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QEP Resources (NYSE:QEP)
Q1 2020 Earnings Call
Apr 30, 2020, 9:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:


Operator

Greetings. And welcome to the QEP Resources first-quarter 2020 conference call. [Operator instructions] I will now turn the conference over to our host, William Kent, director of investor relations. Thank you.

You may begin.

William Kent -- Director of Investor Relations

Thank you Diego, and good morning everyone. Thank you for joining us today for the QEP Resources first-quarter 2020 results conference call. With me today on the line are Tim Cutt, president and chief executive officer; Bill Buese, chief financial officer and treasurer; Joe Redman, vice president of energy. If you've not done so already, please go to our website, qepres.com to obtain copies of our earnings release which contains tables with our financial results, along with a slide presentation with supporting materials.

In today's conference call, we will use certain non-GAAP measures including EBITDA which is referred to as adjusted EBITDA in our a release and SEC filings and free cash flow. These measures are reconciled to the most comparable GAAP measure in the earnings release and SEC filings. In addition, we'll be making numerous forward-looking statements. We remind everyone that our actual results could differ materially from our forward-looking statements for a variety of reasons, many of which will out of control.

We refer everyone to our more robust forward-looking statement disclaimer and discussion of these risk factors facing our business in our earnings release and SEC filings. With that, I'll now turn the call over to Tim.

Tim Cutt -- President and Chief Executive Officer

Thank you Will, and good morning to everybody, and thank you for joining the call today. I'll begin with an overview of the actions we've taken to address the current environment, followed by an update of our first-quarter operational performance. Since January of '19, we are focused on delivering value over volume and are holding firm to this principle through these unprecedented times. Following my update, I'll turn the call over to Bill to discuss our first-quarter financial performance and to provide an update on our liquidity position.

In mid-March, when WTI hit $35 a barrel, we announced plans to lay down one rig and suspend fracking operations in the Permian effective May 1. We also suspended refrac operations in the Williston Basin. The following week, prices continue to drop, and we immediately suspended fracking operations in the Permian and notified the second rig that it would be released. This action leaves us with one rig operating in the Permian to build the necessary DUC counts to execute the 2021 program.

A second rig located in the Williston is drilling the Disco Pad which is a lease-holding operation. This drilling program will complete operations in late May. During July, we plan to complete two of the six wells being drilled to meet our lease obligations. All other operated activities in the Williston have been suspended.

Finally, we have developed a detailed well shut in strategy that is independent of our hedge position to help lower LOE and increase EBITDA. In general, we are prepared to shut in wells once the netback price in the field is equal to the variable LOE plus the transportation expense. We have taken into account technical considerations to avoid any significant impacts to EURs and leasehold obligations to avoid loss of acreage. We have started shutting in wells and given the anticipated price environment during the next few months, we are prepared to take more significant actions, if necessary.

We have also delayed the start-up of 10 completed wells and DSU 1125 in County Line until prices improve. We ran numerous financial models to understand the impact of production curtailments on free cash flow. Given the reduction in the variable LOE and transportation expense and the improvement to hedge -- our hedge position as prices drop, free cash flow is not significantly impacted when price drops, and we shut in additional production. We recently added hedges for May through July at $30 a barrel per month a period of time that is expected to experience the most significant impact to demand.

We now have 13 million barrels hedged over the remainder of the year, at an average price of approximately $56.50. Although current operational performance may not be front of mind for most investors, I do believe that it's critically important to understand what we have been able to achieve during the first quarter to help project our ability to perform once markets begin to recover. We are very pleased with the operational performance in the quarter and are on or ahead of our original guidance in all categories. Drilling and completion operations were complete for the 25 well 0312 DSU in County Line before suspending fracking operations in the Permian.

We are very pleased with all aspects of this development project. As you can see from Slide 6 and 7 of our IR deck, QEP cumulative production rates are exceeding expectations and in most benches, significantly exceeding average peer performance. The budget curve shown on Slide 6 was based on QEP's previous experience in County Line, along with evaluating offset operating well performance. The tank is performing as expected, with the deeper benches producing oil quickly, while the shallower zones take time to dewater the tank before producing oil at type curve rates.

The significant outperformance is primarily coming from the Wolfcamp B and Spraberry C-benches. The Spraberry B-bench is performing better than expected and the Middle and Lower Spraberry wells are now hitting their expected peak rates after helping to dewater the tank. We have three wells with a 30-day average greater than 2,000 barrels a day, four additional wells with 30-day average greater than 1,500 barrels a day and 10 additional wells exceeding 1,000 barrels a day for 30 days. This positive performance is a strong affirmation of the modifications that we have made to our limited entry frac design discussed on Slide 8 of the IR deck.

Reduced cluster spacing, along with fewer and smaller perforations has resulted in a higher perforation friction and, most importantly, improved cluster efficiency. Our drilling and completions team also continues to improve on both cost and efficiency. As you can see from Slide 9 of the IR deck, our most recent wells in DSU 0312 delivered a drilled and completed cost of $500 a foot and fracked over 3,600 lateral feet per day which remains peer leading. In the Williston, we have sustained production from the first of two wells refracked in the quarter, while the second well is being drilled out and prepared for production.

We're encouraged by the results, as demonstrated on Slide 10 of the IR deck. We understand that these results might be overwhelmed by other concerns in the current market, but it is critically important for our investors to understand QEP's ability to efficiently develop our high-quality acreage position in the Midland Basin once the market comes back in balance. We have lowered the 2020 capital budget by 32%, down to $385 million. Please keep in mind that our original plan was front-end loaded, and we have deployed $180 million of capital in the first quarter.

We have significantly lowered spend during the second and third quarters and have retained flexibility to lower the fourth quarter spend further, if price recovery does not support resuming drilling and fracking operations at that time. This plan is expected to deliver more than $100 million of free cash flow in 2020 at a range of price and shut in scenarios. In summary, we have adjusted our plans to allow us to navigate through a period of low price, while continuing to generate significant free cash flow. Our recent development activity in County Line demonstrates our ability to be a low-cost developer of core acreage, while delivering outstanding well results.

We are well positioned to move through this unprecedented reduction in demand, and we look forward to things gradually returning to normal. I'll now turn the call over to Bill to discuss first-quarter financial results, along with information on our liquidity position.

Bill Buese -- Chief Financial Officer and Treasurer

Thank you Tim, and good morning everyone. Over the next few minutes, I'll provide some details on our first-quarter results and update our 2020 guidance before opening the call up for Q&A. For the first quarter of 2020, we reported net income of $367 million compared to a net loss of $110 million in the fourth quarter of 2019. Driving the net income was a $407 million unrealized gain associated with our commodity derivatives position.

At the end of the first quarter, the derivatives portfolio was a net asset of $390 million compared to a net liability of $18 million at the end of the fourth quarter. In the first quarter, we generated $173.9 million of adjusted EBITDA, a modest decrease from the $183.8 million generated in the fourth quarter of 2019 primarily driven by a decrease in equivalent production and realized prices in the first quarter compared with the fourth quarter. Combined total LOE and transportation expense was down slightly to a combined $54 million and G&A was down more than $15 million in the first quarter compared with the fourth quarter. We continue to enter into commodity derivative contracts during the quarter, and we currently hold contracts excluding basis swaps totaling 13 million barrels of oil for the remaining nine months of 2020.

The average fixed price of the remaining contracts for the year is approximately $56.50 per barrel. Please see the 10-Q for additional details on our derivative portfolio. During the first quarter, we generated net cash provided by operating activities of $151.9 million. And as expected, with our capital program being front-end loaded, reported a free cash flow outspend of $31.6 million, a $40 million improvement compared with the outspend in the first quarter of 2019.

The improvement was primarily due to an increase in realized derivative gains and decreases in LOE and G&A expense partially offset by a decrease in oil, gas and NGL sales and an increase to accrued capital expenditures. In the first quarter, we booked $165.4 million income tax receivable largely tied to the CARES Act that was passed in March of 2020. If you recall, we received a $73.9 million AMT credit refund in 2019 and had originally forecasted an additional $75 million of AMT credit refunds over the next three years including $37 million in 2020. The CARES Act allowed us to accelerate all of the remaining $75 million of AMT credit REfunds into calendar year 2020.

In addition, the CARES Act permits us to carry back our 2018 net operating loss into 2014 when we pay tax in conjunction with our midstream business sale, creating an additional $91 million AMT credit that we also expect to receive this year. In total, we now expect to receive approximately $165 million of tax refunds during the second half of 2020. With regard to our balance sheet, at the end of the first quarter, total assets were approximately $5.9 billion and total shareholders' equity was approximately $3 billion. Total gross debt was approximately $1.9 billion.

We had no borrowings outstanding under our revolving credit facility, and we had $70 million in cash. During the first quarter, we repurchased approximately $50 million in principal amount of our 2021 notes, $35 million of our '22 notes and $13 million of our '23 notes, all at discounts, reducing our outstanding gross debt by approximately $100 million to a total of $1.9 billion outstanding. Before moving on to guidance, I wanted to spend a few moments discussing our capital structure and liquidity, as shown on Slides 11 through 13 in the IR deck. Starting with our senior notes.

At March 31, we had $1.9 billion of notes outstanding with maturities ranging from March 1, 2021 to March 1, 2026, and coupons ranging from five and a quarter to 6.875%. The notes require interest to be paid semiannually are unsecured and ranked equally with all of our other existing unsecured obligations. We can redeem the notes at any time before their maturity at a redemption price based on a make whole amount plus accrued interest. The indentures that govern the notes contain customary events to default and covenants that may limit our ability to, among other things, place liens on our assets.

Our revolving credit facility which matures in September of '22, provides for loan commitments of $1.25 billion. The facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. It is important to note that the credit facility is not secured, is not subject to semiannual borrowing base redeterminations and does not prohibit our ability to utilize borrowings for the repurchase and refinancing of our senior notes. The agreement contains financial covenants that limit the amount of total debt we can incur and therefore, may limit the amount available to be drawn.

The three financial covenants are a net funded debt-to-cap ratio that may not exceed 60%, a leverage ratio under which net funded debt may not exceed 3.75 times of adjusted EBITDA and a present value coverage ratio or PV9 ratio, under which the present value of our proved reserves must exceed net funded debt by one and a half times. The present value calculation is required to be delivered to the bank group by April 1 of each year and is calculated using the prior year-end reserve report and an average commodity price deck provided by a subset of the bank group. We delivered our present value calculation to the bank group in early March, and as of April 1, the PV9 ratio is the most restrictive of the three financial covenants with respect to our ability to incur additional indebtedness, and we expect this to be the case through the remainder of 2020. The next time a present value calculation is due to be delivered to the bank group is April 1, 2021.

We are currently in compliance with all covenants under the credit agreement. On the liquidity front, we exited the first quarter with over $300 million of total liquidity made up of $70 million of cash and approximately $240 million of incremental indebtedness allowable pursuant to the PV9 covenant as defined in the credit agreement. You can find more details about our liquidity position on Slide 12 of the IR deck. We believe that the generation of free cash flow, cash on hand and the expected AMT credit refunds will be sufficient to fund our operations, capital expenditures, interest expense and repayment of the $332 million of notes due March 1, 2021, over the next 12 months.

In addition, we expect to have access to borrowings under our credit facility to address any additional liquidity needs that may arise during that time frame. On the liability management front, we continue to evaluate our options regarding our debt structure. While we don't have a specific plan to discuss today, we are closely monitoring the market and remain engaged in constructive conversations with our bank group, bondholders and other investors about their views regarding our capital structure going forward. As I discussed earlier, it is important to remember that our debt securities, both our credit facility and senior notes, are structured substantially different than the majority of our peers.

And as a result, our strategy may look different than theirs. We look forward to updating you on a plan that makes sense for all of our stakeholders on future calls. Moving on briefly to guidance. As stated in yesterday's release, given ongoing uncertainty, continued market volatility and the potential for both voluntary and involuntary curtailments over the next few months, the company's previous 2020 guidance should no longer be relied upon and further guidance aside from capital investment guidance has been suspended until further notice.

In light of market conditions, we have scaled back our capital investment program by 32% from our original 2020 guidance. Excluding acquisition and divestiture activity, the midpoint of our guidance is now approximately $385 million including capital for midstream infrastructure. The Permian Basin will be allocated approximately 75% of the total capital budget. As Tim mentioned earlier, our original plan was front-end loaded, so based on our updated guidance, we currently plan to spend approximately $200 million for the balance of the year, with the bulk of that forecasted to be spent in the fourth quarter, assuming we see the necessary price recovery.

Please see our earnings release for a few additional details on our 2020 guidance. With that, I will now turn the call back over to Tim.

Tim Cutt -- President and Chief Executive Officer

Thanks Bill, and we'll just go straight into Q&A.

Questions & Answers:


Operator

[Operator instructions] Our first question comes from Kashy Harrison with Simmons Energy. Please state your question.

Kashy Harrison -- Simmons Energy -- Analyst

Good morning and thank you for taking my question. So first one for me. I was just wondering, Tim, how much production are you currently curtailing? And Bill, I know your ability to comment on guidance is highly limited just given the uncertain market. But I was wondering if either one of you could provide a best guess on how to think about an exit rate for 2020 at the Fort strip?

Tim Cutt -- President and Chief Executive Officer

Yeah. So let me take those two questions separately. And I'll start off with the kind of talking about 2020 and then a little bit about 2021. So if you look into how we're doing, and you saw the chart we provided on DSU 0312 in the pack, that thing has really performed and builds up to about 30,000 barrels a day.

And in March, we we peaked production and plateaued at around 65,000 barrels a day net for the entire business. If you then -- outside of shut in, assume that we go on a decline which we've started to go on, we would assume, Kashy, that our exit rate will be about 45,000 barrels a day. And I'll put a little bit more color on that. So I know a lot of people are curious about what is the 32% reduction in capex due to your volumes.

If we weren't facing the shut-ins and we were providing guidance, we certainly would have expected without the shut-ins a 32% reduction in capital would have taken about 10% of our volume out for 2020. It would have been higher, but our 0312 has outperformed, and so we're going to come in a little bit higher. So then, then you have to consider shut-ins. Right now, I think we have about 3,000 barrels a day shut in.

I'll talk a little bit more in a minute. So this is going to be a little bit long answer because I think you've answered -- asked what a lot of people are curious about but we'd expect some more shut-ins going forward, and I'll go into that in a little more detail. So if you think about what does all this mean for 2021. So when we had our two year updated forecast for the reduced capital, and I've mentioned that we expected to lower production by about 10% in 2020.

I think if you assume that carries forward into 2021 with kind of a flat 2020, 2021 production, I think that's a good ballpark to be in. But of course, there's lots of caveats around that. We're assuming that if price recovers to the level where we can start fracking again in the fourth quarter, we've got that going on in November. And so we'd entered the year on an incline.

So last year, we entered the year, we were reducing through the first quarter. This year, we entered the year on an increase. But however you look at that, and however you look at the shut-ins, we think kind of a 45,000 barrel a day exit rate is pretty good. So let me now turn to the question on kind of the shut-ins because this is one of the more complex things that the entire market is wrestling with.

And as I mentioned in the prepared remarks, once the netback price is equal to the variable cost plus transportation for any particular well, we will consider shutting in that well. But we're also looking at taking into account technical considerations and also leasehold factors. For instance, we have the new wells in 0312 and the tank, they're over their bubble point. That would be an example of a well we wouldn't want to take off-line.

But it's also an example of a well that has a very, very low operating costs. And so it will be one of the last to go off anyway. We're also factoring in kind of cost to return wells to production after extended shut in periods. And so if you wrap all that together, and you sell at $15 oil price and netbacks ranging from $3 to $10 a barrel depending on the specific field differentials, we think that a $15 same price we'd anticipate selling it about 20% of our total production.

Majority of that coming from the Williston with about 50% of the Williston shut in. I'll finish by kind of telling you that May is a bit of an anomaly. And so we're just looking at this on an individual well basis, and we've sold the physical barrels for May. And so if we have to replace every shut in, and we have to satisfy our contracts, we have to pay a fee which could be up to $8 to $10 a barrel to satisfy those contracts.

So in May, we have to consider that, so we would not anticipate at this point having a significant shut-ins in May. But as we get toward June, price stays where it is, differentials hopefully come in a little bit, the roll comes in a little bit, and we're able to sustain production, then we're prepared to shut in, if not. So that was a really long answer, but I think it gives you -- I guess, a number of the folks on the phone an answer to I think questions on people's minds.

Kashy Harrison -- Simmons Energy -- Analyst

That's very helpful. And I'm assuming when you talk about that 45,000 barrels a day exit rate, you're assuming some of the production that gets shut in, does that -- does some of that production comes back? Is that the assumption there?

Tim Cutt -- President and Chief Executive Officer

Yes. I assume all of it comes back. If we -- it doesn't take a lot of movement where our wells on the calculation I mentioned are delivering good EBITDA. And so if we -- if you look at Fort strip, it's oscillating in the mid-20s, the mid-30s as in the fourth quarter.

And we would anticipate being in good shape to be bringing those wells back on. And certainly, if we saw prices in kind of the mid- 30s, we'd be encouraged to start our activity again. The one thing I want to kind of add to that, sorry, is that we're doing this independent of our hedge position. I know some operators talking about -- I'm talking about barrels above the hedge position.

We think this is -- should be an independent decision. Obviously, the hedge is a financial instrument, and we're looking at every individual well independently, and if it's losing money, we shouldn't be producing it, we should be saving the transportation and operating costs.

Kashy Harrison -- Simmons Energy -- Analyst

So that certainly makes sense. And then I guess for my second question, Bill, thanks for recalling the balance sheet. So given the unsecured nature of the facility, if you wanted to, say, issue second lien or third lien notes similar to what some of your peers are trying to do, what would need to happen? Would you need to transition to a secured facility first and then issue it or do you have the capability to issue subordinated second lien, third lien notes today to take out the maturities that exist in '23 and beyond?

Tim Cutt -- President and Chief Executive Officer

Over to you Bill.

Bill Buese -- Chief Financial Officer and Treasurer

It's a good question, Kashy. The answer is we don't have the ability to issue -- we've limited ability. The credit facility has a small basket under it that is very small. And then of course the notes going the other way, have a basket, a limitation on these basket as well under the indentures that would limit the size of the credit facility.

So we have to get creative. We're having conversations, as I mentioned, with our bank group and bondholders and others just to see the best path forward. But as it stands today, we couldn't go out to answer your question with an example. We couldn't go out and issue $0.5 billion of second lien notes today.

I mean, something like that couldn't happen. We have to modify some things in our capital structure.

Kashy Harrison -- Simmons Energy -- Analyst

OK. Thank you.

Tim Cutt -- President and Chief Executive Officer

All right. Thanks.

Operator

Our next question comes from Neal Dingmann with SunTrust. Please state your question.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Morning. Tim, just a couple of add-ons on this, but I just want to make sure some color on this. How do you view when you think of sort of full shut-ins versus material curtailments? And then sort of as a second part of that, do you anticipate much in the way of cost to bring these shut-ins back?

Tim Cutt -- President and Chief Executive Officer

Yeah. We have factored that in, and I'll hit the kind of cost to return to production first. And we've kind of prioritized the shut-ins into about four different categories. And kind of the easiest one to turn on and off for our gas lift wells, not a lot of mechanical moving parts.

Our rod pump wells, we would say, on average, about $15,000 a well. It costs us $50,000 to repair a part of that same well. So we think about one in four could have that. And so we're putting in about $15,000.

But ESPs get to be a lot more problematic. So we would actually slower our ESPs substantially before shutting them in, a replacement of an ESP and the work over there could be $250,000. So we're considering that as we go. I would consider what we did on 1125 as a curtailment right now with production.

That DSU should be probably hitting just those 10 wells that are shut in at a conservative level of 1,000 barrels a day. So we have quite a bit of oil shut in there, waiting for a bit better price. And so we're going to be smart about this. We don't think this is with us forever.

We hope it's kind of a 3-month phenomenon, but we're prepared to go lower for longer. And then if it looks like a longer sustained period, we're probably more willing to shut in that ESP fully and keep it down and pay the cost to bring back, but we want to be smart about this and balance it.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Got it. And then just one follow-up for you. Just on the DUC count. I'm just wondering where DUC's now? And then where do you sort of see that obviously as you take a break on the fracs for better part of the year? How do you -- when you were kind of giving the -- Kashy the sort of production, how do you think about DUCs today? And will that sort of -- where will that be toward the latter part of the year?

Tim Cutt -- President and Chief Executive Officer

Yeah. I think we've fracked I think 11 wells of 11 25 before we shut down fracking. And so we probably had another 14 wells to go there, that were already drilled but uncompleted. And then we notified the second rig about a month ago, it left on April 24, so it probably drills another couple of wells and then if you just do the math, on every couple of wells a month for the rig that's drilling, that probably gives you a pretty good sense of where we're going to be on DUC count as we get back in November.

If we get back to busy in November, we'd also pick up a second rig at that time. We've got the money in the cash flow forecast to be able to cover both fracking and the second rig. So I don't have an exact number on the DUC count will be at that point. But the technical team assures us that that's enough if we pick up the second rig to get started in November and go with a continuous program.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Very good. Thanks for the details.

Tim Cutt -- President and Chief Executive Officer

OK. Thanks.

Operator

Our next question comes from Derrick Whitfield with Stifel. Please state your question.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Thanks. Good morning all. Perhaps for Tim. Are you attributing the supercharge reservoir condition solely to decrease cluster space or are there other design factors at play?

Tim Cutt -- President and Chief Executive Officer

No. I mean, that's typically what we've seen in Mustang Springs. We had a situation here where we were able to go ahead and do 25 wells back to back. So those first wells were -- we started pressuring up and as you frac across, we were going kind of from the east to the west, they're getting the influence all the way through that of that frac program.

And so that's generally how the tank is designed to perform. We attribute the better performance to really our strategy around limited entry and getting a higher pressure at each of the perforations and getting a better fracture network produced. And so when you look at -- I can't remember, I think it's Slide 8, we show that chart on cluster efficiency, we find that to be extraordinarily encouraging. If you think about cluster efficiency in the past from 60% to 100%, and now you're getting up in the 90% average on cluster efficiency, you're breaking rock and you get a contribution from all of that rock.

And so we're quite encouraged by that. But that's an important thing. And that's also why we want to really keep a close eye on DSU 1125. We're comfortable keeping that shut in for two to three months.

I think after that, we feel less comfortable because you do have production offset and you could see the pressure coming out of the tank, and it could start to potentially impact the EUR. So we're keeping an eye on that. This is new territory for us, but we do have the ability to check pressures on wells as they're shut in. And so we're not going to let that get to a point where we have a concern.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

And Tim, just to clarify on that last question. The cluster efficiency, are you attributing that improvement due to decreased cluster spacing? That was really the heart of that question, my apologies.

Tim Cutt -- President and Chief Executive Officer

Yeah. So I'll say one thing, and I'll turn it over to Joe Redman because he leads that technical group. But it's the combination of the perforation size of fewer perforations and then the cluster spacing and density, but let me turn it to Joe to give you a little more specific.

Joe Redman -- Vice President, Energy

Yeah. Thank you for the question, Tim. So when we think about that cluster efficiency and driving that up, we're really looking at kind of some key variables there. We look at how we space the perforations and the number of perforations in that frac stage.

And so we're driving for that kind of high perforation friction that will ensure that we get a good distribution of frac initiation throughout the number of holes we've put in the pipe. So we do that with a combination of again hole size, number of holes and our pump rate which all works together to create that efficiency.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Great, thanks for the detail. And then as my follow-up, switching over to the Bakken. Could you talk to the drivers behind the improvement in your LOE year over year?

Tim Cutt -- President and Chief Executive Officer

I'll turn that back to Joe as well because he's driving that as well.

Joe Redman -- Vice President, Energy

All right. Yes. Our LOE in both areas actually has been an area of focus for us over the last several months. You'll notice kind of year over year and quarter over quarter, we continue to see improvement there.

In the most recent days, that's been through an effort to really high-grade our workover program. And I'd say now we're being extremely selective with the expenditures on workovers. And we've also taken a pretty hard look at contract labor and ways to bring things in-house. And then kind of lastly, right now, we're working with all of our vendors and suppliers, and they're working with us as well on cost reductions as we kind of continue forward.

So definitely a team effort and a field-led initiative for us to bring those costs down.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Thanks for your time guys. Great update in a very challenging market.

Tim Cutt -- President and Chief Executive Officer

All right. Talk to you.

Operator

Our next question comes from Josh Silverstein with Wolfe Research. Please state your question.

Josh Silverstein -- Wolfe Research -- Analyst

Yeah thanks. Good morning guys. On the debt maturities that are coming up and then the payments the sort of the retirements that you made in the first quarter, just curious with your outlook for free cash flow over the back half of this year and your notes still trading well below par, I'm just curious if you will just continuously be out in the market buying those back? And potentially, would you even think about drawing down $100 million on the revolver to go and do that?

Tim Cutt -- President and Chief Executive Officer

I'll turn that to Bill.

Bill Buese -- Chief Financial Officer and Treasurer

Josh good question. I mean, the answer is, everything is on the table. We'll -- obviously, in the fourth quarter and first quarter, we were able to purchase some notes on the open market. Whether that opportunity there -- is there again, and going forward, we don't know.

But I mean, certainly, it's something we'd consider. And again, as I mentioned in the prepared remarks and my answer earlier, everything is kind of on the table. We're having discussions with everyone, bank group, bondholders, etc. And we look forward to discussing our plans with you guys more going forward.

But everything is on the table at this point.

Josh Silverstein -- Wolfe Research -- Analyst

Great. And then just on the operational side, two things here. One, Tim, you mentioned in your comments that you hope the Permian activity can come back when crude oil is in the mid-30s. We don't really hit $35 on the forward curve until the end of 2021.

So does that mean you guys stay at the one rig pace right now? And just thinking about the activity we started in November, is that something that you've contracted already or do you call somebody up in a couple of months from now and say, hey, what's your best price? And how do we go from there?

Tim Cutt -- President and Chief Executive Officer

No, those are good questions. And again, Josh, you can imagine, we're in kind of the middle of the fire fight right now. I think we've done a good job of getting down to a good run rate we need. We're going to let -- we're going to watch and see how 2021 develops.

I mean, if you would ask me six months ago, when we deliver $100-plus million of cash at the kind of pricing scenarios, I might have said no. And so we'll -- I don't want to lock us in to saying you couldn't take the activity back up. But we're going to be cautious to make sure that we don't go into a large outspend position in 2021. So we'll keep modifying that.

Contracting the equipment and the suppliers, we're confident in doing that. We've had a long-standing relationship with Halliburton on our frac crews. We use unit drilling on the rigs, have rigs and crews available, and we feel comfortable. I mean, we're down to a fairly small operation, good relationships and they're working with us.

So we think we can provide a bit of notice and get going pretty quickly. I ask that question to Chris Longwell, our head of drilling and completions probably weekly, and he said we're standing ready. So I think as we see things improve, hopefully, as we -- none of us know what's going to happen as people shut in and we start seeing the real effects of the fracking slowing down, but as the market comes in balance, I think we'll be poised and positioned as well as anybody to get back after it. And I think oddly, the practice we had last year of going into kind of a cyclical program I think has helped us quite a bit to think about how do we make sure we retain the right people and equipment to shut down and pick back up at pretty short notice.

Josh Silverstein -- Wolfe Research -- Analyst

Great. Thanks guys.

Tim Cutt -- President and Chief Executive Officer

Thank you.

Operator

[Operator instructions] Our next question comes from Gail Nicholson with Stephens. Please state your question.

Gail Nicholson -- Stephens Inc. -- Analyst

Good morning. Thanks for taking my question. I was just curious, when you guys look at the hedge market in '21, can you just talk about what you're seeing there? And anything has changed kind of the standpoint of the liquidity there and the ease of locking in hedges if you guys choose to do so?

Tim Cutt -- President and Chief Executive Officer

Yes. We're not seeing a lot of difference than normal as far as liquidity. It's just a matter of what do you want to start locking yourself into for next year. I think obviously across the industry liquidity -- I mean, across the industry, the hedging activity is down.

The -- as Josh just mentioned, I mean, the Fort strip at the end of the year in the 20s is not encouraging you to try and lock in when you have kind of an increasing price projected in the Fort strip. And so we're making sure that we're honing in on being able to operate if we don't have the bigger hedging opportunities. We hope they do come, and we're poised to move fairly quickly on that. But at this point, I don't believe we would expect to have a liquidity issue if we try to jump in.

That's something -- we have a risk committee. We talk about it every week. We're being smart about that. We're certainly, with improved prices on natural gas, we've been pretty active in getting '21 locked in a little bit more.

But on the oil, I think it's a little more wait and see at this point.

Gail Nicholson -- Stephens Inc. -- Analyst

And then just a further question on LOE, when you look at the fixed versus variable cost in the LOE, is there a higher fixed component in the Williston versus the Permian or can you just talk about how that varies?

Tim Cutt -- President and Chief Executive Officer

Yes. I'll turn that over to Joe to talk about the distribution.

Joe Redman -- Vice President, Energy

Yeah. Thanks for that question. So when we think about our fixed cost versus the variable costs, we're -- in that variable cost bucket, we're looking at things that would be directly related to the cost of production that might include things like chemical water disposal, generally utility, power, things like that. And so there is some variation between the areas.

And as we're making those decisions, we actually take it all the way to the individual well level. So we kind of start by thinking at the big picture field level, and then we dial it in all the way down to the specific well including the contracts and transportation that are directly connected to that well. So our fixed to variable breakout variables between the areas that -- and across wells. And generally, the variable cost is a little bit higher than the fixed cost when you add the dollars up.

Gail Nicholson -- Stephens Inc. -- Analyst

And when you just look at those variable costs, what I guess pieces of those variable costs, have you seen the most I guess deflation in?

Joe Redman -- Vice President, Energy

Yes. So the ones that are in our direct control, like water disposal, there tend to be just kind of direct operating costs. So those are pretty stable. The other things that come through various vendors and suppliers like chemicals.

We're working with them to bring those costs down. And we do bid those kind of services out. And we're doing that actively right now and seeing some movement in that front.

Gail Nicholson -- Stephens Inc. -- Analyst

OK, great. Thank you.

Tim Cutt -- President and Chief Executive Officer

Thanks Gail.

Operator

No further questions at this time. I'll turn it back to Tim Cutt for closing remarks.

Tim Cutt -- President and Chief Executive Officer

All right. Thanks everyone. Thanks for the good questions. And really, I don't have a lot more to say.

I don't want to reiterate what we just went through, but I do want to take the opportunity to sincerely thank our workforce. You can imagine the stress of heading home, having to figure out how to social distance in the field safely and we continue to do that. And I really want to thank directly our field employees are showing up every day, delivering a fantastic service and keeping a positive attitude as they do that. We're checking in with everybody on a very regular basis.

We have our field superintendents on our leadership calls now that I participate in. We're listening to our drilling folks and making sure that every single thing we do is safe for our employees and our contractors. But our employees are just flexible. You can also imagine when we ask them to fundamentally do a business plan in a matter of a couple of days to execute reduction activity that pulled through, we were able to review that quickly with the board and take good action.

So I'm also proud and very confident, and this is -- a number of us have been doing this for a while, and this is one of the worst we've seen, but we're very, very confident we can navigate it calmly and just move through this. So with that, I think we'll sign off. And again, thanks for your interest and dialing in. Appreciate it.

Operator

[Operator signoff]

Duration: 47 minutes

Call participants:

William Kent -- Director of Investor Relations

Tim Cutt -- President and Chief Executive Officer

Bill Buese -- Chief Financial Officer and Treasurer

Kashy Harrison -- Simmons Energy -- Analyst

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Joe Redman -- Vice President, Energy

Josh Silverstein -- Wolfe Research -- Analyst

Gail Nicholson -- Stephens Inc. -- Analyst

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