Ensign Energy Services Q3 2023 Earnings Call Transcript

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November 3, 2023

There are 10 speakers on the call.

Operator

Afternoon, ladies and gentlemen, and welcome to the Ensign Energy Services Inc. 3rd Quarter 2023 Results Conference Call. At this time, all lines are in a listen only mode. Following the presentation, we will conduct a question and answer session. This call is being recorded on Friday, November 3, 2023.

Operator

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

Speaker 1

Thank you, Julie. Good morning, and welcome to Ensign Energy Services' 3rd quarter conference call and webcast. On our call today, Bob Geddes, President and COO and Mike Gray, Chief Financial Officer will review Ensign's 3rd 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 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 or other unforeseen conditions, which could impact the demand for services supplied by the company.

Speaker 1

Additionally, our discussion today may refer to non GAAP financial measures such as adjusted EBITDA. Please see our Q3 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.

Speaker 2

Thanks, Nicole, and welcome, everyone. Ensign had a steady quarter into what we see as a developing construct for the land based We saw static margins in North America through the Q3 and an increase in our margins in our international business unit through the Q3. Oil and gas prices remain relatively strong, while activity in the back half of twenty twenty three was challenging. This enigma is a consequence of record M and A activity and continuing balance sheet discipline by the oil and gas companies. Nonetheless, whilst we see some buffer on activity in the Q3 continuing into the Q4, Ensign has clipped another $54,000,000 of debt in the quarter and As well on the path to reducing debt $800,000,000 through to the end of 2026.

Speaker 2

I'll turn it over to Mike for some details.

Speaker 3

Thanks, Bob. Ensign's results for the 1st 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 $369,000,000 term facility and extended the existing $900,000,000 credit facility to October 2020 The company expects its blended interest rates if 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 is all the near term debt maturities and is an overall positive for the company.

Speaker 3

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 Q3 of 2023. Canadian operations recorded 3,262 operating days, a decrease of 19%. U.

Speaker 3

S. Operations recorded 3,581 operating days, a 27% decrease And international operations recorded 12 65 days, a 27% increase compared to the Q3 of 2022. The company generated revenue of $444,400,000 in the Q3 of 2023, a 3% increase compared to revenue of $432,600,000 generated in the Q3 of the prior year. For the 1st 9 months ended September 30, 2023, the company generated revenue of $1,360,000,000 a 23% increase compared to revenue of $1,100,000,000 generated in the same period in 2022. Adjusted EBITDA for the Q3 of 2023 was 100 $17,300,000 11 percent higher than adjusted EBITDA of $105,400,000 in the Q3 of 2022.

Speaker 3

Adjusted EBITDA for the 9 months ended September 30, 2023, totaled $361,200,000 48% higher than adjusted EBITDA of $243,700,000 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 1st 9 months of 2023 was $229,600,000 an increase of 10% compared to $208,100,000 in the 1st 9 months of 2022. The increase is mainly related to foreign exchange rate on U. S.

Speaker 3

Dollar translation. General and administrative expense in the Q3 of 2023 was 3.1 percent of revenue, a slight increase in the Q3 of 2022, which was 2.9%. General and administrative expenses increased as a result of annual wage increases and a higher foreign exchange rate on U. S. Dollar translation.

Speaker 3

Total debt, net of cash, has been reduced by $143,700,000 since December 31, 2022. Our debt reduction for 2023 is targeted to be approximately 200,000,000 and $600,000,000 from the beginning of 2023 to 2025 based on current industry conditions. Our debt to EBITDA metrics continue 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 $442,000,000 from our peak net debt of 1 point $1,700,000,000 in Q1 of 2019.

Speaker 3

Capital expenditures for the 3rd quarter were $37,900,000 consisting of $1,900,000 in upgrade capital and $36,000,000 in maintenance capital. During the Q3 of The company received sale proceeds of $8,900,000 resulting in net capital expenditures of $29,000,000 Capital expenditures for the 2023 year are targeted to be in line prior guidance of approximately $157,000,000 related to maintenance capital and $18,300,000 in customer funded upgrade projects. The company is also pleased to announce the appointment of Carl Rood to the company's Board of Directors effective November 1, 2023. Mr. Rood most recently served as President and Chief Executive Officer of the Calgary Based Energy Services Company until his retirement in 2021.

Speaker 3

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

Speaker 2

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 Q3 and expect to bump up another 10 rigs on average through the 4th 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 Q1 and up 1 international fleet to 18 rigs active, which should see us roughly 120 rigs Thereabouts active in the Q1.

Speaker 2

The challenge plaguing all contractors continues to be how to capture the value we are creating as we continue to drill record wells. We continue to 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 Time, which means that our R and 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 work environment with 0 incidents. Let's look at North America for a moment.

Speaker 2

Canada, the summer and fall has been somewhat schizophrenic as we saw operators Drop 12 of our rigs midsummer, whilst commodity prices were generous and improving. Again, this talks to the continuing focus on debt levels and discipline with budgets. A and D drilling has since 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 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 2, certainly before Christmas. Operators are already committing to winning 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.

Speaker 2

In the U. S, the same market dynamics have existed south of the border through the back half of twenty So hanging on to market share in the U. S. Takes on a whole new challenge. The effect of all the $500,000,000,000 of M and A activity through the year We'll take a few years to figure itself out at the expense of OFS activity in the short term.

Speaker 2

Currently, with 42 rigs active and line of sight to 45 to 50 by year end, Operator 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 Three 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.

Speaker 2

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 1st 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 will be expanding into the Permian with a major client sponsorship.

Speaker 2

Just coming back to California, we'll point out that we are on a geothermal project there. And the U. S, we always seem to have 1 or 2 rigs working 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.

Speaker 2

2 large projects are underway with 2 majors and will generate Very nice cash flows from this point forward for the next year or 2. In Oman, our 3 ADRs continued 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 280 R3000s 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.

Speaker 2

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 out at $1,000 a day. In the 3rd quarter alone, we installed 5 additional Edge 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

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

Speaker 4

Hey, morning and thanks for taking my questions. 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 non negotiable? And what sort of day rates do you think you can achieve?

Speaker 2

Yes. So it's we have about 70 utilization on our high spec triples in Canada. Within our high spec triple fleet, we have 3 rigs. 2 of them are 2,000 horsepower and 13,000 horsepower that were basically constructed for Horn River deep gas regions. They're harder to market.

Speaker 2

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 Ink pipeline, which will export 1 to 2 Bcf into Future. We as you know, we this summer, we contracted 1 of our 1500 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.

Speaker 2

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 they require will be fully funded by the operator for sure.

Speaker 4

Understood. And then maybe moving to some of your other rig categories in Canada. Sort of exposure do you have in this emerging Manville opportunity? Can you sort of give us an indication of the

Speaker 2

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.

Speaker 2

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 Manville.

Operator

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

Speaker 5

Hi, good morning. Just wanted to start out. Bob, you mentioned producer M and A in the release and In the prepared remarks and appreciate that in the near term M and A generally means a reduction in activity as the customers Consolidated 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, they've been talking about longer and longer wells and it looks like you've You drilled more than your fair share of 3 plus mile horizontals in the Permian.

Speaker 5

So do Do you think that's part of the strategy to mitigate it? Or how do you think about that these days?

Speaker 2

Yes. Well, you hit it on the head. We participated with a certain 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.

Speaker 2

So I think we're well positioned there In that super spec category with the ability to rack back 25,000 feet, it's we've seen through the back half of twenty And move from the PubCos to the PrivateCos. 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 +1 is number 2 In the short term, so we got ahead of that, saw that coming, started to explore more of the private We're doing more work for the private coasts than we have in the past until the POPCO settle down and figure themselves out. But we're well situated to drill up those longer laterals for sure.

Speaker 5

Okay. Thanks for that. And can you just talk about the general trends of how Q4 should shape up? I know there General expectation for kind of flattish activity in Canada, maybe down a little bit in the U. S.

Speaker 5

In Q4. How do you think that ultimately marries up with what your Q4 EBITDA does relative to Q3?

Speaker 2

Yes. Well, we're seeing because we're worldwide, we're seeing some strong 4th quarter International in the U. S. 4th quarter will mirror 3rd quarter. I'm pretty sure that we don't have the seasonality effect down in the U.

Speaker 2

S. Like we have in Canada. In Canada, of course, a lot of operators are saying, well, 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.

Speaker 2

I'm seeing that develop a little more seriously here into Canada because of the seasonality effect. So I think that the 4th quarter will be better for us in Canada than the Q3 in the U. S. I would suggest it's Static and international, I would suggest that the Q4 might be static to slightly better.

Speaker 5

Okay. Thanks for that. 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?

Speaker 5

Any specifics you could provide on the Dollar magnitude of savings

Speaker 2

or to the extent that

Speaker 5

there are any would be helpful.

Speaker 3

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 Reduction on our side as well. So you can kind of just do simple math. We exited here about 1.24 net debt.

Speaker 3

We'll continue to hit Our target of $200,000,000 for this year and then we're looking at $200,000,000 next year. So essentially, you could just do the math based on those numbers and probably come to a fairly reasonable interest rate Interest expense for 2024.

Speaker 5

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

Speaker 3

Thanks, Gabe.

Operator

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

Speaker 6

Thank you for taking my question. Mike, any early thoughts on CapEx for next year?

Speaker 3

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

Speaker 6

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

Speaker 2

Yes, absolutely, Wachar. 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.

Speaker 6

And similar vein in Venezuela, Good to see that one rig could go back to work and we've seen certainly some policy changes from the U. S. Government side. Is there anything, any risks that still remain still remaining from government side, either from U. S.

Speaker 6

Government or Venezuela government?

Speaker 2

Well, it is Venezuela. So that risk always occurs. I do see though that The SPR is down 2,500 barrels. You've got production coming off in the U. S.

Speaker 2

That Venezuela is a nice proxy So I think that there isn't an area in the world we don't run where there is Some geopolitical risk of some sort. But Venezuela, we've been operating in 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.

Speaker 6

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?

Speaker 2

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.

Speaker 2

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'd take up a rig or 2, but I'm not looking for anything substantial there in 2024.

Speaker 6

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

Speaker 2

Yes. I think 2024 is going to be a flip to 2023 because 2023, we entered First half of twenty twenty three with strong 2022 contracts and then the back half turned over. The front half of twenty twenty four will be I'm writing 2023 back half contracts and then re contracting into the back half of twenty twenty four 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 U.

Speaker 2

S. And if we are, It involves capital provided by the operator and we're getting north of $30,000 a day.

Speaker 6

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

Speaker 2

Yes. I think there's going to be some quick pricing tension In the Q1, there's been a lot of operators that have hunkered down to secure the rig and the pricing to the end of Q1. That probably exists on half the fleet. The other half of the fleet should come under some pricing tension. And We should be able to be market makers, I think, on some rig categories in the Q1 again as it tightens up.

Speaker 2

I mean, you got to remember, there's, as As I mentioned, 1 to 2 Bcf is going to have to fill sometime in the end of 'twenty three. And then you've got the TMX Opening up 800,000 barrels a day, so that might squeeze the spread from 25 down to 15. We're a little more bullish on Canada in the macro. Okay.

Speaker 6

Great. Thank you very much. Appreciate the color.

Operator

Your next question comes from Cole Perera from Stifel. Please go ahead.

Speaker 7

Good morning all. Bob, you made 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 We should be thinking about that into Q4.

Speaker 2

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 margin It should creep

Speaker 7

up. Okay, got it. That's all for me. Thanks.

Speaker 2

Thanks, Karl.

Operator

Your next question comes from Joseph Schachter from Schachter Energy Research. Please go ahead.

Speaker 8

Good morning and thanks for taking my questions. 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?

Speaker 2

Trying to think what the statement was.

Speaker 8

During this first statement, the company transferred 2 underutilized Drilling rigs Intuit's international operations reserve fleet.

Speaker 3

Well, that would just be the reserve fleet, so no longer marketed.

Speaker 8

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

Speaker 2

No, no, no. That term means that we put them into the 1st stage of a decommissioning.

Speaker 9

Okay.

Speaker 8

Now going into Venezuela, 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.

Speaker 2

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, dollars 500,000 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 probably arguably some of the best rigs in Venezuela. The first one is going to work, as I mentioned, here in Q1 'twenty four, which we expect the operator will pick up The second rig, it's a slow process because of well trained crews.

Speaker 2

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.

Speaker 2

But on a per day basis, they wouldn't be what you'd

Speaker 8

Lastly for me, given we're getting optimistic comments from a number of the E and P companies about Activity that they see for the second half of 'twenty four and then 'twenty five 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?

Speaker 2

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, geez, we should have started this conversation 3 months ago. But operators have been a little spoiled with the ability to

Speaker 8

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.

Speaker 2

Yes. The team did a great job. Yes.

Speaker 8

Thank you.

Operator

Your next question comes from John Gibson from BMO Capital Markets. Please go ahead.

Speaker 9

Good morning, all. I just had one on the debt reduction program. You're calling for $600,000,000 up 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.

Speaker 9

S. Rig count. So if rig counts move up to the right,

Speaker 2

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

Speaker 9

Okay, great. I'll turn it back. Thanks.

Operator

And there are no further questions at this time. I will turn the call I'll now turn the call back over to

Speaker 5

Bob for closing remarks.

Speaker 2

Thanks, operator. So with WTI staying strong in the mid-80s and natural gas solidly about $3 So 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. Well, exactly the opposite has been happening in the back half of twenty twenty three as operators stick to their budgets and continue to delever more rapidly. With U.

Speaker 2

S. Production starting to come off, rig efficiency plateaued, DUCs at their lowest level 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 twenty twenty four. With that, I'll

Operator

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

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Ensign Energy Services Q3 2023
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