Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the Southwest Energy First Quarter 2020 Earnings Call. Management will open up the call for a question-and-answer session following prepared remarks. In the interest of time, please limit yourself to two questions and requeue for additional questions. This call is being recorded. [Operator Instructions] I will now turn the call over to Paige Penchas, Southwest Energy’s Vice President of Investor Relations. You may begin.

Thank you, Drew. Good morning, and welcome to Southwestern Energy’s first 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 filed 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 about our business plans, 2020 guidance and the potential impact of COVID-19 pandemic on our business. These statements are often identified using words such as anticipate, expect, plan, project, forecast, model, will, could, should, and others noted in the forward-looking statement sections of our annual and quarterly filings with the Securities and Exchange Commission. Forward-looking statements inherently involve risks and uncertainties affecting outcomes. Many of these are beyond our control and only reflect our view as of today. We discuss in more detail in the Risk Factors and the forward-looking statements section in our annual report and quarterly filings with the SEC. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results and developments may differ materially and we are now 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’ll now turn the call over to Bill Way.

Thank you, Paige. Thank you all for joining us today. I hope everyone is safe and well as we manage through the impacts of this COVID-19 crisis. First, I want to extend my profound and heartfelt thanks to every Southwestern Energy employee for your ongoing efforts to stay healthy and safe amid these unprecedented times. We’re proud to be part of the critical infrastructure industry, providing an essential energy to our nation. And I want to shout out to our field employees who are on the frontlines everyday. Your dedication and hard work have made an exceptional impact on our company. You’ve kept us running and largely responsible for the solid first quarter results we’re going to talk about today. So thank you. I’ve never been more proud and more thankful to have you on the team, and we very much appreciate all that you do. It’s part of our culture at Southwestern Energy to support the communities where we work and live. Along with the company’s financial support, we’ve seen countless examples of our employees stepping up to extend support to charitable organizations and first responders in a time when our communities need it most. I want to extend my further appreciation to all of our employees for your kind hearts and generosity in these extraordinary times. In the first quarter, the team delivered results that, once again, were ahead of expectations, as shown in our release last night. Clay and Julian will expand on this more in a few minutes. I’d like to focus my discussion on the developing market dynamic and where we’re headed as a company. Southwestern Energy has a solid foundation with a diverse set of Tier 1 assets that provide flexibility and ensure resiliency through rigorous capital discipline, proactive risk management, leading operational execution,…

Thanks, Bill. We have another solid quarter operationally. But as we all know, the road ahead has challenges for our industry. Continued operational outperformance further strengthens our solid foundation and we believe we are well-positioned to manage through the uncertainties associated with the current market environment. As Bill mentioned, during the COVID-19 pandemic, the energy industry is deemed an essential business and we are taking the necessary steps to ensure the continued safety of our people, all while maintaining efficient operations during this unprecedented time, and they have done this without missing a beat. I’d like to thank all of those that contribute to the continued success of our operations, especially those working in the field. I’ll start with a few highlights from the quarter. Total production was 201 Bcfe, up 10% from first quarter 2019 and at the high-end of guidance. This was primarily driven by well outperformance and operational efficiencies. Gas production represented approximately 80% of total production, with liquids contributing 82,700 barrels per day, a 17% increase. In the first quarter, consistent with our front-end loaded plan, we averaged six rigs and three frac crews. Capital investment for the quarter was $237 million, down 27% year-over-year, in line with the capital reduction announced at year-end. As a result of the continued efficiencies and the further capture of deflationary gains, we now expect to exceed the $100 per lateral foot reduction to well costs and are forecasting our full-year average well costs to be $715 per lateral foot. This quarter, we brought 12 wells online, five in Northeast Appalachia and seven in Southwest Appalachia. In Northeast Appalachia, four wells had an average 30-day rate of 24 million cubic feet per day, representing a 60% increase compared to first quarter a year ago. This increase was driven by longer…

Thank you, Clay, and good morning, everyone. We reported our first quarter results yesterday, which included two non-cash adjustments, a $408 million tax valuation allowance and a $1.48 billion ceiling test impairment. As a reminder, under the full cost accounting method, the calculation of the ceiling test impairment is formulaic, comparing the carrying value of our evaluated oil and gas properties to the value of our reserves calculated using the average backward-looking 12-month SEC prices for oil commodities. Excluding these items, our adjusted net income was $56 million, or $0.10 per share. Net cash flow for the quarter was $191 million, EBITDA was $206 million, and capital expenditures were $237 million. In the second quarter, we will start to see the effects of COVID-19. But much of the impact to SWN so far has been mitigated by the actions that have been taken and already described by Bill and Clay. We currently sell the vast majority of our condensate under term agreements, which has afforded us a higher degree of flow assurance and protected us from some of the recent unpredictable in monthly contract pricing. In the second quarter, we expect to sell our condensate at an average $10 to $13 per barrel discount to WTI. Additionally, 100% of our 2020 condensate production is hedged with a WTI floor price of around $54 per barrel when considering all hedging instruments, including the exposure when prices are below the sub-floor in our collars. In addition to the protection provided by our oil hedges, our hedge portfolio and risk management strategy has helped to mitigate some of the recent commodity price volatility in natural gas and NGLs. We entered 2020 with 83% of our expected gas volumes and 50% of NGL volumes protected. Since that time, we have increased our NGL position…

Yes, sir. We will now begin the question-and-answer session. [Operator Instructions] The first question comes from Arun Jayaram of JPMorgan. Please go ahead.

Good morning, Arun.

Yes. Good morning, Bill. I wanted to get some color from you on your views on sustaining CapEx as we move into a 2021 and 2022 period. I know a couple of your peers are – have shifted kind of to a sustaining CapEx mode with the hopes of generating free cash flow. So I wanted to get your thoughts on that? And I think, your exit rate guide is somewhere between 2.4 to 2.5 Bcfe a day. I wanted to get your views on what sustaining CapEx could look like, given the lower costs that you’re citing with $715 million a foot?

Yes. Maintenance capital today is about $600 million. As we look forward and we shift to a higher natural cash capital mix, we will – and on a rising price, we will continue to adhere to our mandate of investing within cash flow or at maintenance capital as we build out the budget. We haven’t completed the 2021 plan yet. But the discipline that we follow around watching the market, understanding the market, understanding the amount of hedges that we have in place at that time, and we’ve made some good progress already in 2021. Those aspects plus our cash flow and economics will drive the decisions at that time

Great. And my follow-up is just for Julian. Julian, some incoming questions on the 10-Q and some of the language around the net leverage ratio covenant under the credit facility. I was wondering if you could provide some color around that and actions you can take to remain in compliance with that covenant?

Sure. And so let me frame that up. I mean, at this time, we don’t actually anticipate exceeding the debt covenant level of four times. The language in the 10-Q was really precautionary, given all of the COVID-19 uncertainties that the entire market faces and not linked to any single specific concern at SWN. Clearly, the leverage ratio is impacted by commodity prices. And we’ve actually seen some strengthening in the nat gas and NGLs over the last couple of weeks. As we look out at all forecast, we do show the leverage to increase from the current 2.7 times, but we are also showing it improving back to near three times as we enter into 2021. We have always said that free cash flow and leverage are two key pillars in our strategy, and that remains the case. And we do have levers available to us, and adjustments that we can make within the business plan that we can continue to utilize to the benefit of these.

Okay. Julian, I’m going to sneak one more in. We’ve seen a couple of your peers go to the unsecured market with converts. Obviously, you don’t have any near-term debt maturities. But how are you thinking about just capital markets, in general, given the improvement in the equity value?

Yes. I mean, I think you’re right. And probably, the convert market seems to have opened up in the last couple of weeks and people have taken advantage of that window. We – as you know, we don’t have maturities that are looming at this point. Clearly, doing a convert doesn’t change the leverage picture, it just pushes out the maturities. And so, less applicable for us. The strengthening equity price, that’s got to be a positive long-term for the capital market alternatives.

Great. Thanks a lot.

The next question comes from Welles Fitzpatrick of SunTrust. Please go ahead.

Hey, good morning.

Good morning.

Given the Contango, it seems like a pretty short-lived problem. But the 3,200 barrels a day you mentioned of condensate in the queue, how much longer do you think that could flow into storage? And if those wells actually needed to be shut in, how much associated gas would have to go with them?

Yes. So that situation, although minimal, even in the beginning, has continued to improve. That was a back-half of April curtailment. It ended up being less than 1,000 barrels a day net on April. And as we moved into May, we don’t have anything curtailed or shut in.

Okay, great. That’s wonderful to hear. And then, as you talk about moving to the gassier portions of your acreage, is that more to the East and West Virginia? Or is that more of a refocus in Northeastern PA, or still kind of undecided?

It’s both of those two high-rate dry gas areas. Consistent with our portfolio, we’ve always had that optionality. We’ve continued to develop in the dry gas, where we have high-rate Tier 1 acreage. We have continued to lately put more development in that rich gas area in Marshall and Wetzel County. And those recent wells, including the record that both Bill and I spoke off in the script, our wells in that area where we’ve continued to utilize our latest generation completion designs, and we’re seeing really nice improvement in the performance there.

And the definition of liquids in those West Virginia wells is primarily NGL. So that pricing has come back as well, so.

Perfect, perfect. Thank you all so much.

You bet.

The next question comes from Charles Meade of Johnson Rice. Please go ahead.

Good morning, Bill to you and your whole team there. I want to pick up on some of the things that that Welles just asked about. Tell me, do you have any – or have you been drilling any of your dry gas acreage down in your Southwest App or West Virginia position over the last couple of years? And what I’m really curious about is, if there is any on – if there’s any kind of productivity per lateral foot uptick or downtick, because it would seem to me that given with current NGL prices, you’d want to be as dry as possible. So can you talk about the productivity grading? [ph]

Yes, certainly. Yes, do keep in mind, as we think about where we are drilling gas wells, we have gas wells in West Virginia and we have ample of gas wells in Pennsylvania. So part of this shift is moving from state-to-state, part of this shift is moving from condensate rich wells to dry gas well, so economics drive those decisions. So as we prioritize pivot and shift, we work on the highest value generating projects, given strip pricing. So the focus for natural gas was Pennsylvania in the first instance, and then we had wells in progress and testing in our NGL, what we call rich gas, the area that does not have as much condensate, and so we went there. We have tests and have studied the broader part of our acreage And like anything, you focus on the very best and really develop that and you continue to test the other areas. And so we’ve got some tests. Clay can give you some details on it. But right now, with the inventory that we have and the focus that we have on highest best economics, we’re really focused on those two current development areas.

Yes. The only thing I’ll add is just, as we watch commodity prices, we got over 1,000 dry gas Utica locations in West Virginia also…

Exactly.

…that would be additive in addition to all the Marcellus ones that we have.

Yes. That’s interesting. I hadn’t thought about that. Thank you for that. Clay. And then the second question is perhaps for Julian. On the senior debt buyback that guys – debt buyback that you guys did, clearly, that was a good trade. You guys got it at 36% discount and it’s just trading for a lot significantly more than that today. But can you give us a broader framework for how you approach that decision when the opportunity presents itself? And whether that use of funds is kind of matched up against your D&C, or is it at a different bucket with a different decision process?

Yes. And so, obviously, the market did give some opportunities. We’re always looking, Charles, at what opportunities are out there. As it pertains to those buybacks and we had a – have a strong liquidity position. And this was a chance to chisel away at the absolute debt levels, and thereby reduced leverage in an efficient manner. Capital allocation is something we consider and consider all different places, where the capital can go to work. In this particular case, I mean, in a way, you’re using some of the debt or the availability under the revolver to take out those the data discounts. As far as the D&C, remember, when we have the goal of getting back to free cash flow, there are minimum levels of activity we have to have in order to be able to accomplish that. So, we balanced that as well.

Got it. Got it. Thank you, Julian.

The next question comes from Scott Hanold of RBC Capital Markets. Please go ahead.

Yes. Good morning. Thanks. Just a little bit more color on some of the pivot from – to some of the more dry gas areas. Can you give a sense of, where are you see like those IRR shifts on the wells on the strip basis? And just at a high-level like, obviously, you pivoted to dry gas in at some point time, maybe there’s a decision to pivot back to wet gas. But what kind of sustainability in pricing or strip pricing do you need to see to continue to pivot back and forth? So what really drove this decision now to move to more dry gas?

Yes. I think it started with – we’ve always been in dry gas. And gas has been a big part of all our production and we see the fundamentals evolving and improving strip price that looks really good in 2021. And so it was the optionality in our portfolio to allow us to pivot over to more of that. Our returns in the dry gas at a – these prices and, as you look at 2021, are pushing 20%, low-20s. As we think about the optionality, as we go forward, we’ll continue to watch what all the prices do, as we get out of the phase here, where we’ve had some demand issues and we’ll be able to continue to utilize that optionality.

The kind of a way to look at it is, we don’t allocate capital by division, or by individual wells. We allocate capital on a portfolio of wells, forced ranked, racked and stacked against each other on economic value generation. So you have wet gas, you have dry gas, you have a number of different things in that portfolio. And as prices move around, the positioning of those move around. And the great part of it is, if you had a sudden change that could – that was sustainable and you wanted to shift on the fly, we can do that. We – our – we own our own rigs, so we can move them, as Clay said, we can get it done. We can do that very quickly. If there’s any other issues at hand, we can deal with those as well to capture opportunities. So it’s a flexible move. And when would we move back pricing changes and it changes the economics, again, then we can shift around. And it’s not a wholesale one or the other, it’s always both and that’s how our splits are managing.

Okay, great. And just to clarify, you said low-20% return on dry gas, some of these drier gas opportunities. What are the liquids returns, more liquids than super rich?

Yes. The super rich, I mean, it all is – it depends on the oil price and the NGL pricing. But if we are in a $35-plus oil price environments and a $10 NGL environment and a little over a $2 gas price environment, then the super rich are pushing the upper teens to 20% also.

Got it. Understood. And then in Northeast Appalachia, I mean, is there limitations in terms of infrastructure capacity to drive more activity up there?

No. We have a plenty of infrastructure. We’re able to move the product around with all – with our marketing group and all the relationships we have in place to where – that’s not a problem at all.

I appreciate it. Thank you.

The next question comes from Noel Parks of Coker & Palmer. Please go ahead.

Good morning.

Good morning.

When you talked about the Utica, just reminding us that you had over 1,000 dry gas locations out there. I was curious, where do you stand with lateral lengths in the Utica?

Lateral lengths in the Utica are – would be able to be similar to what we’re doing right now in the 12,000 – 11,000, 12,000, 13,000 foot range on average. The regulatory environment around the Utica in West Virginia is actually more amenable to the longer laterals than the Marcellus. Now we’ve caught up to that in the Marcellus with all the land work we’ve done, but lateral length is not an issue.

So that would be considerably in excess in excess of, I guess, the typical wells you build in the past there, right?

In our previous Utica wells, yes. But as you know, with our current development, we’ve gotten our lateral lengths on average to that 12,000-foot linked across the program with several much longer than that.

Sure. Let me – I – please, go ahead.

Well, I was just getting at that it’s kind of – it would be kind of a different animal for the economics of the Utica with those long laterals compared to what we historically have thought of for it.

Yes, good point. I think, yes. And then also, the progression of drilling and completion designs, et cetera, would also benefit.

Yes. And I want to underscore here to be sure, we look at this as a portfolio. We’ve got ample inventory in any of these areas, whether it’s rich gas, super rich gas, dry gas, and even Utica gas. And they get developed as time goes based off of economics and it’s prioritized the economics one against the other. So at even stronger pricing, you get even stronger kind of returns and the mix can go back and forth depending on the commodity. So this is really capturing an opportunity of a changing market. It is not – and it’s great to have the level of inventory in all different areas, so we can pick and choose. And so the sustainability of the program is quite good.

Great. Thanks. And just thinking, between lateral lengths and upgraded completions, the industry has come a long way in efficiency in past years. As we kind of go through this upswing in gas, can you kind of give some context as far as where economics have improved to so that, say, your economics at, say, $2.50 gas now. If we were to rewind back five years or more, is – are your economics today comparable to maybe what you would have gotten at, say, $3.25 back then or?

Yes. So I don’t have the exact numbers there. But clearly, like we’ve talked about as a company the way three years ago, you were in a $3.50 type of model. And with all the improvements we’ve made around well performance and lowered costs, we’ve been able to create quality economics in a $2.75, $2.50 gas price environment. So I think that’s in line with what you were asking that just the efficiencies of the business and the continuous improvement have replicated similar returns, even though we’re in a lower-cost price environment.

Great. Thanks a lot.

The next question comes from Jane Trotsenko of Stifel. Please go ahead.

Good morning, and thanks for taking my questions.

Good morning.

The first question is on letters of credit. In the earnings release, you mentioned that you posted the additional $150 million in letters of credit. I’m curious, what are those related to and what triggered that?

Sure. Yes, we did. We – so we had $172 million. We then actually got a ratings downgrade from S&P, and that triggered the need under our firm transportation to post another $150 million.

Okay, got it.

We – now the one thing to know is that is essentially all of the LCs required under our firm transportation, the existing contracts. So there’s not many more to come.

Okay, that’s perfect. And then, if you guys can talk about the capital cadence for the remainder of the year?

Yes. The capital will be a similar profile than what we’ve seen over the last couple, where the front half is where the bulk of the majority of the capital is with our front-end loaded projects, and then it drifts down in the third and in the fourth quarter and it will have a similar shape this year.

The third question, if I may. So it sounds like based on your commentary that the condensate situation seems like under control and seems like the worst is over. Is it the appropriate interpretation? So you guys are not constraining any wells right now and no constraints are expected in May and June?

Yes. So we are not constraining any wells right now. The situation wasn’t significant initially, and it has gotten better since then. So, there’s quite a bit of uncertainty with COVID and everything else right now, but we’re feeling good about the progression of that situation.

Okay, got it. Thank you so much for taking my questions.

The next question comes from Michael Hall of Heikkinen Energy Advisors. Please go ahead.

Thanks. Good morning. I appreciate the time. Just wondering if you could help bridge the gap a little bit on the well cost outlook. First quarter well costs from the release looks like around $900 a foot in Northeast and $825 in Southwest relative to the annual average you’re talking about $715. How do we get there? Like, how quickly do we get down to the $715 level? And how do you kind of bridge the gap between the two?

Yes. So it’s a similar profile to last year where we beat our target last year. The first quarter was the higher cost as we had all the ramp up the winter weather, et cetera, that increased costs in the first quarter. We had a few one and two well pads that aren’t as efficient in the first quarter, but highly economic wells. As we move forward, you should expect that trend to come down dramatically and we should be in the low-$700, as we move forward.

So like, as we move forward, meaning 2Q forward, you’re in the low-$700s, just to be clear?

Yes. Yes.

Okay. Great. That’s helpful. And then, sorry if I’ve missed this. But can you quantify or have you quantified the inventory that you would characterize as kind of this higher productivity, higher rate gas in – I guess, in both areas, the Northeast and the Southwest, but maybe if you could split them out? And then in the Southwest, like how big of an uplift from EUR per foot or IP30 per foot or whatever metric you think is most reasonable? How big of an uplift do you see in these higher rate areas relative to maybe what the standard well would have looked like otherwise?

Yes. At current strip, we’ve talked in the last few calls that we’ve got economic wells $200-plus in the dry gas Northeast area and $200 or so in the rich area of West Virginia at the current strip. When you move to $2.75 type of gas price, you’ve got close to $650 or So between those two areas. So plenty of inventory there. The production improvement we talked about in the Northeast in the script that we had a 60% improvement when we compared quarter-over-quarter in our dry gas area in the IPs. The well I talked about in the rich, it’s a greater than a 60% improvement, but it’s not different than in the third quarter I talked about a four-well pad in the rich that was also a big improvement. What you’ll see in the production history in the rich area that I’m speaking of, we haven’t been as active there when you look back a couple of three years. And now we have progressed the development there and it’s getting all the benefits of all our latest technical understanding and flow-back approaches. And so we’re seeing dramatic production rate increases there. That four-well pads doing 170 million a day. The pad before this one was a four-well pad that was doing a little over 140 million cubic feet equivalent a day.

That’s helpful. All right. I appreciate that. Thank you.

The next question comes from Jeffrey Campbell of Tuohy Brothers. Please go ahead.

Good morning.

Good morning.

I’ll apologize in advance. I missed the first couple of minutes of the call in case I’m repeating anything. But I just wanted to a little bit better understanding of the West Virginia wells that you were just talking about. Is this new inventory relative to wet gas acreage that was already being developed? Are you breaking in new areas? And also, is this dry gas production economically down the portfolio?

Yes. So the rich gas area is not a new area for us. We’ve had that acreage. We’ve been focused predominantly in the super rich high condensate for the last couple of years. But we’ve been progressing our development in this rich area. And as I’ve mentioned, the last two pads we’ve done in that – in those areas have been improved in all aspects, lower costs, longer laterals, greater rates and the economics have continued to improve in those areas also.

So it’s an area of increasing focus in the current environment. So it’s – we were focused on heavy condensate production there originally.

Yes. And if I understood the other part of your question in the dry gas area, we’ve got over 200 locations even at the current strip right now that are above our hurdle rate economics.

Okay. Thank you. There’s rightly a lot of focus on improving dry gas fundamentals. But we also see NGLs as a beneficiary to reduce unconventional oil activity. I was wondering if right now, are you proactively reducing NGL production for 2020? And what is your – if you have a view, what’s your 2021 view of the NGL front?

Yes. So I’ll start with the answer, and then I’ll let Jason comment maybe on the go-forward view. But we’re – I agree with your assessment around NGLs and with the improving gas price view. And the good news around that, these rich wells get the benefit of that improvement with the NGLs that are associated with the majority gas production. So we see some improvement there and we’re encouraged by it.

Yes. I would agree with what Clay said. Based on what we’re seeing, the forecasted declines in associated gas, given the amount of NGLs that can potentially decline as well, while you still have – as the global restart start after COVID-19, we should still continue to see strong exports in demand as we go into 2021.

So the optionality is clear for what we’re doing, and, again, as we plan, whether it’s annually, quarterly, monthly, we look at those trends. It’s not just a one day shot of those trends, and can adjust to whatever the best option from an economic perspective shows up.

Okay. Thank you. And if I could ask one last one, kind of more macro question. Building on what we were just talking about, the primary backbone of the natural gas improvements seems to be the curtailment of associated nat gas supply. Just wondering what you – I know you guys are astute modelers. So I’m wondering what you think about demand – the demand side of it in 2021 as the economic recovery from CV-19 unfolds? Thank you.

So this is Jason. I think, as we look at this – as the economy restarts, we think that, growth – the growth outlook for exports and power generation will continue to grow into 2021. There could be as much as two to three Bs a day of incremental demand in 2021. There’s definitely new new plants – new coal plants that are still going into service. And then as we get into…

Gas-fired.

…yes, gas-fired plants, switch and coal plants shutting down. And as you look out into the future 2021 and beyond, there’s ample export capacity out of the U.S., as well as incremental pipe capacity to Mexico as well. So we see an improvement for that demand in 2021 on the gas side.

Great. Thanks for answering my questions.

Thank you.

The next question comes from Holly Stewart of Scotia Robert – Howard Weil. Please go ahead.

Good morning, gentlemen, Paige.

Good morning, Holly.

Good morning.

Just one for me. And maybe this is for Julian. Julian, just based on the new capital levels that you’ve outlined, where do you expect to exit 2020 in terms of leverage? And then maybe where does your comfort level fit?

Yes. I mean, Holly, there’s a lot up in the air right now as to where prices will be. As I said earlier, we do expect it to escalate. We’ve got cases where it’s in the – probably in the mid-3s times and we’ve got cases where it pushes up against that four times. But remember, it goes, as we go through the year and then comes back down again, as we move into 2021. And there’s a lot of different levers that can be pulled with continuing to, witness price changes. We’re continuing to witness cost changes, improvements, efficiencies. So, I think, we feel that it’s escalating, but under control.

Okay. I guess, I’m trying – just trying to get – and maybe this is for Bill, but just trying to get a sense of at what point would you cut capital in order to just keep that comfort level on that debt to EBITDA covenant?

Right now, we’re guiding to a capital level that gives us an activity level that lets us manage our business towards free cash flow and getting back there over time and also controlling leverage. So the levels we’ve given, we’re comfortable with.

Okay.

And we – Holly, we – as you would know, we intentionally run a whole series of scenarios and sensitivities. And we run them to force us or force the inflection points, whatever those are to surface, so we can manage them. And so there’s numerous levers, and as you come to know us, we will deal with what we have to deal with to be – to deal with anything that whether it’s this subject or anything else to keep our objectives intact. So stay tuned.

Thank you, guys.

You bet.

And the last question will come from Brian Singer of Goldman Sachs. Please go ahead.

Thank you. I appreciate it and good morning.

Good morning, Brian.

I wanted to follow-up on a couple of the earlier questions. And the first actually goes all the way back to your question at the beginning of the call, where you were talking about maintenance CapEx, maintenance cash flow versus investing within cash flow. And I was thinking more about an upside case for natural gas, if it were back into the mid-2s, upper-2s, or even higher next year. Is your message that you would invest with cash flow, or stick at maintenance cash flow or somewhere in-between?

Our message is, we would invest within cash flow, provided that the economics of those investments meet our hurdles. And whether – and depending on where prices are that determines in our model in your model the quantum of that cash flow. And so positioning ourselves in this whole dialogue around pivoting to nat – more to natural gas on a weighted average basis versus a combination is really trying to anticipate strength that is already beginning to show up. And there’s consensus out there or our views out there that the strength that we – we’re seeing in the market is only just beginning, but we’ll evaluate that. The conversation around maintenance CapEx versus cash flow, we’ll look at the detail of that when we get to that point. But our message is invest within cash flow the maximum.

Great, thanks. And then my follow-up does go back to the leverage point and thinking about the levers to delever as you were just talking to beyond the repurchase of debt. Can you just talk philosophically to how you prioritize deleverage via free cash flow versus EBITDA growth versus asset sales versus acquisition, say, equitized – very equitized-type acquisition?

That’s the [Multiple Speakers]

…portfolio of ideas.

Hey, there’s a lot of levers, as we said. And I think clearly, we’ve always said, maintaining the strength of the balance sheet is very important to enabling us to do everything we want to accomplish with the asset portfolio we have. And so we’re very focused on that. We also recognize the importance of getting to free cash flow and being self-sustaining and living within cash flow. And those are the two pillars that we manage the business under. The rest of the things that you’ve touched on, Brian, are really kind of various levers we can pull to do that. We need to be able to get free cash flow. We need to be able to increase the EBITDA to the benefits of free cash flow and also to the benefit of leverage. We also want to reduce our absolute levels of debt over time – and whether that’s from excess free cash flow, or whether that’s from various capital market transactions that could occur. Those are all things we have to continually think about. And then as far as asset sales, those are opportunistic, right? And you look at them based upon where is the market? And is that an appropriate thing to do? And flipping it over and going for the acquisition side of things, if you can buy something that is accretive to your EBITDA at a price that’s attractive, you would do that, too. So I mean, we’re looking at all these things.

And/or consolidation. And we’ve been – we believe this industry, with all of its costs, all of the resilience required for being able to operate in any price environment consolidation makes sense. And we continue to evaluate opportunities in and around our business and beyond, and we remain committed to looking at those options as well. The portfolio of options, the portfolio of levers, and we pull many of them. They’re on the table.

Thank you very much.

You bet.

This concludes our question-and-answer session. I would like to turn the conference back over to Bill Way for any closing remarks.

Thank you all for joining us today. And I know we have hundreds of our own employees on this call as well. So thank you directly to all of you who are listening. We realize it’s a tough market out there. But we also believe and have proof points to support that we’re positioned to manage through these market challenges. And I’m delighted that we spent a good part of the question-and-answer talking about how do we capture opportunities that may be forming in our space going forward. And so that’s exactly what we’re set up to do. We’ve got an incredibly highly talented team of people who continue to innovate, continue to drive cost out, all the dialogue around the latest technology. It’s all driven and born out of the minds and the creativity of our folks. So pretty excited about that. But everyone on the call, please stay safe. Please stay healthy. It’s exciting to see the country in one form or another beginning to emerge from a very difficult time and begin to restart the incredible engine of this economy. And so we’re – we want to play our role as well. So thanks for joining us. Thanks for your questions, and you all have a great weekend.

This concludes the Southwestern Energy’s first quarter 2020 earnings call. You may now disconnect.