Ensign Energy Services Inc. (ESI) Earnings Call Transcript & Summary

Good day, ladies and gentlemen, and welcome to the Ensign Energy Services Inc. Second Quarter 2023 Results Conference Call. [Operator Instructions] This call is being recorded on Friday, August 4, 2023. I would now like to turn the conference over to Nicole Romanow. Please go ahead.

Thank you, Michelle. Good morning, and welcome to Ensign Energy Services' Second Quarter Conference Call and Webcast. On our call today, Bob Geddes, President and COO; and Mike Gray, Chief Financial Officer, will review Ensign's second 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 the services supplied by the company. Additionally, our discussion today may refer to non-GAAP financial measures such as adjusted EBITDA. Please see our second quarter earnings release and SEDAR+ filings for more information on forward-looking statements and the company's use of non-GAAP financial measures. With that, I'll pass it on to Bob.

Thanks, Nicole. Good morning, everyone. Ensign team delivered a strong quarter with increasing margins year-over-year and quarter-over-quarter as tightness in certain rig type classes continues to support the rate increases as industry realized through the back half of 2022, first quarter '23 and into second quarter '23. But with some cost headwinds building up primarily from higher R&M costs, the result of high-spec rigs continue to drill longer and longer reach laterals. While operating days were fairly static year-over-year for the quarter, our Canadian business unit was frustrated with 25% of its active fleet impacted by the wildfires and floods that affected operations in Western Canada in the quarter. The quarter also had a few timing drags on projects that were scheduled to start in the second quarter that have been delayed until the third quarter. EBITDA margins improved quarter-over-quarter, and gross margins improved. Ensign continues to manage its balance sheet and only spending $53 million in planned maintenance capital to maintain the high-spec fleet in the second quarter. As we have mentioned, the focus continues with the goal to reducing debt by $600 million over the next 3 years. I'll turn it over to Mike Gray for a detailed summary of the quarter. Mike?

Thanks, Bob. Ensign's results for the first 6 months of 2023 reflect positive improvements to oilfield services activity, day rates and financial results year-over-year. Despite the recent volatility in commodity prices, the outlook is constructive and the operating environment for oil and natural gas industry continues to support demand for oilfield services. Overall, operating days remained consistent in the second quarter of 2023. Canadian operations recorded 2,131 operating days, a decrease of 10%. U.S. operations recorded 4,302 operating days, a 1% increase. And international operations recorded 1,247 days, a 21% increase compared to the second quarter of 2022. For the first 6 months ended June 30, 2023, overall operating days were higher, with United States recording a 12% increase and international operations recording a 24% increase, which were offset by a 3% decrease by the Canadian operations when compared to the same period in 2022. The company generated revenue of $432.8 million in the second quarter of 2023, a 26% increase compared to revenue of $344.1 million generated in the second quarter of the prior year. For the first 6 months ended June 30, 2023, the company generated revenue of $916.8 million, a 35% increase compared to revenue of $676.8 million generated in the same period in 2022. Adjusted EBITDA for the second quarter of 2023 was $116.6 million, 71% higher than adjusted EBITDA of $68.3 million in the second quarter of 2022. Adjusted EBITDA for the 6 months ended June 30, 2023, totaled $243.9 million, 76% higher than adjusted EBITDA of $138.3 million generated in the same period in 2022. The 2023 increase in adjusted EBITDA can be attributed to improved industry conditions and increasing drilling activity. Depreciation expense in the first 6 months of 2023 was $152.7 million, an increase of 10% compared to $138.7 million in the first 6 months of 2022. G&A expense in the second quarter of 2023 was 20% higher than in the second quarter of 2022, but lower on a total basis compared to revenue. G&A expenses increased in support of increased operational activity, and as a result of annual wage increases, higher foreign exchange on the U.S. dollar translation. Net capital purchases for the second quarter of 2023 was $53.1 million, consisting of $3.8 million in upgrade capital and $52.7 million in maintenance capital. Maintenance capital expenditures for 2023 is targeted to be approximately $157 million. In addition to maintenance capital, there are certain growth projects for our customers, of which $18.3 million has been funded by our customers. Total debt, net of cash, has been reduced by $112.5 million since December 31, 2022. Our debt reduction target for 2023 is approximately $200 million. Our targeted debt reduction for the period beginning 2023 to the end of 2025 is approximately $600 million. If industry conditions change, these targets could be increased or decreased. We exited the quarter with total net debt to EBITDA of 2.69, which is a 28% reduction from year-end 2022 of 3.76, and a 55% reduction from year-end 2021 which was 5.98. This is our lowest net debt -- total net debt to EBITDA since Q1 of 2016. The company is in discussions currently with our banking syndicate on extending the credit facility and obtaining a term loan facility, which will be used to retire the senior notes due in 2024. The company has not yet finalized such refinancing or the terms thereof. And if it is successfully completed, it contemplates completion of such refinancing before the end of the third quarter of 2023. On that note, I'll turn it back to Bob.

Thanks, Mike. Most of you on the call are well aware that Ensign operates a high-spec fleet of 230 high-spec drill rigs, 90 well servicing rigs and a growing drilling rig control technology business unit, which employ over 4,000 highly trained crews and technicians in 8 countries around the world. Let's start with the U.S., which provides over half of our consolidated EBITDA. With the commodity drag through the second quarter and the general slip in U.S. rig count, Ensign is down about 10 rigs in the second quarter as compared to the first quarter. And going into the third quarter, we have 47 rigs active today in the U.S. And with a strong position in the Permian, we have 36 of those rigs active today in that basin. With the Haynesville play softening due to gas prices, the sales team has been very active churning rigs over on to new contracts. In most cases, where rigs have come off 2022 contracts, we are now seeing some big tension in the market as a result of the rig count decline. So the margin run rate for the third quarter will probably be neutral quarter-over-quarter. In most cases and on more current negotiations, we are more likely to hold rates for a 6-month term. When operators start asking us for more term, we will know it's time to raise pricing again, and I think we're probably a few quarters away from that. Our California business unit, where we have just 3 of our 16 rigs active today, continues to get frustrated with ongoing challenges with drilling permits in that state. It's California. We maintained a solid 7% market share in the Lower 48 and see this stabilizing over the rest of 2023. We are also starting to see operators drill more into their Tier 2 acreage, which means that to maintain production, not grow just maintain, they will need to drill more wells. With that, we predict that rig counts will start to move up in the fourth quarter, but probably not before that. We have close to 25% of our active U.S. fleet on an Ensign emissions reduction strategy, which is a combination of highline power rigs and also natural gas engine rigs with battery energy storage systems, otherwise known as BESS systems, to regulate peak power draws. With the arbitrage between diesel fuel and gas, natural gas that is, the argument becomes more compelling. As a result, we'll continue to see expansion in this area, which not only reduces emissions, it provides Ensign a high-margin incremental revenue stream. Our U.S. well servicing business had one of the slowest starts out of the gate in 2023, purely due to operator project timing, but we are back up to 85% utilization today and look to stay strong through the rest of the year with no rate degradation. Our directional drilling business, mostly Rockies-centric, continues to deliver with steady work on numerous projects. Turning to Canada. Canada had a strong operational quarter, but fell short of expected days as the wildfires directly affected 25% of our active fleet. Because of the wildfires and floods, we dropped at only 16 rigs operating over breakup. Today, we are back up to 40 rigs active and expect to get to 50 later in the third quarter. Our high-spec triple fleet are running well over 70% utilization, which provides continued, strong pricing with solid rate bumps expected in the fourth quarter and into 2024. We continue to see our high-spec doubles be considered for work later in the third quarter, with rates relatively static, still in the mid-20s. The conventional fleet is staying active, but rates have fallen to find bids over the summer. They should stabilize later in the year. Our Canadian well servicing business unit has 14 active rigs today and with more OWA work ahead, we expect to get back to 18 rigs later in the third quarter, with a few of those rigs operating on 24-hour operations. We still have, for sale, roughly $40 million redundant real estate in Nisku, which when sold will go obviously towards debt reduction. International is steady as she goes, generating steady free cash flow and long-term projects. We commissioned our third rig in Oman in the second quarter onto a 5-year contract, the other 2 started up later in 2022. All 3 rigs performing well out of the gate. These rigs are all on performance-based contracts and delivering well above expectations, generating approximately $3,000 a day in incremental margin. Kuwait and Bahrain, where we have 4 of our largest rigs, continue to execute on the top decile of our contracting peer group in these countries. Australia's second quarter results were frustrated with a further delay of 2 large projects that were delayed now until the third quarter. This affected the second quarter results but will, of course, benefit the third quarter results. In Argentina, we have 2 super-spec triples on long-term contracts with strong day rates terming out 1 to 3 years. The situation in Venezuela changes daily, but we're expecting that we may have one of our drilling rigs working by the end of the year. We'll see how that develops. On the technology front, our EDGE drilling solutions product line continues to expand. With a lot of the supply chain issues behind us with respect to computer hardware access, we continue to deploy and commission roughly 1 a month of our EDGE drilling rig control systems on our high-spec rigs worldwide. This attracts roughly $1,000 to $1,500 a day of incremental high-margin technology to the rig. We will have EDGE actively engaged in most of our super-spec and high-spec triples by the end of the third quarter. With the obvious arbitrage between diesel and natural gas, notwithstanding the obvious emission reductions when using highline or natural gas power, we are seeing growing demand for our EDGE emissions reduction strategy, which includes BESS systems, highline power substations. The product offering ranges from the highline power substation, which rents for about $2,000 a day to the stand-alone BESS for about the same rate, to the full-blown natural gas power system with BESS and the Ensign EDGE -- Ensign management system, it's a mouthful, for around $6,000 a day. These are all high-margin opportunities, and they help reduce fuel costs and emissions by as much as 50%. We have about 10% of the North American fleet on one of these strategies. And when we include dual fuel applications, we have roughly 1/4 of the fleet on an emissions reduction strategy. Our ADS, or Automated Drill System, which delivers consistent [ flex ] to slips and automates the routine for the driller, has been now fully tested and is now commissioned on 10 rigs in the U.S., charging [ out ] $1,000 a day. We just can't get these on the rigs fast enough. So I'll turn it back to the operator for questions.

[Operator Instructions] First question comes from Cole Pereira of Stifel.

Just wanted to start on the refinancing. Can you talk about where you are in the process? I mean I'm just wondering with Q2 results out now, could we see something relatively near term?

I can't add much color than what was in the press release. So we're, like I said, looking to complete this before the end of the quarter of Q3.

Got you. Fair enough. And on the wildfires in Canada, I mean, a bit more of an impact than some of your peers. Can you just add some color on that, maybe the specific areas, et cetera?

Yes. It was -- a lot of the Drayton Valley, north and west of that. And we had no impact to our equipment, which is the good news, nor personnel. Everyone were evacuated safely. So it had an impact on about 7 of the rigs that we had. And it impacted also because of some facility issues impacted by the fires, some planned projects were delayed a couple of months. So that's the impact it had, but no equipment or personnel impact, which was a good thing.

Got it. And thinking about the U.S. drilling business, can you just talk about how customer conversations with -- have been going over the past few, call it, weeks or months with regards to pricing, more rig additions, et cetera? And are you seeing a big difference in terms of what privates might want versus the demand from publics?

Yes. We're seeing a lot more privates evolving, and that would suggest maybe the capital markets are opening up a tiny bit for them. The bigger companies are, of course, staying to their plans, staying to their project and continuing to work on operational efficiency. But we are working for a lot of smaller companies that have raised capital and are taking on different projects. So that tells me the capital markets have opened up to some extent for them.

The next question comes from Keith MacKey of RBC Capital Markets.

Just curious, first off, on the U.S. versus Canada rig markets. Do you see a material difference in the trajectory of where the 2 markets go? And does that lead you to potentially think about having to transfer more rigs? Assuming from the U.S. to Canada, but do you think there will be more rig transfers in the next 6 to 12 months given your outlook for both of those markets?

Yes. Good question, Keith. I'm not thinking so. There may be the odd rig that we might move from a basin like California, where there's underutilization on the small or high-spec single area, to Canada. You might see one of those. But generally, there won't be a large migration. We think the gas market picks back up in the back half of 2024 for the U.S. Canada, we're seeing a good bid level, but we're also seeing a bunch of contractors that haven't worked rigs in 2 or 3 months going after the bid.

Yes, got it. And there's been some talk about larger Canadian E&Ps potentially dropping activity, and the rig count did tick down this week. Can you just talk about what you're seeing in terms of rig count expectations for the second half of the year? Do you think we'll get to match or beat last year's level given all these factors?

Yes. Well, I think we continue to drill wells a little bit faster. So the operators are sticking to budget number of wells planned. And I think they're waiting to see a quarter of cash flow buildup with the commodity price, with a thought that perhaps they changed their fourth quarter budget notion to some extent. We haven't seen any real notion of that. We're maybe perhaps contemplating that, that's how they've reacted in the past. But we have had some clients on the high-spec triples and the high-spec singles, which are tighter rig type scenarios, look a little further forward with -- you've got the tightness in the -- [ filling ] the coastal link gas line, that type of stuff in those rig categories only though.

[Operator Instructions] Next question comes from Waqar Syed of ATB Capital Markets.

Bob, it's always very difficult to guess what's going to come next in California. But still, what would be your best guess in terms of any permitting issues resolution or activity pickup? And number two, without rigs returning to work in California, can Ensign's rig counts pick up late in the year or next year?

Yes. I think we're thinking of the U.S. regardless of California, maybe a couple of rigs picking up in California. What we're finding is there is some obvious tension in the permitting process that's being somewhat subrogated, to some extent, by operators suggesting that they will normalize emissions another way. And we've heard a couple of projects that they may be getting engaged on geothermal, which you got to drill a hole in the ground, involves a drilling rig. So one way or another, we may be going to work. And/or emission reduction strategies in other areas of their business. So it is getting approached because there is oil in the ground and they can make money with it. And it's -- some of this stuff is in an appellate court. But it is grinding through. It seems to -- the cloud seems to be -- it's still cloudy, but they seem to be breaking up a little bit in California.

And then you mentioned that your current rig count, if I remember correctly, is 47 in the U.S. currently active. Do you have visibility or do you have any rig release notices that you have in hand? And where do you think your rig count kind of bottoms and likely when?

Yes. I think we're kind of close to a bottom. The rig count has been dropping a little bit, as you well know, in the U.S. I think that what we're finding is our U.S. team is where a rig is coming off contract, they've been very quickly able to recontract it. So we may slip another couple of rigs, Waqar, but I think we're pretty close to a trough.

Okay. And in terms of the day rates for the super triple or what they call super-spec rigs in the U.S., where do you see the leading-edge day rates these days?

So I would suggest that they've been hanging in the low 30s, but we're seeing some people throw a level a few more à la carte items that used to be outside, inside. But there's not as much tension on the super-spec triples. It hasn't moved at all. And maybe one might look at the margins have maybe come off $1,000 to $2,000 a day.

Okay. And then just last question. There are some structural improvements happening in the Canadian market with the LNG coming up, some egress issues being resolved here. How do you see the demand kind of changing or rig activity changing on a year-over-year basis for the next couple of years?

Well, I think there's -- as you point out, if you're going to feed those lines in a basin where you have decline rates, you're going to have to drill to feed into it. It's pretty basic. The pace is the question. The delays in both pipelines, which we're well aware of, continue. But they are getting close to getting a final pipe to end.

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

Thank you, Michelle. While the commodity deck was weak for the industry in the second quarter, the macro construct for the oil business looks stronger for the back half of '23 and into '24. While this is true, the contradiction is that the rig count in the U.S. is still falling, albeit we feel, almost at the bottom. For gas, it will be well into 2024 before we see demand for gas wells increasing again. The recent uptick in commodity prices has generally established a floor, we believe, on rates and it is expected that contractors will start to bid up for fourth quarter work. Ensign expects to be running around 110 drilling rigs and 50 to 60 well service rigs into the third quarter and remaining part of the year. Ensign continues to build out term to help derisk the future and reinforce our debt reduction targets, while being strategic about term and pricing at the same time. Again, when we see operators start asking for more term, we'll know we've turned the corner. We're not there yet but we feel we're not that far away from that turn. The challenge, as I mentioned in my opening remarks, is that R&M costs are coming to roost, and that rate increases need to be applied to start recovering that. The rigs are delivering wellbores at an increasing pace and with consistency. And the costs have to be covered in the rate somehow. Ensign has roughly $1 billion of contracted revenue forward, with about half of that -- half of the fleet tied up under contract, and over 30% of the active fleet on long-term contract of 6 months or greater. The weighted average contract tenure is about 1 year and the average age of the fleet is roughly 11 years old, with another 20 years of economic life ahead of it. Ensign is fully committed to the target of quickly delivering and reducing $600 million of debt over the next 3 years. I look forward to our next call in 3 months. Thank you for attending the call.

Ladies and gentlemen, this does conclude the conference call for today. We thank you for your participation and ask that you please disconnect your lines.