Earthstone Energy Inc (ESTE) 2020 Q4 法說會逐字稿

Good morning, and welcome to Earthstone Energy's conference call. (Operator Instructions) And as a reminder, this conference call is being recorded.

Joining us today from Earthstone are Robert Anderson, President and Chief Executive Officer; Mark Lumpkin, Executive Vice President and Chief Financial Officer; Steve Collins, Executive Vice President of Operations; and Scott Thelander, Vice President of Finance. Mr. Thelander, you may begin.

Thank you, and welcome to our fourth quarter and 2020 year-end conference call. Before we get started, I would like to remind you that today's call will contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 as amended and Section 21E of the Securities Exchange Act of 1934 as amended. Although management believes these statements are based on reasonable expectations, they can give no assurance that they will prove to be correct. These statements are subject to certain risks, uncertainties and assumptions as described in the earnings announcement we released yesterday and in our annual report on Form 10-K for 2020 filed yesterday.

These documents can be found in the Investors section of our website, www.earthstoneenergy.com. Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may vary materially. This conference call also includes references to certain non-GAAP financial measures. Reconciliations of these non-GAAP financial measures to the most directly comparable measure under GAAP are contained in our earnings announcement released yesterday.

Also, please note, information recorded on this call speaks only as of today, March 11, 2021. Thus, any time-sensitive information may no longer be accurate at the time of any replay or transcript reading. A replay of today's call will be available via webcast by going to the Investors section of Earthstone's website, and also by telephone replay. You can find information about how to access those on our earnings announcement released yesterday.

Today's call will begin with general comments from Robert Anderson, our CEO, followed by an operations update from Steve Collins, our Executive Vice President of Operations. Our CFO, Mark Lumpkin, will provide comments regarding financial matters and performance. And then we'll have some closing comments from Robert prior to opening up for Q&A.

I'll now turn the call over to Robert.

Thank you, Scott, and good morning, everyone. We appreciate you joining us for our fourth quarter and year-end 2020 conference call. 2020 certainly presented many unexpected challenges, but our solid results are evidence of the strength and resiliency of Earthstone. We achieved a 14% increase in production in 2020 despite a 68% reduction in capital expenditures from the prior year, with average daily volumes exceeding our production guidance by about 6%. Although oil prices declined dramatically in 2020, our strong commodity hedge position helped us keep adjusted EBITDAX essentially flat with 2019 and generated over $72 million in free cash flow, providing us the ability to reducing our outstanding debt by nearly 1/3. We delivered on our 2020 goal of reducing our leverage ratio to below 1x adjusted EBITDAX, coming in at about 0.8x for 2020. Mark will provide some additional results for the year in a moment.

Our strong financial position supported our ability to execute on our growth strategy of increasing scale with high-quality accretive acquisitions. I'll spend a few moments talking about the acquisition we did. This acquisition of Independence Resources Management, or IRM, which was announced in December and closed on January 7, 2021, added complementary Midland Basin assets. It increased our production and adjusted EBITDAX by approximately 50%, while having a minimal impact on leverage. The $182 million acquisition of IRM was underwritten by a strong PDP value of approximately $173 million and enhances our drilling inventory by about 70 operated drilling locations from IRM's core acreage in Midland and Ector counties to our existing drilling inventory. We expect the IRM acquisition to result in significantly increased production in 2021 with very minimal incremental general and administrative costs, allowing us to continue to achieve high margins in our operations with the benefit of added scale.

A large majority of IRM's production comes from its core acreage in the Spanish Pearl project area in Midland and Ector counties. The approximately 4,900 net acres there are located in well-delineated areas with existing producing wells on all sides from various operators and further derisked by IRM's own development on the acreage, which is about 93% operated and 100% held by production. The Spanish Pearl locations compete for capital with our Midland and Upton County inventory, where we estimate IRRs ranging from 70% to 90% on a 10,000-foot lateral based on $50 oil and $2.5 gas flat for life. Integration of the assets has gone well and is a complement to both our folks at Earthstone and the IRM team. We are pleased with how smoothly the integration has gone and are fortunate to have been able to retain the large majority of IRM's field personnel. And for those of you in the field from IRM listening today, welcome aboard.

We should start to see the results of deploying our operating approach to the IRM assets by midyear, which we expect will result in some improvements on the operating efficiency and cost side. We are also looking forward to including IRM assets in our 2021 drilling program and seeing those results in the near term.

In terms of our 2021 capital plan that we have previously outlined, the 1-rig program will be funded well within our expected operating cash flow, resulting in significant free cash flow. We will continue to pay down debt while considering options for a second rig. Beyond our drilling and completion plans, we continue to be focused on adding additional scale through acquisitions while maintaining our financial discipline.

Now I'm going to turn the call over to Steve Collins to provide an update on operations. Some of you on the call today know Steve and that he manages all of our operations. Steve has been with us at Earthstone and predecessor companies and has worked with Frank and me for over 25 years. Not today either, Steve or myself, but actually, we worked together as field engineers in the early 1990s. So with a long history working together, I'm happy to have him join us today. So Steve, (inaudible).

Thanks, Robert. I'm glad to be on the call. In the fourth quarter, we began completing wells we had drilled but not yet completed when we paused our 2020 drilling program last spring. In December, we completed the 6 wells in our Ratliff project in Upton County, in which we hold 100% working interest. I won't rehash production results since we released that with our operations update in January, but we're very pleased with the performance of these wells.

We exited 2020 with 5 wells still awaiting completion, which are on our Hamman 30 Unit, also located in Upton County. We have finished completion activities and expect to turn these 5 gross/3.7 net wells to sales in the next week or so. We've also resumed our drilling program. With the rig, beginning drilling operations in the past week on a 3-well pad in our Hamman Midland County project, where we plan to drill 1 well in each of the Jo Mill, Lower Spraberry, Wolfcamp B Upper reservoirs. We will then move the rig to the acreage that we recently acquired from IRM, drilling a 4-well pad in the Spanish Pearl project also in Midland County.

Our full year 2021 capital expenditure plan anticipates that we will drill 16 gross/14.8 net operated wells and spud an additional 5 gross or 3.7 net operated wells. Including the 5 gross wells in Upton County that will be turned to sales next week, we anticipate turning to sales a total of 16 gross or 13.5 net operated wells in 2021. Throughout 2020, we continue to focus on cost management and driving down operating costs, with 2020 lease operating expenses averaging just $5.21 per BOE for the year. With the addition of the IRM assets, we anticipate a modest increase in LOE in 2021, but we'll remain acutely focused on cost management throughout the year. We will incorporate some of our operating philosophies and artificial lift changes, like moving from electric submersible pumps to gas lift, which should reduce operating costs in the long term. The enhanced scale of our operating business should also help drive some cost savings over time as we consolidate service providers.

Now let me address the impact of the extreme weather -- winter weather we had in February. As other operators experienced, everybody experienced, the harsh weather and loss of power caused significant disruptions in our operations. I'm happy to say that the large majority of our oil production was back online in 4 or 5 days, and operations are now back to normal with no permanent impacts. Once we gather all the sales numbers, we expect that February will be down about 25% from our plan.

I'll now turn the call over to Mark to review the financials. Mark?

Yes. Thank you, Steve. Good morning. I'm going to start with a recap of our balance sheet and liquidity. We generated $8.4 million of free cash flow in the fourth quarter, which brought us to $72.2 million of free cash flow for the year. As you all know, we've been focused on paying down debt with our free cash flow. With another $15 million of debt reduction in the fourth quarter, for the year, we reduced debt by 32% from $170 million to $150 million at year-end, and our debt-to-adjusted EBITDAX ratio was similarly improved, decreasing from 1.2x at year-end 2019 to 0.8x in 2020. As Robert mentioned, we did close the IRM transaction in early January. So when adjusted to include the debt related to the IRM acquisition, we had an estimated $245 million in net debt outstanding at year-end, with the borrowing base of $360 million and total liquidity of approximately $115 million.

With combined Earthstone plus IRM 2020 EBITDAX of $223 million, leverage as measured by total debt-to-adjusted EBITDAX at year-end would have been 1.2x. As of March 1, we had reduced our net debt by approximately $27 million compared to the $245 million of year-end net debt adjusted for IRM, which also increased our liquidity by $27 million. While we won't necessarily pay down more net debt in the first quarter as the impacts of operational downtime in February impacts cash flow, we do anticipate continued paydown of debt throughout the year. Our accrued capital expenditures totaled about $20.3 million in the fourth quarter and $66.8 million for the year, which was slightly below the midpoint of our 2020 guidance. This represents a 68% reduction in capital expenditures on a year-over-year basis as we drastically cut capital expenditures amidst the oil price collapse last spring, as you all know.

As detailed in our previously released guidance, we expect to spend $90 million to $100 million in total capital expenditures this year, utilizing the 1 rig that we recently deployed. Based on this spending plan, we believe we will generate significant free cash flow and intend for the primary use of that significant free cash flow to be debt repayment.

Now looking at our income statement, let's start with the top line. Total revenues in the fourth quarter of 2020 were $36.7 million. Our average price in the fourth quarter was $26.92 per barrel of oil equivalent. By commodity, our average realized price for crude oil in the fourth quarter was $41.43 per barrel. Natural gas averaged $1.65 per Mcf and NGLs averaged $17.18 per barrel. For the year, our average price per BOE was $25.85. Fortunately, with our hedging strategy, we also realized just over $17 per barrel of oil produced in 2020, and that amounts to just over $10 per barrel of oil equivalent when including all components of our production.

From a production standpoint, our fourth quarter sales volume averaged 14,809 barrels of oil equivalent per day, which was comprised of 48% oil, 28% natural gas and the remaining 24% from NGLs. As Steve mentioned, we did bring on 6 new wells near year-end, and they did not contribute meaningful to the fourth quarter. For the full year of 2020, average daily sales volumes increased 14% compared to 2019, up to 15,276 BOE per day, which exceeded our production guidance by 6%. On the expense side, on a per unit basis, our all-in fourth quarter cash cost, which includes lease operating expense, production and severance tax, cash G&A and interest expense came in at $12.2 per barrel of oil equivalent and $11.08 for the full year. Our lease operating expense came in at $5.26 per BOE in the fourth quarter and for the full year averaged $5.21 per BOE, which was well below our guidance range of $5.25 to $5.50 per BOE.

On the general and administrative side, our adjusted per unit cash G&A expense was $4.57 per BOE in the fourth quarter, bringing cash G&A expense through the year to $3.25 per BOE. The lumpiness in our fourth quarter cash G&A is largely a result of awarding cash incentive compensation in the fourth quarter due to successfully achieving our 2020 operating results compared to a typical year in which we would accrue awards more evenly throughout the year. As aside on G&A, with continued reductions in our cash G&A, the $18.2 million in 2020 is the lowest we've reported since 2016, when we were a much smaller company with no Midland Basin operations and produced less than 5,000 BOE per day, so less than 1/3 of our current production.

The continued reduction in cash G&A and growth in production have allowed us to continually improve our cost structure, reducing cash G&A per BOE by 54% from over $7 in 2017 to the $3.25 per BOE in 2020. With the acquisition of IRM and our continued focus on managing cost and very little incremental G&A related to the Independence -- or IRM acquisition, we do expect to continue to lower our per unit cash G&A cost in 2021 to an implied $2.77 per BOE at the midpoint of our guidance. And like we do in all aspects of our business, we continue to focus on improving our cost structure and our margins. So while we've made good progress, we're not done yet.

From an income standpoint, we reported GAAP net loss in the fourth quarter of $18.4 million or a loss of $0.28 per year, which included an unrealized loss of $21.6 million on our derivative contracts. Our adjusted net income was a profit of $5.5 million or $0.08 per diluted share in the fourth quarter. For the full year 2020, we reported a GAAP loss of $29.4 million or a loss of $0.02 per share and adjusted net income for the full year was a profit of $29.7 million or a profit of $0.46 per diluted share. We reported adjusted EBITDAX of $29.8 million in the fourth quarter, bringing full year 2020 EBITDAX to $144.3 million, which was down only 1% from 2019 despite oil prices dropping by 31% and our CapEx being reduced by more than 2/3.

As is our practice, we remain well hedged for 2021, with swaps on approximately 85% of the midpoint of our oil guidance and on approximately 71% of the midpoint of our guidance for gas at average prices for oil of a little bit over $48 on a WTI basis, plus a little bit of positive differential and $2.81 for gas. We have also been chipping away at our 2022 hedge program and expect to do so over the course of this year.

Going back to our production levels and the impact of the winter weather. As Steve mentioned, our production was clearly impacted, and we estimate the impact to be roughly 25% of volumes in February, which will obviously impact our first quarter results. From a full year standpoint, we think this is roughly a 2.5% impact on production for the year or about 500 barrels of oil equivalent for the year. Given that our production guidance includes a plus or minus 750 BOE range from the midpoint, we are not adjusting our production guidance at this time, but this impact will clearly bias more toward the lower end of the production range. With that, I'll turn it back to Robert.

Thanks, Mark. A lot of information we provided both yesterday in our press release in our K and today this morning. As you can tell, 2021 has gotten off to a strong start for us. We are super excited about the additional scale and the drilling opportunities as a result of the IRM acquisition. But as you can tell, we are just getting started, and we have a great platform for continued growth. Earthstone is well positioned with a good inventory of high-margin, low-cost drilling. And while we are pleased to see a more attractive commodity price environment emerge, we remain focused on a 1-rig program for now, but continue to consider whether adding a second rig to the now larger combined asset base will make sense later this year.

We're very optimistic about 2021 and the future. We believe our operating plan, which is directed towards areas with the highest drilling returns will generate significant free cash flow during the year. We remain focused on maintaining a strong balance sheet and reducing debt with this free cash flow. However, with the IRM assets fully integrated, we continue to seek additional acquisition opportunities that create further scale and complement our low-cost, high-margin operations. Our focus remains committed on creating shareholder value in everything we do, and we will continue to look at consolidation opportunities through that lens.

Now with all that, operator, we'll be glad to take some questions.

(Operator Instructions) Our first question is coming from Neal Dingmann with Truist Securities.

Robert, my question is, first, just on something you had just mentioned. You smartly mentioned about the potential, obviously, with prices today. And your pristine balance sheet about potentially adding a second rig. I'm just wondering how do you and Steve and Mark, the guys think about the optimal -- when you're looking at this and thinking about the optimal level, is it just purely with prices and what level would give you the best free cash flow? Is it a combination of what -- 1 or 2 rigs, what's going to give you the best combination of sort of production and free cash flow growth? Just wondering when you think about optimal level, what are you all sort of thinking about?

Yes, Neal, it does depend on your scale, of course. And with this added acquisition, that helps, and I think it has to -- we're driven by cash flow. So trying to maintain the balance between growing within cash flow and how much growth we actually get out of that and the timing of all that. So we're looking at it every day. And there are some of us who are anxious to put a second rig to work, and there's some of us who are anxious to walk before we run. And we'll, at the appropriate time, consider that second rig again. But I think it's a balance between cash flow and the amount of capital we would spend.

Okay. And then how do you think about timing -- you've got a -- in the press release, it was good to see. You've already been pretty active on drilling. You talked about even the 4 upcoming IRM, the Spanish Pearl, the 11 Upton. How do you think about that in regards to completion? Or another way, I guess, we look at as analysts is sort of '21 production timing based on those completions, how should we think about those?

Yes. As we've done in the past, we generally complete wells kind of in packages. So we'll get the first pad drilled. We'll be on the second pad, and then we'll -- the plan is to start initiating completion. So I'd say by summertime, we're starting to put some wells online. And then the back half of the year will be the Upton County wells. So it's going to be -- it doesn't make sense to go out there and just complete that 3-well pad by itself, unless we've got that other 4-well pad ready to go. So the crew can just move right over. But part of that is a function of all the service companies and their -- how busy they get over the next few months.

Would you do -- on the 10 or 11, would you do simul-fracs?

We have not explored -- and we have not done that. We've seen other people do that. There's probably some timing efficiency that helps you, but then there's also the logistics on doing that the first time. So -- and it also depends on how your pads are set up. Whether you've got big pads. Our typical pad size this year is going to be around 4, and maybe we'll get one that's 5 or something like that. So then it might makes sense in a bigger pad to have 2 frac crews out there. But we have not done that yet. And not that we're resistant, we just haven't had the right opportunity.

Absolutely. And then if I could sneak one last one. And I just can't help but notice on Slide 16. For the Eagle Ford, you all show the 0 drilling locations there. There seems to be a big market out there right now for production cash flow. As I mentioned earlier, you certainly have a pristine balance sheet, don't need to sell anything, but is this consideration in the Eagle Ford?

It's always been a consideration, even going back to when we bought our first operated asset in the Midland Basin back in 2017, it just won't command any capital. The allocation of capital is much more suited to go to the Midland Basin based on returns. And we'll continue to keep that asset because it gives us a good footprint if we find other opportunities in the Eagle Ford, which there are several things that could make sense for us to pursue.

Next question comes from Scott Hanold with RBC Capital Markets.

You all obviously have a history of looking at accretive deals, and it's certainly been a pronounced part of your discussion here in your prepared comments. Can you just give us a sense of like, given what we've seen in the move in oil prices and even some of these equity valuations, like how do you look at it right now? Is there -- when you look at some of these private opportunities out there, is there more or less interest today? And how do you all think about using your stock as currency?

Yes. Good question, Scott. So we think that there is a pipeline of opportunities out there in various basins that we're focused on, both public and private. I think you're going to see some of the public guys start to sell off noncore assets, which we will review and maybe participate in processes, but we'll continue to talk with private guys who recognize that scale is important. The cash they take today is good, but maybe they want to ride some of the upside. And so we'll use equity and cash. And we're going to continue to focus on each deal separately in terms of the structure of how we do that, whether -- we want to make sure we don't get over-levered and each deal looks a little different and the cash flow profile probably has some impact on what kind of leverage we end up with a deal. So I think -- I don't think that our playbook changes much as prices improve and -- because I think there's still an opportunity to continue to consolidate.

Yes. Yes. But I guess, to that point, too, have you seen sellers change -- the appetite to sell by the privates and others, do you see any change in that given what's happened over the last couple of months?

I think they've maybe accelerated their mindset of selling because you never know how long this cycle of improved prices is going to last. Sometimes that's dictated by some foreign countries. And so we'll decide -- I see some improved activity level of divestitures happening in the market as we speak. There are more guys out there and all the banks are busy advising folks on sales.

Yes. And you did mention that the basins you look at, can you help us define that? I mean, obviously, your focus primarily has been the Permian here. And you've obviously talked a little bit to the Eagle Ford. But like when you look at your play -- your playing field, like how are you thinking about that? Are you -- should we expect you guys primarily focusing on the Permian? Or is there other opportunities outside the Permian that look pretty attractive as well?

The primary focus is the Permian and then secondarily is the Eagle Ford. And beyond that, I'd say that we're not focused on looking at anything else.

Okay. Okay. Okay. I just misunderstood that. Fair enough and I just wanted to...

We weren't going to go to the Appalachians and try and compete there.

And any surprises with IRM? You've had it for 2 months, any surprises so far that you're seeing, good or bad?

We integrated it very quickly. And that goes to the talented folks who did a lot of hard work trying to do that. And I don't think that we've seen any surprises to the negative. The positive is the response, and I'm speaking for Steve, but the positives I hear from Steve are the response from the folks in the field. And being part of a bigger organization, and we're going to spend some capital. And I think they're all really glad to be on board. Steve, anything else that you've seen positive or negative?

No, it's mostly positive. The people have reacted well. They are encouraged by a new philosophy and willingness to put some capital to work and make the changes that we need to make.

Our next question is coming from the line of Dun McIntosh with Johnson Rice & Company.

Maybe for you, Mark. Obviously, you can have both ways to the hedge book. It was a huge benefit last year, not that it's negative this year, but you're pretty well hedged under $50. Just wondering how you kind of think about hedging going forward, with the strip here at 60 for this year, a little below for next year. At what point would you look to start layering that on? And would you maybe leave a little more room for upside with prices higher?

Let me address just 1 thing, and you said it, but just for everybody's reference, we managed for the downside risk a little bit. And luckily, that played out very well last year. And yes, we've given away perhaps some upside this year. But you can't have it both ways, right? And so it's balanced and more debt, more hedges, more activity. You underpin a drilling program at whatever price deck you've hedged is another way to look at it. So it is difficult when prices move around and investors or analysts think that you've left too much on the table. I'm comfortable where we are this year, and we'll continue to think about 2021 as we layer in a few more hedges. Mark?

Yes. He means 2022.

Yes. I mean we've got this philosophy that post-OPEC at the end of 2014, it was a complete paradigm shift. And we've traded generally in a range of 40 to 70. Our thought has been, let's make sure we're really well hedged for 1 year and moderately hedged for next year. And in some cases, we've hedged further out there. Some of the hedges we had in 2020 that we benefited from were done in 2018. And one in particular, I remember, is $73.06. We hedged that out longer because the strip was at a contango and it was really strong. Here, again, if the strip continues to strengthen and particularly swaps in the contango, we may hedge out further. I mean we're sort of done hedging 2022 for right now. But there's no doubt we'll continue to chip away at that through the course of the year. And probably not for a couple of months again. But we look at it, I mean, literally every day and think about it. And yes, we are a little bit more biased to downside protection than probably some of our peers are. And that's just our strategy and discipline. We just try to stay consistent with it. And like what it does throughout the cycle, bigger picture.

I appreciate the color. That's good to hear. And then quick follow-up. Appreciate the color on the impacts relative to production with the winter storms. But anything else that we should be aware of, getting that rig up and running, do those completions come on? I mean I know they're on, but that -- everything come on on time? Just -- and then maybe any expectations around maybe additional CapEx or OpEx with any -- fixed any damages that might have occurred?

Yes. I mean everything's -- we're relatively early in the year, even though we have almost 90 days into it. But everything is on schedule. And so far, so good from a scheduling standpoint. No major impact from extraneous cost standpoint related to the winter storms. Maybe a well or 2 needs a workover, but they probably needed it prior to that anyway. The only thing I could say on additional CapEx is with the improvement in prices could we see some non-op activity? And obviously, that's -- we're not aware of anything other than what we've already got in our capital plans. But could we have a partner who decides they want to pick up another rig or increase their activity level, and would we get some additional AFEs this year. So far, I don't think that's going to happen even with the improved prices, because their plans were probably pretty well set. So our focus isn't that we're going to see a bunch of CapEx increases from our non-ops, but it could.

The next question comes from Noel Parks with Tuohy Brothers.

I just had a couple of things. When you're talking about the targets that are going to be drilling, you mentioned the Jo Mill. And I hadn't -- we paid a lot of attention to how results been trending in that formation. Do you drill it on your existing acreage, before the acquisition did you drill it? And is it pretty well established as far as what you expect from results there? Or is there -- there's still some work to be done?

Yes. No, it's a well-established reservoir target for lots of companies. The Jo Mill we're drilling is on our existing assets in Midland County. And there's lots of data in Midland County to show you how good the Jo Mill is, and it is a good target. We participated in some non-op Jo Mill wells last year and in a stack of Jo Mill plus lower Spraberry and Wolfcamp. I believe our guys have told me that the Jo Mill is probably the best of that group of wells that we participated in. So not a new target and not something exploratory. You know us -- the most risk we're going to take is sort of a (inaudible) at this point. And that's a step out of maybe going to a Wolfcamp C like we did in our Upton County block where Apache had drilled a couple of C wells and had really good results, and we had similar geologic characteristics. And so we drilled Wolfcamp C wells also and had good outcome.

Great. And thinking about -- I want to get your thoughts on maybe where you might be headed as far as frac intensity goes? And we're in a pretty different, much better spot oil price environment now than we were just at the beginning of the year. The possibility that services might be getting a little tighter. And of course, when things were -- prices were really weak, so I think there was a lot of interest in maybe scaling back fracs just to see if you -- if you actually were benefiting from the incremental spend to do bigger ones. So just are you inclined to head bigger at this point? Or do you still think there's anything to be learned from what you can achieve by scaling back a bit?

Steve is the expert here on our team about that. My only comment is that it's not necessarily price that dictates that as much as kind of where you are in the development. So you have offset wells and things like that. But I'll let Steve address the intensity side of it. We've been pretty consistent.

Yes. We've been really consistent, and we've not changed frac design based on price. We try to make the best well we can every well. Like Robert said, whether -- it's usually -- we usually look at what's open around that wellbore, parent/child relationships, things like that. And we just try to make the best well every time where we tweak our designs a little bit every time, and we seem to see our type curves moving in the right direction. And so I don't think we're going to change considerably.

The next question comes from John White with ROTH Capital.

Congratulations on a very nice year in a troubling environment. Just curiosity, on the February production and the winter storm, was there one particular reason or one particular problem or well freeze up midstream gathering, was there one item that was predominantly the result of the storm?

Steve, it's electricity, right? Electricity was the biggest, it was everything. The oil trucks couldn't run the roads. If -- you couldn't put your saltwater disposal to the third-party disposal because they didn't have electricity, so they couldn't pump it away. Even our own people had trouble getting around. So it was a combination of everything. And then when you did get it going around, then the midstream didn't have their compressors running, so you had no place to go with the gas. So the whole basin is a giant balancing act, and it just totally got derailed. So it's back up in balance and running now, but it did take a week or 10 days.

Okay. That's good color. I appreciate that. And on the possibility of adding a second rig, is there -- what's the principal factor there? Is it seeing WTI go above 70? Or if you get some non-op increased activity, would that preclude you from adding a second rig? I know you said you don't anticipate a lot of non-op CapEx. But just give us a little more of your thinking on adding a second rig.

Yes. It's not price. I think we're in a pretty good price environment, at least in the near term. And it's -- we've got plenty of free cash flow this year, even if we do get some additional non-op activity. I'd say it's making sure we can operate this rig and the whole logistics of the first one going smoothly and then bringing in the second one. We're not staffed to run multiple rigs like 5 or 6. And so we're pretty small still. And let's get this one running pretty efficient, and then we'll bring in the second one later in the year is kind of what we're looking at and considering. It's also a function of what kind of services are going to be available a little further down the road.

Our next question comes from Gail Nicholson with Stephens.

Could you guys remind me what percent of your LOE is fixed versus variable? And when you look at the workover activity in '21, how does that compare to '20? And then are you doing any initiatives this year to potentially improve LOE on a go-forward basis?

Well, that's a lot of questions there, Gail, that will unpack. I don't know the exact breakout between variable and fixed, maybe Steve does. We do break it out in our reserves in the way we calculate things. I wouldn't guess that it's 50-50, but maybe somewhere around there.

I don't know that exact number, Rob. It maybe a little less than 56, but it's variable, which...

Yes. Then the workover side of it, we've got some additional workover plan because of IRM and their wells and just their operating conditions, right, Steve, I mean we're...

That's correct. And we see some upside in the IRM's wells, and we'd like to put some capital towards that. And with the increased prices, some of those workovers -- our workover budget may grow a little bit this year because all those wells need some attention. We can change lift methods and hopefully reduce failures, which -- so that will take a while to show up. But in the long run, that's where you make all your progress.

And Gail, maybe I'll just add from a little bit of a historical financial perspective, we've typically -- well, I shouldn't say typical because it's moved around. A couple of years ago, in 2019, our workover component went up pretty significantly. And there were some specific reasons for that. And there were sort of just a wave of activity that needed to be done. That happened. I mean sort of year-over-year basis in 2020, our workover went down by about 2/3, which -- part of that was there really was a pretty big wave in 2019. What we recorded sort of internally on the workover piece for 2020 was actually pretty similar to what we did in 2018. So there's a bit of -- in 2018, so there's a bit of a spike in 2019. With IRM, there's unquestionably a lot more workover we're going to do on that basis.

Our own assets, probably not that dissimilar versus last year. But we've identified quite a bit more workover work that either needs to be done or we want to do as we do some things different from a lift mechanism standpoint and other things. So this year, we definitely have more workover built into our guidance and our expectations than last year. And our hope is, well, one, maybe that doesn't come in quite as high as we think it will. It could be higher, but we think it's a reasonable number that we've got embedded in our guidance, in our forecast. Two, our hope is we have a little more of an elevated workover this year, and then it's sort of back to kind of combined normalized Earthstone plus Independence levels next year.

And Gail, I might add, and Steve mentioned this and so did Mark. But the way we look at this is you may -- you spend some money today, you -- that lasts a really long time because you've changed the operating philosophy or what have you and your run time stays up. So it benefits on the LOE side, but also on the production side. And we try and fix things just one time and it lasts a really long time and get some really good run times out of the things we're doing.

So it's fair to assume that in 2022, workover will likely be less than in '21, and there's a good chance that LOE sees further improvement on a go-forward basis in the $6 to $6.50 this year.

Yes. I mean I think that's fair. I mean if you look at last year, and of course, this is Earthstone stand-alone, because the acquisition didn't close until early January, we averaged $5.21 per BOE for the full year of total LOE, which includes the workovers. That might have been just a little bit low just because of the environment and some things we did to try to not spend as much money in 2020 in the environment we're in. But you compare the $5.21 that we had on Earthstone stand-alone basis last year to the midpoint of our guidance for this year, $6.25, so it's a buck higher. I mean you sort of would scratch your head about why is that? Well, I mean, really, the driving factor is Independence. Ours is probably maybe a little biased up from the $5.21 on, but it's not like $7. But the bigger piece is just the chunk of additional expenses we expect, some on just kind of the general LOE side, but largely a step-up in workover expense.

Great. And then you guys are targeting over 60% of your oil production on pipeline in '21. I think that's up versus 42% in '20. When do you get to 100%? And does the move on to pipe improve your realized pricing on the oil side?

Yes, it does improve our pricing. Trucking is a little bit more expensive typically, although in 2018, I think we saw trucking rates at 0 at different times just because of the competition for barrels. It's probably for us impractical to be 100% on pipe just because we don't have big consolidated blocks of acreage. If you did, then you could probably get there. But when you got an outlier asset that has 10 wells and is a long way from a pipeline infrastructure, that's probably always going to be trucked. So at this point, we don't have our target out there if we will want to get to, but we've got a couple of other areas that we're are planning to put on pipe, and it's just a matter of the timing between us and the gatherer to get all that done. It probably won't happen this year, but probably next year.

And then on the realized pricing improvement, should we think just like maybe $0.05, $0.10 on an average basis company wide? Or any thoughts on that?

It's probably higher than that, more like maybe $0.50. Pipeline barrels are less than $1 for the most part and truck barrels sometimes run $1.50 or more.

(Operator Instructions) Our next question is a follow-up coming from the line of Dun McIntosh with Johnson Rice & Company.

I'm Sorry. I think we talked about it a little bit with the impacts, but just sneak one. If we could just get a little bit of color on kind of the trajectory of that production profile this year, kind of when you think about the full year guide and how you kind of get to that midpoint?

Yes, Dun, thanks. That's a good question, it's Mark here. Let me try to address that one. So pre-February, I think we're a little more kind of Q1 was probably the highest quarter from a reduction standpoint. And it still might be. But our sort of forecast was we brought these 5 wells online -- excuse me, 6 wells online at the end of last year. And it was pretty flushed production for the first quarter. And it still is minus the downtime in February. With the February impact, it sort of shifted the shape just a little bit where Q1 is going to be 8% lower than we thought it was going to be just based on February being 25% lower or something in that general ballpark. So that's come down a little bit versus what we thought 3 or 4 weeks ago. That ends up making -- like our profile, it's pretty flat throughout the year. I mean that's probably still hitting something what the (inaudible) on it in the first quarter, but probably not a tad higher than that, with the midpoint of our guidance being 20,250 barrels a day.

That really kind of looks like pretty flat production throughout the year. A little bit of a decline in Q2 and probably so in Q3 and maybe a little bit of pickup in Q4. But it's pretty flat. I mean, I'll say this, we obviously could have, in fairness, reduced the midpoint of our guidance based on the impact because it was probably 500 to 600 BOE per day for the year. Typically, we like to be a little conservative on the guidance, and the midpoint pre the February storm was a little bit lower than the midpoint of our forecast. Now our forecast is lower. It's still within the range of the guidance we gave, but it's definitely on the lower end. So you really just see a bit of a hit in the first quarter, which makes the shape throughout the 4 quarters a bit flatter. And again, probably a little bias lower versus the midpoint of a range.

Dun, I think it just gives us a good challenge to overcome what happened in February and overcome the increase from the IRM additional LOE expense that we see. And so our goal is to try and beat handily what we put out there in guidance, but our models and everything like that are pretty in line with what you see out there. So we've got some good challenges ahead of us that are good incentives for our guys in the field.

We're up to the task, and we continue to hold our feet to the fire. And our field folks do a fantastic job with that, and we're all aligned and very focused on that every day of the year.

It appears we have no additional questions at this time. So I'd like to pass the floor back over to Mr. Anderson for any closing comments.

Thanks, everybody. Appreciate your interest and your time today, and we'll catch you on the first quarter call. Thanks.

Ladies and gentlemen, this does conclude today's teleconference and webcast. We thank you for your participation, and you may disconnect your lines at this time.