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Good morning and welcome to Earthstone Energy's conference call. [Operator Instructions] 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 first quarter 2021 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 Form 10-Q for the first quarter that we 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, May 6, 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 comments from Robert Anderson, our President and CEO; followed by remarks from Steve Collins, our Executive Vice President of Operations; and Mark Lumpkin, our CFO; and then we'll have some closing comments from Robert. I'll now turn the call over to Robert.
Thank you, Scott, and good morning, everyone. We appreciate you joining us for our first quarter 2021 conference call. We had a very successful start to the year, as evidenced by our strong first quarter results and a quarter full of activity. We closed IRM, we resumed a drilling program, we completed wells, and we announced another acquisition.
In terms of results, production volumes rose 37% over the prior quarter to a little over 20,000 barrels of oil equivalent, or BOE, per day, resulting from the contribution of the IRM acquisition that closed in early January and from turning 6 wells to sales late in the fourth quarter. This production more than offset -- sorry, this more than offset production losses due to the freeze in February that resulted in roughly 1,500 BOE per day downward production impact for the quarter. Additionally, we did a great job of controlling operating costs in the first quarter, which came in at $5.93 per BOE, lower than our guidance for the year.
The increased production volumes, cost control and improved prices drove a 47% increase in adjusted EBITDAX to $43.8 million in the first quarter compared to fourth quarter of 2020. With our capital expenditures coming in under $10 million for the quarter and fairly minimal interest expense, we generated a strong, almost $32 million in free cash flow.
In March, we resumed our drilling program by putting one rig to work. And in a few minutes, Steve will walk you through those activities in addition to updating you on the integration of the IRM assets, which has gone according to the plan.
We now look forward to the closing and integration of our next acquisition, the Midland Basin operated assets of Tracker Resources, which we announced on April 1. The transaction is expected to close early in the third quarter and be highly accretive to all key financial metrics while allowing us to execute on our strategy to continue building scale within our low-cost structure. The announced $126.5 million acquisition price carries a PDP PV-10 value of $153 million. So we are buying this at an attractive price, and it further increases our position in the Midland Basin by providing a meaningful increase in production from stable, low cost and relatively lower decline producing assets. We have estimated that these assets will add about 6,000 BOE per day in the second half of the year.
We also add 49 Wolfcamp locations to our inventory. However, we don't have plans to spend capital on these assets this year. Although the producing assets and locations are gassier than our existing properties, the improvement in gas takeaway and NGL pricing do provide for attractive returns.
As a reminder, we are using a consideration mix of approximately 2/3 cash and 1/3 equity. When combined with the free cash flow generated from the assets, the Tracker acquisition is about leverage-neutral, and we expect to end 2021 with 1.25x leverage with our goal of being much lower than that. Tracker is a complementary next step in what we view as continued progress in a multi-step consolidation strategy.
We are excited to get these 2 deals integrated into our business as they fit nicely with our efforts to increase our scale and efficiency through consolidation, which is a key and consistently articulated strategy for us here at Earthstone.
As we highlighted in our investor presentation, the combined IRM and Tracker transactions will increase our base production volumes significantly. It will also add approximately 120 attractive drilling locations while allowing us to maintain our low-cost, high-margin operating metrics and improving our per unit G&A costs as we add minimal incremental staff.
Now I'll turn the call over to Steve to provide an update on operations.
Thanks, Robert. Good morning, everyone. First off, let me update you from our call -- from our March call regarding the impact to the storm in February. Although we only lost production for approximately a week, it took a little longer for third-party gas plants to get back to full operating capacity. We did not have any material increase in expense due to the storm.
Now, I'll move on to the current operations. We have a good pace of activity underway. As I mentioned in our last call, we completed and turned to sales 5 wells in our -- in Upton County in late March. Those wells will be a nice benefit to the second quarter. These 5 gross, 3.7 net, wells are in our Hamman project area and are tracking type curves nicely. So it's still early. These are shorter laterals with average completed lateral length of a little under 4,600 feet and targeted the Wolfcamp A and Wolfcamp B zones. Peak 30-day production average 493 BOE per day per well with 86% oil content.
From a cost standpoint, these wells are completed with an average all-in front costs of $43,000 per stage. Given that these are shorter laterals which creates some minor cost inefficiencies plus an upward price pressure on the service side compared to lows we saw in the fourth quarter, these wells had a higher per stage cost than the long laterals we completed last year. These costs fall in the range of what we expect for the balance of the year.
As you also know, we resumed our drilling program in March with all 3 of our Hamman -- with our 3-well Hamman project in Midland County. We drilled a Jo Mill, a Lower Spraberry and a Wolfcamp B well. We expect to begin completing these wells in the second quarter and have them online by early third quarter. We are currently moving the rig to a full well pad on the Spanish Pearl acreage acquired from IRM. We are drilling 2 Lower Spraberry and 2 Wolfcamp A wells, all of which are 5,000-foot laterals. These are the only IRM wells planned for this year under our current one-rig program. We're excited to get these wells drilled and are intentionally drilling the shorter laterals so we can apply any lessons learned as we will likely drill 10,000-foot laterals when we bring the well -- bring the rig back to the IRM acreage.
We are pleased with the performance of the new IRM assets and glad to have the IRM field personnel on board with us at Earthstone, which has really helped the operational integration go very smoothly. We were focusing on optimizing the production and operating expense of the IRM wells. One of the main ways we were doing this is by changing the lift method from electric submersible pumps, or ESPs, to gas lift or gas-assisted plunger lift. Although it's early, we've been very pleased with the results on the wells that we've changed the lift method on. Let's see where -- there's more work-over costs associated with ESPs. So as we shift wells to gases over time, we ultimately expect to improve the run time and reduce failure rates and aim to decrease the per unit LOE down the road.
On that, we'll turn the call over to Mark to review the financials. Mark?
Thank you, Steve. So from the financial side, we're going to start today as we usually do with the recap of the balance sheet and liquidity, and then get into some other financial matters for the quarter.
As you guys know, for us, strong liquidity remains a focal point as we continue to increase our scale. And we fortunately have been able to improve liquidity versus what it was in early January when we closed Tracker and used a bit of revolver to do that. So as you may have seen, we recently announced an amendment to our revolving credit facility, which increased the borrowing base to $475 million from the previous $360 million. It also provides for an increase from $475 million to $550 million upon closing of the acquisition of the Midland Basin assets from Tracker and Sequel, and we expect that to be completed early in the third quarter.
Going to the cash balance and debt balance at quarter end. As at March 31, we had a cash balance of $1.4 million and a debt balance of $223.4 million. And this debt balance reflects the IRM acquisition that we closed on January 7 of this year. Adjusted for the recently increased borrowing base to $475 million, we now have a little bit over $250 million of undrawn availability under the borrowing base, which puts us at over 50% available under the borrowing base. Based on the $81.6 million, the cash consideration to be paid in the Tracker acquisition plus anticipated interim period cash flows, that will reduce the cash requirement at closing. We actually expect a slight increase in liquidity at closing of the Tracker acquisition given that the borrowing base will increase by $75 million on closing.
For the quarter, we generated a very healthy $31.4 million of free cash flow, and that compares to $8.4 million in the fourth quarter of last year. This allows us to pretty significantly pay down debt over the course of the quarter with our having drawn up to $260 million of gross debt in early January for the closing of IRM, and we ended the quarter at $223 million of total debt. So you saw $37 million are paydown from early January to the end of the quarter. And really, we anticipate continuing to utilize free cash flow for debt repayment throughout the year.
From a capital expenditure standpoint, we totaled accrued CapEx of $9.8 million in the first quarter. And this really was the result of completing 5 gross, 3.7 net, short lateral wells and initiating drilling operations and having run the rig for about a month of the quarter. We're not currently making any changes to our guided 2021 capital budget of $90 million to $100 million based on running one rig for the remainder of the year, but we expect to update guidance if we do add a second rig sometime after midyear. And also generally, we'll update guidance around production and costs when we close the Tracker acquisition.
Now looking at the first quarter of 2021 financial metrics and starting with top line, revenues for the first quarter were $75.6 million, with oil contributing about 80% of the revenues. From a production standpoint, our first quarter sales volumes were 20,231 barrels of oil equivalent per day and were comprised of approximately 58% oil, 22% natural gas and 20% natural gas liquids. The oil percentage was a bit higher -- or quite a bit higher versus Q4 really due to the addition of the volumes from IRM acquisition, which have a little bit of a heavier oil content than our base production but also from new wells that came online in December and a little bit of production from a pad that came online mid-March; also, a slight impact of ethane rejection during the quarter, which probably took the oil content percentage up 1% or 2% as well.
As Steve referenced, we lost about 20% or so of our February production volumes due to the winter weather, which reduced first quarter production by something close to 1,500 BOE per day. As we previously stated, the first quarter volumes benefited from the 6 new wells turned to sales near year-end and the acquisition of IRM and the about 350 BOE a day impact from the wells that came online in mid-March.
As a reminder, our production guidance for full year 2021, which does not include Tracker, is 19,500 to 21,000 BOE per day. Having fallen right in the middle of that range during the first quarter and considering the completion cadence for the year, production should be relatively flat through all 4 quarters. It might be up a little bit in the second quarter versus the first quarter, but it's a relatively flat-looking production profile, and that's consistent with what we expected when we last visited with you guys in March. We will update our guidance to reflect Tracker again. And also, we just note now, and I think Robert mentioned this, but we've previously put out some indication that Tracker should add roughly 6,000 BOE per day of production on the second half of the year. And of course, the exact timing of when that closes will impact how that gets incorporated into our guidance as we will also look at where we are from a year-to-date standpoint and what it looks like for the rest of the year.
Commodity prices for the quarter. Our pre-hedged realized prices were $57.56 per barrel of oil, $2.39 per Mcf of natural gas, and $24.40 per barrel of natural gas liquids for a total BOE equivalent of $41.32. That's a pretty significant increase quarter-over-quarter, which all those are roughly up by about 40% versus the fourth quarter.
On the expense side, on a per-unit basis, our all-in first quarter cash costs, which we include LOE, production and severance tax, cash, G&A and interest expense in, came in at $12.66 per BOE. And our lease operating expense was $5.93 per BOE in the first quarter, which, as Robert mentioned, was a bit below the bottom of our guidance range of $6 to $6.50 per BOE for the year. And really, that was a really good result for the quarter. That is despite some front-end-loaded work-over expense on the IRM assets and also the impact of the freeze in February.
So when you look at that, we're really pleased with our team's work in the field to achieve this result. And as you know, our focus on both production and cost optimization really permeates through our entire organization. And that includes the IRM personnel that now work for us in the field and are doing a really good job.
We'd like to see a few more months with the IRM assets in our hands preferably without any of the exogenous events like the freeze we saw in February, but we're optimistic that we can maintain these lower LOE costs throughout the year and probably have a bias toward being on the lower end of the range of guidance for the year on LOE and may even be able to beat that. This also does not take into consideration what the Tracker assets will do to our per unit operating costs. They'll have a positive benefit because it is a lower cost asset. So we'll fold that in when we announce Tracker closing and update guidance there as well.
So really, considering how we're performing so far this year and still working on the IRM assets and expect a positive impact from the Tracker assets on a cost per unit basis, we're pretty optimistic that we're going to be able to continue driving costs down. And of course, the ultimate goal is to maximize margin, and that's a key piece of it.
On the general and administrative side, our adjusted cash G&A expense was approximately $5 million or $2.76 per BOE in the first quarter, which is really right in line with the forecast and what we guided externally. Our growth in production has allowed us to continually improve our cost structure over the past number of years, and we've been able to reduce cash G&A down to $2.76 per BOE in the first quarter. That compares to $3.25 per BOE last year and over $7 in 2017. I'd also just note that the IRM acquisition had very little incremental impact on G&A costs, and we really do continue to strive to reduce the cost structure as much as we can and are looking forward the addition of the Tracker assets as we continue to focus on lowering per unit costs both on the LOE and the G&A side.
From an income standpoint, we reported a GAAP net loss in the first quarter of $10.6 million or a loss of $0.14 per share, which included an unrealized loss of $22.4 million on our derivative contracts. Our adjusted net income, which excludes the impact of derivatives and transaction costs, was a profit of $13.4 million or $0.17 per diluted share in the first quarter.
We reported adjusted EBITDAX of $43.8 million in the first quarter, up approximately 47% from the fourth quarter. As is our practice, we remain well hedged for 2021, with swaps on approximately 88% of the midpoint of our oil guidance and approximately 82% of the midpoint of our guidance for gas. And these are average prices of a little over $50 for oil, including the basis differential, which is positive; and a little below $2.50 on gas, which includes a negative basis differential.
With that, I'll turn it back over to Robert for closing comments.
Thanks, Mark. As you all can see, we each spent a little bit of time talking about costs and how we maintain a focus on that, and it's a big focus of ours inside the company with all of our folks. Our strong financial position has continued to support our ability to execute on our growth strategy of increasing scale with high-quality, accretive acquisitions.
We have worked really hard to find, close and integrate IRM, and we will do the same thing with the Tracker assets. And we have been pleased that the IRM and Tracker acquisitions have been well received by investors. We are maintaining our focus on alignment with shareholder requirements by creating value with accretive acquisitions, gaining operational scale and incentivizing our team for performance. This is not a new course for us as we've been focused on incentivizing management for absolute share price growth and corporate performance with our compensation plans. As our investor presentation points out, we are fully aligned with shareholders in our executive compensation program, but there still is a lot more work for us to do in all aspects. And certainly, continuing along the path of gaining additional scale through acquisitions is a large component of our strategy.
With the continued growth of our production base through the IRM acquisition and increased further upon the closing of the Tracker deal, we are generating significant free cash flow on a one-rig program and paying down debt at a pretty nice rate. As I alluded to in March about adding a rig in the second half of the year, we are now more likely to add this second rig sometime after we close on Tracker, and we will essentially have combined 3 companies that were running 3 to 4 rigs in aggregate a couple of years ago into 1 company. And with the strong cash flow profile and attractive drilling inventory, we anticipate still being significantly free cash flow positive even with the second rig. As Mark mentioned, we expect to update guidance around the closing of the Tracker acquisition.
We have the inventory and the operational focus to continue to generate attractive returns via the drill bit and create scale and attractive returns through acquisitions, as we have shown with these 2 recent deals. We are pleased with the strong foundation we have built, and we'll continue to execute our strategy of maintaining a strong balance sheet and disciplined growth. The industry is primed with further acquisition targets that could add scale to our operations, but they must meet our criteria and complement our low-cost, high-margin operations, as well as allow us to protect our balance sheet and continue generating free cash flow. Creating shareholder value remains our primary motivation, and our consolidation opportunities must be aligned with that objective.
Now, with all that, operator, we'll be glad to take a few questions.
[Operator Instructions] Our first question comes from Neal Dingmann with Truist.
Rob, I think my first question for you -- and Steve, just wondering on -- I think in the press release, I see where it sounds like most near-term activity will go towards Upton. Could you talk about -- either with that first rig or potential second, would you be returning back to Reagan or Midland or Ector sooner rather than later this year? Or what -- maybe just talk about plans a little bit.
Sure. So we'll end up with having 7 wells drilled in Midland County, and then the rig will go to Upton County. At the point where we pick up a second rig, we've basically got 4 blocks of acreage, and IRM being a bigger block out of those, but we have 4 blocks of acreage, 2 in Midland and 2 in Upton County. And the rigs would rotate back and forth between those to begin with. And then we'll sprinkle in some other -- either Reagan or [ Arian ] or other areas over time.
Okay. And then just the question continues to be asked out there on forecast. I think even with that second rig, again, if prices remain solid and strong like this, I think you could still continue to throw off some pretty nice free cash flow. When you and Mark and the team look at it, the thought of -- when you get to that, I guess what that ideal level that -- my ideal level might be different than what you and Frank decide these days. But when you do hit that level, what's maybe the most near-term plans for that free cash flow at that point besides maybe minimal -- paying debt, continue to pay down?
Yes. That's something we continue to look at, Neal, but it's -- the first course of business is to pay down debt to some minimal leverage amount. And we don't have that exactly figured out, whether that's 0.5 turn or not, and then utilize any other free cash flow to continue to grow our business. It's -- looking for opportunities, bolt-ons acquisitions in and near where we have operations already probably makes the next step.
Our next question comes from Jeffrey Campbell with Alliance Global Partners.
First, I want to ask you about the CapEx spending cadence. The first quarter of '21 looked like it was about maybe 10% of current guidance, and it sounded like it was mainly completion costs on short laterals. And I think you said you got a rig going in March. So I was just wondering, how do you -- not assuming the second rig, but the guidance we have now, how do you see spending unfolding over the next 3 quarters?
Jeffrey, this is easy. It's basically spread out equally quarterly. So you think we're going to keep the rig busy all year long. So that's sort of a fixed cost, and then you figure out when we have completions and we'll kind of complete wells in batches. And so that completion cadence is about equal over the rest of the year. The production cadence -- end of the year's completions don't really pick up until the first quarter of next year. But that's the cadence. It will be equal through the rest of the year.
Okay. No. I appreciate that. And then my second question is, without -- I'm not asking for too great specifics here, but to help us with modeling, if you decide to bring the second rig on, can you give us a range of cost that you anticipate -- maybe a range of per monthly cost that you anticipate that adding that rig might contribute to the spending?
It's really going to be dependent on when we start. But if we bring a rig on even in the latter half of the year, we're probably only going to have drilling costs and no completion cost until the very end of the year with that second rig just to build up some inventory to frac. So I don't know if it's exactly half, but if you think about what we spent in the first quarter or a cadence of equal for the rest of the year at roughly $25 million or so or $30 million a quarter, you could say half of that capital is to a rig without the completion side. So I don't know. That's the order of magnitude.
Jeff, I would just guess. And again, it depends on timing, and it probably adds $30 million to $40 million of CapEx. And the $40 million probably includes a little bit of completion activity. The $30 million probably doesn't. So it just depends on July 1, which is going to -- and we're not going to pick up rig July 1, but that looks a little different than September 1. But I think $30 million to $40 million is kind of a fair guess.
Yes. That's very helpful. I appreciate that. And for my last one, regarding M&A, this -- I'll ask this in a more broad way. As oil prices are firmed and some analysts are calling for even higher prices, do you think this increases or reduces your opportunity set as you continue to look to consolidate the small-cap E&P space?
It will definitely increase the number of opportunities we get to look at, which I'm not sure that's what you were looking for. Does it make us any more likely to be able to acquire assets? A lot of these asset opportunities go through competitive processes. And our discipline isn't going to change just because there's more activity or oil prices are up. We're going to keep the same financial and technical discipline, and we'll see if we're successful or not.
That was what I was looking for.
Our next question comes from Scott Hanold with RBC Capital Markets.
Just curious, on your pro forma asset base including Tracker, what do you all see as sort of the ideal rig count? Obviously, you discussed a likelihood of bringing the second rig. Is that the ideal pace and cadence with the pro forma asset that we should think about through 2022, assuming obviously no other M&A or bolt-ons? Or is there a point where 3 is really the most efficient because it lines up with, say, adding a full-time frac crew?
Scott, we've been really fortunate, and it's Steve and his team working with our vendors that we're not overly concerned about lining up a frac company with our number of rigs perfectly, that we've got a good relationship with our vendors to the point where they know what our schedule is. So I think if we go to 2 rigs, we can keep our efficiency and our timing about the same. And we don't necessarily have to have 3 rigs running so we can have a full-time frac crew. So I don't know that we know the optimum yet, but I'd say right now, 2 rigs looks pretty good. And we still develop a lot of free cash flow, and we continue to delever to the point where we get sub-1x in 2022 without any issues running 2 rigs.
Okay. That makes sense. And just another question around M&A. Can you just discuss, from a corporate perspective, how capable are you taking on a lot more? Like how big right now is your organization? Could you double your size and still be able to execute? So how is the organization sized for potential consolidation down the road?
Yes. That's a great question. And we are sized to be able to handle more production, maybe not an activity but maybe not double at the moment. So every transaction is a little bit different. In these 2 transactions, it's very minor additions to our staff in the office. Obviously, there's some field staff, and that's through LOE, and we'll continue to work hard on that. So I don't have a real good number for you other than we have the capability and the motivation to continue to grow. And we've got the management team and the management plans and the next level of authority in place to where we can really handle more than what we're doing right now. We have a great staff, great team, and I know we can accomplish a lot more.
Okay. I understand. And if I could have one last one here. And you all talked about some -- at least from the -- I think from the frac cost, it's going up a little bit from lows in 4Q. And noticeably in your presentation, on Page 14, where you show the 2021 expected range, it went from $40,000 to $45,000. And obviously, it seems like you're able to handle this in your capital budget. If you could confirm that was sort of baked in there originally or there's a little bit of leeway for that plus.
Secondarily, if you could discuss like where specifically is that pressure coming from.
Sure. Yes. I'll handle the first part and let Steve handle the pressure part but -- or where the pressures are in our costs that we're seeing. But the first part is, we definitely had a little bit of inflation built into our capital plans and thoughts for the year. We just didn't know what it was going to be. I think we were surprised a little bit on some of the costs continuing to inflate. We were hoping they would subside after the first quarter. Steel prices, for instance -- and I stole some of Steve's thunder. But steel prices, for instance, we thought might level off, and they continue to be -- still continues to be a hot commodity in the entire economy of the world and grow. So -- but we definitely had some inflation built into our thinking. So Steve?
Yes. Rob, that -- you're right on the drilling side. It was the steel. On the completion side, probably 2 -- everything has drifted up just a little bit, which we expected. Sand prices probably are the largest factor in that, but they have leveled off pretty good. As the sand suppliers kind of ramp up their production level and their employment level, things are getting a little better. And fuel cost is a big one, too. Diesel has gone up quite a bit. So those are probably the 2 biggest numbers, but they also seem to have leveled off. So I think we -- our models are correct.
Scott, it's Mark. I would just add in, in the fourth quarter, we kind of felt like that was the lows on the frac side, and we completed a longer lateral pad for a little under $38,000 per stage. That was really good. What we just did here recently was more like $43,000 a stage. That was a short lateral. As Steve mentioned, there's some cost inefficiencies on the short lateral. And because that was like 4,600-foot laterals at a smaller pad, like that probably -- $43,000 on that pad is probably equivalent to something more like $40,000 on a longer lateral. So just a little context there.
And yes, we did bump up the range for the year from $40,000 to $45,000 partly because we do have a little bit of a shorter lateral program in place than we probably will next year, but also just a little bit of cushion on the cost side. It doesn't affect what we think it will ultimately deliver. As Robert mentioned, we had a little bit of cost inflation baked into what we put out for guidance, but it probably takes away the cushion.
Our next question comes from John White with ROTH Capital.
Congratulations. I thought it was a strong quarter. You reported significantly higher NGL price than I was expecting, and I've seen several other companies report higher-than-expected NGL prices. I'd be interested in your comments on that market and the strength behind it.
I'll tell you one little piece. Do you buy propane, John? Go look at your propane costs because they've gone up tremendously. I buy a fair amount of propane, so do Steve, just because of where we live, but that is one key. Mark dives into the details. I'll let him handle it.
Yes. Thanks, John. It's a good question. Yes. We love the propane pricing and the NGL pricing in the first quarter, and there are some positive things going on there and potentially some more positive things in the future. The biggest piece is if you look at a barrel of liquids, about 35% of it is propane and about 35% is ethane. Propane prices were exceptionally strong in the first quarter. They've come down a little bit since the quarter in April. I think there was a weak period where they were down about 15%, but they've kind of leveled off and actually flipped into a little bit of contango relative to Brent here recently. That's strong pricing.
I'll also say that we did reject ethane in probably about half of the volumes for the quarter. The impact of that is we have a little bit lower overall reported volumes. It probably shaved 400 or 500 barrels a day equivalent off of our production for the quarter, but the result is you get a higher NGL price, probably $1 or $2, and a slightly higher gas price. So that also sort of added a little bit of boost to the NGL pricing because you end up with less ethane in the barrel. So it's a heavier barrel that you're going to get a better price per dollar of the barrel for.
I'll also say that here, we're in a situation where a year ago, there was tight transportation and fractionation of Permian liquids, and that's really flipped. There's very adequate availability of fractionation and takeaway capacity. And it sort of flipped the dynamics around in terms of -- we've got a little more of a chance to go try to negotiate some better rates on the fractionation in particular. And we're actively doing that. I'm optimistic that it's going to give us a little bit of, other things being equal, boost to the NGL prices going forward, but that's not done. And I would say it was really reflected in the first quarter, but it's positive there. The propane market, in particular, it's very tight. It's not necessarily correlated with WTI, and parts of the barrel are. But propane is the biggest piece that's not necessarily correlated with WTI. And we're pretty bullish on propane just given where things sit from production and storage and potential demand perspective.
So that's really a strong result. I mean honestly, we lost a chunk of production in the quarter because of the February freeze, but the NGL price increase from a cash flow standpoint almost completely offset that.
I appreciate those details. So to sum up, it's ethane rejection and stronger propane pricing.
But more of the propane than the ethane rejection, yes.
Okay. And with all due respect, Robert, I don't buy any propane. I have natural gas piping.
Well, you need to buy some propane, John. Help us out.
Our next question comes from Noel Parks with Tuohy Brothers.
I was wondering, given the couple of transactions now you've done and in the process of doing this year, just a sort of a ballpark. Could -- at the current strip and assuming with higher prices, the sort of cost base revisions from last year, the reserves would have gone away. Can you -- also assuming a second rig. Can you just roughly ballpark what your pro forma proved reserves might look like after the transactions?
That's a good question, Noel. And as we file our proxy, you'll probably see more information regarding that. But if you look at our investor deck, we actually do have a reserve summary in there, and we break it out by entity of proved developed and PUD and then total. And we've got Earthstone, IRM and Tracker. Now the dates aren't exactly the same and it's at $50 oil, but you can do some rough, back of the envelope calculations to see what that does in terms of value. Other than that, we're not going to go too much further into the details until we get our proxy filed.
Fair enough. And I guess I'm wondering a little bit as you look -- well, 2 things. You looked at a lot of deals before you arrived at the ones that you took. So I guess I'm interested in hearing more about what was on the market that you took a pass on. And also just wondering, as you look at the Midland in particular, the more developed, including legacy developed, vertical parts of it and the less developed parts, how do you weigh that in looking at sort of what's attractive to you? Just thinking at least where it's a little bit better [ than that ], maybe inherent more in the way of completion information and what [ factor will ] -- what's going on with -- in the sub service as opposed to the areas with a little more running room that maybe might take a little work though. I guess those areas are probably dwindling at this point.
Yes. That's a good question. And it doesn't matter what we've looked at in the past or what we'll look at in the future. We keep the same view. And as we gain scale and bigger bulk in our production, we probably can look at more deals that have upside or running room. But generally speaking, we like a combination of strong cash flow, therefore, production base. And it's got to fit kind of within our structure that we talked about. It's low-cost structure, high-margin. We might be a little bit ambivalent as what the ratio of oil to gas is. But generally speaking, this basin is outside of -- as you move east a little bit, it's pretty oily, right? I mean, 40% to 50%. The Tracker is a little bit lower than that, but it's still attractive to us because it's a low-cost business.
And we'll continue to look at deals like that. Again, as we gain size and scale on our base production and cash flow, we're going to look for opportunities that have inventory, but we're not going to go out and do a deal that's 100% inventory and borrow money to go do that. In fact, we're -- most of the deals we're looking at come with production. And sometimes, they're a little bit lopsided in one way or the other. But everything we've looked at in the past year or 2 has some component of both of those, and it varies.
[Operator Instructions] Our next question comes from Gail Nicholson with Stephens.
You guys already have a very competitive cash margin with your larger cap peers despite a smaller production pace. But I wanted to dig into the LOE a bit more. When we look at that 1Q '21 level at sub-$6 per BOE, you had some anti-normal weather in the quarter and then I think you had a little bit more normal work-over activity than normal pace. If we remove those 2, how low would the LOE been? And then more importantly, when we look at the transition from ESP into gas lift, how should I think about that improving the LOE going forward? I know you talked about being towards the low end this year to the guide range, but really, when we kind of clear '21, I mean is LOE kind of in a $5 to $5.50 roll in '22 forward?
Well, we would definitely hope so, and we're targeting that as an internal goal, Gail. But we're going to leave some of that cushion on our side for a moment until we figure out how these wells are performing in terms of the cost side. But our target without the LOE is definitely below $5 a BOE -- I'm sorry, without the work-over is below $5 a BOE. The Tracker assets are going to help us. And once we get some new guidance out there for you, you'll see that we're going to be really competitive with our peers then.
Gail, it's Mark here. Just on the first quarter, I mean I candidly was so surprised when the numbers came in -- of LOE, as well as they did. And that was even versus March when I had seen a couple of months of prelim stuff.
Yes. In terms of the work-over, that was about what we expected, which was elevated, and that will still be a little bit elevated at least for the second quarter, but that's probably about it. Where we did really, really, really well and probably a $0.30 or so swing in LOE per BOE was on the direct LOE, which excludes the work-over. So the non-work-over piece, I mean honestly, it's just a testament to Steve and to the folks in the field doing the things we talk about doing that are very focused on reducing cost structure. And some of that is some of the initial effect of moving some of the lift mechanism.
Thinking about going forward, I think there is upside. I mean you know we're not the team that usually is going to overpromise anything and come up short. And we're probably hesitant to tell you things might come out a little better than what we told you before. But there's some reason for some optimism if we continue to execute. I'd love to sit here and tell you that we're definitely going to be below the range for the year. We've really only seen 1 full normal month of IRM because we closed in January. February was messed up because of the storm. So we'd like to see some more months like that. But I mean the early trends are really good and really a testament to the Earthstone approach to managing assets in the field.
The other big thing in all of this, Gail, is work-overs aren't necessarily planned. It's -- when bad things happen in the field in terms of somebody fracs a well and it hits you and it was a good well and we have to go spend some money to return it to production, those are kind of nonrecurring events that -- at least we hope they're nonrecurring. They are really hard to plan on. So that is what we hope to avoid throughout the rest of the year.
Great. And then I know there's moving pieces in the back half of the year with Tracker. When we look at the legacy position of the asset base and the completion tempo [ and CIL ], should we kind of -- production trajectory for the -- on a quarterly progression. Should we kind of think it down 2Q, up 3Q, kind of flattish 4Q pre Tracker? Or any detail that you can provide there just on tempo [ and CIL ].
It's probably a little flip-flop of that. I mean for the first quarter, we were a little over 20, but that was, as Robert mentioned, 1,500 BOE per day sort of artificially low because of the storm. At the end of March, we were definitely a decent bit higher than that. So we're starting from a base for the quarter with the production we brought on in late March. We're probably up a little bit in the second quarter and then maybe kind of a step down in Q3 and kind of roughly flat in Q4.
Thank you. And that's all the questions we have for today. I'll turn it back to Robert Anderson for closing remarks.
Thanks, everybody. We appreciate the time. I know it's been a long day. So we'll hop off and go back to work, and we'll talk to you next month -- or next quarter.
Thank you. This concludes today's conference. All parties may disconnect. Have a great day.