Expand Energy Corporation (EXE) Q2 2020 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the Southwestern Energy Second Quarter 2020 Earnings Call. Management will open the call for a question-and-answer session following prepared remarks. [Operator Instructions]. Today's conference call is also being recorded. I will now turn the call over to Paige Penchas, Southwestern Energy's Vice President of Investor Relations. You may begin.

Thank you, Jamie. Good morning, and welcome to Southwestern Energy Second Quarter 2020 Earnings Call. Joining me today are Bill way, President and Chief Executive Officer; Clay Carrell, Chief Operating Officer; Julian Bott, Chief Financial Officer; and Jason Kurtz, Head of Marketing and Transportation. Along with yesterday's earnings release, we also issued our 10-Q, which is available in the Investor Relations section of our website at www.swn.com. Before we get started, I'd like to point out that many of the comments we make during this call are forward-looking statements that involve risks and uncertainties affecting outcomes. Many of these are beyond our control and are discussed in more detail in the Risk Factors and the Forward-looking Statement sections of our annual report and quarterly filings with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially, and we are under no obligation to update them. We may also refer to some non-GAAP financial measures, which help facilitate comparisons across periods and with peers. For any non-GAAP measures we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release available on our website. I will now turn the call over to Bill Way.

Thank you, Paige, and good morning, everybody. Thanks for joining us today. First, I want to take this opportunity to thank our employees for a job well done during the quarter as the country and the world faces the unprecedented challenges from COVID-19. Inspired by their unwavering commitment to our core values, including health, safety and the care of our environment, our teams through their laser-sharp focus demonstrated top quartile performance, all while dealing with the uncertainty surrounding this health menace. And so to everyone on our team, I'm extremely proud of all of you, and thank you for what you're doing. The people of Southwestern Energy continue to build on our solid foundation, supported by our diverse set of Tier 1 assets that provide flexibility and ensure resiliency through rigorous capital discipline, proactive risk management, leading operational execution, ample liquidity and no looming senior note maturities. The results we achieved in this quarter give me confidence that while the road ahead may be challenging for the industry, we are on a deliberate path to sustainable long-term value creation for our shareholders. I'd like to reiterate one of our top priorities for this year, which is to complete the transition as a major Appalachia gas and liquids producer, enabling the company to invest within cash flow beginning in 2021, which is a fundamental milestone of our strategy. As we power through this challenging environment, I'm confidently telling you today that Southwestern energy remains on track. We reported second quarter operationing results above expectations with total equivalent production, largely unaffected by market conditions. We demonstrated the company's agility and resilience by shifting our drilling and completion activities to stay 1 step ahead of the risks and uncertainties associated with the significant demand destruction, which began to take hold across the country. Specifically, in the quarter, our teams took action to relocate one of our company-owned rigs to a dry gas location in Pennsylvania. As a testament of their agility and flexibility inherent in the operations, the drilling rig was moved to the location rigged up and ready to drill in approximately 1 week following the decision. This type of agility is a differentiator in our industry as few operators can make this type of move without increasing costs. 2 additional rigs began drilling in high-rate, high-volume natural gas locations during the quarter as well. Our drive to top quartile performance among our peers, a major plank in our business strategy was again highlighted by our broad-based cost elimination with full year permanent cost savings across all expense categories, now totaling $90 million. This adds to the $122 million we reduced last year. On the capital cost side, we announced additional well-cost reductions, including a record single well cost of $505 per foot. Of course, given this record, we now have a new target to take aim at and beat going forward. We expect to average 2020 well cost well below our original guidance, and Clay will talk more about that in a moment. For the second quarter, the company reported total equivalent production in line with guidance. And as expected, we had lower liquids volumes offset by higher gas volumes due to changes in activity. Moving on to full year guidance. As a part of yesterday's release, we issued revised guidance with an improvement in cost metrics associated with the cost reductions I mentioned earlier and reflecting the shift in activity, which will rebalance the components of production and activity. As a result, we will have higher annual equivalent production and lower cost. We also lowered the top end of our capital guidance range, which is now $860 million to $915 million, and to be very clear, we will not invest more than the cash flow generated by this company in this year, supplemented by the previously announced earmarked funds from Fayetteville. In addition to the results of our broad-based cost efforts, protecting our balance sheet and liquidity remains a key priority. Our liquidity position was $1.26 billion on June 30. During the second quarter, we further strengthened our balance sheet with open market purchases of senior notes at deep discount and reducing our outstanding letters of credit as well. This strong liquidity position, coupled with our leading maturity runway, remains a critical differentiator with only a small amount of senior notes due before 2025. Now I'd like to address the proactive risk management steps we've taken through our dynamic hedging program. Hedging has been a core part of our strategy since 2016 and is an important risk mitigant to operating in a volatile commodity environment. Our 3-year rolling hedge program utilizes various instruments to hedge our production within a pre-agreed ranges depending on market conditions across several commodities. This year, as an example, we have swaps in place for about 80% of our natural gas production. The fundamentals for natural gas for next year are more constructive, so we've layered on more collars for natural gas, which will allow upside in a higher price environment, while still providing the downside protection. We entered this year approximately 100% hedged on our oil production and expect to benefit from those hedges throughout the year. While delivering from a financial and operating perspective, we also are doing our part to mitigate climate change and promote clean energy future with 80% of our production coming from natural gas. Southwestern Energy remains an industry leader in reducing greenhouse gas emissions, with a 10% reduction in our overall GHG emissions intensity compared to 2018, achieving top quartile performance among peer companies. We are particularly focused on reducing methane emissions, and we have leak detection equipment on every well and consistent with -- among the lowest methane emissions due to our voluntary emissions reduction effort that began several years ago. We are finalizing the update of our annual corporate responsibility report, and it will be issued in the third quarter. Southwestern Energy has managed through a lot of adversity and has built resilience around our commodity mix, with balance sheet protection and operational flexibility as key components. We're a company of disciplined risk management through our hedging program, financial strength with a leading maturity profile, substantial operating flexibility and leading operational execution, rigorous capital discipline and a rightsized transportation portfolio, along with a low-cost structure. Our strategy is to grow differentiated and sustainable shareholder value through returns-driven investment and consistent operational outperformance from our leading high-quality, concentrated and large-scale assets. I'll now turn the call over to Clay to provide some details from the quarter.

Thanks, Bill. Operationally, our teams continue to focus on delivering above-target outcomes through technical enhancements, operational execution, commercial flexibility and efficiency gains. The result was another good quarter that included shifting investment activities to high-rate, high-volume gas wells, reducing capital and expense costs and continuing to protect our employees and contractors during the pandemic. I'll start with a few highlights from the quarter. Total production was 201 Bcfe, up 8% from second quarter of 2019. Gas production was 158 Bcf and at the high end of guidance, representing 79% of total production. Oil and NGL production were roughly 12,000 barrels per day and 67,000 barrels per day, respectively, both slightly below the low end of original guidance, but in line with expectations as we managed activity across our portfolio to mitigate the potential curtailment risk that existed at the time. In the quarter, we averaged 5 rigs and 4 frac crews with capital investment totaling $245 million. We drilled 30 wells, completed 31 wells and brought 31 wells to sales this quarter with 11 in Northeast Appalachia and 20 in Southwest Appalachia. Approximately 80% of the wells drilled this quarter were located in our dry gas Northeast Appalachia and rich gas Southwest Appalachia areas, consistent with our shift to high-rate, high-volume natural gas wells. In Northeast Appalachia, 8 wells were online for at least 30 days, 6 lower Marcellus wells with an average 30-day rate of 14.8 million cubic feet per day. They represent a different well mix compared to the first quarter, where the majority of the wells were located in our higher initial rate Tioga area. The additional 2 wells were Upper Marcellus test wells and had an average 30-day rate of 8.3 million cubic feet per day. The wells tested landing zone and completion designs in the Greenzweig field and have performed in line with expectations. One of the test wells was a 6,000-foot lateral compared to the previous test that averaged approximately 9,000 feet. In Southwest Appalachia, 6 rich wells had an average 30-day rate of 17.2 million cubic feet equivalent per day and 14 super-rich wells had an average 30-day rate of 7.3 million cubic feet per day, including 67% liquids. We temporarily managed the initial flow rates on the super-rich condensate wells lower than normal to mitigate the risk of potential curtailment on condensate in the basin. The wells are now flowing normally and consistent with the type curve predicted performance. We continue to progress our top-tier well costs, averaging $691 per lateral foot for wells to sales this quarter and setting a new company single well record of $505 per foot on a 14,000 foot lateral in Northeast Appalachia. As a result of continued operational efficiencies, completion design optimization and additional service cost deflation, we expect wells to sales in the second half of the year to average $650 per foot with the full year averaging $690 per foot. We remain focused on driving well costs down while optimizing well performance in order to maximize returns from our capital program. As Bill mentioned earlier, we've continued to make progress on shallowing base decline through our ongoing base optimization effort. We originally guided to a base decline rate of 25% for this year, which represented a reduction from the 30% base decline in 2019. We now expect the 2020 base decline to be 23% as a result of outperformance associated with the pad compression project in Northeast Appalachia and artificial lift optimization and frac hit mitigation in Southwest Appalachia. As we look ahead to the remainder of the year, I'd like to highlight a few guidance updates we made this quarter. As a result of our shift in activity, we have reshaped our capital program to have a flatter profile across the first 3 quarters before tapering off in the fourth quarter to assure that we invest within our capital plan. Total equivalent production in the second half is unchanged with lower NGL and oil production, offset by higher natural gas production, all associated with the shift in activity that began in the second quarter. The third quarter total production will be lower, and fourth quarter total production will be higher, along with a higher exit rate than originally guided, building a strong foundation for 2021 performance. We are updating annual per unit cost guidance across all expense categories, including lease operating expense, with a new range of $0.90 to $0.94 per Mcfe representing a $0.03 per Mcfe reduction at the midpoint, which is about $25 million for the year. This reduction is primarily driven by reduced gathering and processing fees associated with contract renegotiations and reduced saltwater disposal costs. Our teams have done a great job managing through the headwinds facing our industry and delivered a solid quarter. Thank you to all those who helped deliver these results, whether at home, in the field or in the office. I'll now turn it over to Julian for the financial results.

Thank you, Clay, and good morning, everyone. In the second quarter, we reported an adjusted net loss of $1 million, EBITDA of $106 million and net cash flow of $87 million. Excluded from these amounts are a $655 million noncash impairment related to our full cost ceiling test. As discussed on our first quarter call, our test for impairments is formula driven under SEC rules using 12 months historical pricing held flat into the future for all commodities. For the second quarter calculation, the gas price was $2.07 per Mcf. COVID and the associated impact to demand put downward pressure on prices this quarter. We reported pre-hedge realized prices of $0.98 per Mcf for gas, $6.43 per barrel for NGLs and $15.69 per barrel for oil. On condensate pricing, we benefited from a relative advantage from having strategically set up portfolio with longer-term sales agreements. As we look forward for the rest of the year, we expect our full year NGL price realizations to improve to 19% to 24% of WTI as a result of the improvement in ethane and propane prices coupled with lower WTI prices. As roughly 80% of our NGL barrel is ethane and propane, we are encouraged by the recent improvement in 2020 and 2021 strip prices for those commodities and believe the fundamentals are supportive. For the third quarter, we expect gas differentials to be a discount to NYMEX in the $0.75 to $0.85 range similar to third quarter of 2029 -- 2019 before improving in the fourth quarter. We also expect our third quarter oil price to be at $11 to $12.50 per barrel discount to WTI and NGL price realizations to be 20% to 25% of WTI. With challenged commodity prices across the sector, our hedging program provided a $0.60 per Mcfe uplift, with $120 million in cash settlements for the quarter, bringing our year-to-date settlements to $213 million. For the full year of 2020, we estimate our cash settlements related to our current hedges to be approximately $400 million based on current strip prices. As Bill explained earlier, we actively manage our hedge portfolio using a variety of instruments to protect our commodities from downside risk, while also allowing the opportunity to capture upside. We share many of the fundamental analysts' bullish sentiment for natural gas prices in 2021, as reflected by our use of collars to preserve some exposure to price improvements. Cost management is a focus, not a onetime initiative for us. We continue to pursue efficiencies to improve our returns as repeatedly demonstrated over the past few years. Following the $122 million of reductions last year, our current year expense reductions totaled $90 million, of which approximately 60% is G&A. Clay mentioned the reduced LOE range earlier, and we have also lowered our guidance ranges for G&A, taxes other than income and interest expense. Another key focus of active management is our balance sheet, where we took actions this quarter to boost liquidity. We reported a leverage ratio of 3.1x with $2.1 billion of senior notes outstanding and $336 million borrowed under our $1.8 billion credit facility. We repurchased an additional $27 million of discounted senior notes, bringing our total repurchases to $107 million at an average 33% discount. We also negotiated to use surety bonds as credit assurance, decreasing outstanding letters of credit by $113 million since April. This not only enhances our liquidity, but also decreases our interest expense. We ended the quarter with $1.26 billion of undrawn commitments under our revolving credit which positions us with ample liquidity, especially considering we only have $207 million in senior note maturities before 2025. We are deliberately and consistently optimizing what is in our control, both operationally and financially to position the company to deliver on our goals of free cash flow, sustainable 2x leverage and the delivery of long-term value for shareholders. This concludes our prepared remarks. So Jamie, could you please open the line for questions?

[Operator Instructions]. And our first question today comes from Arun Jayaram from JPMorgan.

Bill, I was wondering - Bill, I was wondering if you could talk a little bit about thoughts around 2021? I think the goal was to get to free cash flow balance next year. So I was wondering if you could help us think about perhaps sustaining capital to keep either, call it, fourth quarter production, which looks to be now in that 2.5 Bcfe range? And how are your thoughts on sustaining capital are evolving given some of the lower well costs that you cited today?

Yes. I'll start by saying we have not put together or released a '21 plan, but I can give you some of the major tenets around it. First of all, yes, our plan for 2021 is able to achieve a status where we're investing only within cash flow, and we are able to hold exit rate year-on-year at a minimum. We will invest within cash flow in 2021. And as we typically do, as we progress through the year and begin to formulate that plan, we'll set a -- look at the strip, we'll look at our hedge profile, put the numbers together to generate a level of cash flow from the strip at that time and the benefits of hedges and then set a capital program from that point. I expect that, that capital program will have a balance between liquids and gas investments in West Virginia and Pennsylvania, but will be completely determined by the pricing that is in place at that time on a multiyear strip. The quantum of money that it takes to hold our production flat will continue to improve, but we'll see when the time comes, what that exact, again, capital budget is all about. Our current maintenance capital level in total for the company is about $600 million of D&C capital and we're working to try to drive that down through all kinds of efforts, both in terms of cost and in terms of either productivity improvements, efficiency improvements, et cetera, along with capital costs. And you'll see that in some of the results that we put out there. It is our intent going forward that to -- because we are returning to investing within cash flow, you'll recall that we deviated from that as we monetized Fayetteville and 1/3 of our cash flow, but the successful transition and the work that we've done over the last couple of years will enable that to happen next year and beyond in terms of our plan. And again, the quantum of that and how that's distributed will be a function of pricing. Our capital budget and our entire capital program flexes up and down with capital -- with the commodity prices, and that will continue as well.

Great. That's helpful. And the next one is for Clay. Clay, on one of the peer calls earlier this morning, there's a lot of questions on the Upper Marcellus. And your peer indicated, call it, how the EORs were trending, call it, 70% of kind of the Lower Marcellus. But I just wondered if you could give us maybe some thoughts, the economics of the Lower Marcellus in terms of maybe lower D&C costs? And I guess, the importance of the successful, call it, delineation in terms of your overall inventory position?

Sure, Arun. So as we talk about consistently, we're constantly working on our existing inventory to move that resource into the proved reserves and economically viable opportunities. And we've done that with a portion of our Upper Marcellus, and we did the 3 wells last year. And then we added to that with 2 more this year. With the costs that are coming down, we similarly have in the $600 per CLAT -- low $600 per CLAT cost on these wells that they are above our hurdle rate, the ones that we are drilling. They're not as economic as our core Lower Marcellus wells. But as we keep lowering cost and optimizing the completion designs, we're continuing to enhance those economics. And so that's part of why we're continuing to bring those into the program, even though the majority of our program is the core Lower Marcellus and we're continuing to be encouraged by the results similar to these two that we did and brought online this quarter.

Our next question comes from Charles Meade from Johnson Rice.

Bill, I wanted to ask, given the way the strips look now and particularly with -- we're looking at a much better strip for natural gas in '21. Is it a fair read that this shift that you guys have made versus the way you came into '20 where you were more focused on Southwest Appalachia, is it a fair read that you guys are going to be -- this shift to more dry gas areas is a more durable one? And is it possible that -- your split right now is about 50-50, is it possible that it could shift even more in favor of Northeast Appalachia?

Yes. Our investments are returns driven and so I think that, right now, certainly on the liquid side, but even on the gas side, we're in unprecedented volatility period with all that's going on in -- with COVID and the other challenges that the oil side has faced. And I think it's -- we will look at that as we begin to shape the budget for next year, and that will be born out of the strip pricing. We typically set a budget in February, and we review it before then. But it's based off of a strip in that period both for oil, gas, NGLs, differentials, the like, and then it's influenced by our hedges and the hedges are only to figure out the cash flow and not the economics, the hedges of sure economics, but the -- I think you're going to be balancing back and forth. We were a 60-40 in the beginning of the year-ish, we moved to 50-50 as prices move around. It's totally driven by our view on pricing. There's the depth of the inventory, the quality of inventory, the ability to access the inventory. And all of the infrastructure that, that entails is all there, and it's economic decision. So we are primarily a gas company, as you know, 80% of our production is comes from that. So we'll either be in -- if you get really strong condensate and oil prices recoveries, you could be in super-rich acreage. If you're in high rate, high gas, you have the choice between high-rate, high-volume NGL, light and gas, like what we call our rich gas or dry gas in Pennsylvania and economics will dictate that. The certainty is or near certainty, I'll put it, is that we'll be investing in all areas. So I think that you'll see us accessing our inventory in both rich, lean and -- or super-rich, rich, and dry.

Bill, that's helpful insight in your thinking. And then if I could -- this may be for you, Bill, or perhaps for Clay. I looked at -- the way it seems to me when I look at your guidance versus what you had earlier, particularly for wells that you're drilling completed. It seems to me that the efficiency that you guys are driving in your system, you're drilling more wells, but you're not placing more wells or you're not -- you haven't had a big shift in the number of wells you're placing on in '20. And that makes me think that maybe '21 is going to play out a little differently than in the past. And that you guys might be -- have a tailwind early in '21. Is that a fair read on how you're kind of, I guess, deploying your -- how you're reaping the gains from your efficiencies and what the year-end and early next year looks like?

As our expectation and as we -- when we look at either, whether it's cost improvements, well improvements, productivity improvements, decline rate improvements, every one of those is -- our focus on them is to make them sustainable and go followthrough year on year-on-year. So we believe that the benefits to the economics and the program that have been derived this year and in previous years translate into a better position to start in '21.

Yes, I'll add. Like I said in the script, we're going to have a higher exit rate going into '21, which will benefit, and we're going to have greater number of DUCs that we updated in the guidance going into '21. So I think that's all very consistent with your comment.

And just to sub-note, we don't manage DUC inventory to opportunistically play in the market, can't guess the prices. And so that's something very wise. Our DUC inventory flexes with activity, and it's all about efficiency and optimization in that space, so I think we're in a pretty good spot.

Your next question comes from Kashy Harrison from Simmons Energy.

So sticking with -- I wanted to go back a little bit to the earlier maintenance CapEx question that we all love to ask. I know you don't have an updated estimate relative to what was provided last quarter, but I was wondering if you could maybe walk us through some of the inputs that went into that number, just to help us think through where those estimates will be headed? Specifically, were those maintenance estimates based on the $700 -- $730 per foot? Were those estimates based on the 25% base declines? Just some sort of metrics around that so we can maybe hone in on where we're headed moving forward?

Sure. So we think of our maintenance capital on a December exit to December exit. As you mentioned, the starting point number was based on all our budget assumptions. We've had improvement in those assumptions. We've had an activity shift in the middle of all that, that needed a little bit of time for the curtailment situation to resolve itself and then move into gas. So there's moving parts in all of that. When you think about it on a snapshot, all those things to me, probably lean us to the better part on the lower end, below $600 million. But then as you look at the definition, which is exit to exit, we're going to have a higher exit as we come to the end of the year. And so I think $600 million is a good number as we keep thinking about year-over-year. But things that we do that cause improvements directionally should be benefiting that number.

Got it. Got it. That's helpful. And then maybe a question surrounding capital allocation once you get to your exit rate. In the past, you've talked about either spending within cash flow or maintenance once you get to the end of 2020. And so should we take that to mean that once you get to your $2.5 Bs exit rate that maintenance CapEx is the ceiling moving forward as it pertains to capital spending, while discretionary cash flow is the floor, depending on the pricing environment? Or should we be thinking about if we saw $3, $3.50 next year, whatever the price may be, that you would still be investing 100% of discretionary cash flow? Just trying to think about how you guys are thinking about spending as a percentage of cash flow moving forward?

Yes. I think the detail of exactly where that will land will be part of our '21 guidance, but what I can tell you from a framework of thinking. First of all, we will invest within the cash flow. It will be against strip pricing at the time, and it will be flexed up and down depending on what's happening with commodity prices. And the -- and so that's the mechanics of how we'll do it. To kind of pick on one part of your question, if we set that plan, and then there's some sudden surge of gas pricing, and if you look at the strip, there's a little period of time where there's an increase in gas pricing but then it tends to fall back off, we're not going to invest against that. We'll take that money and that extra cash flow and use it to pay down debt or what other practice makes sense. I think the key here is, our goal is to get to where we are generating free cash flow. That's been a stated goal all along. And so that goal remains along with our leverage ratio and along with our mandate -- self-imposed mandate that we will -- all of our capital allocation is driven by returns. And so where we can make a return that exceeds our target, we will focus on that. If we can't make a return because pricing has moved against us or whatever, then we pull back. And so it's a quantum of capital, but the major mandate override is, the returns are what drives those decisions.

That's helpful. And if I could maybe sneak just one more in, a quick modeling question for Julian. If you were to look at the forward strip in 2021, specifically for ethane and propane and looking at it for oil, I was just wondering if you could give us a ballpark of where -- at the fourth strip today where you would expect those NGL realizations to come in? It's just one to those more opaque markets that's hard to pin down, so I was wondering if you could maybe just help us on NGL realizations as you look at 2021?

I'm going to let Jason have go at that.

Yes. I think really, with the volatility that's out there in the market right now with crude and the relationship between crude and NGLs moving around and being as volatile as what it has been. I think as we look at 2021, we'll just have to wait until we get closer to the period when we build our budget and see how it's shaping up then. But what I can tell you is just based on what we're seeing now with the new infrastructure that went in place in the Northeast Mariner East 2, the volatility that we have experienced in the differentials prior to 2019, that's not there anymore. And so things should be a lot less volatile as we look out into the future on the differentials on our NGLs

Our next question comes from Holly Stewart from Scotia Howard Weil.

Maybe just the first one, sort of thinking about the 2020 and 2021 activity set. It looks like you averaged 6 rigs in 1Q, 5 in 2Q and now running about 2 rigs. So I guess the question would be, where do you expect to exit 3Q and the year? And then I have a follow-up on '21.

Sure. We should exit 2Q -- or 3Q, sorry, with about 2 rigs running and 1 frac fleet consistently, but there might be a second one in there in the early part.

Okay. And then the year, Clay?

Sorry, average for the full year, is that what you're asking?

The exit for the year?

So if you're talking about from an activity standpoint, as we get into December, we'll come into December with 1 frac fleet running and 2 rigs running, and then we'll want to position for our New Year budget in '21 and we'll potentially start to move in rigs into December preparing for the new year.

Okay. And I guess that was sort of my follow-on would be, as you think about positioning for that free cash flow program in '21, how does the activity set really shift as you enter the new year?

Well, by the time we get towards the end of the year, we will know what -- we will be pretty close to knowing what our '21 program will be. And I think, as Clay mentioned, around the year-end, beginning to plan and execute for the following year, the level of activity that's approved in that plan will drive the amount of activity in December that is done, so that we're up and running and getting after it right away in January. So they're tied together. If the program is -- if you look at the cadence of the program, front-end loaded, light loaded in the back, brings greater value and all the reasons why we do that. And it will be dependent completely on the amount of the budget and the timing of that. So same kind of thing that we traditionally did.

Our next question comes from Jeffrey Campbell from Tuohy Brothers.

My first question is regarding the self-funding next year. Just wondered if you had a leverage range in mind for 2021 or over the next couple of years, if you prefer?

Yes. So as we project forward, we actually see leverage this year peaks up, fourth quarter being our highest level and then it starts coming back down as we go through next year. We've said on a longer-term basis, we want to get to 2x. That is going to take some time. But that still remains an objective, so you should see it stepping down next year.

Okay. And just to quickly follow-up. Is the drop next year or at least early in the year, is that basically predicated on an assumption for more EBITDA because of better pricing?

Yes. It's just as you run through the economics, the pricing, the volumes. And we can see that being three or even below.

Okay. Yes, that's helpful. And I just wanted to ask what you guys think about effects from the cancellation of the Atlantic Coast pipeline and the likely completion of the Mountain Valley pipeline? I've been listening to some other people talking about this and kind of thinking about regional supply demand, maybe a regional basis and even firm transportation?

Yes. So this is Jason. So I think when we think about ACP, I think near term, we don't really expect that much of an impact. There's open capacity out of the basin. We think that -- maybe there was probably -- based on where the differentials are, there was some consensus that it could potentially get canceled. I think really longer term on the basin, in general, it really depends on what the ultimate production levels, where they end up as well as the timing around Mountain Valley. And then right now, there's a pretty strong secondary market out there for transportation out of the Southwest Appalachia region. And then we're not a shipper on MVP, but based on what we're hearing from people in the industry, it looks like it's sometime in that early Q1 2021 could be the pitch 1 service date for Mountain Valley.

Our next question comes from Noel Parks from Coker & Palmer.

On the service cost front, I was wondering, we've continued to see improvements in vendor costs. And for -- on the frac side, how long a horizon are your vendor is willing to give you current pricing levels? Is that something that they're willing to commit to through the end of the year? Or are they willing to even give you that pricing into a longer-term contract, say, into next year?

Yes. So as you know, we operate a full frac fleet ourselves. And as we've talked about in the past, it results in a really good working relationship with the other pumping service providers that we supplement over and above the one that we have. There's a lot of insight on our part, and they know with what true costs are from our own operation. And so we start in a really good spot in what our negotiated service rates are around pumping. We've got a long-term relationship with the main provider that has been very good. Our costs are negotiated and are with us throughout the year. We update those annually. And so we feel very comfortable with the cost structure that we have. There have been some reductions due to incremental deflation as we've moved through the year, and then we will rebid all of that as we move into the start of 2021. But we have maintained a very low-cost structure, and we benefit by the fact that we also do all this ourselves.

Okay. Great. And to the degree, you received inbound calls from folks, just checking to see if you might consider adding external crew. Are you -- is the pricing still kind of on a downward trend continuing even further from where we started the year and now a little bit past midyear? Or are they more just looking to put capacity to work and -- but not willing to be more aggressive on price than they have been so far?

Yes. There's definitely been a reduction in the first half of the year. They're definitely wanting to be able to put crews to work. I think there's been some documentation out there around frac fleets starting to pick up as we move through the third and into the fourth quarter to where I wouldn't expect significant further reductions in the back half of this year. I think they've pushed their costs pretty low on where they sit right now.

Our next question comes from Scott Hanold from RBC Capital Markets.

I'm curious on, Julian, your comments on the long-term goal of 2x leverage. I know that's something you all have targeted before and you are chipping away at it, obviously, taking out some debt below par and, obviously, with forward outlook. But big picture, how long do you think it will take to achieve that goal? And would you guys evaluate something inorganic to get there sooner?

Well, so I think that it really depends on a number of things. As you know, prices have a major impact, both on our cash flow. If we have excess cash flow and we're accomplishing all we need on the operational side, then you can start looking at using that cash flow to also reduce the absolute level of debt. So it is very price dependent, performance dependent, as to what we will do organically. And as I said, we have a good line of sight for next year at an improving leverage ratio from where we will sit at the end of the year. But 2x is further longer-term site. As far as, therefore, would we do something from an inorganic nature? I assume you mean acquisitions or some type of activity like that and we've always said that we will look at opportunities. I think Bill has always talked about looking at opportunities. We believe that there's benefit to greater scale consolidation. But we do that with our key goals in sight. So it has to be accretive to cash flow, and it has to be accretive to our balance sheet and to the leverage. So yes, if there's something out there that is inorganic and it helps the cause to advancing those 2 objectives, it's in consideration.

I appreciate that. And just maybe on that point, I mean, is there stuff out there right now considering what's the volatility we've seen in the first half of the year in commodity prices, are you seeing things on the consolidation front improve? Are there things that fits the bill out there or is there still some room that needs to be tightened?

Scott, we've looked across the areas where we work and beyond and we've -- there's a lot of interesting things out there. I think there's a number of dynamics at play, some of which are companies involved in spending a lot of time on self-help activity rather than thinking about building scale and growing greater value or taking cost out of the business for the industry. And so it's a pretty volatile time and so some of those businesses are quite involved in other activities. But there's a lot of interesting things out there, and we'll continue to work that. We believe in consolidation and the benefits of it. And as we've said many times and as you would expect, when we're trying to sell something, we'll tell everybody about it. When we're trying to look at consolidation opportunities or whatever, we'll keep that to ourselves till it's done.

I appreciate that. I understand. And Clay, real quickly, you talked about reducing that maintenance base decline rates. And can -- there are several efforts you spoke about, but when you look at the capital that's put in and the cost put in to make those base decline reductions, do you have a sense of what kind of rate of return that provides to Southwestern? So I'm just trying to get a sense of, like, capital for that versus capital to, say, drill another well?

Yes. It's the best return opportunities that we have. They're the quicker payout types of projects, the compression project, very good economics that we started in Northeast Appalachia, and we continue on. And that project was the main driver of lowering the base decline that we came into the year with when we went from around 30% or high 20s to 25% this year, and then now that continues to perform well. We're getting a further benefit in our Southwest Appalachia assets around the artificial lift optimization, frac hit mitigation, those things. Where our teams consistent with the focus on lowering cost, capital expense, it's all about optimizing the well performance and they always end up be in those projects are the most economic things we can do.

Our next question comes from Brian Singer from Goldman Sachs.

I wanted to go back to a couple of popular topics. The first is really talking about the leverage and free cash flow goals. And maybe it is the benefit of not having much of the debt coming due over the next couple of years, but I just wanted to really better understand that are you essentially planning to stay within cash flow at strip type prices next year? Or does the need to bring leverage down over time warrant a free cash flow-focused strategy where you would be spending less than cash flow?

Yes. I think we've said, Brian, that we will live certainly and invest within our cash flow, again, price dependent. So we would love to be generating excess cash flow. We do have a certain amount of activity that you have to be able to get done in order to sustain the production levels and, therefore, sort of protect the leverage that way. We do look to reduce absolute debt level. If we're living within cash flow, it's not going to go up, right? It's going to be flat at worst. And then we would look to reduce it. You've seen us do things previously where we go out and buy bonds at a discount and that is chiseling away at it. But I think to get to our overall objective, it will be a combination of reduction in absolute debt and growth in cash flow.

And let me underscore something on for the call because I'm hearing this maybe being defined out there a little differently than we intend. My statement of investing within cash flow means we will not invest $1 pass the cash flow that we generate. That doesn't mean we'll use all the cash flow for investing. And I think that's the question and it's entirely dependent on commodity price, basis price, our ability to continue to drive cost out, all of those things. But it means that we will not outspend our cash flow. And again, if circumstances are right, we'll under -- we'll invest less than our cash flow and we have the opportunity to do exactly what Julian is talking about.

And then my follow-up is with regards to the maintenance capital and really trying to put that into context with the activity levels that we should expect and the CapEx levels we should expect in the second half of this year. I think you had talked earlier about the fourth quarter being really more at a seasonal low from an activity perspective, CapEx is normally front-end loaded. It would seem like the maintenance capital levels that you're projecting would be at or below where your fourth quarter would end up and maybe I'm lost in that a little bit. But can you just kind of talk about what we should expect for how maintenance activity would look like relative to what we will see from the company in Q4 and the second half?

Yes. As we talked about, the capital will come off in 4Q, we're flattish. The first, second and third quarter, we're going to see our highest production for the year in the fourth quarter and that's driven by, as you know, the lag in the capital activity where the production shows up later, but also more so this year because of the shift in activities that we did in the second quarter and that a lot of that is high rate gas, that then is online for the full quarter in the fourth quarter, and so we're going to see a nice uplift there as we come into 2021.

Got it. And that would render the fourth quarter CapEx run rate to essentially -- which would be a low for this year, but essentially be a fair maintenance capital of $150 million or so per quarter on a going-forward basis?

I think plus or minus, that's about right.

And our next question is a follow-up from Holly Stewart from Scotia Howard Weil.

Just a follow-up on the well cost. I know you guys have renewed your well cost guidance lowering it. Any commentary on just an ultimate well cost target that we could see?

Well, as Bill mentioned in his script, every time we set a new record, that's his new bar. So it will continue that we will be driving towards continuing to be as efficient as we can be there. Now our #1 goal is to maximize the value from the type curve coupled with the capital that we spend on them. But we've been able, our teams have done a great job through efficiencies, through ongoing completion optimization, where we're continuing to elevate performance, but costs keep coming down. So we will keep shooting for records and then keep driving that average closer to those.

So Clay, 500, here we come?

Don't put a time frame on that, but that's directionally what we're talking about, yes.

And ladies and gentlemen, with that, we'll conclude today's question-and-answer session. I'd like to turn the conference call back over to Mr. Way for any closing remarks.

Well, I'll just simply recap the quarter. If there was any time that demonstrated the resiliency of our asset portfolio, that demonstrated the agility and preparedness of our teams in the face of challenges and the quality of execution, it's now. But we also realized we just crossed through half time, the year is not done. So we have more to do in the second half, and we're pretty excited about some of the achievements that we will deliver as we power into this second half period. So until then, my sincere thanks to everybody at Southwestern Energy, who has contributed to all these results and greatly appreciate that. And then to all of you who continue to be interested in our company, to everybody, stay healthy, be safe and enjoy your weekend. And thanks for being here.

Ladies and gentlemen, with that, we'll conclude today's conference call. We do thank you for joining. You may now disconnect your lines.