Ensign Energy Services Inc
TSX:ESI
Ensign Energy Services Inc
TSX:ESI
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Earnings Call Transcript
Earnings Call Recording
Other Earnings Calls
Good afternoon, ladies and gentlemen, and welcome to the Ensign Energy Services Inc. Third Quarter 2022 Results Conference Call.
[Operator Instructions]
This call is being recorded on Friday, November 4, 2022. I would now like to turn the conference over to Nicole Romanow. Please go ahead.
Thank you, Andrew. Good morning, and welcome to Ensign 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 Ensign'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 SEDAR 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 Ensign'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 the most desired fleets moving forward with our allocation of our EDGE AutoPilot drilling rig control system and our performance advisers which helped 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 9 high-spec triples on long-term contracts for the Permian at rates well into the mid-upper 30s. This brings us now to 31 rigs worldwide that we have received or that have received upgrades largely funded by operators through covered costs and/or incremental rate increases.
Adding to the recent recontracting of our 2 high-spec 2,000 horsepower AC rigs in Bahrain, our international team at Oman secured long-term 5-year contracts for 3 of our high-spec ADRs, all 5 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 wait into the winter with winter rates being established. These will all have incremental volume 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% owner 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 Ensign vested into the upside that is anticipated as a result of the consolidation strategy and it also allows Cathedral to have access to Ensign's EDGE AutoPilot drilling ran control system platform, which is arguably the most easily and cost effectively drilling on 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 6 months. For upgrade requests less than $1 million, we assist the operator to 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 waited through 2023, Ensign 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 tele-doubles along with our new EDGE AutoPilot light drilling rig control system for anywhere from $2 million 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 rig experience is challenging, we continue to find ways to attract recruit and train new employees to the Ensign team.
Ensign's global skill 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 trading 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 3 years versus 8 years only a decade ago.
To address this accelerated wear issue, we are now modifying the current contract with our clients for by 100% of downgrades will be fully cost recovered with new replacement joints at the operator's expense, where operators have requested [ 9 ] inventory drill streams. 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 6 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. Ensign's results for the first 9 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% and 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 9 months, September 30, 2022, operating days were higher with the Canadian operating -- operations achieving a 76% increase. The United States a 51% increase and a 10% increase in the 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 9 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 9 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 9 months of 2022 was $208.1 million, a decrease of 3% compared to $214 million for the first 9 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 in 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. Ensign also has a strong foothold in the Rockies and California, both challenging areas to operate in from a regulatory standpoint. With the 9 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 U.S. 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 8 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 6 man crude tubulars and our EDGE AutoPilot platform. We still have lots of runway as rates need to be closer to $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 Sentimental 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 call it, the backdraft effect as some of the midtier contractors look to get some rig and crew 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, Montney stays strong. We're bidding the high-spec doubles in the low 20s and the high spec triples the low 30s as we enter into winter pricing scenarios. I'll point out again that Ensign still has lots of up 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's light drilling rig control system for anywhere from $2 million to $4 million. Again, we will be working with our clients to cover the upgrade cost for those transactions.
We do see contractors moving rates slowly in the 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 service rigs in the Western China Basin and have 15 operating today with visibility to 20 brands. 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 successful in recontracting our Bahrain rigs on to 5-year contracts with performance-based kickers as well as successfully negotiating to put 3 of our high-spec ADRs in Oman to work on 5-year contracts also at 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 nonperformance-based contracts, where both the operator and Ensign win. Our rigs in Kuwait are performing in the upper decile and have 3 more years on their primary term. In Australia, where we operate one of the largest suites in the country, we are finally emerging out of COVID challenges, which stunned the business levels severely in the first 3 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 midsized high-spec rigs. We have also planned 2 to 3 EDGE AutoPilot installations in the near future in Australia, which will generate incremental income of $1,600 a day.
Argentina has 2 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 8 rigs are cold stacked and a secure site and ready to go back to work with very little capital once the U.S. lives or modifies its current OFAC policy.
On the technology front, we now have our EDGE AutoPilot platform installed on 56 rigs worldwide. And the other thing slowing us down or the only thing slowing us down is a global chip problem.
So with that, I'll turn it back to the operator for Q&A. Thank you.
[Operator Instructions]
Your first question comes from Aaron MacNeil from TD Securities.
Mike, obviously, a big working capital build this quarter. I don't think you're relying to get into the nuances of buy. But more importantly, looking ahead, what do you think working capital requirements will be as well as maybe your first or initial blush at 2023 maintenance and growth capital. And I guess what I'm ultimately trying to drive that is, what do you think cash flows 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?
Yes. 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 -- we're still feel firm on the $165 million. 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 will 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 will definitely go towards the balance sheet and reducing the credit facility.
Bob, you mentioned a slowdown in upgrades. Was that specific to a certain class? And what would your inventory of rigs that can be upgraded to a 1,500 horsepower super-spec rig B? And maybe you could put it into buckets of $1 million to $2 million, $3 million to $5 million or whatever other buckets you feel are relevant, we've got a follow-up on the doubles that separately?
Right, right. So what we mean is through 2022, of course, there was a strong push from 2021, people started to get after the upgrade. 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 conversations 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 scenario. Here is 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 5 to 10 triples that can be upgraded. I'd say they're probably in that 3% to 5% 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 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 in the U.S. for the U.S. stuff.
Your next question comes from Cole Pereira from Stifel.
So, many of your peers in the U.S. guided to sequential increases in drilling margins of the, call it, USD $2,000 a day range in Q4. Obviously, you don't disclose this, but should we expect sort of a similar range from Ensign?
Yes. Yes. Yes. It's -- the harbor moves similarly absolutely, yes.
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?
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 2 or 3 going to work type of thing on the high spec triples. On the high-spec doubles, we've probably got capacity. And high-spec doubles can range -- we're finding high spec levels are starting to push into the smaller -- what we call now super high-spec double is 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 sorry, 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 5 months to avoid it going current. Obviously, the bond market is very challenging in the current environment. Can you just talk about how you're thinking about the strategy for that?
Yes, 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 in the last couple of years, the story is definitely strengthening. So definitely, the high-yield market has been a bit 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, it'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 had preferred 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.
Your next question comes from Waqar Syed from ATB Capital Markets.
Mike, in Q3, were there any rig reactivation cost that were embedded in the OpEx number?
There would be some. We have some rigs in the U.S. that are reactivated [indiscernible] a little bit, it wouldn't be material by any means.
A couple of million dollars, $2 million, $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 spudded this week and last week. So we've got some start-up costs with that as they get on the payroll and then throughout the United States, there might be 1 or 2 here and there. But for the most part, the international is where we'll see some reactivations.
And how big a number that would that be for the international?
Once again, it's 2 rigs, so fairly immaterial.
And then Bob, in terms you've recontracted a number of rigs in the Middle East, what is the -- how does the new rate compared to the previous one and then the margin compared to where they were contracted before?
Yes. The turnover rate -- I mean, negotiations in the Middle East happen over a year or 2 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 could at least model the same, but with the application of our autopilot and our performance, we think 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. Some of there was some cash outflow 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 USD 417 million 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 movement in the last couple of weeks of the U.S. dollars that I have Yes, it was quite significant.
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 season right now. But I mean, predominantly, we're looking at maintenance capital going forward. And having customers pay for upgrades.
It will be less. We're seeing some...
I'm sorry, Bob, you said year-over-year, it will be less?
Yes. I think right now, we're seeing that on a net basis. Again, we're pushing operators to cover any upgrade costs and our strength and that positioning gets stronger as the market gets tighter. So I'd be very surprised if it wasn't last to 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 would still be higher year-over-year or could be flat to lower?
The gross amount should be lower from what we're seeing. Like it will predominantly be maintenance capital. We've done 30-plus rig upgrades and activation. So there's less rigs to be activated, but there'll out to be a probably a higher cost, of which would be probably funded by the customer. So from our point of view, as of sound right now would be less and less, we get into an upgrade cycle.
Your next question is from John Gibson from BMO.
Bob, your commentary on this call seems to be more bullish in terms of rig adds 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 the market dynamics for pricing and margins, combined with the expected rig as you touched on this morning?
Yes. I think -- I mean, generally, the comments are pointed in the same direction. We're -- the commentary that I provide is the reality we see down in the sales desk and the operations side. So that's what's happening. So yes.
Okay. Fair enough. And then just last one for me. You spoke to contract terms, maybe extending on the high spec rig clauses, can you put some goalposts around the length of contracts you're signing now versus, say, a few months ago?
Yes. Yes. Well, it's always a balance. We always find that when operators start asking us for term when they go from 6 months to 1 year and 1 year to 2 years, we're getting some clients saying they want to tie the rig up for 2 years. Those are leading indicators, of course, that they also believe that rates are going to move up. So we're trying to tie that in. We've restructured any type of conversation along the lines like that, where we say, well, we'll tie in a 2-year contract. But we're going to already establish what the second year of that contract term would look like at it'd be a 10% to 15% bump. We've also got some clients where we're purposely saying we will -- you can have the rig. The rig isn't going away, but we're going to renegotiate every 6 months. And every client is a little bit different in that regard.
So we want to make sure we keep our cadence proper and our rig turnover such -- a 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 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 and the upcoming continued upside that we continue to see quarter-over-quarter. These things go and pushes. At the beginning of 2022, we had a push of -- 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-companies -- 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 to 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.
Got it. And maybe I'll just sneak one more. And you talked about day rates of upwards of $50,000 needed to contemplate new builds, and this is -- seems to be moving up constantly. Is that just based on your expectations for a newbuild price and just given the inflationary environment over the past few months? Or what's going on there?
Yes. No, you know that I think the cost to build a high spec -- 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, 1 example, drill pipe costs are up significantly from where they used to be because drilling wells faster. The other thing is, as 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 close to $50,000 a day before I think anyone would sensibly contemplate a new build.
There are no further questions. I'm sorry, there is a question now in the queue. This question is from Keith Natal from RBC Capital Markets.
Sorry about that. I apologize if there is some background noise. I just had one question to start off with. You monetize -- you talked about your Canadian directional drilling business and you talked about 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?
Yes. It's quite a completely different business down in the Rockies. The Rockies is a much smaller business area in Canada, Calgary, the center of the Canadian oilfield service space. So there's about 20 some directional companies in Calgary. In the Rockies, there's barely a handful. 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 Mud motors in shop, we would build that out. We would assemble them and repairing them. But we were more of a -- 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. And maybe a follow-up would be, how are you thinking about the portfolio, the balance sheet and financial liquidity over the next 3 to 6 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?
Yes. When we look at liquidity, we'll definitely see the 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 the laser focus on the balance sheet, laser-focused on cost and laser focus on performance.
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 Ensign 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 work in up cycle markets. And let me suggest we're definitely at the front end of that up cycle 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.