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

Good Afternoon, ladies and gentlemen, and welcome to the Ensign Energy Services Inc. Third Quarter 2023 Results Conference Call. [Operator Instructions] This call is being recorded on Friday, November 3, 2023. I would now like to turn the conference over to Nicole Romanow, Investor Relations. Please go ahead.

Thank you, Julie. Good morning, and welcome to Ensign Energy Services Third Quarter Conference Call and Webcast. On our call today, Bob Geddes, President and CEO; and Mike Gray, Chief Financial Officer, will review Ensign's third 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 third 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, and welcome, everyone. Ensign had a steady quarter into what we see as a developing construct for the land-based drilling business moving forward worldwide. We saw static margins in North America through the third quarter and an increase in our margins in our International business unit through the third quarter. Oil and gas prices remained relatively strong, while activity in the back half of 2023 was challenging. This enigma is a consequence of record M&A activity and continuing balance sheet discipline by the oil and gas companies. Nonetheless, whilst we see some buffer on activity in the third quarter continuing into the fourth quarter, Ensign has clipped another $54 million of debt in the quarter and is well on the path to reducing debt $800 million through to the end of 2026. I'll turn it over to Mike for some details.

Thanks, Bob. Ensign's results for the first 9 months of 2023 reflect positive improvements to oilfield services 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. I would like to point out that subsequent to the quarter, the company obtained a 3-year $369 million term facility and extended the existing $900 million credit facility to October 2026. The company expects its blended interest rates at Federal Reserve banks hold interest rates at current levels to be approximately 8%, which will allow us to continue to reduce our interest expense going forward and further reduce our interest expense with continued debt reduction and improving debt metrics. This will [ solve ] the near-term debt maturities and is an overall positive for the company. The senior notes will be redeemed in Q4 of 2023, utilizing the term facility and liquidity on hand. Now to discuss the quarter. Overall, operating days declined in the third quarter of 2023. Canadian operations recorded 3,262 operating days, a decrease of 19%. U.S. operations recorded 3,581 operating days, a 27% decrease and international operations recorded 1,265 days, a 27% increase compared to the third quarter of 2022. The company generated a revenue of $444.4 million in the third quarter of 2023, a 3% increase compared to revenue of $432.6 million generated in the third quarter of the prior year. For the first 9 months ended September 30, 2023, the company generated revenue of $1.36 billion, a 23% increase compared to revenue of $1.1 billion generated in the same period in 2022. Adjusted EBITDA for the third quarter of 2023 was $117.3 million, 11% higher than adjusted EBITDA of $105.4 million in the third quarter of 2022. Adjusted EBITDA for the 9 months ended September 30, 2023, totaled $361.2 million, 48% higher than adjusted EBITDA of $243.7 million generated in the same period in 2022. The 2023 increase in adjusted EBITDA can be primarily attributed to year-over-year improvements to the industry conditions and improving revenue rates. Depreciation expense in the first 9 months of 2023 was $229.6 million, an increase of 10% compared to $208.1 million in the first 9 months of 2022. The increase is mainly related to the foreign exchange rate on U.S. dollar translation. General and administrative expense in the third quarter of 2023 was 3.1% of revenue, a slight increase than in the third quarter of 2022, which was 2.9%. General and administrative expenses increased as a result of annual wage increases and higher foreign exchange rate on U.S. dollar translation. Total debt net of cash has been reduced by $143.7 million since December 31, 2022. Our debt reduction for 2023 is targeted to be approximately $200 million and $600 million from the beginning of 2023 to 2025 based on current industry conditions. Our debt-to-EBITDA metrics continued to improve with us exiting the quarter with 2.57 total debt to EBITDA. This is the lowest metric since Q1 2016. In addition, we have reduced our net debt by $442 million from our peak net debt of $1.7 billion in Q1 of 2019. Capital expenditures for the third quarter were $37.9 million, consisting of $1.9 million in upgrade capital and $36 million in maintenance capital. During the third quarter of 2023, the company received sale proceeds of $8.9 million, resulting in net capital expenditures of $29 million. Capital expenditures for the 2023 year are targeted to be in line with prior guidance of approximately $157 million related to maintenance capital and $18.3 million in customer-funded upgrade projects. The company is also pleased to announce the appointment of Karl Ruud to the company's Board of Directors effective November 1, 2023. Mr. Ruud most recently served as President and Chief Executive Officer of the Calgary-based energy services company until his retirement in 2021. On that note, I'll pass the call back to Bob.

Thanks, Mike. I'll start with an operational update. We've been running roughly 100 to 105 drilling rigs plus about 60 to 70 well service rigs daily through the third quarter and expect to bump up another 10 rigs on average through the fourth quarter to that 110 to 115 range and then peak at about 55 to 60 in Canada in the first quarter, 45 to 50 in the U.S. in the first quarter. And up one in our international fleet to 18 rigs active, which should see us roughly 120 rigs thereabouts active in the first quarter. A challenge plaguing all contractors continues to be how to capture the value we are creating as we continue to drill record wells. We continually drill these record wells faster and more consistently than ever before. With our equipment being pushed to twice the work duty in the same period of time, which means that our R&M costs on a per day basis are generally up 50% over the last 5 years. These increased costs have not carried themselves up into the day rates, not yet anyway. Happy to report that our fleet is running with an industry-leading safety record with year-over-year improvements and that we continually drive to a work environment with zero incidents. Let's look at North America for a moment. Canada. The summer and fall has been somewhat schizophrenic as we saw operators dropped 12 of our rigs mid-summer while commodity prices were generous and improving. Again, this talks to the continuing focus on debt levels and discipline with budgets. Canadian drilling has since the summer popped up 6 rigs from 38 to 44 and had the largest week-over-week gain of any contractor gaining 2.5% market share in that week alone. The sales team is suggesting that we have 52 rigs contracted forward and which will start in the next month or two, certainly before Christmas. Operators are already committing to winter projects, so they ensure that they get the most efficient rigs. Canadian well servicing is performing well and gaining market share quarter-over-quarter with steady and strong demand building into the winter. In the U.S., the same market dynamics have existed south of the border through the back half of 2023. So hanging on to market share in the U.S. takes on a whole new challenge. The effect of all the $0.5 trillion of M&A activity through the year will take a few years to figure itself out at the expense of OFS activity in the short term. Currently, with 42 rigs active and line of sight to 45 to 50 by year-end, operators are sticking to their budgets and will take any excess cash flow generated and put that against debt. California is down about 7 rigs year-over-year and currently has 3 active rigs today. Rockies has 6 rigs active today with expectations to grow to 7% to 8% by year-end and into 2024. Our U.S. Southern business unit, which is Permian-centric and will stay steady in the 30 to 35 rig range through the rest of 2023 and into the first quarter '24 with some expectation that this improves into 2024. U.S. well servicing is steady as she goes and our trucking division is really hitting its stride and expect to generate growing revenue year-over-year. Directional is right on budget, and we'll be expanding into the Permian with a major client sponsorship. Just coming back to California, I will point out that we are on a geothermal project there in the U.S. We always seem to have 1 or 2 rigs working in geothermal projects in the U.S., a small but growing part of our business. On the international front, Australia, we have 8 rigs active in Australia today with visibility to 9 into the new year. Two large projects are underway with 2 majors and will generate very nice cash flows from this point forward for the next year or two. In Oman, our 3 ADRs continue to deliver ahead of schedule and safely on a performance-based contract with a major in the country. Bahrain and Kuwait, we have 2 of our ADR 2000s on long-term contract in Bahrain operating on plan and our 2 ADR 3000s are running like a clock in Kuwait, generally operating in the upper decile. Venezuela, it looks like we will have one of our rigs going back to work in the new year for U.S. major and some expectation for that to be followed up with a second rig before the end of 2024. On our drilling solutions front, our EDGE drilling rig control system continues to be installed at a pace of a rig a month and we continue to see growing demand for our Automated Drilling System, the ADS, which charges up to the $1,000 a day. In the third quarter alone, we installed 5 additional EDGE drilling rig control systems, which brings us up to roughly 60 EDGE units installed worldwide today and generating revenue between $1,000 to $2,500 a day with margins in the 75% to 80% range. With that, I'll turn it over to the operator for questions.

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

Bob, what's the current utilization of your AC triples in Canada. And if you do have any that are idle, what sort of capital requirements do you think you need to incur to get them back to work? Is a customer-funded upgrade nonnegotiable? And what sort of day rates do you think you can achieve?

Yes. So it's -- we have about 70% utilization on our high-spec triples in Canada. Within our high-spec triple fleet, we have three rigs, two of them are 2,000 horsepower and one 3,000 horsepower that were basically constructed for the Horn River deep gas regions. They're harder to market. When we exclude them, we're probably running about 75% to 80%. So we have capacity. We can -- we probably have capacity for 7 of our high-spec triples to go to work, which we think will feed into what we see as a developing play for natural gas to fill the coastal link pipeline, which will export 1 to 2 [ Bcf ] into the future. We -- as you know, we -- this summer, we contracted one of our 1,500 high-spec triples out of the Rockies up into Canada because it was a sister rig with another operator here in Canada. We signed that up into the mid-30s. They paid for the full move. There weren't any modifications on that rig. It was ready to go, and that's a 2-year contract. So that's kind of the anchor spot for pricing and anyone who wants to -- we're in current conversations with another client about another rig in Canada, any modifications that are required will be fully funded by the operator for sure.

Understood. And then maybe moving to some of your other rig categories in Canada, what sort of exposure do you have in this emerging Mannville opportunity? And can you sort of give us an indication of the potential magnitude of the opportunity for Ensign?

Yes. I think it's an interesting question. And we are in the midst of basically putting our finger on the perfect rig for that platform. It will, of course, turn into much like the Clearwater, a [ pad ] type configuration eventually. They're not big rigs, but they're highly mobile powerful smaller rigs, which would be your high-spec doubles -- your quick moving high-spec doubles with [ pad-moving ] capability or your high-spec singles with larger pumps. We've got lots of capacity in the high-spec double market, as you know. So we're pretty excited about the opportunities in the Mannville.

Your next question comes from Keith MacKey from RBC.

Just wanted to start out. Bob, you mentioned producer M&A in the release and on the -- in the prepared remarks and I appreciate that in the near term, M&A generally means a reduction in activity as the customers consolidate rigs and asset bases. Can you just talk about perhaps your strategy to mitigate some of that effect? What do you think your general exposure is now? And just the final piece of it is with the Exxon Pioneer deal, you've been talking about longer and longer wells, and it looks like you've drilled more than your fair share of 3-plus mile horizontals in the Permian. Do you think that's part of the strategy to mitigate it? Or how do you think about that these days?

Yes. Well, you hit it on the head. We participated with a certain client in drilling 3-plus mile laterals almost all the time, we're doing a mile a day. It seems that we've got more than our fair share of 3-plus mile under our belt. So I think we're well positioned there. That super-spec category with the ability to rack back 25,000 feet. It's -- we've seen through the back half of 2023 a move from the pub co's to the private co's. We're doing a lot more work for the private companies now, and we -- for the very reason that you mentioned, when 2 big companies get together, 1 plus 1 is never 2 in the short term. So we got ahead of that, saw that coming, started to explore more of the private co's. We're doing more work for the private co's than we have in the past until the pub co's settled out and figure themselves out, but we're well situated to drill up those longer laterals for sure.

Okay. And can you just talk about the general trends of how Q4 should shape up? I know the general expectation for kind of flattish activity in Canada, maybe down a little bit in the U.S. in Q4. How do you think that ultimately marries up with what your Q4 EBITDA does relative to Q3?

Yes. Well, we're seeing -- because we're worldwide, we're seeing some strong fourth quarter international. In the U.S., fourth quarter will mirror third quarter. I'm pretty sure of that. We don't have the seasonality effect down in the U.S. like we have in Canada. In Canada, of course, a lot of operators are saying, while we want to start up January 1, and we're going well, that's just not going to be possible. We've got people that are willing to take a rig just before Christmas or later in November. And -- but they want to hang on to it for the full season. So you're going to have to get going early if you want to hang on to the rig or pay a standby. They have that option. I'm seeing that develop a little more seriously here into Canada because of the seasonality effect. So I think that the fourth quarter will be better for us in Canada than the third quarter in the U.S., I would suggest it's static. In International, I would suggest that the fourth quarter might be static to slightly better.

And one last one if I could sneak one in for Mike. Mike, good to see the debt refinancing done in Q4 here. Can you just talk about what you expect your interest expense to do in 2024 relative to 2023? Any specifics you could provide on the dollar magnitude of savings or to the extent that there are any, would be helpful.

Yes. So our blended interest rate on the go forward will be about 8%. Potentially if the Federal Reserve starts to reduce rates in 2024, we'll see a reduction on our side as well. So you can kind of just do simple math, we exit the year about 1.24 net debt. We'll continue to hit our target of $200 million for this year, and then we're looking at $200 million next year. So essentially, you can just do the math based on those numbers and probably come to a fairly reasonable interest rate -- interest expense for 2024.

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

Mike, any early thoughts on CapEx for next year? .

Going through budget season coming up right away, but I think we're going to be similar to year-over-year around the $150 million on the maintenance capital, that's going to exclude any sort of customer funded growth upgrades or any potential upgrades that we see. But definitely that $150 million is our, I think, our target for next year.

Okay. And then Bob, it looks like Australia activity continues to shift to the right that pick up. Do you see anything change there in terms of confidence in terms of these additional rigs being picked up?

Yes, absolutely, Waqar. We're also seeing -- we're kind of exiting the option years on some contract terms that were established 3 to 4 years ago. So we're kind of through that. And now we're entering a new contracting phase into a relatively more bullish market in Australia. So you'll see our Australian business unit starting to get some legs under it here moving forward, for sure.

And a similar [ vein ] in Venezuela, good to see that one rig could go back to work. And we've seen certainly some policy changes on the U.S. government side. Is there anything -- any risk that's still remaining from government side, either from U.S. government or Venezuela government?

Well, it is Venezuela. So that risk always occurs. I do see, though, that the SPR is down 250 million barrels, you've got production coming off in the U.S. that Venezuela is a nice proxy for another 100,000 barrels. So I think that there isn't an area in the world we don't run where there is some [indiscernible]. But to Venezuela, we've been operating Venezuela for 15 years. We know it well. We hung in there through OFAC with some sense that at some point in time, it would open back up and here we go.

Yes. And then just finally on California. Anything changed there? you talked about the geothermal wells, but do you see any hope of activity picking up next year there?

Hope is a key word. Yes, it's such an enigma, California. They continue to consume more gallons of gasoline every year, but they don't want to. Yes, it's a permitting issue in California. We're seeing -- and I don't -- I mean we're seeing some light in the sense that operators are able to offset that now by maybe getting involved in geothermal. That's why you're starting to see some of it. So operators will find a way to make it work. It's a slow [ file ], but we got a great operation in California. So maybe we tick up a rig or two, but I'm not looking for anything substantial there in 2024.

And staying in the U.S., do you see the day rate environment kind of bottom out, pricing bottom out? Or are you still seeing pressure on the downside?

Yes. The -- I think 2024 is going to be a flip to 2023 because 2023 -- we entered first half of 2023 with strong 2022 contracts. And then the back half turned over. The front half of 2024 will be riding 2023 back half contracts and then recontracting into the back half of 2024 will move up. I mean we're taking short-term contracts usually quarter-to-quarter type thing. We're not taking any long-term contracts in the U.S. And if we are, it involves capital provided by the operator, and we're getting north of $30,000 a day.

Okay. And in Canada, do you expect pricing gains next year?

Yes. I think there's going to be some quick pricing tension in the first quarter. There's been a lot of operators that have hunkered down to secure the rig and the pricing to the end of first quarter. That probably exists on half the fleet. The other half of the fleet should come out of some pricing tension. And we should be able to be market makers, I think, on some rig categories in the first quarter, again, as it tightens up. I mean you've got to remember this. As I mentioned, 1 or 2 [ Bcf ] is going to have to fill sometime in the end of '23, and then you've got the TMX opening up 800,000 barrels a day. So that may squeeze the spread from 25 down to 15. So we're a little more bullish on Canada in the macro.

Your next question comes from Cole Pereira from Stifel.

Bob, you made a comment on margins in North America being static sequentially. Are you able to differentiate at least directionally at all between Canada and the U.S. and how we should be thinking about that into Q4?

Yes. The margins on both sides of the board were very similar within 100 or 200 bps of each other. I do think that the U.S. margins will stay static, Q4 over Q3. I think the Canadian margins will move slightly upwards because obviously we have boilers. And we also have more days over a fixed overhead base. So the margins should creep up.

Your next question comes from Josef Schachter from Schachter Energy Research.

First, on the international, you mentioned that there were 2 underutilized rigs that you moved to the international. Which countries did you move those to?

I'm trying to think what the statement was.

The company transferred 2 underutilized drilling rigs in its international operations reserve fleet.

Well they'll just be the reserve fleet, so no longer marketed .

Okay. So they're not in any specific country or you're thinking that they might get taken down in [ use ] at some point?

No, no, no. That term means that we put them into the first stage of a decommissioning.

Okay. Now the -- going into Venezuela, did the -- did you have to do much upgrades to the rig that's working and then the one that you hope will start by the end of the year? And how are day rates comparable to other on your international side? Are you getting decent margins on those?

Yes. So Venezuela is -- no one's brought any new equipment into Venezuela for a decade. So the equipment is arguably what you'd run in North America 10 or 20 years ago. So the CapEx to bring the rig back up to working order is basically just some recertifications, items $0.5 million or less in a cumulative basis. We have a yard in Venezuela and a secure yard that we basically had a couple of guys looking after the rigs over the last 5 years basically. So the rigs are ready to go back to work with very little capital. We have 2 of the arguably some of the best rigs in Venezuela. The first one is going to work, as I mentioned, here in first quarter '24, which we expect the operator will pick up the second rig. It's a slow process because of well-trained crews. Not all of them are around, they've dispersed over a 5-year period. Venezuela is a very tough area to operate and to build back into but we've had a strong base and a good client there for some period of time. On the margins, the margins are right now, not what they would be, for example, compared to the Middle East. The margins are -- for the assets we have invested in the company are good. But on a per day basis, they wouldn't be what you'd expect in the Middle East.

And lastly for me, given we're getting optimistic comments from a number of the E&P companies about activity that they see for the second half of '24 and then '25 on the natural gas side because of LNG Canada and then potentially the announcement of a second train. Are you starting to see conversations about locking up more equipment in that Northwest Alberta, Northeast BC side?

Yes, yes. We have. It started this summer notionally, and I think it's starting to pick up ever so slightly. It's -- once you get over 80% utilization in any rig category, things go a little crazy, all of a sudden, everyone goes, [ Jesus ], we should have started this conversation 3 months ago. But operators have been a little spoiled with the ability to pick and choose over the last few years. I think that may change into 2024.

Okay. Super. And then just a comment. Congratulations on resolving the debt and extending it to take that issue off the plate. That's it for me.

Yes. the team did a great job.

[Operator Instructions] Your next question comes from John Gibson from BMO Capital Markets.

I just had one on the debt reduction program. You're calling for $600 million out to 2025. I'm wondering what type of rig count environment this assumes, obviously, you're on track to meet your targets this year despite a pretty steep decline, at least in the U.S. rig count. So if rig count move up to the right, could you look to exceed these levels?

Yes. We can maintain that expectation running 100 to 110 rigs every day, which is kind of where we're at. So that's why we're very confident moving forward that we can deliver on that.

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

Thanks, operator. So with WTI staying strong in the mid-80s and natural gas solidly above $3, the latest tension in the Middle East provides yet another interesting set of possible energy supply disruption situations for the world to work through. Nonetheless, with generous cash flows being generated by operators, you would think that our industry would be talking about how much busier we are getting and how rates are working up. While exactly the opposite has been happening in the back half of 2023 as operators stick to their budgets and continue to delever more rapidly. With U.S. production starting to come off, rig efficiency plateaued, DUCs at their lowest levels in a decade and with the onset of more Tier 2 inventory, this will certainly manifest itself into more rig demand moving forward. It's a nice construct for the future. We think that we will see a disciplined uptick in demand for our rigs and other services generally starting in early 2024, which will be followed with stronger pricing support manifesting in the back half of 2024. With that, I'll look forward to sharing our fourth quarter '23 and year-end results with you on our next call in the new year. Thank you for listening.

Ladies and gentlemen, this concludes your conference call for today. We thank you for joining, and you may now disconnect your lines. Thank you.