SM Energy (SM) Q2 2020 Earnings Call Transcript

SM Energy (SM -2.18%)
Q2 2020 Earnings Call
Jul 31, 2020, 10:00 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Jennifer Samuels

Welcome to SM Energy's second-quarter 2020 financial and operating results webcast. Before we get started on our prepared remarks, I will direct you to Slide 2 and remind you that we will be making forward-looking statements about our plans, expectations and assumptions regarding future performance. In particular, we will be providing updated guidance for 2020 and beyond, as well as commentary on strategic objectives beyond 2020. These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements.

Please refer to the cautionary information about forward-looking statements in today's earnings release, the related presentation posted to our website and the Risk Factors section of our most recently filed forms 10-K and 10-Q. Discussion of second-quarter results includes non-GAAP financial measures that we believe are useful in evaluating our performance. Reconciliation of those measures to the most directly comparable GAAP measures and other information about these non-GAAP measures are provided in our earnings release and the investor presentation referenced during this call. Today's prepared remarks will be given by CEO Jay Ottoson, CFO Wade Pursell and President and COO Herb Vogel.

I will now turn it over to Jay Ottoson. Jay?

Jay Ottoson -- Chief Executive Officer

Thank you, Jennifer. Good afternoon, and thank you, everyone, for your interest in our company. I hope that you and your families have been well. I am going to start on Slide 3.

Our key message for you today is that although we are currently in challenging times from a macro perspective, our priorities have not changed. And our recent operating performance has been outstanding. As a premier operator of top-tier assets, we're focused on generating cash flow growth while spending within our internally generated cash flow and using that free cash flow to reduce debt, resulting in lower debt leverage and cash flow growth per debt adjusted share. Implicit in our concept of premier operatorship is that we want to be a model of good environmental, social and governance practices in our industry.

Our team here at SM has adapted well to new safety protocols related to the COVID-19 pandemic while rapidly evolving our operating plan to adjust to lower oil prices. Our costs have moved remarkably lower over the last quarter, while our well performance continues to be strong. Wade will take you through our second-quarter performance and our revised plan, and Herb will elaborate on our operating results. Before I turn the call over to them, however, I want to note that our board took several steps recently to strengthen oversight and disclosure of our environmental, social and governance performance.

Our board has always been highly engaged on these topics. But took the additional step in their last meeting of revising the charter of our Governance Committee to specifically include environmental and social issue oversight. And they have directed us to increase our disclosure related to our ESG performance by initiating participation in the carbon-disclosure project. We will also be publishing SASB metrics, which will be included in our updated corporate responsibility report.

With that, I will turn the call over to Wade.

Wade Pursell -- Chief Financial Officer

Thanks, Jay. Good afternoon. Obviously, a lot of moving parts in the second quarter. I'm going to start on Slide 5.

Wild commodity price swings, impact of the roll, production shut-ins, deferred completion timing, aggressive focus on cost and an extended debt exchange complicated the second quarter. However, we took these actions to navigate through a very challenging environment, and we believe they were effective. My comments today will be in the context of the first two areas of focus Jay mentioned, the importance of growing within cash flow and the importance of working leverage down, and that target is two times. As always, refer to the schedules in the release and the appendix to the IR presentation for detailed data on the quarter's results.

However, I would like to highlight a few things and walk through results of the debt exchange. I'll start by highlighting free cash flow. Capital discipline, better-than-expected performance from previously completed wells and cost management complemented our good hedge positions to deliver $28 million in free cash flow. On a trailing 12-month basis, we have generated $124.7 million in free cash flow.

And for those of you calculating a yield to market cap, that's a very healthy 29%. Capital expenditures of $125 million were well below our guidance of $165 million to $175 million. But this is predominantly due to further cost deflation and cost management, as well as some timing differences. Well costs have continued to come down, and Herb will elaborate on this further.

So let's look at certain line items now. Starting with second-quarter price realizations for Permian oil revenue, which makes up the majority of total revenue. Realizations were understandably tough to model, so here are the components. Benchmark oil was $27.85.

From that, the Midland differential averaged a reduction of $0.27, the effect of the roll averaged a reduction of $3 and then subtract general point of purchase differences and you get $22.86. This does not include hedges. We realized a $25.81 per barrel increase in oil prices from hedging. Second-quarter operating cost came in better than expectations, which was a combination of aggressive cost management and the deferral of certain workovers.

We have lowered guidance for LOE for the year to reflect cost savings but do expect third- and fourth-quarter operating expenses to be higher than the second quarter on a per-BOE basis, inclusive of workovers. I believe most of the other line items are self-explanatory. So turning to hedging on Slide 6. We're very well hedged for the second half of 2020, with about 90% of oil production hedged at $55 per barrel or higher and about 50% of natural gas production hedged at an average of $2.20 per MMBtu.

And we have separate Waha hedges for our Midland natural gas. We've also added significant positions for 2021 to protect the downside, including oil hedges at around $40 per barrel, gas hedges around $2.40 per MMBtu to Houston Ship Channel, plus additional Permian gas hedges to Waha. As always, the detail by quarter is in the appendix to the slide deck. So turning to the balance sheet on Slide 7.

The debt exchange successfully reduced long-term debt by $290 million and pushed out and reduced near-term maturities in 2021 and 2022 by $249 million. To recap, $612 million of unsecured senior notes and $107 million of convertible notes were exchanged for $447 million of new second-lien notes, $54 million of cash and warrants to certain holders to acquire the 5% of the outstanding stock of the company under certain conditions, that being the achievement of at least $1 billion in market cap for four or five consecutive trading days prior to expiration on June 30, 2023. In terms of debt strategy going forward, this leaves only $65 million due in 2021 and about $294 million due toward the end of 2022. And this compares to $865 million of availability under the revolver, as well as significant current additional second-lien capacity.

Our total leverage, that is debt-to-trailing 12-month EBITDAX at the end of the second quarter is just under two and a half times. As a reminder, the covenant under the revolver is four times. As I will now discuss, our planned forecast growing within internally generated cash flow for the foreseeable future at current strip prices. So let's turn to that midyear forecast now on Slide 8 and see where we're headed over the next few years.

Considering the difficult macro environment, we're pretty excited about our direction. So let me take a few minutes with this, and then Herb can elaborate on the great operations driving the results. Again, our current focus is to grow within cash flow and reduce leverage to two times. In this current low price environment, that means keeping leverage in the three times area then moving toward two times over time sooner with even a modest recovery in commodity prices.

The forecast we have laid out reduces total capital expenditures for this year to $610 million to $630 million, which incorporates lower cost and deferral of certain activity. Capital activity stays relatively flat in third quarter from second quarter, then ramps up in the fourth quarter with a second crew and more completions. As a result, we expect declining production in the third quarter and fourth quarter with a stronger exit rate, leading to higher first-quarter 2021 production. Applying strip pricing, the third and fourth quarters are free cash flow neutral to positive and debt to EBITDAX at year-end is around 2.75 times.

Looking ahead into 2021 and again, assuming strip pricing. We expect a slightly increased capital budget that will be more heavily weighted to completion activity, growth in total production driven by oil, free cash flow neutral to positive, with net debt to adjusted EBITDAX ending around three times at the end of the year. And then, looking further ahead to 2022, again, assuming strip pricing, leverage falls well into the mid-twos area. And with the recovery of oil prices to the $50 area, our forecast shows leverage in the two times target area so on that positive note, I'll turn the call over to Herb.

Herb?

Herb Vogel -- President and Chief Operating Officer -- Analyst

Thank you, Wade. As Wade noted, there were a lot of moving parts in the second quarter driven by the commodity price environment. I'll start with a few comments about our proactive response and how that affected production before turning to the slides in the deck. Key factors influencing production were better-than-expected existing PDP well performance, curtailment or shut-in of some production, deferral of turning newly completed wells to sales to the end of the quarter.

And reduction in the number of wells turned to sales in the quarter relative to previous quarters. In the Midland Basin, performance from our existing PDP wells was better than we had modeled at several well pads. Notable outperformance relative to expectations came from the Merlin Maximus, Balboa, Tackleberry and McFly pads. This outperformance was offset by voluntary curtailments or shut-ins of certain producing wells in response to the adverse pricing environment.

This amounted to an average reduction for the quarter of around 3,000 BOE per day at a relatively high oil percentage. Another action we took during April and May was to defer bringing online newly completed wells in the Midland Basin. All 10 net completions in the second quarter returned to sales during June rather than spread through the quarter. Finally, as we indicated we would do in the first-quarter call, we reduced overall D&C activity.

Over the past couple of years, we completed an average of more than 20 net wells in the Midland Basin each quarter. So with just 10 net completions, we were well below our norm for our quarter. One effect that you will note from the delayed start-up of completed wells and fewer total completions in the quarter was an increase in the percentage of gas production relative to our total Midland Basin production. For those of you who are not very familiar with well performance, the percent oil content is highest when a well first comes on production then slowly declines as a percent of total well production over time at a very predictable rate.

Our deferral actions led to a higher proportion of production from gassier existing wells rather than oilier new wells during the quarter. This production mix, coupled with less layering, thanks to strong third-party gas plant uptime, resulted in the higher gas percentage from our Midland Basin production. Now it's worth noting that Howard County production has some of the highest oil percentages in the basin. As wells undergo depletion, the gas oil ratio increases at a slower pace in Howard County, Wolfcamp and Spraberry wells than farther West in the center of the basin, as a result of the unique characteristics of the oil and reservoir pressures and temperatures in the county.

This is, obviously, an attractive characteristic. I will add, just to be clear, that the higher gas percentage this quarter has nothing to do with spacing or from which interval wells we're producing. So now turning to the deck and Slide 9. Midland Basin well performance continues to be very strong and delivers great economics as a result of lower capex and optimized completion designs.

Our Midland Basin assets offer low breakeven flat oil prices. And while we are slowing total capital activity for the year in response to conditions, we remain focused on returns and will only drill well pads that meet our threshold returns. On this slide, we show our reduced activity for 2020 in terms of completion counts, slowing our spending and cadence in the current commodity price environment. As you can see, we pushed more completions into the second half, 29 in the first half with 39 planned in the second half.

During the second quarter, we continued to see cost deflation and optimize our completion designs resulting in a remarkable, anticipated drill complete and equip cost of $560 per lateral foot for the second half of the year. We really need to give full credit to our ops and procurement teams for the relentless pressure they apply to make this possible while maintaining high safety and environmental standards. In the Midland Basin, we currently have four rigs and one completion crew active and expect to drop one rig and add one completion crew in October. Turning now to Slide 10.

I'd like to highlight how really strong our Midland Basin economics are. RSEG or Envers analysis ranks SM as having the lowest breakevens in the Midland Basin for 2019. And I suspect our low 2020 well costs will again position us in the top tier among peers this year. Slide 11 breaks down some of the contributors to the extraordinary cost improvements year to date.

We are drilling and completing substantially more lateral feet per day now than even the exceptional rates we delivered in 2019. Year to date, we are drilling 18%, completing 33% faster than last year. On top of that, we have cut sand costs in half since the start of 2019 and continue to gain efficiencies by extending lateral lengths, thanks to our contiguous acreage position. Now turning to Slide 12 in South Texas.

In response to adverse commodity prices, we have also cut back capital activity in South Texas, reducing from 16 net drills and nine net completions in the February plan to 12 net drills and four net completions in our latest plan for the year. We are also reducing well costs further down to around $600 per lateral foot anticipated for the second half of the year. Delaying certain activity sets us up for economic advantages in 2021, as contracted costs for produced gas transportation decline and condensate sales prices increase relative to index from where they are today. Combine this with higher oil content of Austin Chalk wells and the result is breakeven economics as an entirely new and attractive level in South Texas.

As we've talked about the last several quarters, our geoscience teams identified the potential for substantial economic inventory additions from the Austin Chalk on our South Texas acreage. The Austin Chalk extends over a wide area. But we believe it has unique attributes in particular, higher permeability on our acreage. It's also substantially more condensate and NGL rich than the deeper Eagle Ford, and that significantly enhances revenues from Austin Chalk production.

As a result, we embarked on a delineation program that has delivered nine Austin Chalk wells to date, two of which just commenced flowback this month that I will not address today. We gathered substantial science data from these wells and have continued to optimize landing zones and completion designs. If you turn to Slide 13, I will highlight our latest three Austin Chalk wells that have been producing for more than a month. The Briscoe 109H, San Ambrosia 1009H and Galvan 910H outstanding new wells and have set new records for oil and condensate production for us.

In fact, the 109H and 1009H have delivered higher oil rates any of the South Texas wells we completed over the last 10 years. Initial rates for these wells are shown on the slide. But let me point out in particular that both of these wells had more than 58% oil and 80% liquids in their three-stream production. The new 910H well has only been flowing for five weeks.

This well is located further East on our Galvan acreage where the reservoir is deeper and more overpressured. It is early days for assessment, and we have not yet reached an IP30 yet. But based on wellhead pressures and production rates this looks to be a very strong well. The 24-hour IP was 3,960 BOE per day three stream, with 32% condensate and 61% liquids, and that rate is constrained by our facilities.

The API gravity of the oil or condensate from these wells ranges between 51 and 53, significantly lower and therefore, have more value than our historical condensate production. Bottom line and based on go-forward development costs, we estimate that these wells have a flat oil price breakeven 10% return that is below $20 per barrel for the 1,009H and 109H and around $31 per barrel for the 910H. This assumes gas of $2 per million BTU for the first half of 2021 and then $2.40 per million BTU gas after that. Simply put, these latest well economics are competitive with any basin in North America.

So let's recap the value drivers of our South Texas activity. Austin Chalk wells have higher oil and NGL content and better economics than former Eagle Ford wells at current strip prices for natural gas. We've optimized completion designs, refined optimal landing zones and reduced costs significantly so that we now see top-tier drilling opportunities on our acreage. Our South Texas gas production is subject to a step-change improvement in transportation costs of $0.25 and an additional $0.35 per Mcf in mid-2021 and mid-2023, respectively, that will enhance revenues from our South Texas asset.

In addition, we anticipate that prices for condensate will yield an additional $5 per barrel relative to index starting late this year. Each of these efforts adds up to a sizable value creation for our South Texas position. While we focus on the liquids-rich Austin Chalk now, we also retain the option to drill natural gas in the Eagle Ford, if prices rebound next year as some have suggested. Turning to Slide 14.

Let me highlight some of the advances in ESG for a moment. Jay mentioned the steps we have taken at the board level to enhance ESG oversight, as well as our efforts to expand our public reporting of metrics through CDP and SASB. We have also published to our website our 2019 performance on key metrics for the upstream sector. Compensation for all employees has performance targets for safety, greenhouse gas and methane emissions and spills.

In 2019, we recorded top quartile results among our peers who report greenhouse gas and methane emissions and spills. Stewardship is implicit in being premier operators. We seek to foster a cultural stewardship beyond compliance and compensation targets that incorporates innovation and responsible decision making at all levels in our day-to-day operations, as well as in our long-term planning. I'll now turn it back to Jay for closing remarks.

Jay?

Jay Ottoson -- Chief Executive Officer

Well, thank you, Herb. In summary, I'll reiterate that although we are in challenging times, our priorities have not changed. We've done exceptional work year to date to generate free cash flow and reduce debt and intend to continue running our business, spending within our internally generated cash flow and applying that free cash flow to debt reduction in order to deliver improved leverage and cash flow growth per debt adjusted share. I think anyone who works with us regularly in any of our office or field locations knows that our team members are highly committed to environmental stewardship, safety performance and social responsibility.

But we are going to do more to improve transparency with respect to our ESG data, goals and results. We look forward to taking any questions you might have during our live Q&A session tomorrow morning. And we thank you for your time and attention.

Questions & Answers:

Operator

Ladies and gentlemen, thank you for standing by. And welcome to the SM Energy Q2 2020 financial and operating results Q&A call. [Operator instructions] Please be advised that today's conference is being recorded. [Operator instructions] I would like to now hand the conference over to your speaker today, Jennifer Samuels, VP of investor relations.

Please go ahead, ma'am.

Jennifer Samuels

Thank you, Joanne. Good morning, everyone. And thank you for joining us. I have to say it's good to be back this quarter with a live call and have the opportunity to elaborate on the second quarter where we generated big free cash flow and reduced debt despite a challenging macro environment, as well as have the opportunity to further discuss the very solid outlook we are presenting through 2021.

First, allow me to quickly remind you that we may discuss forward-looking statements about our plans, expectations and assumptions regarding future performance. These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements. Please refer to the cautionary information about forward-looking statements in the 2Q earnings release, the IR presentation and the Risk Factors section of our Form 10-Q, which was filed this morning, all of which are posted to our website. Our discussion today may include discussion of non-GAAP financial measures that we believe are useful in understanding and evaluating our performance.

Reconciliation of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are provided in our earnings release and IR presentation. Here to answer your questions this morning, our CEO Jay Ottoson, EVP and CFO Wade Pursell, and President and COO Herb Vogel. Let me turn it back to the operator, Joanne, if you would take our first question.

Operator

[Operator instructions] Your first question comes from the line of Gabe Daoud from Cowen. Your line is now open.

Gabe Daoud -- Cowen and Company -- Analyst

Hey, good morning, everyone. Thanks for all the prepared remarks last night. I guess maybe, Jay, can you maybe just elaborate a little bit on the decision to pursue growth next year and perhaps define what meaningful growth equates to in your eyes for next year?

Wade Pursell -- Chief Financial Officer

Sure. I'll answer, certainly, the last part. I mean I think, we didn't give specific numbers for next year. This is Wade, by the way.

But you can assume something like double-digit growth from a production standpoint and even stronger when you're thinking of oil growth. So I would characterize it more like strong double-digit growth. And that's coming off of a reduced number this year, obviously, with what's going on in this quarter.

Jay Ottoson -- Chief Executive Officer

Yeah, this is Javan. I think there's sometimes in these downturns people have a misunderstanding about levered companies. And we really don't have an option here to just stop activity and watch our leverage skyrocket, right? That's just not what you should expect a fairly levered company to do. So when prices drop, we cut activity very quickly in order -- and then as we think costs start to get to bottom, then we will increase activity again to keep our cash flows up and maintain -- and keep our leverage down.

And that's what you should expect levered companies to do in this part of the cycle.

Wade Pursell -- Chief Financial Officer

And probably, three important points for me for that 2021 activity is the returns that will be generated are all well above our hurdles. I think we stated that it would be within cash flow overall. And it maintains leverage into the year at like a three times level. So I think those are the key points.

Gabe Daoud -- Cowen and Company -- Analyst

Yeah. Thanks, guys. That's helpful. I guess as a follow-up, you stay within free cash flow next year.

Is that on strip pricing, I guess, as a quick follow-up? And then -- and so that's the pricing rate, is that right?

Wade Pursell -- Chief Financial Officer

Yes, it's strip-pricing. I can tell you that. And the strip that we were using when we ran that is very similar to today, so.

Gabe Daoud -- Cowen and Company -- Analyst

Understood. OK. And then, just and maybe quantify the amount of activity that you are adding in 4Q? And then, a 10% increase in budget activity or capital activity for next year. What does that mean from like a rig and crew perspective? And is all that capital directed for the Permian? I'll just stop there.

Thanks, guys.

Herb Vogel -- President and Chief Operating Officer -- Analyst

OK, yes, Gabe, this is Herb. So roughly, it's about a 10% capital increase from our latest guidance from this year. And in terms of rigs, it will be around 3%, maybe a little bit more in the Permian. And then, in South Texas, it will be between 1% and 2%, and it will depend a little bit on where commodity prices are.

And we haven't finalized our plans anyway. So we've got multiple scenarios. It will depend on what the outlook is when we get to the end of the year.

Gabe Daoud -- Cowen and Company -- Analyst

Thanks, Herb.

Operator

Your next question comes from the line of Steve Dechert from KeyBanc. Your line is now open.

Steve Dechert -- KeyBanc Capital Markets -- Analyst

Hey, guys, just want to get a little bit of color on the strategy behind adding the total swaps in 2021. And then, are you guys adding or planning to add more hedges in 2021 on top of those? Thanks.

Wade Pursell -- Chief Financial Officer

Yeah, sure. This is Wade. So you probably know our hedging strategy really well, and it's tied very directly to our leverage levels. And with our projected leverage next year and maintaining in that three times area, we think it's really important to protect the cash flow that supports that.

So putting -- as oil kind of trended back up toward the low 40s area, we've been adding hedges swaps for next year. And a very similar program on the natural gas side. We've been very pleased with the move-up in the strip on the natural gas side. So we've been adding hedges there as well.

And all the details are in the appendix. You can see that. But that's our strategy. We don't go too far out because we know that with the recovery the cost will likely go up over a period of time as well.

So we're just now starting to put in slivers, I'll call them hedges, in 2022.

Steve Dechert -- KeyBanc Capital Markets -- Analyst

All right. Thank you. And then, just on the NGL and gas for 2021, kind of what's the level of growth there you guys see? I know you guys said, obviously, a strong oil production growth, just on those two. If you could give a little color there, that would be great.

Thanks.

Jay Ottoson -- Chief Executive Officer

Steve, I couldn't quite catch the start of your question. The phone cut out right there. Can you repeat the start of that question?

Steve Dechert -- KeyBanc Capital Markets -- Analyst

Yes. Just on the kind of some color on the level of gas, NGL production in 2021.

Wade Pursell -- Chief Financial Officer

I guess we should start by repeating that what we're saying is double-digit overall growth next year with strong double-digit oil growth next year so that that implies, obviously, less when you look at gas and NGL side.

Jay Ottoson -- Chief Executive Officer

And frankly, we haven't put those plans together. We've got multiple scenarios. So depending on the environment, the gas and NGL could decrease a little bit or it could increase a little bit depending on the scenario. So when we get to the year-end, we'll finalize those numbers.

And in all the scenarios, as Wade said, it's double-digit growth, and then it's oil-weighted.

Steve Dechert -- KeyBanc Capital Markets -- Analyst

OK, great. Thank you.

Operator

[Operator instructions] Your next question comes from the line of Brad Heffern from RBC Capital Markets. Your line is now open.

Brad Heffern -- RBC Capital Markets -- Analyst

Hey, everyone. Thanks for taking the questions. I have a couple on South Texas. For the Austin Chalk results, sometimes farther to the East, you see this relatively rapid-phase shift.

I know it seems like you have something of a sweet spot that maybe is a little different geologically. So I was just wondering if you could talk about how the oil rates hold up over time? And if you do indeed see a rapid-phase shift?

Herb Vogel -- President and Chief Operating Officer -- Analyst

OK, yeah, Brad. So first of all, we're super pleased with what our geoscience teams have come up with there on the Austin Chalk. As time's gone on, they've really refined the landing zone. And that's really shown that we have higher permeability rock on our acreage than elsewhere, and so the productivity is high.

And then, you're correct that the phase that's produced varies over our acreage. To the Northwest, it's much oilier and less gas buried NGL rich and you move east and south, and it gets gassier. And it's like trends the same way the Eagle Ford except at a completely higher level of condensate and NGL than the Eagle Ford just because of shallower. So yes, as we go east, it will be high productivity, and it'll just be gas here.

And you can see that in those well results we gave with 58% oil over on the Northwest and 32% oil over more toward the Southeast. So in all cases, the NGL content is quite high.

Brad Heffern -- RBC Capital Markets -- Analyst

OK, got it. Sorry, I maybe used the wrong language there. I was more talking about the productivity of the well over time. Do you see like a significantly more rapid oil decline than you see from the liquids and gas? Or is it sort of more steady in this area?

Herb Vogel -- President and Chief Operating Officer -- Analyst

No, it's a transition from both oil to condensate through our acreage. And so the rates hang in there quite well. It's not like a Permian well that will decline relatively rapidly. The wind up facility limited, so we can only produce so much so the gas state on plateau for a while and the condensate stays up there with it, and then it will decline over time.

But yes, it's a different character of decline than what you'd see from the Permian.

Brad Heffern -- RBC Capital Markets -- Analyst

OK, great. Thanks. And just a couple of sort of administrative things on South Texas as well. So I know you guys have called out that in mid-2021, you have the transportation contracts rolling off.

But the last couple of quarters, the transportation expense has been quite low relative to where it sort of used to hang out, at least on a nominal basis. So I was wondering if anything has changed there? And then, also, you've called out this $5 per barrel improvement in in 2021. And is that associated with like a new contract? Or what's the reason for that? Thanks.

Herb Vogel -- President and Chief Operating Officer -- Analyst

OK, yes, this is Herb again. So there's two parts to your question. Let me give the second one first. So on condensate, we have a contract that has a specific volume amount, and we will have fulfilled that contract sometime later in the year and then we'll reup the contract.

And currently, contract rates are quite a bit better than they were from that older contract. So that's benefit there. And then, on the transportation cost, are you talking about our overall corporate transportation costs? Because that's simply -- there's more of a mix weighted more toward the Permian, which has transportation costs of effectively zero. So if you take the transportation cost for South Texas, it will be blended down from additional Permian production and then there's an additional impact, and that's with the Austin Chalk, it's more liquids rich.

So it's going to be a little bit lower transportation cost per BOE also.

Brad Heffern -- RBC Capital Markets -- Analyst

OK, yeah, I was more looking at like just on a nominal basis, like typically, the transportation expense for South Texas is like $45 million a quarter or something like that, and it's gone down into sort of the mid-30s. But maybe the Austin Chalk is the explanation for that.

Herb Vogel -- President and Chief Operating Officer -- Analyst

Well, and that's rates, too. The rate's gone down, right, versus Austin Chalk. It's by the rate and higher Austin Chalk percentage.

Brad Heffern -- RBC Capital Markets -- Analyst

OK, thank you.

Operator

Your next question comes from the line of Michael Scialla from Stifel. Your line is now open.

Michael Scialla -- Stifel Financial Corp. -- Analyst

Hi, good morning. Jay, I know you're not done yet, but I wanted to congratulate you on your upcoming career. Herb, congrats to you as well in your new role. Wanted to ask on the preliminary 21 plan for South Texas.

Does that contemplate having a JV partner or no?

Herb Vogel -- President and Chief Operating Officer -- Analyst

Yeah, Mike, that's a no. Does not contemplate a JV.

Michael Scialla -- Stifel Financial Corp. -- Analyst

Got it. Thanks. And when you talk about the double-digit growth just clarify just talking about year-over-year growth, are you presenting that from fourth-quarter revenue?

Wade Pursell -- Chief Financial Officer

Mike, if I heard your question correctly, is that year-over-year growth or 4Q to 4Q, year over year?

Herb Vogel -- President and Chief Operating Officer -- Analyst

Year over year.

Wade Pursell -- Chief Financial Officer

Year over year, that's an annual growth number, yes.

Michael Scialla -- Stifel Financial Corp. -- Analyst

Got it. Thank you.

Operator

Your next question comes from the line of Neal Dingmann from SunTrust. Your line is now open.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

My first question is around Slide 9. You just talked about the revised plan there. Specifically, can you really what it looks like the drill wells didn't change dramatically. But I would say, the completion didn't either, but I'm just wanted to thoughts on the revised plan.

Now the prices are back up. I think in the revised plan now, you're talking about 68 wells completed for the year versus previously thinking around 77. So just your thoughts around that.

Herb Vogel -- President and Chief Operating Officer -- Analyst

Yeah, Neal, this is Herb. So that is just the Midland Basin and what you're quoting there. And if you combine South Texas, we've actually dropped our total number of drills by 12 for the year and our number of completions by 26 for the year. And obviously, that's the extraordinary environment we encountered in March.

And so we did what any company would do as we quickly reacted and put in a proactive plan in place to revise plans and optimize our cash flows to reach our objectives for 2020, as well as '21. So we didn't do it just in isolation of one year. We looked longer-term in defining the new scenarios for the plan that we'll develop later in the year.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

And just, Herb, that kind of leads to my second question is just you've been one of the few -- with this new capex, it looks like you've spent almost exactly 50% in the first half where most others spent very heavily in the first quarter and are essentially spending very little in the fourth. Can you just talk about what's your thoughts behind that? Do you think that will lead to a better '21? Or it's just definitely noticeable that you are definitely much more sort of equal weighted on spending this year than most of the other E&Ps out there?

Herb Vogel -- President and Chief Operating Officer -- Analyst

Right. So Neal, we basically, as I said, we look at 2020 and '21. And when March came around, we put in place a plan very quickly and that really cut our activity, and we wound up with curtailments in May and June. And so we really had a trough in capex spending in second and third quarter.

And then we ramped up at the back end of fourth quarter and get into '21, which, based on strip pricing, was the optimal way to work our way through this unprecedented event.

Wade Pursell -- Chief Financial Officer

There's a significant deflation versus first quarter.

Herb Vogel -- President and Chief Operating Officer -- Analyst

Yes. Oh, yes. And then, obviously, we've had significant deflation in 2Q, 3Q, and we've locked in great prices for services.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

OK, makes a lot of sense. Thanks, guys.

Operator

[Operator instructions] Your next question comes from the line of Harry Halbach from Raymond James. Your line is now open.

Harry Halbach -- Raymond James -- Analyst

Hey, guys, just quick questions on your premise for 2021. You said it would be more heavily weighted to completion activity. And I see that you'll drop around 12 drilled wells and 26 completed. So would 14 extra completions compared to drills next year be a good proxy for that? And how many DUCs do you plan on entering the year with?

Herb Vogel -- President and Chief Operating Officer -- Analyst

OK, Harry, this is Herb again. I think I kind of -- yes, you're right, we dropped 12 drills and 26 completions. So obviously, we build our DUC count through this year at a kind of slow pace. And then, as we go into next year, the way we would do this is we pull down the DUC count.

And that will be just kind of getting more to natural levels by the end of '21. And we don't have a plan for '21. So I can't give a specific DUC count right now for where we see it, but that's something we'd share later in the year.

Harry Halbach -- Raymond James -- Analyst

OK, great. Thanks. And do you think you could possibly give me a rough split and completions between the two basins?

Herb Vogel -- President and Chief Operating Officer -- Analyst

Completion is -- well, that's really when we look at it right now, we run multiple scenarios. And we can say, OK, if this is the environment we get to at the end of the year, this is the scenario that optimizes to our objectives. And if the environment is this way, it's a different one. So no, we wouldn't give that split yet.

Harry Halbach -- Raymond James -- Analyst

All right. Well, thanks for the help.

Operator

Your next question comes from the line of Gail Nicholson from Stephens. Your line is now open.

Gail Nicholson -- Stephens Inc. -- Analyst

Good morning. You guys have had some really nice LOE improvement in the Permian Basin since the fourth quarter of 2019. I know some of it is less work over activity and curtailments. But when we look at kind of a normalized LOE rate, where are you today in the Permian versus two quarters ago? And what have you really done to drive that LOE lower?

Herb Vogel -- President and Chief Operating Officer -- Analyst

OK, Gail, this is Herb. You're right. Our LOEs come down significantly, and there was a component that was less workover expense. Obviously, it doesn't make sense to spend much on workovers when prices were where they were in the second quarter.

So unilaterally across the board, we wind up with lower service costs at our LOE expenses. And we've aggressively contracted for lower expenses. That's the main driver. And then, we've also optimized things like use of compression and use of generators that also reduced costs.

So it's pretty much across all LOE categories that we've reduced cost.

Gail Nicholson -- Stephens Inc. -- Analyst

OK, great. And then, just looking at the Austin Chalk in the presentation deck, you guys talk about the latest three wells having a breakeven at $17 to $31 oil. I think that uses like a $2 or $2.40 gas environment. I was just kind of curious, if gas is $3, how does that change the oil breakeven for the Austin Chalk?

Herb Vogel -- President and Chief Operating Officer -- Analyst

Gail, so then the gas were at $3, then the oil breakevens would drop lower significantly, actually with and those eastern ones, that $31 one would drop more than the $17 one where it's oilier.

Gail Nicholson -- Stephens Inc. -- Analyst

OK, great, thank you.

Operator

Your next question comes from the line of Joseph Rokous from Goldman Sachs. Your line is now open.

Joseph Rokous -- Goldman Sachs -- Analyst

Hey, good morning. This is Joe Rokous on for Karl Blunden. I think you discussed this a little bit, so apologies if I missed the answer here. But what is the main driver of that reduced well cost guidance versus the April results? Is the main driver there is service cost deflation or mainly efficiency gains driving that?

Herb Vogel -- President and Chief Operating Officer -- Analyst

Yeah, Joe, this is Herb. So if you're looking at like just a single well, deflation, how much that is versus 2Q, how much we saw when it was a blend versus what we've done for the year as a whole. Are you asking about for a single well or are you talking about for our program?

Joseph Rokous -- Goldman Sachs -- Analyst

I think overall across the program.

Herb Vogel -- President and Chief Operating Officer -- Analyst

Yes. So it's more deflation than anything else. So a single well. So you're looking at single well a 75% deflation and 25% improvement.

If you look at that program, obviously, it's a blend of first-quarter costs and later cost. But for a single well, it's 75% deflation.

Joseph Rokous -- Goldman Sachs -- Analyst

Got it. Thanks very much. And then, my follow-up, can you just discuss what are your preferred methods of refinancing your remaining bond maturities when they come due?

Wade Pursell -- Chief Financial Officer

I think I heard the question of upcoming maturities in '21 and '22.

Jay Ottoson -- Chief Executive Officer

He wants to know preferred method in dealing with this.

Wade Pursell -- Chief Financial Officer

Yes. I mean we have, obviously, I can't give you a specific plan today that wouldn't be very prudent, but we have multiple options, significant liquidity, significant, I'll call it, significant secured capacity overall, significant liquidity and the revolver. Also pretty significant remaining second lien capacity that was not used earlier. That amount is actually in excess of what is coming due in '21 and '22.

And then, there's nothing in '23, no bonds mature. So multiple options, we'll be opportunistic and try to look at the lowest cost alternative for retiring those.

Joseph Rokous -- Goldman Sachs -- Analyst

Great, thank you very much. I'll turn it over.

Operator

Your next question comes from the line of Michael Scialla from Stifel. Your line is now open.

Michael Scialla -- Stifel Financial Corp. -- Analyst

Actually, Wade just answered my follow-up question. Thanks.

Wade Pursell -- Chief Financial Officer

Well, that exhausts our list of questioners. Thank you all for attending today. We appreciate your interest in the company. It's, obviously, been a very challenging second quarter.

We're accomplishing our goals. We're generating free cash flow. We're reducing debt. And over time, we intend to increase debt-adjusted per share cash flow for our equity holders.

So thank you again, and we'll talk to you next quarter.

Operator

[Operator signoff]

Duration: 47 minutes

Call participants:

Jennifer Samuels

Jay Ottoson -- Chief Executive Officer

Wade Pursell -- Chief Financial Officer

Herb Vogel -- President and Chief Operating Officer -- Analyst

Gabe Daoud -- Cowen and Company -- Analyst

Steve Dechert -- KeyBanc Capital Markets -- Analyst

Brad Heffern -- RBC Capital Markets -- Analyst

Michael Scialla -- Stifel Financial Corp. -- Analyst

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Harry Halbach -- Raymond James -- Analyst

Gail Nicholson -- Stephens Inc. -- Analyst

Joseph Rokous -- Goldman Sachs -- Analyst

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