Ensign Energy Services Q3 2024 Earnings Call Transcript

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November 1, 2024

There are 7 speakers on the call.

Operator

Good afternoon, ladies and gentlemen, and welcome to the Ensign Energy Services Inc. 3rd Quarter 2024 Results Conference Call. At this time, all lines are in listen only mode. Following the presentation, we will conduct a question and answer session. This call is being recorded on Friday, November 1, 20 24.

Operator

I would now like to turn the conference over to Nicole Romano, Investor Relations. Please go ahead.

Speaker 1

Thank you, Andrew. Good morning, and welcome to Ensign Energy Services' 3rd quarter conference call and webcast. On our call today, Bob Geddes, President and COO and Mike Gray, Chief Financial Officer, will review Ensign's Q3 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.

Speaker 1

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 services supplied by the company. Additionally, our discussion today may refer to non GAAP financial measures such as adjusted EBITDA. Please see our Q3 earnings release and SEDAR Plus 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.

Speaker 2

Thanks, Nicole, and good morning, everyone. So the Q3 buoyed by strong and increasing demand for our high specs Ensign ADR Canadian rigs, especially our high specs singles, doubles and triples drove another strong quarter over quarter gain with a solid bump from 2nd quarter results. The Canadian business unit led the charge and provided a substantial increase in activity year over year for the quarter. This was however tempered with a decrease in activity in our U. S.

Speaker 2

Business unit, but with relatively steady margins. We saw a steady quarter over quarter year over year in our highly active international business unit, where we have 17 of our 30 high spec rigs active today operating in 6 different countries around the world. With steady margins and solid activity levels generally around the globe, we continue to execute on our plan. In the quarter, we addressed another $45,000,000 of debt reduction, which takes us to $135,000,000 year to date and keeps us solidly on the path to reduce $600,000,000 of debt over the next 3 years. This is built on a steady free cash flow stream into a solid forward book and increasing margin construct.

Speaker 2

Over to Mike for a summary of the Q3, then I'll come back to provide an operational update in each of the operating areas. Mike?

Speaker 3

Thanks, Bob. Customer consolidation and volatile commodity prices have impacted Ensign's operating financial results over the short term. However, despite these headwinds, the outlook for oilfield services is constructive and the operating environment continues to look stable. Overall, operating days were consistent in the Q3 of 2024 in comparison to the Q3 of 2023. The company saw a 14% decrease in the United States to 3,065 operating days, offset by Canadian operations achieving 3,861 operating days, an 18% increase.

Speaker 3

International operations recorded 12 69 days, consistent with when compared to the Q3 of 2023. The 1st 9 months ended September 30, 2024, overall operating days declined with the United States recording a 27% decrease, offset by an increase in Canada and international of 9% and 6%, respectively, when compared to the same period in 2023. The company generated revenue of $434,600,000 in the Q3 of 2024, a 2% decrease compared to revenue of $444,400,000 generated in the Q3 of the prior year. For the 9 months ended September 30, 2024, the company generated revenue of $1,260,000,000 an 8% decrease compared to revenue of $1,360,000,000 generated in the same period of 2023. Adjusted EBITDA for the Q3 of 2024 was $119,000,000 1 percent higher than adjusted EBITDA of $117,300,000 in the Q3 of 2023.

Speaker 3

Adjusted EBITDA for the 9 months ended September 30, 2024 totaled $336,700,000 7% lower than adjusted EBITDA of $361,200,000 generated in the same period in 2023. The 2024 decrease in adjusted EBITDA can be primarily attributed to year over year declines in drilling activity, primarily in the United States. Depreciation expense in the 1st 9 months of 2024 was 261,800,000, an increase of 14% compared to $229,600,000 in the 1st 9 months of 2023. General and administrative expense in the Q3 of 2024 was 1% higher than in the Q3 of 2023. General and administrative expenses increased primarily as a result of annual wage increases.

Speaker 3

However, G and A was down 12% from Q2 2024 to Q3 2024. Interest expense decreased by 24% to $23,800,000 from 31,300,000 dollars The decrease is the result of lower debt levels and reduced effective interest rates. Our interest expense will continue to decline as our debt level decrease and interest rates continue to be cut as our interest rate on our debt is floating. During the Q3 of 2024, dollars 44,700,000 of debt was repaid and a total of $135,000,000 was repaid during the 1st 9 months of 2024. From January 1, 2023 to September 30, 2024, a total of 352 600,000 of debt has been repaid, leaving 247,400,000 of the 600,000,000 debt reduction target expected to be achieved by the end of 2025.

Speaker 3

The company is on track to achieve its stated debt targets. Net purchases of property and equipment for the Q3 of 2024 totaled $33,500,000 consisting of $5,000,000 in upgrade capital and $32,300,000 in maintenance capital, offset by disposition proceeds of $3,800,000 Capital expenditures for 2024 are targeted to be approximately $167,000,000 primarily related to maintenance expenditures, tubular purchases and selected growth and upgrade projects that have been funded by customers. On that note, I'll turn the call back to Bob.

Speaker 2

Thanks, Mike. So it's running around the world here and doing operational update, starting with Canada. The combination of expanded pipeline capacity both for oil and LNG, the tightening differential and with the low Canadian dollar, the net effect is that more drilling will occur in the Western Canadian Sedimentary Basin. It's safe to say that the demand for our high spec singles and high spec triples is at the highest it has been in quite some time, at least a decade. This has also helped to drive the high spec double market to enjoy utilization above 60%, which is a typical threshold where contractors are able to move pricing.

Speaker 2

Almost 1 third of Ensign's Canadian fleet are high spec doubles, so we have lots of product to feed into this construct. Our fleet of high spec singles and high spec triples are essentially booked well into 20 25. Canada is back to the Q1 levels of activity which rarely happens in the Canadian market in the Q3. Historically,

Speaker 3

over

Speaker 2

a third of the operating days typically occur in the Q1 of the winter drilling season. Our Canadian drilling business unit has 50 rigs active today and looking steady through November with a drop off as we get closer to Christmas and operators shut down over the Christmas break. After Exmas, we have visibility to quickly get back to 55 rigs, perhaps even peaking at 60. Rates for the high spec singles and high spec troubles will be moving higher as utilization in these rig categories continues to be very strong. Notwithstanding, day rates are still well below any new build metrics.

Speaker 2

Rates need to be in the 50s before we see new build super spec triples and for the high spec singles and high spec doubles, rates will need to be in the very high 30s before investment could be made in new builds with a reasonable rate of return that covers at least the cost of capital. We're also seeing lots of interest in our Edge Auto pilot with specific apps such as the ADS, the automated drill system, which charged out at $1,000 a day being initiated on certain high spec triples growing into Canada. While on the incremental revenue theme, we have also expanded certain apps from our Edge Autopilot platform onto our ADR high spec singles, again, more opportunity to drive incremental revenue streams on existing active assets. As mentioned, we have almost 90% of the current active Canadian fleet contracted until the end of the Q1 of 2025. While we witnessed very competitive bidding into the 3rd Q4, we did strategically place ratcheting rate increases compounding as we move through the fall season and into the winter drilling season.

Speaker 2

Our Canadian well servicing business continues to have a strong schedule ahead of for its rigs in the heavy oil area and is expected to pick up as we continue to capture more of the OWA work into 2025. Our rental fleet of tubulars, tanks and other high margin ancillary equipment continues to grow as more and more specialty equipment is called for, usually high torque tubulars to attach to our high spec ADR drill rigs. With accelerated wear an issue on tubulars as a result of the high penetration rates, it is becoming the norm for tubulars to be charged separate from the rig rate and to recognize the consequence of accelerated wear on full cycle tubular costs. Moving to international, we have a fleet of 30 plus drilling rigs that operate in 6 countries around the globe, of which 17 are under contract today. In the Middle East, we have 100 percent of our high spec ADR fleet actively engaged in long term contracts and with half of them on PBI contracts, so it's performance based contracts.

Speaker 2

We're able to get paid for the performance our high performance drilling team provides when coupled with our Edge Autopilot drill rig control systems. In Elan specifically, we drilled the project well ahead of schedule and as a result, we have 2 of the 3 ADRs on standby until year end, at which time they will pick right back up and get after the 2025 drilling campaign with a client. In Argentina, we're running at 100% utilization with both our 2,000 horsepower high spec ADRs operating and under long term contracts. We have one of our drill rigs working in Venezuela with another ready to start up the next month. Australia is staying steady with very little change.

Speaker 2

Moving to the United States, we have a fleet of 77 high spec ADRs in the U. S. Stretching from the California market up into the Rockies and with the main focus back down into the Permian West Texas. We operate roughly 37 rigs today, which is what we ran on average through the Q2. We expect a little change for the rest of 2024 with possibly upside of 1 to 2 rigs.

Speaker 2

The challenge in U. S. Is that in addition to the depressed natural gas prices, we saw $500,000,000,000 of M and A activity in the last 18 months occur, which has manifested itself into less work in the short term. The natural gas story may take a little bit longer to correct itself. The good news is that we have mainly been an oil focused driller in the U.

Speaker 2

S. Market. Coming back to the effects of M and A until the combined entities get through a budget cycle and start addressing decline rates, we don't expect solid improvements in the U. S. Market until late 5 at the earliest.

Speaker 2

Our U. S. Business unit continues to expand its PBI contract base and now has over half the fleet on a PBI contract to some degree that builds off our high performance and highly trained field teams coupled with our Edge Autopilot drilling rig control system technology. Not only do we get a superior rate for Edge Autopilot technology, we capture the upside value generated to the operator through performance metrics. Everybody wins.

Speaker 2

The operator delivers all bores for lower costs and we help de risk that with our PBI contract form. Our U. S. Well servicing business unit, which is focused primarily on the Rockies and California well servicing market, continues to enjoy high utilization in the upper 80s and delivered a record quarter. Our directional drilling business, which is essentially a mud motor rental business that utilizes proprietary technology continues to provide some of the best motors with high quality rebuilds in the Rockies.

Speaker 2

We're also expanding this into the Permian. Move to the technology, Edge Autopilot Drilling and Control Systems. Happy to report we have successfully beta tested our Ensign Edge ATC. ATC is the auto 2 phase control. This paves the way for seamless control of automated directional drilling from those operators who utilize remote operating centers and utilize in house DGS directional guidance systems.

Speaker 2

We continue to grow and deploy Edge Autopilot onto our active rigs across the globe. We most recently installed and commissioned our rig or Ensign Rig OS on our Bahrain rigs, which are starting to execute on the PBI contracts. We continue to expand the Edge APSA platform on each of the rigs that already have our Edge Autopilot DRC technology. This part of our business continues to grow at a rapid pace year over year and deliver results with reduced well times, increased P rates with reduced well tortuosity and help differentiate Ensign from our competitors. With that, I'll turn it over to the operator for questions.

Operator

Thank you. Ladies and gentlemen, we will now begin the question and answer session. Your first question is from Aaron MacNeil from TD Cowen. Please go ahead.

Speaker 4

Hey, morning all. Bob, in your prepared remarks, you mentioned you were essentially booked on the triples in Canada. I was under the impression that you had a couple of idle rigs in the region. So I guess is that still the case? And if we as we look into LNG Canada coming into service, how are you thinking about marketing either I guess idle rigs in Canada or the U.

Speaker 4

S. And what do you think it costs to get them running?

Speaker 2

So in Canada, we have today, we've got a few that are ready to go to work, no capital involved in putting them back to work. They've got 2 or 3 bids out on them. I fully expect they will be contracted as we go into the Q1. So that's what we mean by that comment. LNG, the effects, I think that you're probably going to see more of that weaving itself into the back half.

Speaker 2

I don't see any immediate response to fill pipeline capacity today on LNG. I think everyone's got the capacity to kind of filter into that. The question is how do they to kind of filter into that. The question is how do they keep that moving along and with some of the debottlenecking and pipeline efficiencies working through, yes, you're going to need a steady platform of high spec triples to keep that moving along. So and as I mentioned, the cost to put a new rig together is right now burdensome.

Speaker 2

Rates are not into the 50s where they would need to be to support a $50,000,000 super spec triple type rig, which is what the operators are always wanting. They want the highest technology for the best price.

Speaker 4

Got you. Maybe this one's for you, maybe it's for Mike. I know it's not specifically disclosed, but can you speak to U. S. Gross margins for your drilling rigs?

Speaker 4

And if not, the specific dollars then maybe the trend that you're observing as you think about day rates as well as sort of the prevailing cost structure?

Speaker 3

Yes, for sure. I mean, we've seen some margin compression over the last couple of quarters just with the sort of static to the flat activity in the U. S. And with idle rigs and other basins. But the cost structure overall has been fairly static, if not slightly down the whole supply chain.

Speaker 3

So the issues that came from COVID seem to be alleviated now. So from our standpoint, the margin compression is really more on potential revenue rates than really on a cost basis, but we're seeing that being fairly flat to static on a go forward basis.

Speaker 4

Very helpful. Thanks guys. I'll turn it back.

Operator

Your next question is from Keith MacKay from RBC. Please go ahead.

Speaker 5

Hey, thanks and good morning. Mike, can we start out on the Q4 free cash flow and liquidity? Maybe if you could just walk us through the pieces of free cash flow for Q4. We know you've got some mandatory debt repayments and now there is a credit facility liquidity coming in for Q4. Can you just kind of walk through what we should expect on the free cash flow side to help keep you on side of that of the revised liquidity?

Speaker 3

Yes, no, for sure. I'll start off. I mean, we're definitely going to be on the right side. When you look at it, consensus right now is about $120,000,000 for EBITDA. CapEx with $167,000,000 for the quarter will probably be around that $30,000,000 growth CapEx.

Speaker 3

Interest expense will be between that $20,000,000 to $25,000,000 So that leaves you about $65,000,000 of free cash flow left over for debt repayments. There's potential for some non operating cash flow inflows from some property and asset dispositions that could come into Q4. So when we look at the free cash flow based on where consensus is, CapEx and interest, we should be in a pretty good position. We exited the quarter, Q3 with 66,300,000 in liquidity. So with the 75,000,000 reduction in the facility and the 27,000,000 term loan payment, we don't foresee any issues and we'll exit the year with liquidity.

Speaker 3

Going into Q1, with 2025 looking fairly stable to static kind of year over year. We don't really see a big demand for CapEx or anything like that. So everything is looking, like I said, to be on the right side going forward.

Speaker 5

Okay. That's very clear. And just on 2025, I know you haven't given guidance yet, but what's sort of the ballpark we should be thinking about for 2025 CapEx at this point? Is it roughly a flat year given the rest of the activity levels should be roughly flat?

Speaker 3

Yes, what we're seeing is probably pretty flat year over year. Like I said, if activity in the U. S. Picks up in the back half, that might increase a little bit. But what we're seeing right now is a fairly static year over year, which I think from the balance sheet perspective is quite good.

Speaker 5

Yes, got it. And just one final one for me on the Canada Duvernay specifically. I know you've got pretty high utilization on your triple rigs as it is and you've been pretty active historically in the Duvernay and I know that asset one of the assets in the Duvernay anyways has recently changed hands. Can you just talk maybe about some of the trends you're seeing in the Duvernay? Do you expect activity there to pick up in the next 1 to 2 years?

Speaker 5

Or should things there stay relatively flat?

Speaker 2

My sense is they stay relatively flat with maybe a small uptick. But it seems that the Canadian market has moved away from this heavy first quarter, drill your brains out, settle down 2nd quarter, slow down 3rd quarter, 4th quarter into a more stable. And that's a lot to do with the infrastructure has been more robust, we built out and we have pad rigs that can drill right through breakup. So it's taken the seasonality out of it a little bit. So you're seeing a more common static approach.

Speaker 2

So I would suggest static to maybe 1 or 2 rigs.

Speaker 3

Got it. Okay. Thanks very much.

Speaker 2

Thanks, Keith.

Operator

Your next question is from Makar Sied from ATB Capital. Please go ahead.

Speaker 6

Thank you for taking my questions. I have a few of those. First of all, on your EBITDA margins, they look to be up like 300 basis points year over year, which is fairly impressive. Is it all the margin uplift is all being driven by Canada Drilling or is it also well servicing as well contributing as well in international because we know U. S.

Speaker 6

Is perhaps down?

Speaker 3

Yes, no, it's a combination of all, the Canadian market while servicing, and then the international predominantly in Australia. So, we're seeing, let's say, margin expansion in areas like that. And then we're seeing, like I said, fairly static to slightly down on the U. S. Side just given some of the pricing constraints.

Speaker 6

Now in Australia, you said also helping, is it pricing is up in Australia?

Speaker 2

Generally, it's fairly flat. We've got 2 large rigs on large. They're almost integrated project management projects, Waccar that can lead the way in those results. 2 out of the 7 that we have running are kind of skewing those numbers a little bit.

Speaker 6

Now this is good that the rig mix has shifted, but it feels to me like over the last one year, Australia activity hasn't really picked up as at least how I expected. What's going on there?

Speaker 2

Well, they a good question. I mean, they seem to have fallen into they can drill enough to keep 13,000,000 LNG going off the coast and satisfy their internal needs, which are growing, electricity needs are growing. But we see a growing construct there moving into the future. There's always been a little bit of political challenges. Australia isn't void of those, but are more generous with the gas development.

Speaker 2

I do think though that it we think of it as fairly static, no fundamental problems and it will grow slowly over time, but we're not expecting any rapid jumps.

Speaker 6

Okay. And now shifting to the U. S. Market in California, what's your mix in terms of drilling between geothermal and for hydrocarbons? And then do you see any opportunity for rig activity in Nevada for drilling for lithium bearing brines?

Speaker 2

We don't have any lithium wells underway today. We have 1 rig in California growing to we'll have 1 up in Oregon, doing geothermal. So most of it is oil and gas. I mean geothermal doesn't make a market. You get geothermal wells between other oil and gas wells when the rigs are down, but you don't get geothermal projects back to back to keep a rig busy.

Speaker 2

It's more anecdotal. But we've got more experience than anyone drilling geothermal wells and we've got a great team that understands what's required. So when the engineering teams look after these geothermal wells who don't have any experience or very little experience in the area, we can help them de risk the project.

Speaker 6

Yes. There is have you has any one of these lithium companies in Nevada approach you guys about future needs for drilling rigs or nothing as yet, no talk as yet?

Speaker 2

Nothing I'm aware of, Nicole. No, no. Not that we're aware of, Makar.

Speaker 6

Yes. And then could you talk about your rig moves from U. S. To the Canadian market? Have they all happened or are there still some rigs on the move?

Speaker 2

Yes, basically, there's one other one underway that will weave itself in probably in the Q1 type of thing. And we had 12,000 horsepower rig that was built for the Horn River by Trinidad, which drilled a few wells and then sat down for a period of time, drilled 1 or 2 wells after that, it's moved into Oregon to drill a deep geothermal well. And then it's contracted into the Rockies after that. Rigs, as you know, are getting deeper because of 4 5 mile laterals and more racking capacity. So a 2,000 horsepower rig all of a sudden becomes a little more desirable in certain markets.

Speaker 6

Yes.

Speaker 2

But not the Horn River market in Canada.

Speaker 6

Sure. Well, that's all for me. Thank you very much. Appreciate the color.

Speaker 2

Thanks, Ricard. Appreciate it.

Operator

There are no further questions at this time. Please proceed with closing remarks.

Speaker 2

Thank you, operator. So looking forward, it continues to be an exciting time for Ensign as we build on last quarter's robust Canadian and international market fundamentals. We are seeing an improving long term outlook in all our U. S. Markets, but don't expect any meaningful growth until back half 'twenty five or into 'twenty six.

Speaker 2

With over $800,000,000 of forward revenue booked under contract, we expect to continue to steady run rate of 100 to 110 enzyme drill rigs and roughly 60 to 70 well service rigs operating daily. A third of those are on long term contracts with contract tenure of about a year and roughly 25% of those contracts are on a performance based contract of some sort. With that, we have excellent visibility for sustained free cash flow with consistent margins, which will provide the ability to continue executing on our debt reduction plan, just as we said we do. With the application of Edge Autopilot combined with an expanding PBI contract base, backed up with our superior performance drilling teams in the field, Ensign is delivering value to operators, which supports rate increases moving forward. Again, the focus continues to be accelerating debt reduction into a steadily improving construct for the drilling and well servicing businesses globally.

Speaker 2

I'd like to thank our highly professional crews and all of our employees, along with our customers for helping Ensign achieve the performance and industry milestones that the industry recognizes us for. Look forward to our next call in about 3 months' time. Stay safe. Thank you.

Operator

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

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