Ensign Energy Services Q1 2024 Earnings Call Transcript

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May 6, 2024

There are 8 speakers on the call.

Operator

Good afternoon, ladies and gentlemen, and welcome to the Ensign Energy Services Inc. Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer session. Over to Nicole Romano, Investor Relations.

Operator

You may begin your conference.

Speaker 1

Thank you, Julie. Good morning, and welcome to Ensign Energy Services' 1st quarter conference call and webcast. On our call today, Bob Geddes, President and COO and Mike Gray, Chief Financial Officer, will review Ensign's Q1 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 Q1 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.

Speaker 2

Thanks, Nicole. Good morning, everyone, and thanks for joining our call this morning. I'm pleased to report that once again, the Ensign team continues deliver on debt reduction along with increased free cash flow and margin expansion. Since 2019, Ensign has clipped off close to $500,000,000 of debt off the balance sheet, that while executing on a few opportunistic acquisitions, which are generating strong EBITDA margins and free cash flow today. We saw the usually busy Canadian Q1 winter, somewhat muted by the effect of abnormally cold weather, which affected operations.

Speaker 2

We had a week of 40 below and we are seeing a paradox develop in the U. S. For record oil production, extremely low levels of DUCs combined with decline rates not translating into rig activity, more on this later. This quarter's results emphasize the benefits of being a global player, While the U. S.

Speaker 2

And Canada were off in the quarter, more so in the U. S. And Canada, our International Business segment was up in the quarter year over year. Once again, our global footprint helps to de risk the company and provide lower beta risk on any geopolitical or specific commodity pricing differentials, which may occur in different places around the world. The impact of the TMX will lead to increased activity in the Western Canadian Basin due to compressed differentials, but gas pricing remains a challenge worldwide with Europe emerging from a 2 sigma warm winter and storage is 60% full at the end of April.

Speaker 2

I would be remiss if I didn't mention that the excellent operational performance in the Q1 was achieved with a reduction in incidence year over year and with the team delivering the 2nd best safety record in Ensign's history. So I'll turn it over to Mike, our CFO, for a deeper dive into the financial results for the quarter. Mike?

Speaker 3

Thanks, Bob. Fluctuating commodity prices and customer consolidation have been headwinds impacting Ensign's operating and financial results over the short term. However, despite these short term headwinds, the outlook for oilfield services is constructive and the operating environment for the oil and natural gas industry continues to support steady demand for services. Total operating days were lower in the Q1 of 2024 with United States and Canadian operations recording a 32% and a 1% decrease respectively, while our international operations saw a 19% increase compared to the Q1 of 2023. The company generated revenue of $431,300,000 in the Q1 of 2024, 11% decrease compared to revenue of $484,100,000 generated in the Q1 of the prior year.

Speaker 3

Adjusted EBITDA for the Q1 of 2024 was $117,500,000 an 8% decrease from adjusted EBITDA of $127,300,000 in the Q1 of 2023. The decrease in adjusted EBITDA was primarily due to the decrease in activity across our North American operations. Depreciation expense in the 1st 3 months of 2024 was $88,300,000 13% higher than $77,900,000 for the 1st 3 months of 2023. The depreciation expense increased because of drilling rigs being moved from the marketed fleet into the reserve fleet in 2024. G and A expense in the Q1 of 2024 was 4% higher than the Q1 of 2023.

Speaker 3

G and A expense increased due to annual wage increases and higher nonrecurring fees. Net capital purchases for the quarter was $51,500,000 with $54,800,000 of purchases, offset by $3,300,000 in sales proceeds. Our CapEx budget for 2024 is $147,000,000 Interest expense in the Q1 of 2024 was $26,500,000 a decrease of 23% for the Q1 of 2023. This is a result of lower debt levels and improved interest rates based on improving debt metrics. The company expects its blended interest rates with the Federal Reserve Bank's hold interest rates at current levels to be approximately 8%.

Speaker 3

Total debt, net of cash, was reduced by $13,600,000 since December 31, 2023. Our debt reduction target for 2024 will be approximately 200,000,000 dollars Our debt reduction for the period 2023 to the end of 2025 is approximately 600,000,000 On that note, I'll turn the call back to Bob.

Speaker 2

Thanks, Mike. Just for a macro before we get into the divisional business units. As mentioned before, we saw a Q1 in Canada with activity only off 1%, while industry was off closer to 4% year over year, implying market share gain by Ensign. But we experienced a more serious drop in the U. S.

Speaker 2

With a 32% drop in drilling activity year over year. Once again, our international business unit on the other hand was up 19% on operating days. Record M and A activity in the U. S. Over the last year is seriously muted activity as competitors volleying to hang on to market share.

Speaker 2

Our thesis is that this will manifest itself into higher activity, but not until very late in 'twenty four, but certainly into 'twenty five. It's currently breakup in Canada, so our global rig count is down into the 80 to 85 seasonal range and a 50 to 55 range on our well service business segment focused in North America. Let's start with the United States. United States market seems to have now stabilized with disciplined pricing and everyone holding their market share, but we will still see some pricing pressure anecdotally. We currently have 38 rigs active today in the U.

Speaker 2

S, but we feel that is more likely to stabilize with perhaps a few more rigs dropping off next few months but building back slowly in 3rd and into 4th quarter. While our call was at the back half of 'twenty four, we'd start to see an uptick in activity. We have moved that call to the Q4 post election. California and the Rockies are still plagued with permitting challenges. With that, we expect to run between 8 to 10 rigs in those areas.

Speaker 2

It's ironic that while California's Dynase permits, the state will be taking Canadian crude most likely drilled by an Ensign rig in Canada by the TMX pipeline to California refineries. The Permian seems to be or seems to have bottomed out at just north of 300 rigs active today, but seems stuck here for at least another few quarters. We're seeing rates struggle to get back to the 30s for the super spec triples, but expect that log jam to release itself in the back half of the year, close to the Q4. Our Well Servicing business unit, which is focused primarily in the Rockies in California, is still very active with 42 of our 47 rig fleet active on any given day. Our directional drilling business in the Rockies continues to build market share in the motors supply part of the business.

Speaker 2

Moving to Canada. In Canada, we're of course in the middle of breakup. We expect Canada to climb up from its current activity of 28 rigs to 30 5 to 30 to 35 post breakup and then 50 to 55 mid late summer building up to 60 in Q4. I'll point out that we are about we are up about 50% year over year in activity through breakup, and we gained market share exiting the winter and into breakup. We have transferred up 2 of our ADR-300s from our U.

Speaker 2

S. California business unit and have placed both these highly versatile rigs on the long term contracts and with the operator covering the mob and retrofit costs required for their specific projects. Operators are finding our ADR-three hundred is the most flexible and efficient of the super spec designs currently available. We still find the super spec triples in the low mid-30s and the high spec double in the low mid-20s depending on the rig configuration. We're contracting our super spec ADR-300s in the low-20s with strong demand for our flexible super spec ADR-three hundred design for the Clearwater man built plays.

Speaker 2

Our well servicing team continues to see visibility back close to 20 well service units active post breakup and currently have 11 out on jobs today. The rentals business unit continues to run with high rental utilization on its assets and sees a growing opportunity for drill pipe rentals as drilling contractors move to put drill pipe on the outside of day rate contracts due to accelerated wear and other nuances. On the international side, our international business unit has 17 rigs active today, down 1 in Argentina from our last call. Australia remains steady with 8 rigs active with increasing bid activity. Oman, which has 3 of our ADR-300s operating on an IPM project, is performing extremely well and has been earning increasing margins due to the PBI contracts.

Speaker 2

These rigs are tied up well into 2027. Kuwait remains steady with 2 rigs active, with both rig contracts extended out into mid-twenty 25. Our 2 rigs in Bahrain continue to operate in the top tier operationally and are contracted into mid-twenty 25. As mentioned, we had one of our super spec triple rigs in Argentina come down for a short period. We fully expect this rig to be back up and running later in Q3 or beginning of Q4.

Speaker 2

We have one rig up and running in Venezuela today and have signed the contract to start up a second rig, which should start up later in the Q3. On the technology side, our Drilling Solutions business unit, we continue to grow this technical automation AI component of our business by 15% year over year. Our Edge Autopilot drilling rig control system continues to be installed at a pace of a rig a month, and we continue to see demand for our automated drill system, what we call our ADS, which charges out at $1,000 a day on top of the Ensign basic core, which is $6.25 a day. Again, we continue to see demand for that Edge Autopilot platform. With all the bells and whistles, it charges out at about $2,400 a day.

Speaker 2

We're currently backlogged out at least 4 months on our ADS installs. We're also starting to put our Edge autopilot platform in some of our Middle East rigs. On the environmental product line, we have 4 products that are available on Ensign rigs in which to deliver high margins and significantly reduce emissions. We also commissioned a few more new natural gas BEST systems, battery energy storage systems, which charge out in the $5,000 a day range and help to reduce emissions by 60 Best systems are battery energy storage systems, as I mentioned, that help store and modulate electrical power delivery on natural gas engine applications. The best systems on an a la carte basis charge out in that $1700 to $2,000 range.

Speaker 2

Our investment in a leading BESS manufacturer has provided Ensign secure, reliable and cost effective access to BEST units into the future. Our first NPower substation arrived and is being rigged up on a job as we speak. Ensign substation will drive further emission reductions while generating a solid ROI for all electric rigs connected on the High Line projects. These units charge out about $200 to $2,500 a day. So with that, I'll turn it back to the operator for questions.

Speaker 2

Thank

Operator

you. Your first question comes from Aaron MacNeil from TD Cowen. Please go ahead.

Speaker 4

Good morning. Appreciate the time to take questions. First one is for Mike. Kind of start to see the credit facility get reduced in Q2 and then again in Q4. I know you soaked up a lot of cash in Q1 on CapEx and working capital, but how should we think about working capital flows into the Q2?

Speaker 4

Can you give us any updates in terms of how you're engaging with the syndicate or if you even need to or if you see any issues there as the year progresses?

Speaker 3

Thanks for the question. Yes, when we look at it, so we ended the quarter with about 878 on our facility. So we do have to be a $28,000,000 reduction. To get to the $850,000,000 we have our term loan payments of 28,000,000 dollars So essentially $56,000,000 of debt reduction needs to take place. In Q2 of this year, if you look in the prior year, we did close to $84,000,000 in debt reduction in Q2.

Speaker 3

That's a very, let's say, heavy cash flow input in comparison to Q1 where you have a lot of CapEx and operating expenses. So when we look at it, I think we're in good shape for that to take place. You also look at our interest payments. Q2 of last year, we had about $41,000,000 in cash interest payments. Our bonds were due in April as well as in October for interest.

Speaker 3

So we'll see cash savings on the interest expense. Once again, we had about 132,000,000 in cash interest or interest expense in 2023. We're expecting that to be a sub 100. So when we look over year over year, we're seeing about 32,000,000 in interest savings that can go towards debt reduction. Our CapEx spend last year was 175,000,000 compared to about $147,000,000 this year.

Speaker 3

So there's about $28,000,000 in savings there. So all in all, when you put those parts together, we're confident on the $200,000,000 debt reduction and then confident on the reduction in the facility as well as the term payments.

Speaker 4

Total sense. Bob, I think you mentioned in your prepared remarks for pricing below $30,000 per day in the Permian. I guess in the absence of a higher rig count, do you see pricing further deteriorating for the balance of the year? Or do you generally see your competitors acting disciplined on the even far between new bids that do occur?

Speaker 2

Yes. I mean, we're seeing some stabilization, but anecdotally, we see some of the smaller players taking a crack some of our and others consistent clients, which encourages a little bit of conversation. We turn that conversation over into a performance based contract saying, okay, if there's some pressure on rates, we'll take you up on that. But we also want it as quid pro quo, a performance based contract. Some cases, we've been able to actually increase our net day rate per day with the performance based incentives.

Speaker 2

But we're kind of normalizing that with those conversations over the last few months. But I would say that there's still some pressure on pricing as we go into the summer. And we're not seeing anyone saying, hey, I want to tie up for 2 years, which always tells us that the operators are still rolling up their sleeves a little bit on pricing.

Speaker 4

Got it. Thanks guys. I'll turn it back.

Speaker 2

Thanks Eric.

Operator

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

Speaker 5

Yes. Hey, good morning. Just wanted to retouch on the debt. Certainly, one of the things we've been getting questions about is covenants and it looks like you're getting fairly close on that senior debt to EBITDA covenant. Mike, can you kind of walk us through the pieces for Q2 of how that works?

Speaker 5

I'm assuming EBITDA will be a little bit lower, but it looks like debt reduction for Q2 will also come down significantly. So can you just kind of talk to that specifically and some of the pieces there?

Speaker 3

Yes, for sure. I mean, when we reset the balance sheet back in October, I mean, we did it in a sense that everything is achievable. So when we look at it, there's no concerns on those covenants. All of our debt structure is right now is senior debt, where before we would have a mix between senior and the unsecured, which would have went to the total debt. So we look at Q2, like once again, to Aaron's question, the free cash flow in Q2 will be quite significant.

Speaker 3

It will give us the ability to reduce our facility as well as make the term loan payment. The term loan payment, once again reduces your senior debt, again, we'll improve that covenant. So when we look at it, we're quite confident on everything going as planned. So from our perspective, just the way Q2 works with the cash inflow or reduced interest expense. And like I said, Q1 is always heavy CapEx.

Speaker 3

We don't foresee any issues. So we'll see that covenant ratio continue to go down. That's the one benefit of the term loan is that is paid off. There's about $110,000,000 that will be paid off this quarter or this year, which once again will reduce that covenant ratio as we continue to basically perform as we are.

Speaker 5

Yes, thanks for that. Can you just talk a little bit about Canada? Q1 was down about 1% year over year in terms of rig days. Can you just talk about how you're thinking about the second half of the year on a year over year basis in Canada?

Speaker 2

Yeah, it's as I mentioned, we've got 50% more rigs running through breakup than we did last year. We had about 17 last year. Keith, we have 28 this year. And we're starting to build up into the 30 to 35 range post breakup, should be back to 50 by end of summer. We've got contracts and visibility for that.

Speaker 2

We've also got the 280 or 300s that we brought up from California. They were retrofitted over the winter to the operators' specific requirements. They're ready to go out the door as soon as we can get them out on the road bands. And then we're I think we're seeing indications from operators wanting to make sure that they grab their best rigs going into the fall. So for us, it's quite a different year than last year.

Speaker 2

We grabbing some more market share as we entered breakup, gaining market share through breakup and I think we'll continue that through 2024.

Speaker 5

Okay. That's it for me. Thanks very much.

Speaker 2

Thanks, Keith.

Operator

Your next question comes from wakar Saeed from ATB Capital Markets. Please go ahead.

Speaker 6

Thanks guys. Good morning. Mike, what would your guidance be for DD and A for Q2 and the following quarters?

Speaker 3

We don't really give guidance on that. I mean historically we've run between that $75,000,000 to $85,000,000 in depreciation. So that would probably be the ballpark.

Speaker 6

Okay. So this pickup in Q1 for accelerated depreciation, that additional part is just 1 quarter issue or is that has some lingering impact to the course of the year?

Speaker 3

There'll be some lingering impact for the course of the year.

Speaker 6

And Bob, could you talk about the geothermal side in California? What's the outlook there? Do you see some incremental drilling?

Speaker 2

Yes, yes. We're having more and more discussions on bids on geothermal projects. We've got a few underway now. I think we have 2 underway right now. But yeah, it's more of a conversation, drilling more geothermal wells in California in that West Coast area, all the way even up into Oregon.

Speaker 2

All while the irony is, all while Canadian oil comes down to the TMX in the California to sell the increasing demand for gasoline at the pumps. But yes, that's where we're on geothermal.

Speaker 6

Okay. And then in Venezuela, when did you say your second rig could start up?

Speaker 2

We're thinking end of Q3. So it'll be the end of the summer.

Speaker 6

And have you received a go ahead from the operator to start preparing the rig or are you still waiting for that?

Speaker 2

We have a contract signed and they've forwarded the monies for the upgrade on the rig.

Speaker 6

Great. And then in terms of the Canadian market, I think there were some expectations of price increases there by maybe up to about 5%. Is that still a possibility or not really now?

Speaker 2

Yes, for sure. It's generally, we're putting out our high spec doubles with that level of increase and our high spec triples in that range or higher as the market continues to tighten up into the Q4 Q3, I'm sorry.

Speaker 6

Okay, great. Thank you very much. That's all from me.

Speaker 2

Thanks, Sarkar.

Operator

Your next question comes from Josh Jain from Daniel Energy Partners. Please go ahead.

Speaker 7

Thanks. First one, could you please speak to the opportunity set for consolidation within the United States well service sector? And specifically, do you see much on the market? And if you do, how would you characterize the quality of those businesses?

Speaker 2

Good question. The well service business in the U. S. Is certainly a lot more fragmented and area specific than what you would find north of the border, for example, where there has been some consolidation. I would suggest that, again, the activity focuses on different areas, consolidation.

Speaker 6

I'm not seeing

Speaker 2

or not hearing of any consolidation efforts. So I can't expand on that other than we're fairly active in the areas we are, which is focused on Rockies and California with our well servicing. But as far as consolidation, I'm not thinking consolidation as necessary in the well servicing area as it might be perhaps in the Permian drilling area, for example.

Speaker 7

Okay. And then maybe a follow-up on the U. S. Drilling side. So you noted in your release, so 80% of your rigs that are contracted today will sort of roll off in the next 6 months in the U.

Speaker 7

S. You talked about the decrease in day rates. Are customers in the U. S. Still wanting to sign up term contracts today?

Speaker 7

And are you seeing them opportunistically look at term potentially maybe more so than they were 6 months or 9 months ago?

Speaker 2

Not yet. Not yet. We're still running 6 month type contracts, which is fairly typical. And we haven't seen a discussion for people saying, hey, we want to sign you up for 1 to 2 year contracts. When that starts to happen, of course, you know that it's starting to

Speaker 7

turn. Okay. Thank you.

Speaker 2

Thank you.

Operator

There are no further questions at this time. I will turn the call back over to Bob Geddes for closing remarks.

Speaker 2

Thanks, everyone, for joining us again. Continuing current geopolitical tensions in various places around the globe in the world's confliction with the desire to reduce emissions all while expressing a desire for a better quality of life with the expanding demand for the hydrocarbon molecule, along with record M and A activity bump behind us, demand for continuing record U. S. Production coupled with record low DUCs inventory and continuing decline rates, we believe this will manifest itself into steady drilling activity uptick through late 2024 and into the future. Gas is a completely different story.

Speaker 2

It will take some time to figure itself out. Natural gas cogen plants will grow as the world moves off coal and gets onto clean burning natural gas. And along with that, natural gas demand expected to rise percent in the next 15 years. In the meantime, gas oversupply will plague the gas side of the business. Ensign has a fleet of over 200 high spec drill rigs ranging from 200,000 pound to 1,500,000 pound of gold capacity along with a fleet of close to 100 well service rigs of varying capacity situated in 8 different countries around the world, all ready to perform safely and profitably.

Speaker 2

Management stays laser focused on delivering best in class performance, which will provide sufficient free cash flow to maintain our fleet in top condition and keep to our debt reduction targets of $200,000,000 a year. Thank you and look forward to our next call in the summer.

Operator

Ladies and gentlemen, this concludes today's conference call. You may now disconnect. Thank you.

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Key Takeaways

  • Ensign has reduced debt by approximately $500 million since 2019 while expanding free cash flow and margins, targeting a further $200 million of debt reduction in 2024 and $600 million by end-2025.
  • In Q1 2024, revenue was US$431.3 million, down 11% year-over-year, and adjusted EBITDA was US$117.5 million, down 8%, primarily due to a 32% drop in US and 1% drop in Canadian drilling activity.
  • North American softness was offset by a 19% increase in international operating days, highlighting the benefits of Ensign’s diversified global footprint in de-risking commodity and geopolitical exposures.
  • Looking ahead, US drilling activity has stabilized with disciplined pricing but modest downward pressure, with an anticipated pickup in late 2024 post-election; Canadian rig count is expected to climb from ~28 at breakup to ~60 by Q4.
  • Investments in technology and environmental solutions remain a focus, with automated drilling systems (Edge Autopilot, ADS) growing over 15% annually and battery energy storage systems reducing emissions while commanding premium day rates.
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Earnings Conference Call
Ensign Energy Services Q1 2024
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