low base decline allow Range to adapt its investment program throughout 2020. We started the year with a capital investment program targeting flat production at a spend of $520 million. Early in 2020, we reduced planned capital investment to $430 million and at year end closed out at $411 million in capital or 21% better than originally budgeted while maintaining Marcellus production. When a team is able to achieve drilling and completion costs below $600 combined with top deer recoveries per foot, there's a dramatic uplift on investment returns. Equally important, are improvements in cash unit costs. Fourth quarter unit costs of $1.84 per unit were in line with the preceding quarter and improved by an aggregate 20 cents or 10 percent compared to full year 2019. Twenty cents in unit costs multiplied by total production equates to over $150 million in annual improvement driven by reduced gathering processing transport, lease operating costs, and GNA. Year-over-year savings in GP&T is due in part to the sale of Louisiana, allowing certain gathering and transportation contracts in northeast Pennsylvania to expire, and to a lesser degree, changes in NGL prices. Lease operating expenses declined to $0.08 per unit on extremely efficient operations with specific improvements in water handling and the divestment of higher cost assets. Recurring cash G&A expenses declined to $31 million in the fourth quarter, or $124 million for the year, which is down 10% from full year 2019. Overhead cost savings come from every line item, but the most significant contributor is a more focused, efficient workforce of 533 full-time employees, which is down 33% from 2018. Cash interest expense was $46 million in the fourth quarter, Higher interest expense is the result of refinancing initiatives during 2020, which reshaped the debt maturity profile of the company and enhanced liquidity. Liability management projects reduced bond maturities through 2024 by almost $1.2 billion, while at the same time improving liquidity to approximately $2 billion following the January bond offering. Cash flows are expected to retire debt maturities in coming years, and are backstopped by ample liquidity. Additionally, recent bond issuances are callable such that we have the ability to redeem and or refinance these series when economic. There's been substantial improvement in the debt markets, and it is evident in the trading levels of ranges bonds that both access to and cost of capital has improved. Despite a challenging backdrop during 2020, Ranges liquidity and running room before debt maturities was materially improved. Effective liability management temporarily increased interest expense. However, this avoided higher cost forms of capital that would have diluted shareholder ownership and participation in what we see as a steadily improving natural gas and natural gas liquids business. Further improving the balance sheet through absolute debt reduction remains a principal objective. Shareholder value creation through the generation of free cash flow and its prudent redeployment is our focus. At current commodity prices, by the end of 2022, ranges leverage is approaching target levels, even without incremental action. It should be clear by our past practice, however, that we will not stand idly by. We will continue to explore virtually every option that improves financial strength, reduces costs, de-risks the company, and expands free cash flow per share. Our steady full-cycle unit cost improvement provides stable and competitive base to generate material free cash flow. We believe total unit cost levels achieved over the last six months, total, meaning capital spending and fully loaded cash unit costs, represent a leading break-even cost among Southwest E&Ps. Looking forward through 2021 and into 2022, A healthy and more prudent message appears to have taken root in the industry, that of prioritizing shareholder returns while responsibly managing environmental, social, and governance matters. This reflects a maturing of the business where cash flow growth and returns are the key measures as opposed to units of production. So what does that imply for range, assuming a maintenance capital program? To illustrate the free cash flow generation potential of range's business, using the midpoint of 2021 guidance for all costs, including exploration and brokered marketing, fully loaded cash unit costs total an estimated $1.99 per unit. Add to that maintenance capital to arrive at full cycle economics by taking this year's D&C capital budget and divide it by annual production, and you get approximately 50 cents. Those total approximately $2.50 per unit. As an example, assume $3 net realized price, and you have 50 cents per unit of free cash flow or nearly $400 million for the year in free cash flow. Obviously, there is working capital and periodic one-off items that affect this illustrative math, but the example does not take into account reduced interest expense through continuing debt reduction, nor additional capital and operating cost efficiencies, some of which are contractually declining costs like gathering expense. Range is well positioned to reduce leverage and target cash returns to shareholders in the not too distant future. Our strategic actions over the last three years have been focused on reducing risk while maintaining and enhancing the intrinsic value of the asset base. We believe Range holds the largest portfolio of quality inventory in Appalachia. Exposure to that inventory on a per share basis has been preserved and enhanced by our strategic actions in 2020. Our portfolio also includes diversified takeaway, reaching a variety of customers and pricing points, paired with a consistent and data-driven hedge program, which de-risks the downside while preserving exposure to an improving market. We believe steps taken represent material progress in positioning Range as a more resilient business, primed to participate and improvements in both natural gas and natural gas liquids pricing. On the topic of hedging, you'll note that we maintained both a commercial and risk management approach while hedging 2021 volumes. We believe this was a balanced approach to risk management and participation in rising prices. For over a decade, we have a steady practice of hedging a significant portion, over 70 percent, of natural gas production. While we have a glide path or a common range in which we add positions over the course of a year, based on data indicating prices needed to rise to balance the market, we intentionally moved at a deliberate pace during 2020 as we added 2021 hedge positions. We plan to follow similar principles this year in adding hedges for 2022 and beyond. By that I mean we will seek to prudently de-risk cash flows while not hedging away the improved supply-demand balance into backward-dated price curves. The well-defined and, we believe, achievable objective that all of us at Range work toward daily is to sustain a highly investable business that will be resilient through cycles, return cash flow to shareholders, and responsibly create compelling value not only compared to other independent producers, but across industrial sectors. Jeff, back to you.
spk05: Operator will be glad to answer questions.
spk00: Thank you, Mr. Ventura. The question and answer session will now begin. If you would like to ask a question, please indicate by pressing the star key, then 1. If you are on a speakerphone, please pick up your handset before asking your question. If you would like to withdraw your question, you may do so by pressing the pound key. Once again, please press star 1 to ask a question. The first question comes from Subash Chandra with Northland Securities. Your line is now open.
spk08: Hi, thanks, guys. Good morning. A question on the asset sales program, if any. You know, given the stronger fundamentals here, are you going to be more, you know, picky about the bids you get or, you know, and if you can characterize the A&D market currently?
spk06: Good morning, Subhash. This is Mark. I'll start that one off. I think the good news for range is the significant improvement in liquidity in the balance sheet. So, therefore, we are in a position of strength of making choices that are most economic. Choices on divestitures specifically are economic-based. They're not out of a need base to refinance or repay indebtedness. So, more directly to your point, the A&D market, there have been a few transactions. You've got some decent comps in the area of what assets are going for. Pick your measure, but dollars per flowing. predominantly PDP-based valuations. So you do have to take a step back and say, what is most accretive for your shareholders? What contributes the most cash flow, free cash flow to your shares? And would you rather be a seller or a buyer in this market? So there's been good interest in some of our non-core areas, but for the time being, I think we're focused on just maximizing cash flow and are in a good position, as I started off with, given where the balance sheet currently is. So we keep a lot of options open to us.
spk08: Okay, great. And you just mentioned, I guess, being a buyer. Is that on the table?
spk06: We'll consider virtually all options. It's about free cash flow per share. It's about deleveraging. It's about the strategy going forward for maximizing shareholder value. So, again, you just run the economics. Is it better to be a buyer or a seller? Right now, it might tilt towards being a buyer.
spk05: And clearly, anything we would do would be in the Appalachian Basin, in and amongst us, deleveraging, cash flow accretive, all those things that Mark just mentioned.
spk08: Great, thanks. And if I just ask a follow-up on FT, do you feel differently about holding onto it long-term, given, I think, some of the tightness in the market, at least in the fourth quarter of last year?
spk07: Yeah, good morning. This is Dennis. I think as you look back over the landscape of 2020, it certainly lends itself to making the decisions along the pathway of those expirations that make most sense with our maximizing our margins and our returns. So earlier on, the FT packages that were acquired associated with our production are going to be more in line with plants that early came on with, let's just say, early program production growth. So Those programs are going to most likely get us to the Gulf. 80% of our production gets out of the Northeast, so we're going to have 50% of it getting down to the Gulf Coast, and we're going to have the remainder getting to the Midwest and other markets. So we will look to continue to maximize the portfolio to make sure that it's taking into account cost and also how do we get to premium markets. But those earlier packages that will start to expire will also be Some of them are smaller in nature. That will also allow us to be strategic as we hold on to them or not. This could certainly lead into a broader basis type discussion, but as you look back on 2020 and the tech co-capacity that was taken out of service due to some infrastructure upsets along with co-point maintenance, as we look forward, there's around three to four BCF of demand plus takeaway capacity that's going to be available. couple that with flat maintenance programs that Range is executing along with many others and a flat production profile, we see this gives us a lot of optionality as we look forward, whether it's how we manage basis or also those FT packages moving forward.
spk08: Thanks, everybody.
spk00: Thank you. The next question comes from Doug Legate with Bank of America. Your line is now open.
spk03: Oh thanks, good morning everybody. I appreciate you taking my questions. Guys, you've obviously made terrific progress in reducing your cost for lateral fruit, as you pointed out, the most efficient in the industry. My question is on the sustainability of that. When you look at the quality of the engine you've laid out, you've talked about locations, but you haven't parsed that into what can be sustained at that level of capital efficiency. So my first question is, what proportion of the inventory you've laid out do you think can be sustained at that current capital efficiency way that's long?
spk05: Doug, I'd like to refer you to slide 15. You know, we put some third-party data on the bottom right of that slide. And according to, you know, that third-party data, there's over 16 years or about 17 years of inventory that generates good returns below $2.25 and $2.40. So it's clearly high quality in terms of the well count, and we would agree, and of course we have more of that up there along with the map on the left. So we've got plenty of locations, and let me turn it over to Dennis to talk a little bit about well cost. Yeah, good morning, Doug.
spk07: The cost structure we see is very durable and repeatable, and A lot of it comes down to what we see is a couple of key drivers, and one is going to be the efficiencies that we've captured year over year. No doubt we talk about it every single quarter, whether it's drilling our fastest days in the lateral by our drilling team or whether it's drilling our longest laterals. 2020 saw us in some regards have a repeatable drilling efficiency in the lateral from a, let's just say, footage per day. But really what we saw is we were able to repeatedly and successfully drill longer laterals, reducing our cost per foot by an additional 12%. So that was an incremental bolt-on versus prior years. Completion side continues to chip away at completion efficiencies. We saw our crew pumping efficiency go up 10%. Part of that was due to the efficiencies associated with both of our providers, but also pretty heavily contributed by our electric fracturing fleet in 2020. So team continued to do good work there. And the other part is water savings. We hit three records in 2020 for range on cost per barrel, amount of barrels that were handled, and also reduction in some of our trucking logistics from a freshwater perspective. And all of that just translates into a reduction in cost. So part of the reason we see this being durable going forward is because we see us building upon that, but also the last component is we continue to look at new technologies. Part of what helped us in 2020 was a scheduling tool that we put together. It's collaborative, allows multidisciplinary team input, very quick, responsive type communications, allows the team to make real-time choices around how we look at capital allocation, what wells we drill, and how we keep the gathering system fully utilized. Couple that with water logistics software that we have now deployed that will help us further reduce the any wasted time, understand our water movements in the field, and it really turns into additional cost savings. And then lastly, it really all starts with our team. We can have some of the best tools in the world, but it really starts with the creativity of our teams and their ability to continue to drive innovative solutions. So we're very optimistic when you look back on slide nine and you see what our cost track record has been just the past two years. You could look farther back and we'd have a similar story. We expect to see similar cost reductions and improvements as we go forward in the years ahead on the inventory that Jeff touched on.
spk05: I appreciate that, Jeff. I was just going to say, having a big blocky position in a core area with a high-quality team, being able to go back to existing paths with that team, we can do that for a long, long time.
spk03: So, guys, I appreciate that. As I say, we're about 15, so I'll nudge that up a little bit, but thank you for that. My follow-up is on the break-even, because obviously, as you know, you're in this kind of ex-scroll sustaining capital mode. The free cash flow to help us calibrate that, it looks like your fixed cash costs are somewhere around $1.87 to $1.99. Interest would be another $0.35. I guess, sorry, that quotes interest, sorry. Sustaining capital would be about another 30 cents, I guess, on an energy basis. And then finally, you've got the basis differential. That gets us to about 250 to 260. I'm just curious if you can tell us what you think your sustaining break-even gas price is so we can calibrate our free cash flow.
spk06: Sure, Doug. I think you're right in where we stand today. I think the important factors to consider is how that trend's in 2022, 2023, and shortly thereafter. So one important thing to note is what our realized prices look like. There is, of course, a basis, a differential for gas, but with the NGLs, one really important thing to look at is what's the uplift. I mean, if you just look at current NGL prices for calendar 21, you're talking $23 a barrel, which equates to $4 in MCFE. So there's a positive realized differential there when you're looking at units of production on an equivalent basis. So one factor there at the top line. As you move down the cost structure, we've talked about it quite a bit, but there are built-in contractual savings on gathering, processing, transport. There's some detail given in the press release, but just through 2025, you have substantial savings. You're looking at $70 million incrementally and then another $100 million total savings on unit costs. You know, thereafter, we have options, as Dennis just mentioned, about whether or not it's economic to let additional long-haul transport go or whether our margins are best retaining that. So, again, options to further reduce that. As we just move down the line items of unit costs, interest expense. I mean, if we just look at cash flow using the example you gave, the pricing and the break-even cost, it's the same as the simple math I gave during the scripted portion. If you use that and look at what cash flow does just over the next couple of years, that's also illustrated in the new deck on slide 14, you're looking at roughly, again, this is illustrative math, you're looking at close to $700 million in debt reduction over two years. Well, let's just make the math simple and assume 5% coupon. That's $35 million in savings just over the two years, 4 cents improvements. That's ongoing. That's continuous. This is compounding, growing cash flow, reducing unit costs. So I think as a starting point, we would agree with where you're at. But the trend line, I think, in terms of each of these unit costs is contractually built in and a positive feedback loop.
spk03: Really helpful, guys. Thanks again for leading on. Thank you. Thank you.
spk00: Thank you. The next question comes from Brian Singer with Goldman Sachs. Your line is now open.
spk01: Thank you. Good morning. Good morning, Brian. You discussed the long inventory that well exceeds approved reserves, and I wondered from a gas perspective what your outlook is for the ability for industry to stimulate demand within the region, and then how you think about the cost-benefit around that time lag as you await the region to, and maybe this is similar words to what you used, need, ranges, growth down the road. versus the opportunities to monetize via further divestitures?
spk05: Well, let me start off. We'll probably all pile in with different comments. But one, you've seen natural gas, you know, replace coal. As coal continues to get retired, there's a slide, I think, in the deck somewhere that talks about gas at one point being, you know, coal being about two-thirds of power stack. Now it's in the low 20s. I think given the advantages of gas being so much cleaner, and of course, part of that will be renewables, but gas has been capturing about two-thirds of that, I think, with time. So coal will continue to decline, and that'll happen within the region. Ultimately, in some cases, a nuclear replacement coupled with growth and just in-basin power generation. So there's good opportunities there to grow. Also on the deck, we talk about, as a country, LNG exports also continuing to grow, and we think that'll grow significantly with time. You really have the same situation globally as in the country. You've got still a lot of coal being burned internationally in places like China and elsewhere, and ultimately, I think natural gas will take that market as well. So, and we've got information in the deck that, you know, we think having a long-life core inventory is key, and we see others exhausting that core inventory. In some cases, you know, in a relatively short time frame, within Appalachian on slide 15, again, bottom right, it shows some of the peers having core inventory of two years to, you know, five years. So, having that core inventory, I think, will put us in a good place. As Mark mentioned earlier, we're always open to whatever's best for our shareholders and optimizing the value of the inventory depending on what opportunities are available. Mark, Dennis, want to add to it?
spk07: Yeah, Brian, this is Dennis. Real quickly, I think in addition to Jeff's comments, I mean, we currently have clear line of sight on Shell's Cracker facility as being local demand infrastructure development and that getting into service here in the in the near future. PTT is another name that, you know, clearly they're an organization that is looking to build some infrastructure for local demand as well. When you look at the pipe takeaway capacity that's been developed, not only for the natural gas side, but also on the liquid side to get to Marcus Hook, it really starts to create an advantage for range based upon our continuous acreage position. And we'd like the ability of how that ties back to our not only our future development of the inventory Jeff touched on, but also the NGO realization capture that we're going to be able to see in the future. And then to add to the LNG discussion, we're also seeing some discussions take place about potential future LNG development that could take place on the East Coast. Again, thinking about logistics out of out of Marcus Hook in that region starts to make not only range advantage, but also adding to that energy stack where we can contribute in a positive way. So very constructive outlook.
spk01: That's great. Thank you for that. And then my follow-up, Mark, I thought I heard you use the phrase return cash to shareholders as a goal, and I wondered if you could add any more color on what your thresholds would be from either a leveraged credit rating or or other perspective where you would consider that and what the mechanisms would be to consider?
spk06: Sure. So, our stated long-term objective of running the business is substantially below two times. So, as we approach that, we are at a position where we can articulate more clearly, more definitively what that framework looks like. What's the reinvestment rate of cash flow? What is the form of returns of capital to shareholders, be it a dividend, be it a variable dividend, be it share repurchases, what's the most economic and appropriate return of that capital. So, you know, as we approach sub-two times leverage, as we approach and then hopefully gain and sustain an investment-grade balance sheet, you know, you'll see that hopefully in advance, more clearly articulated, we'll be able to share what those targets are. In the shorter term, what you're going to see is the board's expectation consistent with what I just articulated and explained, how they've outlined ranges strategy being sub two times leverage in the form of new compensation targets, long-term performance share targets of well below two times. You'll see that fully disclosed in the proxy. So as we get a little bit closer, and again, I'll refer back to slide 14, just articulating how quickly range can get to that two and even sub two times just through current prevailing market prices could be near the end of 2022. So sometime in advance of that, we could further go into detail there.
spk08: Great. Thank you. Thank you.
spk00: Thank you. We are nearing the end of today's conference. We will go to Josh Silverstein of Wolf Research for our final question.
spk04: Yeah, thanks. Good morning, guys. You know, over the past few years, your NGL realizations have been improving, and this year you're guided towards a premium over Montbellevue. Is that one to do premium what you guys are receiving now, or do you think this continues to – and I think you mentioned before that there's some more upside to this. So I'm wondering if that premium then continues to grow as you're going into 22. Hi, Josh.
spk09: This is Al Mainberg with the – I head up our liquids business, so I'll try to answer your question here. The NGL market value right now is currently trading over $25 a barrel. That's up $7 a barrel versus the fourth quarter, you know, 39% increase. Just for context, in 2020, our pre-hedge realization was about $15.43 per barrel. So at the current strip, we're looking at realizations of roughly $23 per barrel for 2021. And again, versus 2020, that's an increase of $7.75 per barrel. So it's a 50% increase, which just on that basis is about $280 million in additional revenue. Now, that's at current strip. And our view is that current strip is actually pretty conservative. And I'll just walk you through an example of why I think that. So propane stocks have declined considerably this season, right? And I'm talking about the winter season. So the withdrawal is starting back on October 1st. We've withdrawn from inventory at a rate that's twice that of last year and significantly over the five-year average. Now, February, a lot of that is driven by, you know, just real good domestic demand that's up considerably versus last year. but also the exports that have been very, very strong. If we look forward, if we continue to export at, let's say, the average rate that we were exporting in the fourth quarter and in January of this year, I'm not saying February because February has been a bit of an anomaly because of weather and some other factors. But if we continue to export at the same rate, we're actually going to go into next year's winter season, so October 1st, with a big inventory deficiency. In fact, we'll be at, my projection is around 45 million barrels of inventory. And that's only 21 days supply. The market typically wants to have 40 days of supply going into winter or call it 80 million barrels of inventory. So to get there, we're going to have to, something's got to change. And what's going to happen is that the U.S. prices are going to increase relative to where the strip is right now, and relative to international pricing. And that's going to lead to some reduction in actual exports. I'm calculating around 8 to 10 BLGCs per month that would need to come out of the program to get us to the low end of where we need to be to start next winter, which is around 80 million barrels. So again, this all implies better overall NGL realizations. As Dennis mentioned earlier, we've added to our position at Marcus Hook. We can export more. We expect our premiums relative to Bellevue to continue to be strong. And I think there's, you know, very positive tailwinds in place for us from a cash flow basis through the rest of the year.
spk04: Great, Tim. Thanks for that, Alan. And then maybe just on the BFN side, I don't think you guys are recovering anything additional this year in guidance, but just wondering what price point or what may trigger you guys to be able to extract a little bit more, or do you think that won't be happening this year?
spk07: On an ethane front, Josh, we kind of maintain a course of kind of a middle-of-the-road extraction, somewhere in the 60,000 to 65,000 barrel per day trajectory. We ensure that we're meeting all of our commitments that we have contractual through the program year. But it also leaves us optionality in the event, as Alan was pointing to, we see something constructive that allows us to take advantage of an opportunity. We further add to the cash flow bottom line, as Mark touched on, and improve our overall realization. So we leave that flexibility in play. And having export, I'm sorry, takeaway capacity on three of the four main outlets in the Northeast gives us an opportunity to do so So we'll look for those opportunities through 2021, just as we have in prior years.
spk04: Great. Thanks, guys.
spk00: Thank you. Thank you. This concludes today's question and answer session. I'd like to turn the call back over to Mr. Ventura for his concluding remarks.
spk05: Yeah, I'd like to conclude with just a really brief summary of the range story. We have best-in-class drill and complete costs with the lowest decline rate in the basin, leads to lowest maintenance capital. Couple that with the largest Tier 1 inventory really leads to sustainable free cash flow for many years. We're doing that into a better macro pricing environment. We are, and we're focused on being an environmental leader amongst E&P companies, and our compensation framework is aligned with shareholders and our strategic objectives. Thanks, everybody, for participating in the call this morning, and feel free to follow up with our team for any additional questions.
spk00: Thank you for your participation in today's conference. You may now disconnect at this time.
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