Ensign Energy Services Inc

TSX:ESI

Earnings Call Transcript

[Operator]

Good afternoon, ladies and gentlemen, and welcome to the Ensign Energy Services Inc. Conference Call. [Operator Instructions]. I would now like to turn the conference over to Nicole Romanow, Investor Relations. You may begin your conference.

[Nicole Romanow, executive]

Thank you, Julie. Good morning, and welcome to Ensign Energy Services First Quarter Conference Call and Webcast.

On our call today, Bob Geddes, President and COO; and Mike Gray, Chief Financial Officer, will review Ensign's first 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 defensive 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 first 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.

[Robert Geddes, executive]

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 to deliver on debt reduction along with increased free cash flow and margin expansion.

Since 2019, Ensign has clipped off close to $0.5 billion of debt off the balance sheet debt while executing on a few opportunistic acquisitions, which are generating strong EBITDA margins and free cash flow today. We saw the usually busy Canadian first quarter winter, somewhat muted by the effect of abnormally cold weather, which affected operations. 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 as results emphasize the benefits of being a global player. While the U.S. 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 derisk 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 Sedimentary Basin due to compressed differentials but gas pricing remains a challenge worldwide, with Europe emerging from a 2 Sigma warm winter in the storage at 60% full at the end of April. I would be remiss if I didn't mention that the excellent operational performance in the first quarter was achieved with a reduction in incidence year-over-year and with the team delivering the second 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?

[Michael Gray, executive]

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 first quarter of 2024 with the United States and Canadian operations recording a 32% and a 1% decrease, respectively, while our international operations saw a 19% increase compared to the first quarter of 2023.

The company generated revenue of $431.3 million in the first quarter of 2024, 11% decrease compared to revenue of $484.1 million generated in the first quarter of the prior year. Adjusted EBITDA for the first quarter of 2024 was $117.5 million, an 8% decrease from adjusted EBITDA of $127.3 million in the first quarter of 2023. The decrease in adjusted EBITDA was primarily due to the decrease in activity across our North American operations.

Depreciation expense for the first 3 months of 2024 was $88.3 million, 13% higher than $77.9 million for the first 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&A expense in the first quarter of 2024 was 4% higher than the first quarter of 2023. G&A expense increased due to annual wage increases and higher nonrecurring fees.

Net capital purchases for the quarter was $51.5 million, with $54.8 million of purchases, offset by $3.3 million in sales proceeds. Our CapEx budget for 2024 is $147 million.

Interest expense in the first quarter of 2024 was $26.5 million, a decrease of 23% for the first quarter 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 at the Federal Reserve banks hold interest rates at current levels to be approximately 8%.

Total debt net of cash was reduced by $13.6 million since December 31, 2023. Our debt reduction target for 2024 will be approximately $200 million. Our debt reduction for the period 2023 to the end of 2025 is approximately $600 million. If industry conditions change, this target could be increased or decreased.

On that note, I'll turn the call back to Bob.

[Robert Geddes, executive]

Thanks, Mike. Just for a macro before we get into the divisional business units. As mentioned before, we saw a first quarter 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. 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&A activity in the U.S. over the last year has seriously muted activity as competitors volleyed to hang on to market share. Our thesis is that this will manifest itself into higher activity but not until very late in '24, but certainly into '25.

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 in 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.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 third and into fourth quarter. While our call was that the back half of '24 we'd start to see an uptick in activity, we have moved that call to the fourth quarter 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. It's ironic that while California stimies 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 are 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 fourth quarter.

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.

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 35 -- to 30 to 35 post breakup and then 50 to 55 mid late summer, building up to 60 in the fourth quarter. 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.S. California business unit and have placed both these highly versatile rigs onto long-term contracts and with the operator covering the [ mobe ] and retrofit costs required for their specific projects.

Operators are finding our ADR 300s are 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 300 design for the Clearwater [ Manville ] plays.

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 [ Reynolds ] business unit continues to run with high rental utilization on its assets and sees a growing opportunity for drill pipe rentals as drilling contracts is moved 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 actively 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. These rigs are tied up well into 2027.

Kuwait remains steady with 2 rigs active with both rig contracts extended out into mid-2025. Our 2 rigs in Bahrain continue to operate in the top tier operationally and are contracted into mid-2025.

As mentioned, we had 1 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 the third quarter or beginning of the fourth quarter. We have 1 rig up and running in Venezuela today and has signed the contract to start up a second rig, which should start up later in the third quarter.

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 or 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 $625 a day. Again, we continue to see demand for that EDGE Autopilot platform with all the bells and whistles, that charges out at about $2,400 a day. 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 at Ensign rigs in which deliver high margins and significantly reduce emissions. We also commissioned a few more new and natural gas BES systems, battery energy storage systems, which charge out in the $5,000 a day range and helped to reduce emissions by 60%. BES systems are battery energy storage systems, as I mentioned, that help store and modulate electrical power delivery on natural gas engine applications.

The BES systems on an a la carte basis charge out in that $1,700 to $2,000 range. Our investment in a leading BES manufacturer has provided Amazon a secure, reliable and cost-effective access to BES units into the future. Our first [ empower ] substation arrived and is being rigged up on a job as we speak. The Ensign substation will drive further emission reductions while generating a solid ROI for all electric rigs connected on high line projects. These units charge out at about $2,000 to $2,500 a day.

So with that, I'll turn it back to the operator for questions.

[Operator]

[Operator Instructions]. Your first question comes from Aaron MacNeil from TD Cowen.

[Aaron MacNeil, analyst]

First one is for Mike. We're going to 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 second quarter? 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?

[Michael Gray, executive]

Thanks for the question. Yes, when we look at it, so we entered the quarter with about $878 million on our facility. So we -- it'd have to be a $28 million reduction to get to the $850 million, we have our term loan payment of $28 million. So essentially $56 million of debt reduction needs to take place.

In Q2 of this year, if you look in the prior year, we did close to $84 million in debt reduction in Q2. That's a very, let's say, heavy cash flow input 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 last year, we had about $41 million in cash interest payments. Our bonds were due in April as well as in October for interest. So we'll see cash savings on the interest expense. Once again, we had about $132 million in cash interest or interest expense in 2023. We're expecting that to be [ sub ] $100 million. So when we look over year-over-year, we're seeing about $32 million in interest savings that can go towards debt reduction.

Our CapEx spend last year was $175 million compared to about $147 million this year. So there's about $28 million in savings there. So all in all, when you put those parts together, we're confident on the $200 million debt reduction and then confident on the reduction in the facility as well as the term payments.

[Aaron MacNeil, analyst]

Makes 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 few and far between new bids that do occur?

[Robert Geddes, executive]

Yes. I mean we're seeing some stabilization. But anecdotally, we see some of the smaller players taking a crack at some of our -- and other's 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 as a 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. 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 you up for 2 years, which always tells us that the operators are still rolling up their sleeves a little bit on pricing.

[Operator]

Your next question comes from Keith MacKey from RBC.

[Keith MacKey, analyst]

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 just kind of walk us the pieces for Q2 of how that works. 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?

[Michael Gray, executive]

Yes, no 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 when we look at Q2, like, once again, to Aaron's question, the free cash flow in Q2 will be quite significant. It will give us the ability to reduce our facility as well as make the term loan payments. The term loan payment once again reduces your senior debt. And once 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 of Q2 works with the cash inflow or reduced interest expense. And like I said, Q1 is always heavy CapEx. 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 it's paid off. There's about $110 million that will be paid off this quarter -- or this year, which once again will reduce the covenant ratio as we continue to -- based on the perform as we are.

[Keith MacKey, analyst]

Yes. 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?

[Robert Geddes, executive]

Yes. 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. We've also got the 2 ADR 300s that we brought up from California. They were retrofitted over the winter to the operator's specific requirements. They're ready to go out the door as soon as we can get them out on the road bans.

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

[Operator]

Your next question comes from Waqar Syed from ATB Capital Markets.

[Waqar Syed, analyst]

Mike, what would your guidance be for DD&A for Q2 and the following quarters?

[Michael Gray, executive]

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

[Waqar Syed, analyst]

Yes. 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?

[Michael Gray, executive]

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

[Waqar Syed, analyst]

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

[Robert Geddes, executive]

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 yes, it's more of a conversation, drilling more geothermal wells in California in that West Coast area all the way even up into Oregon, all while the irony is all while Canadian oil comes down to the TMX in the California to fill the increasing demand for gasoline pumps. But yes, that's what we're on geothermal.

[Waqar Syed, analyst]

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

[Robert Geddes, executive]

We're thinking end of third quarter. So it will be the end of the summer.

[Waqar Syed, analyst]

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

[Robert Geddes, executive]

No, we have a contract signed and they've forwarded the monies for the upgrade on the rig.

[Waqar Syed, analyst]

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

[Robert Geddes, executive]

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 in the fourth quarter -- third quarter, I'm sorry.

[Operator]

[Operator Instructions] Your next question comes from Josh Jayne from Daniel Energy Partners.

[Josh Jayne, analyst]

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?

[Robert Geddes, executive]

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. I'm not seeing 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.

[Josh Jayne, analyst]

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 -- at 6 months -- in the next 6 months in the U.S. You talked about the decrease in day rates. Are customers in the U.S. still wanting to sign up term contracts today? And are you seeing them opportunistically look at term potentially maybe more so than they were 6 months or 9 months ago?

[Robert Geddes, executive]

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 turn.

[Operator]

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

[Robert Geddes, executive]

Thanks, everyone, for joining us again. Continuing current geopolitical tensions in various places around the globe and 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&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. It will take some time to figure itself out.

Natural gas cogen plants will grow as the world moves off coal and gets on to clean burning natural gas and along with that natural gas demand expected to rise 50% 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 pounds to 1.5 million pounds of oil capacity, along with a fleet of close to 100 oil service rigs of varying capacity situated in 8 different countries around the world, all ready to perform safely and profitably.

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 million 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.