Welcome to the Range Resources Second Quarter 2021 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 now 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 second 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 will be referencing certain slides on the call this morning. You will also find our 10-Q on Range's website under the Investor's 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.

Thank you, Laith and thanks everyone for joining us on this morning's call. The second quarter of 2021 saw Range make continued steady progress towards our key objectives, improving margins to cost controls, generating free cash flow, operating safely and efficiently and ultimately positioning the company to return capital to shareholders as the most efficient natural gas and NGL producer in Appalachia. I’ll touch briefly on each of these before turning it over to Dennis and Mark to cover in more detail. Starting with unit costs and margin improvements. Range’s unit costs for the quarter were in line with our expectations as NGL prices strengthened during the quarter processing costs increased as expected as a result of our percent of proceeds contracts. But this was more than offset by the improvement in natural gas liquids prices resulting in vast improvements in Range’s margins and cash flow. Looking at prices, Range’s, un-hedged realized price for the quarter was approximately $3.25 per mcfe, which was $0.41 above the NYMEX Henry Hub equivalent price of 284. This premium to Henry Hub is outstanding particularly when considering seasonality in certain natural gas and NGL markets and it is the result of our liquids production in diversified marketing portfolio. This pricing uplift from liquids reduces ranges breakeven natural gas price and improves margins when compared to producing only dry gas. In fact, Range’s cash margin of approximately a $1 per mcfe for the first half of the year is roughly double where we were last year. Given the improved fundamental backdrop for NGLs with approximately 65% of our activity in the liquids-rich window this year Range is very well positioned to continue to benefit. In the second quarter, Range produced $177 million in cash flow and with capital spending coming in at just $120 million for the quarter. Range’s generated solid free cash flow despite seasonally weak pricing and the second quarter being the high point of capital spending for the year. The team did an outstanding job leveraging our large contiguous acreage position to complete the operational plan safely and with peer-leading capital efficiency. Range’s blocky acreage position affords us operational advantages on multiple fronts including water recycling, infrastructure, rig mobilization, long lateral development and equally optimization. When combined with a dedicated and focused technical team with years of experience in the basin, this equates to class leading well cost and capital efficiency and having delivered operational programs below budget for the last three years Range remains on track to do the same for the fourth consecutive year in 2021. Taking this level of efficiency and combining it with strong recoveries, a shallow based decline of under 20%. a sizable inventory and liquids optionality Range has what we believe is an unmatched foundation for generating sustainable free cash flow for the long-term. As shown on Slide 15 of Range’s investor presentation, we see significant free cash flow with strip pricing. This organic free cash flow supported by thoughtful hedging through the end of this year and into 2022 puts us well on our way towards meeting our balance sheet targets in the near future. Mark will provide more detail, but at recent strip prices, leverage is forecast below two times early next year. The significant rate of improvement in our balance sheet is a testament to the progress we've made reducing debt in improving our cost structure in recent years and now reflects the free cash flow potential of the business. We are excited about where Range is today and equally excited about what the future holds. Natural gas and natural gas liquids will continue to play a critical role as the world moves towards cleaner, more efficient fuels. We believe that producers who can most efficiently deliver these products to end markets from a cost and emissions’ perspective will be the most successful and we believe Range is well positioned within that framework. We remain ahead of schedule in achieving our absolute emissions reduction targets in our 2025 goal of net zero. In our emissions profile is near best-in-class amongst producers globally. Importantly, what further differentiate Range from peers is our ability to efficiently deliver clean burning natural gas for an extended period of time given our multi decade core inventory. For context Range’s 2021 activity of approximately 60 wells is just a fraction of or 2,000 Marcellus locations with EURs that are greater than 2 bcfe per 1,000 foot of lateral. The average recovery of these 1,000s of wells is very similar to the wells Range has turned to sales for the last several years providing Range an unmatched runway of high quality wells that's measured in decades. And that's before counting other horizons such as a Utica Point Pleasant or Upper Devonian. This type of runway is not found in most natural gas producers and we believe Range’s position as well as any upstream company to generate competitive returns in a free cash flow over the medium and long-term. Before turning it over to Dennis and Mark, I'll just reiterate that Range remains committed to discipline capital spending. Over time, we believe Range will stand out amongst peers as a result of our low sustaining capital, competitive cost structure, liquids optionality and importantly our multi decade core inventory life, which is an increasingly competitive advantage as other operators exhaust their core inventories. We will continue to focus on safe, efficient and environmentally sound operations, prudent capital allocation and generating sustainable returns to our shareholders. Over to you, Dennis.

Thanks, Jeff. As we look back on the second quarter, all-in capital came in at $120 million with drilling and completion spending of approximately $116 million. Capital spend for the first half of the year totaled $226 million or approximately 53% of our annual plan. During our first quarter call, we touched on some of our recent efficiencies driving this capital result and we'll expand on those during the operations update today. Looking forward, consistent with our activity forecast for the second half of the year, the remainder of our capital spending is expected to taper through year end in line with our activity forecast previously communicated and placing us at or below are all-in budget of $425 million. Production for the quarter closed out at 2.1 Bcfe equivalent per day. Our activity resulted in 25 wells being turned to sales, with 75% of the turn in line activity landing in the back half of the quarter, setting us up for higher sequential production for the balance of this year. Looking back at the quarter, I'd like to point out six of our Marcellus wells turned to sales on an existing pad in the heart of our wet gas acreage position. Initial development and production on this pad occurred in 2016. Similar to the example we walked through during our first quarter call, we returned to this pad to add additional wells building upon our prior technical learnings, efficiencies and cost savings. Initial production rate for three of the new wells placed them at the top of our Marcellus program history. And the pad itself is now Range’s top Marcellus pad to-date based on average initial production per well. And lastly, production from this pad was comprised of approximately 50% liquids from an average lateral length of just under 14,000 feet and aligns with our liquids marketing results we will cover later in this section. Not only does this provide further evidence of the quality and sustainability of our large contiguous acreage position, but it also demonstrates that even after more than a decade of Marcellus development, we continue to optimize and enhance well performance through technical and operational innovation. Looking at some of our operational highlights, the German team operated to dual fuel horizontal rigs during the second quarter split between our dry and super rich acreage footprint. Average lateral links for the wells drilled in Q2 was approximately 12,000 feet, with five wells exceeding 16,500 feet. Similar to updates from prior quarters, we returned to pad sites for a significant portion of our activity in Q2, with approximately 75% of our new wells drilled on pads with existing production. In addition to maximizing infrastructure utilization, the combination of longer laterals and returning to existing pads continues to drive efficiency improvements and reduced drilling costs. As an example, and the first half of 2021, we've seen a 10% reduction in average drilling cost per lateral foot versus full year 2020, which fell below $200 per foot. It is improvements such as this that further support our year-to-date capital spend and ensuring that we deliver within our capital budget. On the completion side, the team completed 20 wells with a large -- with a total lateral footage of more than 225,000 feet with an average horizontal length of approximately 11,300 feet per well, including four wells with lateral links exceeding 18,000 feet per well. These long laterals returned to sales covering the end of Q2 and beginning of Q3 driving our second half of year production. Similar to our drilling results, the completions team is capturing continued efficiency gains from longer laterals and cost savings by returning to pads with existing production. The team successfully executed over 1,100 frac stages in the second quarter, while hydraulic fracturing efficiencies in the first half of the year increased by more than 6% versus the same time period a year ago. In addition to these efficiency gains, our emissions reduction strategies were advanced by expanding the operations associated with our electric frac fleet to include electric powered pumped down equipment, wireline units along with other supporting equipment. The testing of electrification of additional onsite equipment coupled with our production facility design and pilot program with Project Canary are just a few examples underway to deliver on our broader ESG goals and our emissions target of net zero by 2025. Water operations once again exceeded our operational and capital efficiency expectations in the second quarter through increased utilization of third-party produced water. The team was able to efficiently utilize just under 1 million barrels of third-party water in addition to Range’s produced water. And as a result, completion costs were reduced by over $1.6 million for the second quarter. The continued success of our water operations along with the efficiencies captured by the completions team has reduced our overall water costs for the first half of the year by just under $7 million or $15 per foot less in cost and it represents a 28% improvement in water costs versus the same time last year. Water savings can vary each quarter depending the location of our operations. But generating these type of cost reductions has become a repeatable part of our program. And it aids in our ability to deliver at or below our 2021 drill and complete cost per foot target of $570 per foot. Strong field runtime continued in the second quarter. Like the first quarter, unseasonable weather conditions threatened to hamper production with prolonged high ambient temperatures and storm events in June. But the production facilities teams work diligently to keep the field running at a high rate with minimal impact to production or operating expenses. With the winner behind us lease operating expenses for the quarter closed out at $0.10 per Mcfe equivalent and are projected to remain at a similar level for the remainder of the year. To complement our operational results, I'd like to provide a quick update on Range’s safety performance. When looking at our key safety metrics year-to-date, we continue to see improvements compared to the same time period a year ago. With our team's ongoing dedication to hazard identification and training, it has been over a year since our last employee recordable incident. Year-to-date, this contributed to a total workforce recordable incident rate in line with last year, which was Range’s best safety performance in the program history and benchmarks in the top quartile for safety performance among our peer group. Now shifting over to marketing, Echoing the theme from our last call, market prices strengthened during the quarter for both NGLs and condensate with Mont Belvieu propane prices ending the quarter at its highest level in almost three years. Demand for both NGLs and condensate continues to increase with supply remaining stable. As a result of these tightening fundamentals and the corresponding improvement in prices throughout the quarter Range’s NGL price was $27.92 per barrel, a $2.24 premium to Mont Belvieu. This represents a record for the highest premium to Mont Belvieu in company history and the highest quarterly NGL price in absolute terms since 2014. A key driver for the higher premium in the quarter was the new and diverse LPG export strategy that allowed range to optimize its sales portfolio through increased flexibility and product placement and sales timing. Due to the timing of Range’s LPG exports, the second quarter average NGL barrel was heavier than normal meaning that it included a higher propane and heavier component percentage than prior quarters. During the second half of this year, we expect strong fundamentals to result in higher absolute prices for domestic propane and butane, which would compress our premiums of U.S. LPG exports. Coupled with a lighter barrel from export timing and seasonality and domestic sales, we expect lower premiums to Mont Belvieu, but improving overall NGLs price realizations. Range’s premium NGL differential remains an expected positive $0.50 to $2 per barrel for the full year showing the benefit of our diversified NGL portfolio and access to international markets. On the condensate side, realized price for the second quarter was $57.60, a differential of $8.36 per barrel. As expected, the condensate differential to WTI narrowed slightly quarter-over-quarter and is expected to stabilize near this level for the rest of the year. As we previously discussed, condensate values are primarily supported by continued recovery in demand for transportation fuels. As business and personal travel around the world continues to increase to pre-pandemic levels. As we enter the second half of the year and continue into 2022. The value of Range’s entire liquids portfolio is strongly supported by both domestic and international fundamentals and Range is uniquely positioned to maximize value in this constructive environment. Similar to our results and view for liquids, positive movement is the theme of the day for natural gas. During our Q1 call, several signs pointed towards the potential of another supplied market. With operators administering capital and production discipline this year ongoing strength in LNG exports at 11 Bcfe per day and overall storage levels running below the five-year average and under supplied market has materialized further impacting 2021 pricing and movement in the forward curve above $3 for 2022. As we look at the second quarter, Range reported a Q2 natural gas differential of $0.39 under NYMEX, including basis hedging. Looking ahead, we see potential for additional positive improvements for natural gas pricing and basis with regional storage levels behind the five-year average. As we reach the major point for the 2021 program, our second quarter and year-to-date results showcase some of our best milestones to-date for the program. By looking at our environmental and safety performance, operational efficiencies, cost and well results. We will build on these operational results during the second half of the year, while delivering our best program yet. I'll now turn it over to Mark to discuss the financials.

Thanks, Dennis. During first quarter comments, I started by saying efficient operations delivering planned production, combined with margin enhancing expense management drove free cash flow. In other words, delivering on stated objectives, which is Range’s fundamental strategy and something the team successfully executed again during the second quarter. Reliably efficient operations again delivered planned production. Our relentless focus on expenditures that drive cash flow in addition to diversity and sales points for natural gas, natural gas liquids and condensate resulted in cash flow from operations of $177 million before working capital compared to $120 million in capital spending. Significant improvements in free cash flow compared to past periods were driven by a 100% improvement in pre-hedge realized prices per unit of production versus the prior year period with realized price per unit reaching $3.25 in the second quarter. This realized price per unit is $0.41 above NYMEX Henry Hub driven by a 118% increase in NGL price per barrel, which reached $27.92 pre-hedge. Realized NGL price on an Mcfe basis equates to $4.65 and condensate realizations equate to $9.60 per Mcfe hence the realized premium to Henry Hub. Additionally, Range’s NGL prices exceeded Mont Belvieu equivalent NGL barrel by $2.24 due to our unique portfolio of domestic and international sales contracts. Realizing the benefit of higher commodity prices during Q2 was possible in part due to a thoughtful approach to hedging. We maintain our strategy of reducing risk through an active hedge program. However, hedging too early before prices reached levels estimated as sufficient to support industry maintenance capital could have resulted in a loss of significant revenue. For 2022, we've continued to be balanced in risk management, so as to not hedge away improved fundamentals, such that at quarter end and assuming the election of outstanding swaptions Range was approximately 40% hedged on natural gas at a floor of $2.80 and with a ceiling of $3.04. NGLs are typically hedged on a rolling three to six months basis, meaning exposure to higher NGL prices in the second half of 2021 was largely retained with improving hedge averages by quarter. As an example, Range’s average swap for condensate production improves by $10 per barrel in the third quarter, while propane, butane and natural gasoline averages all improved by approximately $0.20 per gallon versus the second quarter. This hedge book compares a very favorably to the industry allowing Range to capture improved pricing, growing cash flow per share, while also accelerating deleveraging particularly in the next several quarters and ultimately cash returns to shareholders. Margin enhancing focus on unit cost is a constant state of mind at range. Lease operating expenses remain near historic lows at $0.10 per unit on the back of consistent efficient Marcellus operations. Cash G&A expenses increased slightly to $31 million or $0.16 per unit. The increase stems from two line items, first, roughly $1.5 million related to legal expenses this should tail-off next quarter. And second what appears to be a temporary increase in medical costs. Absent these two transitory items G&A spending was in line with the preceding quarter. Cash interest expense was roughly $55 million flat with the preceding quarter and with reduced debt balances should begin to decline in coming quarters. Gathering, processing and transportation expense increased, but it is important to keep in mind that this is a positive byproduct, a strong NGL prices that resulted in significantly higher NGL margins. Recall that Range’s processing costs are some percent of proceeds contracts, such that we pay a percent of NGL revenues as the fee. Consequently, a fraction of the materially higher prices received for NGLs is paid as a higher processing cost of the quarter. As discussed previously, an increase in revenue of $1 per NGL barrel equates to approximately $0.01 per Mcfe in cost. The structure is unique to Range in the Appalachian Basin, and is a right way risk arrangement that has led to reduced costs for several quarters of lower prices and now continues to drive material margin expansion. For reference, since February Range’s forecasted NGL realizations in 2021 have increased by approximately $7 per barrel potentially resulting in an increase of approximately $250 million in pre-hedge revenue. Net of price linked processing costs, forecasted 2121 pre-hedged cash flow from NGLs has increased by approximately $200 million since February, demonstrating the significant margin expansion from rising NGL prices. In aggregate revenue improvements stemming from diverse marketing arrangements, coupled with prudent hedging and thoughtful expense management resulted in cash margin per unit of production expanding to $0.93. Turning to the balance sheet, as described last quarter near-term maturities have been a focus, such that we reduced bond maturities through 2024 by almost $1.2 billion, while at the same time improving liquidity to nearly $2 billion. During the second quarter, we reduced total debt by $66 million including all subordinated bonds. Forecasted cash flows, strip pricing are expected to exceed debt maturities in coming years and are backstopped by ample liquidity. There has been substantial improvement in the debt markets and it's evident in the trading levels of Range’s bonds that both access to and cost of capital has improved. Future debt retirement is expected to be funded primarily by organic free cash flow. We will be cost conscious to effectively manage debt retirement while also being mindful of the costs and benefits of potential refinancing activity. Liability management over the last two years has as expected, temporarily increased interest expense. However, this avoided much higher cost forms of capital that allowed Range to retain per share exposure to growing free cash flow in a substantially improved natural gas and natural gas liquid environment. Further improving the balance sheet remains a principal objective our core commodity prices, forecasts indicate leverage in the mid one-time’s area is achievable in the first half of 2022. Tangible shareholder value accretion is first being driven by using free cash flow to reduce absolute debt. As target leverage levels come into sight potentially as early as the first half of next year, the discussion of Range’s return of capital framework becomes the logical next step in a balanced macro environment. The second quarter and year-to-date results are a byproduct of relentless work by the entire Range team being focused on enhancing per share exposure to what we believe is the largest portfolio of quality inventory and Appalachian. To put it concisely, we believe we are delivering on stated objectives. We seek to continue this trend of disciplined value creation for our shareholders. Jeff back to you.

Operator, we will be happy to answer questions.

Thank you Mr. Ventura. The question and answer session will now begin. [Operator Instructions]. The first question comes from David Heikkinen of Pickering Energy Partners. Your line is open.

Good morning, guys…

Good morning, guys that's a new sound and a good one to me.

Good morning to me.

I had a quick question as you think through next year, you get to 1.5 times leverage and you’re hedged. The first question was, do you have an ability to hedge any NGLs for next year? And then, as you get down to that lower leverage, do you think you continue to layer in this level of hedges or do you flex that down some other companies have talked about a lower level of hedges in 2023 and beyond as that comes down?

Good morning David, this is Mark, I'll start-off on that one. I think with our target leverage levels getting fairly close first half of next year that does certainly open up certain optionality and how we approach risk management and how we structure the business. I think taking a step back, the portfolio approach to pricing on the NGLs gives us a lot of flexibility there. As we've mentioned before, the nature of the NGLs market and the depth of the derivative market, our ability to hedge around that three to six months has been roughly speaking the cost effective approach to not hedging into what is a more backward dated forward market for NGLs. But again, with the portfolio of outlets, the variety of contracts and price linkages that that gives us a lot of resilience in that pricing structure. So in particular, Alan’s ability to move product internationally. So with that, could we hedge out further, we certainly can, we have different baskets within that physical contracts that give us latitude to do that in various ways. And then at a higher level, just speaking about the hedging program broadly not specific to NGLS, but as you reduce leverage, you certainly have the capacity to reduce your hedging targets. It is after all, a risk management exercise. It's not a profit center. It's not a trading exercise. So we are seeking to make cash flow more predictable, make our operations and resilience of the capital program and the drilling costs per foot so forth steady and predictable over the course of the year. That's the underlying objective the hedging program. So over time, as leverage comes down, you could begin to reduce the target hedge levels where historically when we've entered a calendar year, we've been 60% to 80% hedged. You could reduce that and retain some exposure to what you perceive as a positive supply demand. I think what you've seen though, is while we haven't changed our current targets, given the objectives of reducing risk, you've seen a slightly different cadence of how we've added hedges. We've done it more slowly, you stepped into the hedge positions on a year forward and we've used some colors to retain exposure to the upside. So there's some flexibility and how we've done it while still achieving the desired risk mitigation right now.

Okay. And then you talked about securing cash flows. Can you talk at all about cadence for activity levels in 2022? Is it similar to 2021 or more low level? Do you have any early thoughts as far as how you started-off fast and then -- or do you -- do more load level activity heading forward as well?

For next year, you'll see us at discipline spending maintenance capital. We don't have the exact details of that yet. You'll hear more later in the year. But, we're just focused on being disciplined maintenance and working on generating free cash and improving margins, so...

Okay. Thanks, everyone.

Thank you.

Thank you. Our next question is from Josh Silverstein of Wolfe Research. Your line is now open.

Hey, thanks. Good morning, guys. Just wanted to touch on a couple of things on the NGL side. Can you talk of -- you mentioned about the barrel composition change from heavier to lighter. Can you talk about some of the flexibility there? And then are there any limitations to you guys selling any more NGLs into this price environment right now is or you have everything contracted on A tax or the [indiscernible] system as possible.

Hey, good morning, Josh. This is Alan. Yeah, on the barrel composition, we took over managing our exports at markets starting back in April. And it gives us a lot more optionality and flexibility in terms of timing of some of those vessels in the sales. So that's one of the levers that we have to -- that we have access to now, but we really didn't have access to before. Going forward in terms of ability to optimize and take advantage of good pricing in marketplace. Yeah, we can still do that we've got a fair amount contracted but we do have a significant amount of flexibility as well. And for instance on [indiscernible], we could still pull out 20,000 barrels per day if the market opportunity was there, we wanted to go after that. So there's a lot of different things we can do whether it's timing of sales on propane and butane to the export market or to the domestic market or potential and recovery [indiscernible].

I guess do the flexibility right now, if you want to -- if same prices or I guess at the end, [Frankfurt] allowed you to -- could you extract that 20,000 barrels a day and put it into the market pretty easily?

I'd say yes.

Got you.

Again, we were pretty well situated, right. We've got access to all the takeaway out of the Northeast. So whether it's one of the two pipelines for both pipelines going up to Sarnia, Ontario, whether it's Mariner East, going to the international market, ATEX going down to the U.S. Gulf Coast as well as access to opportunities within the Northeast. So all that gives us the capability to move that thing pretty much unencumbered. The good news also though is that from a fundamental standpoint prices are good now, but we actually see them increasing quite a bit as we go on through the rest of the year and into next year. So we're at about $0.33 per gallon, as of this morning. And I would say that by the end of the year, given current fundamentals is a good chance that we'll be touching on $0.40 per gallon. So again, we're going to be patient and smart about how we optimize but typically, we could always sell pretty easily 5,000 a day over existing contracts.

And then just curious on M&A as well. I know you guys had the terrible sale last year. But with prices strengthening right now and local prices stronger, any interest or pickup in interest in terms of other asset packages you may have up in Appalachia to divest as well and bring forward those debt reduction efforts.

I guess I'd start off with what's the trajectory of the company today? What is the per share exposure to Range's asset base, the predictability of the inventory and the cash flow and exposure to that growing free cash flow per share. So I -- as you look at the motivations and the value creation of much M&A, a lot of it -- you may have heard me kind of oversimplify M&A previously, but a lot of times, it's driven by quantity of inventory, quality of inventory or balance sheet improvement. We clearly have quantity and quality of inventory in a great spot for Range. As far as the balance sheet goes, I also believe we are in a very good spot approaching target levels in the first half of next year and continuing to improve thereafter, with the capacity to return cash to shareholders in the not-too-distant future. So with all of that, what is the motivation to do M&A. Clearly, it would have to be value enhancing, meaning, improved cash flow per share, improved free cash flow per share, perhaps accelerate some of that deleveraging. There's some potential benefits from size, but size getting bigger for bigger sake isn't necessarily a primary motivator. It's all about cash flow per share. So it's something we certainly are monitoring. We keep an eye on it. Our goal is always to improve shareholder value. But it's a high bar, given that we have the key objectives as Range sits today, a pretty good line of sight to achieving those.

Great. Thanks, guys.

Thank you.

Thank you. Our next question is from Holly Stewart of Scotiabank. Your line is now open.

Good morning, gentlemen.

Good morning.

Maybe first one for Mark. Just trying to reconcile to that Slide 15 the $1 billion of free cash flow between ‘21 and ‘22 at strip was maybe hoping you could walk us through just how you're defining free cash flow internally and then maybe just a highlight for that -- the number for the quarter?

Sure. Happy to do that. So I think as you look at the updated deck, one thing to note here is that we're just using strip pricing. So this is reflective of current market conditions, what's achievable out there and baked in our current cost guidance and our current hedge book. So this is reflective of what we believe is a reality and our best estimates of forward cash flow generation. What we're showing here in the upper right-hand side of the chart, I think you're focused on absolute debt levels, these are principal levels in ballpark ZIP code of what 2021 could look like in 2022 could look like again at current conditions, hedges and everything fully loaded. So using current strip pricing for NGLs for gas and oil, you get to something close to a model should generate something close to and around $1 billion of free cash flow to the end of 2022. So that would get you running the numbers again at current cost guidance, realized prices, you can arrive at around EBITDA estimate. But roughly 2.5 times or better toward the end of this year and mid-1 times area next year. So this is intended to reflect what actual cash in the door would be and that application to absolute debt reduction.

Okay. Mark, I guess what I was trying to get at was just are you including that Terryville divestiture contract payment within the free cash flow, $1 billion number? Or is that excluded?

Yeah. It is included?

Okay. That's great. And then moving on, I'm not sure if this is for Mark or Jeff or Dennis, but you've beaten your CapEx guide. I think, at least the last few years, and you're sort of trending below that historical run rate. I think now you said at 53% in the first half. Is there something unusual or kind of onetime that we should be looking for in the next couple of quarters? Because I think according to -- I mean, if we have this right, I think you've tilled about 70% of your wells already in the first half of the year. So just trying to understand, is there any color there? Or are you just really ahead of your budget here?

Holly, this is Dennis. I'll start off with this one. As we look at the year, part of -- there's a couple of drivers, I think, when you look at both capital and tie it back to a till type assessment. And one of them is we tried to touch on it a little bit in the prepared remarks today, but we did see 25 wells get turned to sales during the second quarter. But a big bulk of those, around 70% to 75%, were later in the quarter. So what -- though we can count those as wells turned in line because the completion activity was certainly wrapped up -- but really, the bulk of the production effect is going to be seen through the second half of the year as we continue to produce those wells. So if you were to, let's just say, push those wells literally a week to 10 days, some of those could actually change the numbers by instead of 70%, maybe it's more like 60% to 65%. So we're going to see some of those wells really be impactful to our production profile for the second half of the year. And of course, the other thing is we continue to really see really strong efficiency gains by the team, whether it's improvements in our drilling cost per foot by another 10% through the first half of the year versus last year's average water recycling, we've reached some new thresholds and how much not only volume we've moved, but the savings that we've been able to capture. The team has really been creative. We've done a great job through the first half of the year. And then, of course, lastly, we've been able to see more completion efficiency gains as well. 6% may sound like a smaller number compared to some of the historical results. But when you start to total that up over a program year, that can mean, let's just say, advancing a whole pad forward one particular month of the year. So we like the path we're on. We're on a trajectory to be at or below both our CapEx and our cost per foot targets, but we wouldn't anticipate maybe to hit something directly that you'd asked us. We don't expect a onetime event in the second half of the year. We're on track. We expect the end of year cadence down to one drilling rig and one frac crew and really like what we're seeing from a cost standpoint once again.

Okay, great. Thanks, guys.

Thank you.

Thank you. Our next question is from Scott Hanold of RBC Capital Markets. Your line is now open.

Thank you. Appreciate your time. Can you talk a little bit more about your thoughts around the shareholder return plan? Obviously, you all have accelerated that leverage reduction efforts. And what do you anticipate is going to be a discussion next year if share prices pull in? And part of my question does relate to like where does leverage really need to get to when you guys look to initiate a program. I know below two times was sort of the general thought, but I know there's also some long-term incentive plans that certainly bias the number down toward 1.5 times.

Sure, Scott. All very fair questions around shareholder returns. I guess I would start with our focus on this has really begun through debt reduction. You think about enterprise value and just shifting the pie chart there, shifting the value from the debt holder side to the equity holder side, $1 billion in debt reduction so far. We also bought back 10 million shares last year at a very low price very accretive for shareholders. So continuing that trend of creating value and shifting more and more of that value to the equity holders side of the equation, it is our focus. Further debt reduction, as we talked about already on this call. I think as you consider target leverage levels, the way that was laid out in the proxy and the way we've verbally described that in the past is substantially below two times. So a little bit more color provided in the proxy was target 1.5 times excellent as one times. Obviously, we will strive to achieve something closer to that excellent level. I think as you have a clear line of sight, meaning it's durable, it's not just a transient situation of the durable condition. So pricing is resilient the supply demand equation, the macro condition still remains balanced or perhaps undersupplied. So that there's a positive skew in the pricing or expectations of commodity prices. Those are kind of the preconditions to, I think, us initiating. But as we plan out next year with the Board this fall as we get better clarity on what prices are for next year, I think that puts us in a situation where perhaps early next year, we could begin to discuss the framework. But stepping out of the details for a moment, I think the frameworks that have been discussed broadly by the industry largely makes sense. There's some modest base level dividend that could be employed. This is a cyclical commodity business, it's capital intensive. So you need to have that variable component, whether that's a variable dividend or variable share repurchases. That's a matter of economics at the time in the share price. And then as you go down, the waterfall of capital allocation, then you've already met all of your debt reduction targets. So that's kind of how we think about it. The commodity price environment has accelerated our deleveraging. So this is a discussion item that we'll be focused on through the remainder of this year and into early next year.

Okay. So just for me to clarify. So what I'm hearing is, obviously, as you get below two times, I mean, it's a real discussion that there's visibility to that. But you want something durable. The ideal situation is getting close to one but probably looking at when it's durable around 1.5 times, that's when it's probably going to make more sense. Did I hear that correctly?

I think that's a fair hypothetical. I mean, again, it's subject to us working through the budget for next year and ultimate Board approval of the plan to be announced. But I think conceptually, that would make sense to think about it in that fashion.

Got it. And then when you look at your -- I know, you've obviously not set out the capital budget for 2022. But if you could just give just some generalities, I think he said, 65% of the activity in liquids areas this year, do you anticipate that's a good way to look at your progression going forward or is there some mix shift that could happen as the market shifts as well?

Scott, this is Dennis. I do think the way you're viewing our program in 2021 is a very fair way of projecting out for what 2022 could look like. When you start to look at our inventory, we approximately have 2/3 of it in our wet gas acreage footprint. I'll say wet and super rich. It's processable gas. And the other 1/3 is -- resides in our dry gas position. So as we look to further consider what 2022 would look like, it would be moving back into pads with existing production, utilizing that existing footprint as much as possible, keeping infrastructure utilized at a very, very high level. And having a similar well mix for 2022 as we would in 2021. We try to leave flexibility though, throughout the program. And again, moving back into pad sites allows us to, let's just say, move quickly when we need to. But as we look out for the program year anywhere from 12 to 18 months in advance. As we're thinking about the upcoming program, we also don't try and overcorrect the steering of the car. Because we know that in some regards, that could actually be unhealthy for whether it's efficiencies or whatever our ultimate goals that we're trying to -- and objectives we're trying to deliver on. We like the program, and it should be real similar.

Yes. And so when you look at the existing pads, it's about the same mix as your inventory, about 2/3, 1/3. When you look at existing -- returning to existing pads, is that about the same mix as well as your overall inventory?

I think it can fluctuate, no doubt quarter-to-quarter, if you look at the results we just communicated. You know, we drilled roughly 70% to 75% of our wells on pads with existing production, you could actually see in some other quarters, that might be less, but I think, on average, to consider us being somewhere between 50% to somewhere as much as two-thirds, I think is a very fair proximation on how we'll look at utilizing our existing footprint.

Thank you.

Thank you.

Thank you. Our next question is from Gail Nicholson of Stephens. Your line is now open.

Good morning. I just wanted to follow up on the transportation obligation in Northwest Louisiana. It looks like you guys recorded about a $28 million reduction in that obligation this quarter. And I just wanted to know how should we be thinking about that in the near-term impact? Should we still be assuming it's about a $20 million impact a quarter? Or is it now lower because of the obligation reduction?

Yes, good question, Gail. Thank you. Some estimates of the ultimate liability were updated, and the costs are coming in better than originally projected, hence, the $28 million reduction in the NPV of that recorded liabilities. So over time, the marketing team is always looking for ways to improve our infrastructure and midstream capacity that we can influence, and that improvement was recorded this quarter. I think for coming quarters, nearest term for simplicity's sake, I would model $20 million a quarter for the time being.

Okay, great. And then do you have any color on the potential contingent payment you could potentially receive in the first quarter of 2022 and regarding the sale?

Sure. So there is the capacity to receive $75 million of contingent payout, the current recorded asset values in the $30-some-million range. it's not the full amount because the present value is calculated based on the strip pricing, which is backwards. So as prices roll toward us based on the current supply demand equation, we might expect and we're very optimistic that a good portion of that full $75 million could roll to us. So the way it works is it's calculated on an annual year, and we would receive the first portion of that potentially during the first half of '22 related to realized prices of the asset during 2021.

Great and then just one housekeeping question just based on the first half of ‘21 lateral lines, is it fair to assume that in the second half of this year, lateral lines are going to be averaged over 12,000 feet?

I think it would be fair, Gail, to assume that our lateral length is going to be somewhere between 10,000 and a little bit in excess of that. I don't have the exact average number for the second half of the year in front of me. But our average program year in and year out runs a little over 10,000 feet.

Okay, great. Thank you guys.

Thank you.

Thank you. Our next question is from Noel Parks of Tuohy Brothers. Your line is now open.

Good morning.

Good morning.

Good morning.

Just a couple for me. Looking at how the gas markets have been behaving in the last couple of months and weeks, we've kind of had sort of a perfect positive storm. The COVID, post COVID bounce back in demand and extreme heat in some of the regions that benefit gas consumption most. So I'm just wondering kind of what your current thoughts are on where we're headed in terms of seasonality? Do you think this sort of summer is going to be looking like more of a new normal going? Do you think it's more just the normal sort of fundamental variations we see?

I think the markets have been strong for the reasons that you've said. And then you add in LNG exports have been strong. They've run 10 up to 11 Bcf per day. We think that strengthens as you go toward the end of the year, maybe toward 12. Mexican exports have been 7-plus Bcf per day. So strong exports. If you look, there's a slide in the back of our deck that shows electricity generation from coal is almost a straight line down. It's gone from 50% to now 20% of U.S. electricity generation. We think that continues to drop with -- and you can see on that same chart with natural gas and renewables have done. And gas has taken a significant share of that market. Storage is below the five year average. Gas is a cleaner fuel. Producers have been disciplined to shale 3.0 model. So I think we're setting up for strong natural gas prices for this year as well as into next year.

Great. And thinking about the service cost side now, this is the first quarter in a while where we've heard some of the service producers express a little bit of optimism about what they might be able to do in terms of regaining a little pricing power. So just curious, in the event that say, over the next 12 months, we see inflation be significantly higher than recent years or more maybe than we're all thinking. Can you just talk a little bit about how that might impact your development plan or just how you lay out where and when you might be drilling?

You bet, Paul. This is Dennis. From a service cost perspective, one of the things that we do is we really try and focus heavily both from an operations and technical team on a good quality rollout of annual bid process so that we can secure for the program here, what our pricing structure will look like as much as possible. Part of that's been a driver each year and us coming in below our capital expectations and no doubt it's influencing this year as well. We've seen some small we'll say, moves and shakes in pricing. And I know a lot of you have seen them as well in areas like steel and tubular goods. But that represents overall. We pre-purchased a large portion of our tubular goods at the beginning of the year. further helping insulate us from those price fluctuations. But secondly, we also know that at the end of the day, it represents around a 5% portion of our total D&C costs. So very, very small from that standpoint. As you look forward into -- so for the rest of this year, we're expecting little to no price changes at all. And anything that we would see are very small and nuanced in basis. And what we would see is that our efficiency gains that we spend time talking about have not only offset it, but actually taking our costs further down than what we've actually had historically. So we're encouraged about not only delivering on our well cost projections, but also on our capital budget. But as we look at 2022, there's a lot of question marks still that will have to unfold. And some of it is going to be activity related. As we've already heard on the call, there's a lot of operators who are administered both capital and production discipline and that will play a role into what kind of pricing structure we'll see for next year. I'll kind of point to slide 29, though, in our slide deck, and just remind everybody that as you look across all three areas, there are variations in the cost that we see across our wells, but the economics are strong across all areas. And as you've heard Alan touch on from an NGL perspective, we continue to see really positive uplift both in absolute pricing and our margins as we both look at '21, second half of the year and 2022. So again, I like the path we're on. We'll couple all of these things together with a strong bid program again in this upcoming fall. And operators tend to align themselves with Range because we deliver on a program that we say that we're going to do. And efficiencies are really, really key of meeting some of their financial objectives. So our service partners are important and we're optimistic that we're going to stay on a healthy glide path on costs for 2022 as well.

Great, thanks a lot.

Thank you.

Thank you, Noel.

Thank you. We are nearing the end of today's conference. We will go to David Deckelbaum of Cowen for our final question.

Thanks for letting me close it out guys. I wanted to ask, as you think about 2022, Mark, you mentioned before looking at, one, forecasting $1 billion of free cash; Two, you're going to be sub-2 times levered in the first quarter. You guys put in the verbiage that Range is prepared to return capital to shareholders or potentially could in the near future. You also talked about the cost of capital out there and potentially refi-ing. So I guess how do we balance all of these things when we think about, one, is there an absolute debt number that you think Range needs to be working to near term? You have some near-term maturities next year, and then obviously, the '26 notes are callable. But you could also refi those high-cost notes at a very low cost of capital and keep some extra dry powder around to perhaps buy back shares. How do you guys think about just managing toward those goals?

Yes, a good question. It's kind of a multi-varied equation as we look at how best to apply cash flow. Efficiently apply the cash flow so as to not have a negative carry with cash balances on the balance sheet. That's not a phrase we've heard in a few years of having material cash flow balances for a producing company in a while. So these are the things we're thinking through. To your point, where bonds are trading today, the '26 early next year, become callable. And clearly, we could refinance those at a significantly lower rate, saving material interest expense and significantly reducing unit costs on the interest line item, as I said during the prepared remarks, it was an expected temporary increase in cost of capital there. So higher coupon, but certainly much lower cost than other forms of capital that might have been dilutive to shareholders. So as we look at 2022 and think about the most efficient way of redeeming debt ideally at par, or if early refinancing on something that's clearly economic NPV-positive savings on interest expense like redeeming the 26 as early. It comes down to balancing what the upfront cost, what is the early redemption costs of those. There is a call, but it's -- it comes with price an upfront price, but the savings are quite compelling. So those are the things that we're balancing right now, I think waiting a little bit longer makes some sense, as we generate the cash flow, allowing maturities to roll toward us, particularly given the significant work we did reshaping the maturity profile. There's $218 million coming due next year. The following year is $500-some million. So again, free cash flow should be able to comfortably cover those quite efficiently by paying them off out of at list-to-par just a little bit early. Then it comes down to the economics of an early refi up on the '26s for example. So not a specific answer to your question because the market moves every day. Both on the commodity prices and the capital markets. But you are spot on in terms of the things we are looking at on the financial front in ways of reducing debt, efficiently, reducing our unit costs and taking advantage of improved market conditions.

Mark, it doesn't sound like you guys are bored. But my follow-up is along similar lines, I don't want to ask about increasing activity. But I think, if you were to stand up a rig today and half a frac crew and add to a program going into the end of the year, especially as your capital tape resolve, it seems like a strip that, that free cash payback at the corporate level is perhaps 12 months or less. Is there -- a lot of this is obviously driven by NGL pricing. But I guess how do you think about the right production or spending level as it relates to achieving free cash because we're entering into a commodity period right now where perhaps adding activity could actually accrete more free cash back to you in fairly short order?

Well, let me start at a high level, and Mark may tack on to the answer. But you could have used that argument many times over the last six or seven years, and that didn't work out so well for the industry. So I think the industry now is all about shale 3.0 disciplined growth. Unfortunately, given the big blocky position and high-quality inventory we have, if we just stay focused on what we're doing like is in the hedge book, as Mark said, we can generate significant free cash flow of over $1 billion. So I think you'll see us stay disciplined and stay focused on that and in meeting our corporate objectives and decreasing debt significantly, both on an absolute basis as well as leverage on a debt-to-EBITDAX basis. So Mark, you want to tack on?

Yes. I would just tack on two things. One, Range is in the enviable position of being able to grow cash flow in a maintenance capital scenario, given our declining unit costs that are contractual within our gathering contracts in other areas. And interest expense like we just talked about. They're built in creative steps that are available to us. So that's the first factor to remember is that the growth in cash flow is available even in a maintenance capital scenario. The second piece of it is what are the motivations to grow actual production. As we look at forward curve, some months maybe north of $4, but as you fast forward to 2023, you're sub $3. So as we look at the curve, it's really incentivizing and telling us that we need to commit that capital long term into a still backward dated natural gas curve. We're still reluctant to do that. We think significant value can be created for our shareholders by paying down debt, staying focused. Staying on a maintenance level for the time being and for the period of time that, that curve and market conditions indicate that's the best value.

Thank you guys for the answers.

Thank you.

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.

Yeah, I just want to thank everybody for taking time to be on our call this morning. And please follow up with any questions you have with the IR team. Thank you.

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