Ensign Energy Services Inc. (OTCPK:ESVIF) Q4 2023 Results Conference Call March 1, 2024 12:00 PM ET
Company Participants
Nicole Romanow – IR
Bob Geddes – President, CEO
Mike Gray – CFO
Conference Call Participants
Aaron MacNeil – TD Cowen
Cole Pereira – Stifel
Josef Schachter – Scatter Energy Research
Keith Mackey – RBC Capital Markets
John Gibson – BMO Capital Markets
Operator
Ladies and gentlemen, welcome to the Ensign Energy Services Inc. Fourth Quarter 2023 Results Conference Call. [Operator Instructions]. This call is being recorded on Friday, March 1, 2024.
I would now like to turn the conference over to Nicole Romanow, Investor Relations.
Nicole Romanow
Thank you, Julie. Good morning, and welcome to Ensign Energy Services fourth quarter and year-end 2023 conference call and webcast. On our call today, Bob Geddes, President and COO; and Mike Gray, Chief Financial Officer, will review Ensign’s fourth quarter and year-end 2023 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 fourth quarter and year-end earnings release and SEDAR filings for more information on -looking statements and the company’s use of non-GAAP financial measures.
With that, I’ll pass it on to Bob.
Bob Geddes
Thanks, Nicole. Good morning, everyone. Let me start off by saying that Ensign is pleased to report that we delivered on what we promised in 2023. In 2023, we delivered superior operational results that enabled $217 million of debt reduction, this against the backdrop of a year where the market started strong, but quickly fell off as commodity prices hampered drilling projects in North America. Canada was affected with the early summer forest fires, which affected operations on 7 rigs, and Canada played catch up in the back half of 2023 in a subdued market going into the fourth quarter. The U.S. faced similar challenges manifesting not only from unstable commodity prices, but also from record M&A activity. International performed reasonably well in contrast.
Nonetheless, Ensign delivered our best fourth quarter EBITDA since 2012 and delivered our third highest free cash flow since 2012 and 2006. This is the result of a highly efficient and well-maintained fleet of high spec rigs and highly trained professional crews that delivered on keeping the budget on sustaining CapEx and low downtime.
As I mentioned earlier, this performance provided us the ability to pay down $270 million of debt, our largest annual debt reduction in Ensign’s history and a testament to management’s laser focus on our debt reduction target of reducing debt by $600 million through the 2023, 2025 year period. Also want to applaud our operations team worldwide, whom logged in a record safety year for Ensign. I took a little bit of the year.
Steam there Mike, I’ll turn it over to you on the rest of the financials.
Mike Gray
That’s good. Thanks, Bob. Ensign’s results for the fourth quarter 2023 year-end reflected steady oilfield services activity and improved financial results year-over-year. Despite recent volatility in commodity prices, the outlook is constructive and the operating environment for the oil and natural gas industry continues to support steady demand for oilfield services.
Total operating days were down in the fourth quarter of 2023, with Canadian operations reporting a decrease of 9% United States operations a 35% decrease, which was offset by a 24% increase in international operating days compared to the fourth quarter of 2022. For the year ended December 31, 2023, total operating days were down with Canadian operations reporting a 9% decrease United States operations, a 12% decrease, which was offset by a 24% increase in international operating days compared with the year-end December 31, 2022.
The company generated revenue of $430.5 million in the fourth quarter of 2023, an 8% decrease compared with revenue of $468 million generated in the fourth quarter of the prior year. For the year ended December 31, 2023, the company generated revenue of $1.79 billion a 14% increase compared with revenue of $1.580 billion generated in the prior year. Adjusted EBITDA for the fourth quarter of 2023 was $129 million lower by 1% than adjusted EBITDA of $130 million in the fourth quarter of 2022.
Adjusted EBITDA for the year ended December 31, 2023, was $490.2 million, a 31% increase compared to adjusted EBITDA of $373.6 million generated in the year ended December 31, 2022. The 2023 increase in adjusted EBITDA is primarily due to improving industry conditions. Adjusted EBITDA margins for the fourth quarter of 2023 was 30%. This was the company’s highest since Q1 of 2012. G&A expense for the fourth quarter of 2023 was $14.9 million, compared with $12.8 million in the fourth quarter of 2022.
G&A expense totaled $58 million for the year ended December 31, 2023, compared with $48.6 million for the same period in 2022. G&A expense increased due to annual wage increases and the negative foreign exchange translation on converting U.S. denominated general and administrative expenses. G&A expense as a percentage of revenue was 3.2% for the year ended December 31, 2023, which is consistent with 2022 and is the company best since 2006.
Net capital expenditures for the fourth quarter of 2023 totaled $28.8 million compared to net capital expenditures of $40.6 million in the corresponding period of 2022. Net capital expenditures during the fiscal year ended 2023 totaled $160.7 million, compared to $126.8 million in the corresponding period of 2022. Our CapEx budget for 2024 is set at $147 million, which is primarily relates to maintenance capital.
Net repayments against debt totaled $217.6 million since December 31, 2022, exceeding the Company’s 2023 debt reduction target of $200 million. Since the first quarter of 2019, when the company’s total debt, net of cash, peaked at $1.69 billion, the company has reduced net debt by $498.2 million over the past 5 years, while completing 2 countercyclical and accretive acquisitions over the same 5 year period, which totaled $162.7 million.
Our net debt adjusted EBITDA for the year ended 2023 was 2.43. This is the lowest ratio since 2015 and will continue to reduce as the Company hits its debt targets. The Company’s debt reduction for 2024 is approximately $200 million. Our target debt reduction for the period 2023 to the end of 2025 is approximately $600 million. If industry conditions change, this target will be increased or decreased
The Company expects its blended interest rate if Federal Reserve Banks hold interest rates at the current levels to be approximately 8%, which will allow us to continue to reduce our interest expense going forward. Lastly, the Company redeemed its senior notes in December of 2023, completing the transformation of the balance sheet.
On that note, I will turn the call back to Bob.
Bob Geddes
All right. Thanks, Mike. So we continue to run between 105 to 110 drill rigs globally and about 54 well servicing rigs in North America. We see the macro improving ever so slightly as economies improve and demand increases generally, while oil pricing is being managed well by OPEC, the reverse is true of natural gas. Various factors, of course, such as associated gas and constrained takeaway capacity keeps pricing pressure on natural gas and hence various true gas drilling projects on the go today.
Let’s focus on the Canada for a moment. Oil is relatively strong with TMX Canada coming on stream this year. The differential will tighten further enhancing operators’ cash flow to fund drilling activity. In addition, we’ve got the Coastal link LNG pipeline coming on soon, but awaits the completion of the LNG Kitimat facility on the East Coast, expected end of ’24 into ’25. Supporting that notion, CAP recently announced a slight increase in capital spending year-over-year, and we’ll be sure to get our share of that.
Exactly the opposite, of course, through natural gas, we’re seeing a lot of gas related projects getting reevaluated, impacting certain projects in Western Canada. Currently running 51 drill rigs in Western Canada now that we’re into March. We are a slave to the weather at this point. The colder weather will help to extend the work we have, and today, that holds true. Nonetheless, we have visibility to see 20 plus rigs running over breakup and uptick year-over-year, and we expect to build back up to 50 rigs late summer and then build up into what we think is a much healthier environment in the back half of 2024.
We recently repositioned 2 of our ADR 300 high spec singles from California into Canada on long-term contracts with upgrades funded by the operator. We expect the mods to the rigs to be complete and the rigs ready for operation in the coming months. As we have expressed in prior calls and with day rates still very low, we requested operators fund the capital upgrades they request, which ultimately deliver record wells and reducing net well cost for them.
We just cannot make full cycle returns on major equipment upgrades requested by operators in such a cyclical environment, we apply the same philosophy globally. Let’s go to well servicing. Our Canadian well servicing fleet was impacted in the first quarter by that 10-day stretch of minus 40, which brought well servicing field operations to a halt. We have 60 well service rigs currently running today and expect to see that improve to roughly 18 to 20 post breakup.
Moving to the U.S., we currently have 40 rigs active in the U.S., 31 in the Permian, 5 in the Rockies, 4 in California. Both the Rockies and California continue to have permit delays, so we expect a steady state of roughly 9 to 10 rigs running between those two areas into the near future, not much change.
In the Permian, where the rig count has definitely bottomed out at just above 300 rigs operating, we will wait to see how all the M&A activity plays out. It certainly won’t manifest itself into more activity anytime soon. We are still seeing a very competitive bidding market, but rates seem to have found some base in most cases. With depletion curves starting to accelerate, production at its peak, DUCs with a low inventory and oil pricing very compelling, one would expect more drilling has to take place at some point in time.
On international market, our Kuwait business unit operates 2,000, 3,000 horsepower ultra-high spec rigs and are contracted into 2025, and both rigs continue to generate solid returns there. In Bahrain, our 2,000 horsepower super spec rigs are contracted out to mid-2025. In Oman, we have the 3 ADRs tied up in long-term contracts. They continue to set records on well times and deliver well on the performance-based contracts we have in place there.
Australia has rigs active today with another one of our 1,500 starting up in the second quarter. Argentina has two of our high spec ADR 2000s active on long-term contracts into 2025 and running very well with very few operational issues.
Moving north into Venezuela, we just started up last week one of our 1,200 horsepower electric ADRs for a major on a short-term contract, obviously, within the compliance of an FX exemption. On the Drilling Solutions side, we continue to grow this high margin growing technology side of our business 25% year-over-year. Our Edge drilling rig control system continues to be installed at a pace of a rig a month and we continue to see demand for our ADS, which charges out at $1,000 a day, along with growing demand for our Edge Autopilot platform, which with all the bells and whistles charges out at $2,400 a day.
We are currently backlogged out at least 4 months on ADS installs. We’re also in discussion to put our Edge Autopilot platform on the Middle East rigs and tie that into performance-based contracts. On our environmental product line, we have four products that are available on Ensign rigs, which deliver high margin and significantly reduced emissions. We also commissioned 2 new NG BESS systems, natural gas BESS systems, Battery Energy Storage Systems is the acronym there, which charge out in the $5,000 a day range and help to reduce emissions by as much as 60%.
BESS systems are battery energy storage systems, as I mentioned, that help store and modulate electrical power delivery on natural gas engine applications and also have an application on diesel engine applications. The BESS system on an a la carte basis charges out in that $1,700 to $2,000 range. Our first N Power substation arrives next month and will further drive emission reductions, while generating a solid rate on return on investment for all our electric rigs connecting on highline power projects. These units charge out for about $200 to $2,500 a day.
So that’s the operational update for Ensign. I’ll turn it back to the operator for any questions.
Question-and-Answer Session
Operator
[Operator Instructions]. Your first question comes from Aaron MacNeil from TD Cowen.
Aaron MacNeil
Bob, one of your competitors guided down on U.S. margins pretty materially for Q1. I know some of that was the reduction in idle but contracted rigs, but the company also spoke to less leverage over fixed costs and modest pricing reductions. Is that an expectation that we should also have for Ensign’s U.S. Business? How would you characterize the sequential change in both pricing and leverage over your fixed costs or change in IBC mix in that context?
Bob Geddes
Well, I think there’s certainly some truth to the fact that as rigs come off contract, you’re bidding into a pretty active market. So you’re not able to raise prices. In some cases, prices are moving down ever so slightly. But we’re seeing that trend slow down a lot in the last month. Certainly, it came out of the gate. We were catching bids.
On the cost side, we’ve also seen, we’ve applied a few unique ways to reduce costs on our mud pumps example. Mud pumps and top drives are the 2 single biggest items that caused downtime and cost a lot of money to maintain as we drill these record wells. We’ve seen that in the fourth quarter of ’23 and into ’24 level off. So we’re starting to see some benefits of some of the unique things that we’ve been applying there. So I would suggest that margin compression would be very slight in the first quarter.
Aaron MacNeil
Moving to Canada, got a couple of questions there. Can you remind us what you’re doing to mobilize some idle AC triples? And I know that the capital program is maintenance focused, but do they require customer funded upgrades to get those to work? And then you mentioned the ADR single mobilization. So similar question on the Clearwater, what’s your current market penetration in the play? And do you expect you’re getting your share of that market?
Bob Geddes
Yes. So the first question, the high spec truck was no, we don’t need any capital upgrades to put rigs to work. We’ve got a little bit of excess capacity there that can be contracted. On the Clearwater Mannville, you saw us move 2 of our ADR 300s out of California, which are super spec singles, so that kind of rig. So we’re feeding into that market. Obviously, those rigs are perfect Clearwater Mannville rigs. And we’re still finding some operators looking at more pad drilling. With pad drilling, you’ll see the evolution of super high spec doubles start to increase capacity. I think we’re running about close to 60% of our high spec doubles at this point in time on our high spec singles. We don’t have a lot of them. We’re running about 80% capacity on those.
Operator
Your next question comes from Cole Pereira from Stifel.
Cole Pereira
So there’s a pretty significant improvement sequentially in gross margins. Anything one-time ish non-recurring in there? And if not, what really drove that and was it more Canada or the U.S.?
Bob Geddes
No, there’s no one times, really comes down to cost control and the operations and the team doing a great job out there as well as trying to get the rate increases that we saw kind of over 2023. So cost control has really been our big focus, in particular with our debt targets. So that’s what we’ll continue to focus on going forward.
Cole Pereira
So I guess going forward then you kind of see margins being in a reasonable range over the next few quarters, reasonably similar range?
Bob Geddes
Yes, we should start to. We said there might be some deviations as with the U.S., but for the most part, we should see margins continue along.
Operator
Your next question comes from Josef Schachter from Scatter Energy Research.
Josef Schachter
A couple of questions, starting with the well servicing with the consolidation by your competitor. Do you see over time as they rationalize that we’re going to see more discipline in terms of pricing for the rigs? What’s your outlook there in terms of how profitability could expand in 2024, 2025?
Bob Geddes
Yes. I think that consolidation and rationalization of fleets does have an effect, especially when you look at newbuild metrics and the rates you need to make a reasonable rate of return if you could find a banker willing to give you some money or some private equity on a raise. So yes, it leaves a little bit of running room for margin expansion in the well servicing business.
Josef Schachter
Going to debt, you paid down $217 million, you’re talking $200 million this year. Is there an official target we should be looking at? Like is it $500 million, $600 million for 2 years from now? And that would be at the point where you would be looking at potential shareholder return stock buybacks and dividends. Is there some magic number that you’ve been comfortable with talking about?
Bob Geddes
Yes, when you look at the balance sheet, we did the refinance with the term loan, which took out the senior notes. And our target in 2023 was $200 million, 2024 is $200 million, 2025 is going to be $200 million. That will get us to sub a $1 billion close to $800 million which would be less than 2 times debt to EBITDA. And when we look historically where we’ve been, that will be kind of in the historical norms. So at that point in time, then potential conversations could take place, but they’ll have to happen at the Board level and we have to achieve our targets to get there.
Josef Schachter
Anything going on in terms of M&A, in terms of consolidating that you see as tuck unders to either parts of the U.S. business or Canadian business because it looks like weaker players are probably going to need a little bit of help here. Do you see anything that fits for your business book?
Bob Geddes
Not with ours. I mean we’re laser focused on free cash flow towards debt reduction. And on the more general comment about consolidation, there’s probably not much more in Canada. There’s probably tuck ins for certain companies in the U.S., perhaps the same way. You’ve got a more competitive environment in the U.S. you’ve got 5 big guys and you’ve got 50 people below that.
And then there’s rig type bifurcation, you start to bifurcate on drilling rig types, the super triples and that. And they’re $30 million to $35 million to build now. So you see discipline in certain rig types. But on the bottom end, there’ll be, there’s always some consolidation. There’s always something happening there, Joseph. But you’re probably not going to see much from us. We’re focused on debt.
Operator
Your next question comes from Keith Mackey from RBC Capital Markets.
Keith Mackey
Bob, I’m just hoping you can maybe compare and contrast the U.S. and Canadian high spec triple markets in terms of pricing. Where is pricing now? Where do you expect it to go? I know there’s been more optimism around the Canadian market relative to the U.S., but we have noted some natural gas directed CapEx cuts recently. So any context and color you can give around that would be helpful.
Bob Geddes
Yes, yes. Well, the Canadian high spec triple market is a tighter market than it is in the U.S. The numbers are probably very similar. We’re all trying to find and hang on to a $30,000 a day base, mid-20s to 30 base. And then you’ve got your a la carte items. We’re finding the a la carte items like drill pipe and things like that especially in the U.S. Where we have drill pipe degradation has almost become a consumable on water based muds in the Permian.
We’re only getting like a year and a half out of a $2.7 million string. So we’re having to charge $8,000 a day for that. So we’re finding that what’s changed is some of the other items that are now outside of the day rate that used to be inside of the day rate. So in Canada, I would say you get through bidding cycles and there’ll be another bidding cycle coming up this summer for a lot of the high spec triples going into the fall.
We think that there’s some momentum moving up into the fall from current numbers. But 30 is where we kind of need to get to. On new replacement, the runway is I mean, you got to get the $45,000 a day before you get your head around any new construction. So there’s still a $15,000 delta there.
Keith Mackey
And you mentioned consolidation amongst U.S. customers. Can you just maybe run through your exposure to that a little bit and some thoughts on what you think might happen and your plans to mitigate any issues as they arise and that kind of thing?
Bob Geddes
Well, all the big ones. The Exxon Pioneer, we’re a big driller for Pioneer. What we find is between Pioneer and a few other large clients who have gone through or in the process of M&A activity, we’re in their upper quartile of performance. So we believe we’ll probably be the last ones laid down. We all know that when mergers happen 1 plus 1 never equals 2. It usually equals about 1.5 for a year and then starts to build up from there. So we’re happy that we’re performing in the upper quartile. And that’s our defense basically.
Operator
[Operator Instructions]. Your next question comes from John Gibson from BMO Capital Markets.
John Gibson
With CapEx moving lower in ’24, I know there might be some puts and takes on activity levels and pricing, but could you potentially see debt reduction targets once again exceeded this year pending activity levels hold relatively flat from here?
Bob Geddes
Let’s get the crystal ball out, Mike.
Mike Gray
Yes, I mean, for sure, I mean, activity definitely picks up. We can see it go. I think from a CapEx point of view, we’re quite confident in that spend for to keep the rigs that we have running and running. So, yes, I think there’s some room for improvement. But like you said, we’re laser focused on it. So we’ll be making sure that we perform to get that done.
Bob Geddes
Yes. Any upgrade growth capital that we talk about, we always demand less than one year payout on that or it doesn’t get approved. So that discipline is to Mike’s point allowing us to stay on to a debt reduction target with confidence.
John Gibson
Second for me, on the Drilling Solutions side, you talked about I think 25% year-over-year growth. Was that a revenue number? And I guess what impact did this have do these have on your margins maybe in Q4 and 2023 in general?
Bob Geddes
Right. Yes. And that was a top line number. But keep in mind, we make about 75% gross margin on our technology. And we’ve got 200 rigs around the world running 100 every day. The Edge, the way I look at it is we’ve got like kind of like the Microsoft Office Suite installed on half of those rigs currently. We keep on working on installing more and more of it. And then our sales team goes out and talks to the operator about what do you want to turn on, Excel, PowerPoint, etcetera, etcetera. And we feed into that.
I would say, we’re kind of 10% of the way there as we don’t segregate down to that level as far as numbers go. So Mike, unless you wanted to expand on that now.
John Gibson
I guess just to follow on, when you think about adding new systems. I know you talked about a backlog there, but what could this number look like in 2024 again say just activity levels get flat from here?
Mike Gray
So some numbers I can give you. I mean, we’ve got we’re going to be up to about 20 of our ADS implementations by the end of the year. They charge out at $1,000 a day. We’ve got 50 rigs today running at about $750 a day of drilling solution revenue application. And then you tack on 25% year-over-year growth, that’s kind of our target. You build the number there.
Operator
And there are no further questions at this time. I will turn the call back over to Bob, President and COO, for closing remarks.
Bob Geddes
Thank you. So to wrap up, despite current geopolitical tensions in various places around the globe and the world’s desire to reduce emissions, all while expressing a desire for a better quality of life, we think the demand for oil and the apparent discipline with production amongst the OPEC players will manifest itself into steady drilling activity through 2024.
Gas, that’s a different story. Ensign has a fleet of over 200 high spec drill rigs and a fleet of close to 100 well service rigs of varying capacity situated in 8 different countries around the globe all ready to perform. Management stays laser focused on delivering best in class performance, which will provide free cash flow to maintain our fleet in top condition and keep to our debt reduction targets of $200 million a year. Thanks for joining the call. Look forward to talking to you in the spring.
Operator
Ladies and gentlemen, this concludes your conference call for today. We thank you for joining, and you may now disconnect your lines. Thank you.
