Ensign Energy Services Inc.

Good afternoon, ladies and gentlemen, and welcome to the Ensign Energy Services Inc. Third Quarter 2022 Results Conference Call. At this time, all lines are in listen-only mode. Following the presentation, we will conduct a question and answer session. If at any time during this call you require immediate assistance, please dial star zero for the operator. This call is being recorded on Friday, November 4, 2022. I would now like to turn the conference over to Nicole Romano. Please go ahead.

Thank you, Andrew. Good morning and welcome to Enzyme Energy Services' third quarter 2022 conference call and webcast. On our call today, Bob Geddes, President and COO, and Mike Gray, Chief Financial Officer, will review Enzyme's third quarter highlights and financial results, followed by our operational update and outlook. We'll then open the call for questions. Our discussion today may include forward-looking statements based upon current expectations that involve several business risks and uncertainties. The factors that could cause results to differ materially include but are not limited to political, economic, and market conditions, crude oil and natural gas prices, foreign currency fluctuations, weather conditions, the company's defense of lawsuits, the ability of oil and gas companies to pay accounts receivable balances, or other unforeseen conditions which could impact the demand for the services supplied by the company. Additionally, our discussion today may refer to non-GAAP financial measures such as adjusted EBITDA. Please see our third quarter earnings release and see our filings for more information on forward-looking statements and the company's use of non-GAAP financial measures. With that, I'll pass it on to Bob.

Thanks, Nicole. Hello, everyone. I'm happy to report that Enzyme's third quarter results came in ahead of expectations and, most importantly, a solid indication that the OFS space is finally starting to deliver sustainable profits with positive net income. A few key highlights. In the U.S., we are definitely seeing another push on rates in the 10% range as operators quietly contract their most desired fleets moving forward. With our application of our Edge Autopilot drilling rate control system and our performance advisors, which help the operator reduce net well delivery costs, we actually deliver real value with our rate increases, which makes rate increases very sustainable. In our U.S. Southern Business Unit, the team successfully completed and commissioned nine high-spec triples on long-term contracts for the Permian rates well into the mid-upper 30s. This brings us now to 31 rigs worldwide that have received upgrades, largely funded by operators through covered costs and or incremental rate increases. Adding to the recent recontracting of our two high-spec 2,000-horsepower AC rigs in Bahrain, our international team in Oman secured long-term five-year contracts for three of our high-spec ADRs, All five of these rigs will utilize our EDGE autopilot drilling control system engaged on performance-based incentive contracts, which will enhance the rig operating margins. We currently have 124 rigs on the payroll today and have visibility to 140 by year-end. Most of that uptick in rig count will come from Canada and all with rate increases as we wade into the winter with winter rates being established. These will all have incremental boiler revenue as usual. At the end of October, we rationalized our Canadian directional drilling business unit for approximately 7 million shares in Cathedral Energy Services, making us about a 4% order in that business. The DD space in Canada is extremely competitive and crowded, necessitating a trade into a consolidation strategy to unlock the value in that business unit. The deal keeps Enzyme vested into the upside that is anticipated as a result of the consolidation strategy, and it also allows Cathedral to have access to Enzyme's edge autopilot drilling ring control system platform, which is arguably the most easily and cost-effectively drilling ring control system solution out there. As we have expressed on prior calls, incremental CapEx for upgrade reactivations must be funded by the operator at least 50%, and that the day rate adjustments must be significant enough to generate sufficient cash flow to cover the remaining CapEx within six months. For upgrade requests less than $1 million, we insist the operator cover the upgrade 100%. I think we've seen the wave of upgrades and associated capital requirements through 2022 slow down, as the most desirable and easily upgradable rigs have been completed and reengaged into the market. As we wade through 2023, Enzyme still has lots of upgradable rigs, especially in the double category in Canada, where we have 40 underutilized teledevils that can be upgraded to high-spec, self-moving teledevils, along with our new Edge Autopilot Lite drilling rig control system, for anywhere from $2 to $4 million. Again, we would be working with our clients to cover the upgrade costs for those transactions. While finding new skilled labor with rigged experience is challenging, we continue to find ways to attract, recruit, and train new employees to the Enzyme team. Enzyme's Global Skills Standard, GSS, trains field personnel on a managed competency career path, much like you see in most other trades, and is arguably the most desirable training protocol in the space. We continue to drive efficiency through systems around the world. With that, we reduced our G&A per operating day by 12% in the quarter. With record penetration rates and reduced well delivery times, industry is finding accelerated wear and drill strings. In some cases, we're finding drill strings in the Permian lasting only three years versus eight years only a decade ago. To address this accelerated wear issue, we are now modifying the current contract with our clients whereby 100% of downgrades will be fully cost recovered with new replacement joints at the operator's expense. Where operators have requested non-inventory drill strings, the operator will be requested to provide the pipe at their cost or accept a market rental charge. We've also introduced, I'm sorry, we've also started to see operators wanting to contract for longer terms, always a sign that they feel another rate push coming. With that, we will take term in the upper 30s, and we generally like to respond with defined bumps every six months or annually. I'll come back to an operational update, but before that, I'll turn it over to Mike Gray for a run on the numbers.

Thanks, Bob. Enzyme's results for the first nine months of 2022 reflect positive improvements to oilfield services activity, day rates, and financial results year over year. Despite the recent pullback in commodity prices, the operating environment for oil and natural gas industry continues to improve. Overall operating days increased in the third quarter of 2022. Canadian operations recorded 4,009 operating days, an increase of 41%. U.S. operations recorded 4,937 operating days, a 61% increase, and international operations recorded 996 days, a 7% increase compared to the third quarter of 2021. For the first nine months, September 30, 2022, operating days were higher, with the Canadian operations achieving a 76% increase, the United States a 51% increase, and a 10% increase in international operations when compared to the same period in 2021. The company generated revenue of $432.6 million in the third quarter of 2022, a 61% increase compared to revenue of $268.6 million generated in the third quarter of the prior year. For the first nine months ended September 30, 2022, the company generated revenue of $1.1 billion, a 59% increase compared to revenue of $699.4 million generated in the same period of 2021. Adjusted EBITDA for the third quarter of 2022 was $105.4 million, 76% higher than adjusted EBITDA of $59.8 million in the third quarter of 2021. Adjusted EBITDA for the nine months ended September 30, 2022, totaled $243.7 million, 57% higher than adjusted EBITDA of $155.3 million generated in the same period in 2021. The 2022 increase in adjusted EBITDA is due to improved industry conditions, increasing both drilling and well-servicing activity. In addition, operating activity increased as a result of the acquisition of 35 land-based drilling rigs during the third quarter of 2021. Depreciation expense in the first nine months of 2022 was $208.1 million, a decrease of 3% compared to $214 million for the first nine months of 2021. General and administrative expense in the third quarter of 2022 was $12.8 million, or 2.9% of revenue, compared to $10 million, or 3.2% revenue in the prior year. Capital purchases for the third quarter of 2022 were $46.9 million, consisting of $18.4 million in upgrade and growth capital, and $28.5 million in maintenance capital. Capital expenditures for 2022 is still targeted to be approximately $165 million. On that note, I'll turn the call back to Bob. Thanks, Mike.

So let's start with the U.S. In the U.S., we operate a fleet of 89 high-spec ADR rigs and 48 well-servicing rigs, along with a Rockies directional drilling business. The team has grown its market share in the U.S. up to 7%, most of which is concentrated in the highly active Permian region. Enzyme also has a strong foothold in the Rockies and California, both challenging areas to operate in from a regulatory standpoint. With the nine recent upgrade reactivations in the southern business unit, now commissioned and out operating. We now have a total of 62 rigs in the payroll in the US. With the bid book recently picking up again, we are seeing visibility to 65 to 70 rigs operating by the end of the year. The Permian now has 41 of our high spec ADR 1500 ADR rigs operating with a high probability that we will exit closer to 45 by year end in that area. California stays steady at eight rigs out of our 17 in the state. State licensing issues are still a challenge in California. Depending on whether licensing opens back up, we could see our U.S. California business unit moving back up to 10 rigs in short order. Rockies currently at 13 drilling rigs could possibly see another few rigs being picked up by the year end. Our U.S. well servicing business, which operates a fleet of 47 relatively new well service rigs, continues to run at high utilization rates and keeps finding ways to grow its business year over year in both the Rockies and the California area. Our directional drilling team in the Rockies continues to deliver high-performance service and has a steady book moving forward with a very local client base. As mentioned before, we are seeing a strong wave coming at us again for our high-spec triples, and we are solidly bidding into the upper 30s with six-man crew tubulars and our agile pilot platform. We still have lots of runway as rates need to be close to the $50,000 per day all in before one could rationalize building a new super high-spec triple and receiving a reasonable rate of return above one's cost of capital. In Canada, we operate a fleet of 123 rigs that are focused in the Western Canadian Centimeter Basin. Today, we have 46 rigs in the payroll, with bookings that will get us to 55 in short order, targeting 60 by year end. While we were able to elevate pricing right across all rig categories coming out of breakup, we have seen some price resistance in certain conventional rig type categories. This is a bit of what we called a backdraft effect as some of the mid-tier contractors look to get some rig and crews started up before the winter. That's not the case in the high-spec rig types where we enjoy very strong utilization and leading edge price traction. We continue to see growing demand occurring in the high-spec doubles and high-spec triple rig categories as the Clearwater moves over to deeper well plans and Duvernay and Montney stay strong. We're bidding the high-spec doubles in the low 20s and the high-spec triples in the low 30s as we enter into winter pricing scenarios. I'll point out again that Enzyme still has lots of upgradable rigs, especially in the double category in Canada, where we have 40 underutilized tele-doubles that can be upgraded to high-spec self-moving pad tele-doubles, along with our Edge Autopilot light drilling rig control system for anywhere from $2 to $4 million. Again, we will be working with our clients to cover the upgrade costs for those transactions. We do see contractors moving rates slowly into winter, but expect rates to elevate another 10% through the first quarter 23 on spot pricing, setting the stage for the rest of 2023 for continuing rate increases of 10 to 15%. Our well servicing business operates a fleet of 52 well serviced rigs in the Western Canadian Basin and have 15 operating today with visibility to 20 by year end. Again, rates are moving with every program negotiation. On the international front, we have a fleet of 34 drilling rigs, of which 14 are situated in Australia, 8 in the Middle East, and 12 in Latin America, South America. As mentioned in my opening summary, our Middle East team were successfully recontracting our Bahrain rigs onto five-year contracts with performance-based kickers, as well as successfully negotiating to put three of our high-spec ADRs in Oman to work on five-year contracts also with performance-based kickers. We are finding that there is a growing mark for high-performance applications of our EDGE autopilot drilling rig control system engaged on performance-based contracts, where both the operator and Ensign win. Our rigs in Kuwait are performing in the upper decile and have three more years on their primary term. In Australia, where we operate one of the largest fleets in the country, we are finally emerging out of COVID challenges, which stunted the business levels severely in the first three quarters. Projects are coming back strong, and we expect a very strong year ahead. Rates on our deeper high-spec rigs have been moving up about 15% to 20%, with a tighter market developing in the mid-size high-spec rigs. We have also planned two to three edge autopilot installations in the near future in Australia, which will generate incremental income of $1,600 a day. Argentina has two rigs operating now, with a third opportunity being negotiated. The need to generate electricity in Argentina is driving a strong push for our deeper high-spec ADR rigs. to deliver gas in-country cost-effectively. In Venezuela, the prospect to get some of our fleet operating looks encouraging, but we won't hold our breath. In any case, our eight rigs are cold-stacked in a secure site and ready to go back to work with very little capital once the U.S. lifts or modifies its current OFAC policy. On the technology front, we now have a RegAuto pilot platform installed on 56 rigs worldwide, and the other thing slowing us down, or the only thing slowing us down, is the global chip problem. So with that, I'll turn it back to the operator for Q&A.

Thank you. Thank you.

Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press the star key followed by the number one on your touch-tone phone. You will hear a three-tone prompt acknowledging your request, and your question will be pulled in the order that they were received. Should you wish to decline from the polling process, please press the star key followed by the number two. If you're using a speakerphone, please lift your hands up before pressing any keys. One moment, please, for your first question. Your first question comes from Aaron McNeil from TD Securities. Please go ahead, sir.

Thanks for taking my questions. You know, obviously a big working capital bill this quarter. I don't think we really need to get into the nuances of why. But, you know, more importantly, looking ahead, you know, what do you think working capital requirements will be, as well as maybe your, you know, first or initial blush at 2023 maintenance and growth capital? And I guess, you know, what I'm ultimately trying to drive at is, you know, what do you think cash flow's available for debt reduction? might look like in 2023. So I know you're not going to give guidance, but any help on the other moving pieces might be helpful.

Yeah. So for the working capital, we saw about a 76 million increase in accounts receivable. A lot of that was from the activity pickup. We saw going from Q2 into Q3. From a capital perspective, I mean, we're still fairly firm on that 165. We're about 133 million into it. So from the accounts receivables coming into the door with sort of the CapEx requirements in Q4 and going into 2023, it'll be, I think, sort of less than what we have seen. So if anything, we'll see our liquidity build up and the free cash flow definitely go towards the balance sheet and reducing the credit facility.

Okay. Bob, you mentioned a slowdown in upgrades. you know, was that specific to a certain class and what would your inventory of rigs that can be upgraded to a, you know, 1500 horsepower super spec rig B and, you know, maybe you could put it into buckets of one to 2 million, three to 5 million or whatever other buckets you feel are relevant. I've got to follow up on the doubles separately.

Right. Right. So when, what we mean is, um, Through 2022, of course, there was a strong push from 2021. People started to get after the upgrades. So there was a strong push through 2022. The pace of upgrades has slowed down with the clients. They've kind of gotten through their 2022 budget. We're already starting to see some uptick in some conversation with clients where they go, hey, we like this rig. have you got another one just like it? And if we're talking the high-spec triple for a moment, we go, well, we can upgrade a rig. Here's the scenarios. Here's the day rate, and you're going to have to fund the upgrade. We've got, in the U.S., we've probably got at least another five to ten triples that can be upgraded. I'd say, you know, They're probably in that three to five range that would follow into that question. In the high spec doubles, of course, those would be focused in Canada where we've got the greatest concentration of doubles. As I mentioned, we have 40 upgradable doubles. Some of them are already high spec doubles that would be upgraded further. because they're not fully utilized. We've still probably got about 10 of those that we can put to work. So we've got capacity for not a lot of money to put those to work, and those would be in the $2 million to $4 million range. CAD for the Canadian stuff, for the U.S. stuff.

Okay, that's great. I'll turn it over. Thanks for your time.

Thank you, Aaron.

Your next question comes from Cole Pereira from Stifel. Please go ahead.

Morning, all. So many of your peers in the U.S. got it to sequential increases in drilling margins of the, call it, U.S. $1,000 to $2,000 a day range in Q4. Obviously, don't disclose this, but should we expect sort of a similar range from Enzyme?

Oh, yeah, yeah, yeah. It's the harbor moves up. Similarly, absolutely, yeah.

Got it. And you mentioned 60 rigs in Canada by year end. Should we be thinking about that number as your Q1 peak, or could that figure go higher?

Oh, no, Q1 peak will go higher. I think we might get to 70 in Q1, peak 70.

Got it. And as well, I know you kind of just briefly referenced it, but Maybe on a percentage or absolute basis, how many of your Tier 1 rigs in Canada do you expect to be active in Q1?

I would say probably close to 100%. We're probably on the Tier 1 high-spec triples. We're already at 90%. So it's kind of the last two or three going to work type of thing on the high-spec triples. On the high spec doubles, you know, we've probably got capacity and high spec doubles can range. We're finding high spec doubles are starting to push into the smaller, what we call now super high spec doubles are starting to push into the high spec triple market. As you can imagine, we've got clients that currently have a high spec double doing great work, great crews, and they want to put bigger pumps on it. They want to put a little bigger top drive, that type of thing. So It's an evolution. There's some convergence there between our high-spec doubles and the high-spec triples that are out in the market currently. So the margins are very equivalent. I mean, our super high-spec doubles are making the same margin as the high-spec triples in Canada.

And is that on a dollar basis or a percentage basis?

Dollar basis.

Got it. And as well, you have a bond due in April 2024 that you'd need to refi in the next five months to avoid it going current. Obviously, the bond market's very challenging in the current environment. Can you just talk about how you're thinking about the strategy for that?

Yeah, we're looking at it. I mean, the story is definitely improving quarter over quarter. When you look at where consensus is to where we've been the last couple of years, the story is definitely strengthening. So Definitely the high-yield market is in a bit of turmoil right now, as you said, but from our perspective, we're continuing to improve the story, and we'll look to hit the markets when we think we're ready from it going current. I mean, if it goes current, that's not the end of the world by any means. So we'll look to do what's right with the company going forward.

Got it. So, I mean, you would prefer to wait it out and maybe – do a similar, call it, unsecured issue as opposed to increasing the security or some sort of other dilutive event or something of that nature?

We don't have any specifics. I mean, we'll look at all the different options that are in front of us and select what's best for the company going forward.

Got it. That makes sense. That's all for me. Thanks.

I'll turn it back. Thanks, Cole. Your next question comes from Makar Saeed, ATB Capital Markets.

Please go ahead.

Thank you for taking my question. Mike, in Q3, were there any rig reactivation costs that were embedded in the OPEX number?

There'd be some. We had some rigs in the U.S. that were reactivated. So, yeah, there'd be a little bit. It wouldn't be material by any means.

A couple of million dollars to $3 million, is that a reasonable number?

Probably within the ballpark.

Okay. And then for Q4, do you have any guidance for rig reactivation costs?

We have the Oman rig starting up, which actually started this week and last week. So we'd have some startup costs with that as they get on the payroll. And then throughout the United States, there might be one or two here and there. But for the most part, the international is where we'll see some reactivations.

And how big a number would that be for the international?

Once again, it's two rigs, so fairly immaterial.

Okay. Okay. Sounds good. And then, Bob, in terms, you know, as you've recontracted a number of rigs in the Middle East, what is the – how does the new rate compare to the previous one and then the margin compared to, you know, where they were contracted before? Sure.

Yeah, the turnover rate, I mean, negotiations in the Middle East happen over, you know, a year or two type of time frame, not over a month. The recontracted rates are, with our performance-based contract, slightly higher than where we were before. So there should be, you know, you could at least model the same, but with the application of our autopilot and our performance, we think... You know, in a P50, we can increase rates by about $5,000 a day. P90 by about $3,000 a day. Contract over contract.

Right. Okay. That makes sense. And then, Mike, the net debt number went up by about $58 million. You know, some of that was, you know, there was some cash outflowed in the quarter. But there was beyond that, is it all translation effect of currency or is there something else going on?

So it would be all FX, so it would be taking the high yield issuance, which is about $417 million USD outstanding, and translating at the quarter end rate. I mean, when you look at foreign exchange this quarter, the income statement translation was almost $0.10 lower than the quarter end translation, just given the FX move in the last couple of weeks of the US dollar. It was quite significant.

Great. Any early indication of where the capex could be for next year?

No particular guidance as of yet. I mean, we're going through budget seasons right now, but I mean, predominantly we're looking at maintenance capital going forward and having customers pay for upgrades. Yeah, it'll be less.

I think we're seeing some... I'm sorry, Bob, you said year over year it'll be less?

Yeah, I think right now we're seeing that on a net basis. Again, we're pushing operators to... to cover any upgrade costs. And our strength in that positioning gets stronger as the market gets tighter. So I'd be very surprised if it wasn't less year over year.

For sure. But I was just thinking from a cash flow statement perspective, the gross number that you report in there for CapEx, that number you know, what would still be higher year over year or could be flat lower?

The gross amount should be lower from what we're seeing. It would predominantly be maintenance capital. We've done 30-plus rig upgrades and activations, so there's less rigs to be activated, but those would have to be at probably higher costs, of which would be hopefully funded by the customer. So from our point of view, as it sounds right now, it would be less unless we get into an upgrade cycle.

Okay. Great. Thank you very much.

Thanks, Vikar.

Your next question is from John Gibson from BMO. Please go ahead.

Good morning, all. Bob, your commentary on this call seems to be more bullish in terms of rig ads and pricing relative to forward guidance in the release this morning, particularly in the U.S. Just wondering how we should reconcile these statements, just given... you know, the market dynamics for pricing and margins combined with the expected rig ads you touched on this morning?

Yeah, I think, I mean, generally the comments are pointed in the same direction. You know, the commentary that I provide is the reality we see down on the sales desk and the operations side. So that's what's happening. So, yeah. Yeah.

Okay, fair enough. And then, Celestin, for me, you spoke to contract terms maybe extending on the high-spec rig classes. Can you put some goalposts around the length of contracts you're signing now versus, say, a few months ago?

Yeah, yeah. Well, it's always a balance. We always find that when operators start asking us for a term, when they go from six months to one year and one year to two years, we're getting some clients saying they want to tie the rig up for two years. Those are leading indicators, of course, that they also believe that rates are going to move up, so they're trying to tie that in. We've structured any type of conversation along the lines like that where we say, well, we'll tie a two-year contract, but we're going to already establish what the second year of that contract term would look like, and it would be a 10% to 15% bump. We've also got some clients where we're purposely saying we will renegotiate. You can have the rig. The rig isn't going away, but we're going to renegotiate every six months. And every client is a little bit different in that regard. So, you know, we want to make sure we keep our cadence proper and our rig turnover such, contract turnover such that we don't have them all coming off at the same time because that's never good in the market as well. We like to, you know, Cadence about a quarter every quarter of the fleet is the ideal situation. And we're getting pretty close to that. So we've got a pretty good contract book on cadence that I think will allow us to react quick on any end, the upcoming continued upside that we continue to see, you know, quarter over quarter. These things go in pushes. You know, at the beginning of 2022, we had a push of, you know, on the high spec triples, $5,000 to $8,000 a day. And then, of course, the backdraft effect, which I call when the mid-cap companies come in and they take up some market share back, and they do that with a little bit of rate. So you see a rate steadying through that process. Now we're seeing them utilize the market share that they seem to feel comfortable with, and now there's another push. So we're able to push another $2,000 to $3,000 a day increases in current bid process.

Maybe I'll just sneak one more in. You talked about day rates of upwards of $50,000 needed to contemplate new builds, and this seems to be moving up constantly. Is that just based on your expectations for a new build price and just given the inflationary environment over the past few months, or what's going on there?

No, you nailed it. I think the cost to build a super high-spec triple is $30,000 to $35,000. base operating costs are a little bit higher. I mean, everyone is seeing, and I mentioned drill pipe, one example, drill pipe costs are up significantly from where they used to be because we're drilling wells faster. The other thing is, you know, and I pointed out, a reasonable rate of return above one's cost of capital. Everyone's cost of capital is moving up as well, right? So now we're into, you know, close to $50,000 a day before I think anyone would sensibly contemplate a new build.

Great. Appreciate the call. I'll turn it back.

Thank you.

There are no further questions. Oh, I'm sorry. There is a question now in the queue. This question is from Keith Nadeau from RBC Coppola Markets. Please go ahead.

Hey, Keith. Keith Nadeau, please go ahead. We're still hearing this end.

Keith is live.

This microphone is live at the moment.

Hi, can you hear me?

Oh, there we go. Hello, Keith.

Hi, sorry about that. I apologize if there's some background noise. I just had one question to start off with. You've monetized, you've talked about your Canadian directional drilling business and talked about the competitive dynamics of why. Just curious how you're thinking about your U.S. directional business in the Rockies and Do you see the same sort of dynamic down there, or is that a more favorable business to launch, do you think?

Yeah, it's quite a completely different business down in the Rockies. The Rockies is a much smaller business area. Canada, Calgary, the center of the Canadian oil field service space, so there's about 20-some directional companies in Calgary. In the Rockies, there's barely a handful of And we focused on, we have a directional drilling mud motor shop where we take motors and we basically manage the motors for the operators. So we basically don't do a lot of directional drilling in the U.S. We've kind of focused in on a key area that we can make a 30% margin. And we've got a good client base that we service well. and they're quite loyal, and we do a heck of a job there. So it's not to be confused with the Canadian directional drilling space, which we did not build outmod motors in shop. We would build that out. We would assemble them and rebaring them, but we were more of what you would consider a competitive directional drilling business with directional drillers, well plans, things like that in Canada. So it's just a different business down there.

Okay, thanks for that. Maybe a follow-up would be, how are you thinking about the portfolio, the balance sheet, and financial liquidity over the next three to six to 12 months? Are there other assets you'd consider monetizing for the right price, or are you pretty happy with what you've got where you've got it?

Yeah, when we look at liquidity, we'll definitely see it expand going into year end and then going forward as well. I mean, the large chunks of CapEx were spent looking for the customer to pay for the upgrades next year. So from our perspective, liquidity will continue to grow. The balance sheet will be in better shape quarter over quarter with improved results as well. So from our perspective, it's just being laser focused on the balance sheet, laser focused on cost, and laser focused on performance.

Thanks for this information.

Thank you. If there are no further questions at this time, please proceed.

All right. Well, let me wrap up here. It's clear that the $12 trillion underinvestment in the oil and gas business over the last decade has created the opportunity for drilling companies like Enzyme to see more opportunities to expand our active operating rig count And with that, the ability to move our rates more into a range that provides a reasonable rate of return on the capital invested. In addition, the capital investments industry has made in high-torque top drives, self-moving pad systems, additional high-pressure pumping capacity, and the application of drilling and control systems that use algorithms and AI to replicate record wells over and over again provide real value to our clients with reduced well cycle times and reduced well costs. As most of you on the call understand, the drilling contracting business has lots of margin torque in upcycle markets, and let me suggest we're definitely at the front end of that upcycle market. Look forward to reviewing our Q4 results in the new year with you. Have a safe and merry Thanksgiving and a merry Christmas. Thank you.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you now please disconnect your lines.