Ensign Energy Services Inc. (OTCPK:ESVIF) Q2 2022 Earnings Conference Call August 5, 2022 12:00 PM ET
Company Participants
Nicole Romanow – Head, Investor Relations
Bob Geddes – President & Chief Operating Officer
Mike Gray – Chief Financial Officer
Conference Call Participants
Aaron MacNeil – TD Securities
Keith MacKey – RBC Capital Markets
Cole Pereira – Stifel
Waqar Syed – ATB Capital Markets
John Gibson – BMO Capital Markets
Operator
Good afternoon, ladies and gentlemen, and welcome to the Ensign Energy Services Inc. Second Quarter 2022 Results Conference Call. At this time, all lines are in a listen-only mode. Following the presentation, we’ll conduct a question-and-answer session. [Operator Instructions]. This call is being recorded on Friday, August 5, 2022.
I would now like to turn the conference over to Nicole Romanow. Please go ahead.
Nicole Romanow
Thank you, Sergio. Good morning, and welcome to Ensign Energy Services second quarter 2022 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 defense of lawsuits, the ability of oil and gas companies to pay accounts receivable balances or other unforeseen conditions, which could impact the demand for 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.
Bob Geddes
Thanks, Nicole. Good morning and thank you for joining in on our call today, which will reflect on our 2Q results. Ensign had a very strong operational quarter with strong safety, low downtime and continuing opportunities being landed. As we have mentioned in prior calls, the team identified 24 rigs that could be upgraded, reactivated for very little capital approximately $40 million. And where these rigs were all contracted at rates with $5,000 a day bumps on average. And most importantly, these are all projects where we would have paid out on our incremental capital within six months of commissioning.
Again, the goal is to make sure we have pay out on any incremental capital within the fiscal year, so as to maximize debt reduction in the period. The second quarter results were somewhat muted by the fact that only half of those 24 rigs were actually commissioned in the back half of the second quarter, essentially contributing only one month of high-margin cash flow to second quarter results. Obviously, the third quarter and onward we’ll see the benefit of an additional 12 rigs with significantly enhanced margin and operating days.
We currently have 124 rigs running today, 61 in the US, 49 in Canada, 14 internationally. And we have visibility to give or take get up to 150 rigs by year-end, 65 to 70 in the US; 60 to 65 in Canada; and 15 to 20 internationally.
We have guided with CapEx for the year close to $165 million of which $115 million is attributed to maintenance CapEx and nominal reactivation costs on the additional 50-plus rigs, which will be reactivated through 2023 to feed the uptick in the market. The other $50 million of capital is growth CapEx targeted on client-sponsored upgrading of rigs at enhanced rates of $5,000 a day or greater. In some cases, we have recovered the capital via elevated mob fee, but I’ll point out that in all cases with respect to the approximate $50 million of upgrade projects, mostly on the drilling side, but also some on the well servicing side that these projects will pay out well within the 2022 fiscal period.
Again, finding that delicate balance or respecting the balance sheet within the fiscal period, while at the same time taking advantage of the upswing market and the opportunity to upgrade rigs with quick payouts on incremental capital. So when the smoke clears at the end of the year, we will have upgraded close to 30 rigs, and where these rigs will command superior rates in the low 30s in which we’ll all be on long-term contracts. Also important to understand is that over half of the contracted fleet today will be rotating over onto new contracts at significantly higher rates through the back half of the year, and then an additional 30-plus rigs active in the back half will all be at much higher rates.
I’ll turn it over to Mike for a more deep dive into the analysis or into the results. Mike?
Mike Gray
Thanks, Bob. Despite the recent pullback in commodity prices, the operating environment for oil and natural gas industry continues to support demand for oilfield services. Ensign’s results for the first half of 2022 reflect positive improvements to oil field service activity, day rates and financial results year-over-year.
Overall, operating days increased in the second quarter of 2020. Canadian operations recorded 2,369 operating days, a 124% increase from the prior year. US operations recorded 4,277 operating days, a 48% increase. And international operations recorded 1,030 days, a 22% increase compared to the second quarter of 2021.
The company generated revenue of $344.1 million in the second quarter of 2022, a 62% increase compared to revenue of $212.3 million generated in the second quarter of the prior year. For the further six months ended June 30, 2022, the company generated revenue of $676.8 million, a 57% increase, compared to revenue of $430.9 million generated in the same period of 2021.
Adjusted EBITDA for the second quarter of 2022 was $68.3 million, 50% higher than adjusted EBITDA of $45.6 million in the second quarter of 2021. Adjusted EBITDA for the six months ended June 30, 2022 totaled $138.3 million, 45% higher than adjusted EBITDA of $95.5 million generated in the same period in 2021. The 2022 increase in adjusted EBITDA can be attributed to improved industry conditions and as a result of the company’s acquisition of 35 rigs in Canada in the second half of 2021.
Depreciating expense in the first six months of 2022 was $138.7 million, a decrease of 1% compared to $140.7 million for the first six months of 2021. General and administrative expense in the second quarter of 2022 was 38% higher than the second quarter of 2021. The G&A expense increase due to increased operating activity as well as the end of the wage subsidies and full reinstatement of salary rollbacks and annual wage increases.
Further increase in the G&A expense is the negative foreign exchange translation on converting US dollar-denominated general and administrative expenses into Canadian dollars. Net capital expenditures for the quarter were $50.1 million. The capital budget for 2022 is estimated to be now $165 million. Part of the increase relates to two drilling rigs that will be reactivated in the fourth quarter in the Middle East as well as other selective upgrade projects. Long-term debt net of cash has decreased $83 million since December 31 2021.
And on that note, I’ll turn the call back to Bob.
Bob Geddes
Thanks Mike. So, let’s run around the world and do an operational update starting in the US. We have upgraded and reactivated nine rigs since our last call which brings our current active rig count today to 61 rigs in the US. We expect a few more rigs in the Rockies and also Southern which should get us close to 70% by year-end. Some of that dependent on whether California permit challenges get resolved before year-end.
We have three or four rigs in California waiting on the outcome of permit delays. Our high-spec rigs are bidding north of $30,000 a day and in all cases specialty pipe like the 5.5-inch drill pipe for example is being rented out at close to $5000 a day to the operator. We’re also pushing services that do not attract a margin back over to the operator in the contract. Those are the items like trucking etcetera high dollar amounts that are a drag on our cash and generate no margin.
Our well servicing division in the US is running close to 40 rigs that’s 80% utilization and continues to expand in our highly profitable rental side of the business. Our directional drilling team while small is a tactical team that supports our turnkey projects and has three kits in the hole today.
Turning up to Canada. We have 49 rigs on the payroll with visibility to 55 by September and 60 to 65 by yearend. As mentioned previously of the nine rigs that are being upgraded, four of them were commissioned in the last month of the quarter June; then we had two in July; and the other three are scheduled to be commissioned in August.
Our Canadian fleet is predominantly high-spec doubles and high stack triples. The high-spec doubles — or I’m sorry the high-spec triples are of course highly utilized and are getting north of $30,000 a day on leading rates. With respect to the high-spec doubles with 32 of them in our Canadian fleet Ensign has the largest fleet of these newer high-spec doubles in Canada. We currently have about 1/3 of them under contract today and while this rig category has been muted when compared against the high-spec triples over the last 12 months, we are seeing very strong demand and the greatest opportunity for our high-spec doubles in the Clearwater and shallow [ph] or Montney regions.
Being we have excess capacity in this rig type and with the market in this rig type getting tighter, we have been able to raise rates up to $5000 a day. The remaining 20-plus high-spec doubles we have are ready to go with essentially no capital required to start them up. We are now bidding our high-spec doubles in the low to mid-20s with specialty drill pipe outside. We see another 5 to 10 of our high-spec doubles going back to work before year-end. We’re already getting calls to book into first quarter ’23.
Our Canadian well service team has 15 well service rigs active today and has visibility to 20 by September and as much as 25 by yearend. The Canadian directional drilling business, despite some consolidation still remains a low entry-level business for the most part. And as such while getting busier has had difficulty in moving pricing.
On the international front, we have 15 active today nine in Australia, two in Kuwait, two in Bahrain, two in Argentina. As mentioned earlier we have successfully landed two possibly three rigs on long-term contracts in Oman. Roughly $5 million of CapEx required to reactivate and upgrade the two rigs will all be recovered via upfront mob fees which will occur late in quarter.
The team also successfully re-contracted our two rigs in Bahrain and has re-contracted both our rigs in Argentina that are currently operating both with $5000 a day rate increases. In Australia, where we see the effects of COVID-related issues we re-contracted one of our high spec triples with a major where approximately $5 million of upgrades requested by the operator are all being recovered in the mob fee. This rig is expected to start drilling on the project in the fourth quarter. We’re also in the middle of recontracting half the active fleet in Australia with rate increase in the $3000 per day range.
So with that summary I’ll turn it back to the operator for Q&A.
Question-and-Answer Session
Operator
[Operator Instructions]. Your first question comes from Aaron MacNeil from TD Securities. Please go ahead.
Aaron MacNeil
Hey good morning all, thanks for taking my questions. Bob are there any additional details you’d be willing to provide on the reactivation in Oman? I guess, I’m specifically thinking about contract term day rates. What would an Oman rig — like what would the capital cost be for a rig like that…
Bob Geddes
So the — we’ve got two types of rigs in Oman the 1500s and the smaller ADR rigs which were sent over there about 10 years ago and successfully drilled up the Mukhaizna field. Two of those and probably a third one, two for sure are being refitted onto Oman rural project in Oman on three to five year contracts. It’s minimum three with two to one-year options. The rates are in — typical for that size of rig is about low 30s, high 20s depending on what’s in and what’s out. Again our focus on making sure that capital outlay is matched in a current fiscal period. We put all the upgrades into the mob fee so they all get recovered. That mob will probably happen in November certainly before the end of the year.
Aaron MacNeil
Understood. And a similar question for the high-spec doubles in Canada. Like what does the contract look like in terms of duration? And with low to mid-20s pricing what’s your daily margin for that rig in that asset class?
Bob Geddes
So the — through the summer we’ve been careful not to contract our high-spec doubles past October 1. We’re already starting to see traction in the low-20s on those. And if you think of a high-spec double is needing a five-man crew at $8500 a day and let’s say $3,000 a day of R&M you’re at $11500. And so you’ve got about a $10,000 a day margin.
The point is of course when we bought Trinidad, we went after it mostly for it’s high-spec double market in Canada. They had a lot of — they had the biggest portion of high-spec doubles in Canada at the time. The Cardium fell apart, everything else all apart. And it’s been the last category to come back. But it’s coming back strong.
The Clearwater is moving over to pad drilling from the singles-type drilling over the last couple of years. You’re seeing operators wanting to go a little further putting pads. So the high spec doubles are coming into play. The point is that we’ve got 32 rigs of these only 11 rigs of them are running today and none of them are contracted purposely past October because we’re raising rates. And we’re going to see another five to 10 of those I think get contracted before the end of the year certainly in the first quarter 2023.
Bob Geddes
That’s very helpful more than I thought you will give to me on that question. So Mike maybe a last one to…
A – Mike Gray
Let’s go Aaron.
Aaron MacNeil
The year-to-date debt reduction of $83 million is noted, but the credit facility is practically fully drawn. Leverage ratios are still elevated. You bumped the capital program here which makes sense given the outlook.
I assume you’re also going to have to direct some cash towards working capital in the back half. But do you think we’ll see Ensign add a little breathing room on line of credit in the near future? Can you maybe just give us a sense of how you’re looking at capital allocation and debt reduction as we look ahead?
Mike Gray
Yes, for sure. So I think — I mean we see in the first half of the year we had about well about $80 million worth of capital of which now those rigs are going to be generating free cash flow going into Q3 and Q4. So I think we’ll see that liquidity on the facility continued to increase for the remainder of the year. So when we look at our accounts receivables and everything like that I think we’ll see more and more liquidity being added on to the balance sheet for the remainder of the year and then I think that will continue to expand. We’ll definitely continue to expand into 2023. So I think from operational cash flow we’ll see continued deleveraging.
Aaron MacNeil
Thanks, Mike. I will turn it over.
Mike Gray
Thanks, Aaron.
Operator
Thank you. Now your next question comes from Keith MacKey from RBC Capital Markets. Please go ahead.
Keith MacKey
Hi. Good morning. Thanks for taking my questions. Just wanted to start out on the gross margin in the second quarter. How much were — was that impacted by any OpEx reactivation costs? And where should we expect to see the gross margin trend through the second half of the year?
Mike Gray
We would have saw probably 200 bps maybe on, sort of, that margin compression on the reactivation. So I mean you have a lot of cost just within the rehire getting people drug tested people associated to the rig and everything like that. So we would have saw an increase in labor that we won’t see going forward with lots of reactivations coming up pretty quick.
So I would expect margins to increase, I’d say quite substantially into Q3 and going into Q4 where to Bob’s point before you have the contract. So recontracting taking place so you’ll see a higher day rate on the rigs going forward. And then we won’t see that reactivation of, sort of, the consumable build up and everything that you see when the rigs go back out to the field. So, definitely in Q2, you saw a bit of a decrease and then you’ll see that increase going into Q3 and Q4.
Keith MacKey
Perfect. Thanks Mike. And just maybe a follow-up on the labor. So, how many of the rigs you expect to get out in the second half of the year? Have you already got staffed up? And maybe if you can just talk a little bit about staffing trends in general that would be helpful too?
Bob Geddes
Sure, sure. Yes, it’s — we always say and it’s true it’s tight but what we’re finding is that more people are getting out of their basement and needing to go to work. There has been significant increases at the field level on pay over the last six months. Drillers — or I’m sorry roughnecks can make about $90,000 a year now on US side of the border. We’re starting to fill those gaps on an as-needed basis. We’re also seeing the turnover slowdown on both sides of the border.
Australia has always been a little bit of a challenge. So, they’re still kind of caught up in COVID fever — excuse the pun, but there’s a lot of industry in mining and offshore attracting personnel. It’s a little tighter, but we’re able to find the crews in the US. In a period of two months, we ramped up nine rigs. And each rig requires about 20 guys. So, there’s a couple of hundred people that were able to successfully go out and acquire.
A third of them had experience in the business which was quite interesting. We are attracting people back to the business. Our good safety record puts us ahead of our — some of our competitors in that regard. People always like to work with safe companies. We’ve got a rigorous training. It almost mimics a trade program called our global skill standards. So, when we introduce people we bring them up the ladder relatively quickly with great competencies. So, we’re not — it’s tough, but it’s not causing us any operational concerns.
Keith MacKey
Perfect. I’ll leave it there. Thanks very much.
Bob Geddes
Thank you.
Operator
Thank you. Your next question comes from Cole Pereira from Stifel. Please go ahead.
Cole Pereira
Hi, good morning everyone. So, it sounds like you have visibility to add an additional nine rigs in the US before the end of the year. I’m just wondering how much of those would be call it Tier 1 rigs in the $33,000 to $35,000 a day range? And have you had many conversations in the US with regard to 2023? And just any color you can share on what — how those have been going? Would be helpful. Thanks.
Bob Geddes
Yes. The — probably half of the nine rigs would be the high-spec triples. The other half would be — for instance in California, their rigs don’t require any upgrades. They are the midsized type. The other ones in the Rockies and US Southern area would be our — not our super spec triples, but our high-spec triples, which are getting in the $25,000 per day. The back half of your question I’m sorry it was again related to?
Cole Pereira
Just what visibility you have regarding 2023? And if you’ve been having any customer conversations with that? Just any color would be helpful.
Bob Geddes
Yes absolutely. We’ve already started some conversation in the Rockies and Southern with clients. So, they’ve got some visibility in our 2023 budget maybe not quantifiable but certainly they know they want to make sure they hang on to the best rigs. And they have some rigs where they may want to consider some upgrades too that they’re willing to pay for.
Those are kind of conversations. We’ve been purposely contracting as we moved up the ladder on pricing in six-month intervals sometimes in four-month intervals. We’re now starting to when we get into the low 30s with pipe and that we get into the mid-30s we’re starting to be takers of one-year contracts. And the odd two-year contract with a bump in the second year predetermined and also with escalation fully covered on labor which is most likely going to increase over time here as inflation occurs.
Cole Pereira
Okay, great. That’s helpful. Thanks. And maybe building on Keith’s question a little bit. So, based on your guidance and what some of your competitors have said through Q3 in Canada, it seems like it’s going to be sort of a steady climb peaking at call it the end of Q3. I mean is the biggest factor there just labor? Is it other logistics headwinds, or is it really just the timing of customer programs?
Bob Geddes
Just the tip of the ladder, the timing of customer programs. The summer is always quiet in Canada. And Calgary had a real stampede this year. So, brain cells — it takes a while for them to recoup and people to get back to picking of their program. Plus September, things get very dry and it’s easy to start to access the land so to speak everyone gets back to school and gets at it. So I think we’ll see, the usual third quarter bump and then people hanging on. Maybe a few people, wanted to get on their winter programs in late November, perhaps ahead of the first quarter, just so they get the rigs that they want. But the key point, was that we’ve got lots of capacity in the high-spec doubles, which is becoming the next hottest market.
Cole Pereira
Okay great. that’s all for me. Thanks. I’ll turn it back.
Bob Geddes
Thank you.
Operator
Your next question comes from Waqar Syed from ATB Capital Markets. Please go ahead.
Waqar Syed
Thanks for taking my questions Bob, Mike, even if the leading-edge day rate does not increase here in the US, when can your — by when will all your rigs have repriced to be at leading-edge rates?
Bob Geddes
I would say, certainly into the fourth quarter, they will evolve in a reset.
Waqar Syed
Okay. So — and then following up on an earlier question on the gross profit margins. I believe they were about 23.4% in Q2. And you mentioned Mike, that you expect a substantial bump. Is substantial in that 400 basis point kind of range — would that be substantial enough, or not substantial enough for you?
Mike Gray
No I think that would be substantial enough. Like you can see us getting into the high 20s to low 30s, going into 2023. Just as the rigs turn over to the higher day rates, we are seeing some cost inflation on certain items, but the day rates are definitely in excess of what we’re seeing on those increases. And then we’re not seeing the sort of start-up costs, that we’ve seen with recruitment and getting the rigs out the door. So I would agree with that number.
Waqar Syed
Okay. Great. And then Bob, in terms of supply chain challenges, if you think about like novel maintenance kind of stuff engines, mud pumps, drill pipe things like that. Could you maybe talk about like, how easy it is to secure that equipment?
Bob Geddes
Yes it’s a very good question, Waqar. The drill pipe — we’re always buying drill pipe, securing drill pipe for delivery six to 12 months out. So we have a good handle on drill pipe. The challenge with drill pipe is always picking, what’s going to be the trendy size and tool joint. As we drill out further, we’re seeing 5.5-inch drill pipe being used more often on our super high spec triples in the US, which a year ago we may not have seen. So we’re good on drill pipe engines we’re good on.
We also have a lot of Tier 1 reserve rigs and Tier 2 reserve rigs with the type of engines that we can grab go get rebuilt and bring them back into service. We’re not worried about engines. Mud pumps, we’ve got a program where we’re buying a certain amount of mud pumps every month rotating them over and rebuilding them. We also have mud pumps in our Tier 1 fleet and on Tier 2 fleet that can be accessed. So it’s the consumable things, like drill line is a perfect example where drill line is twice, as expensive as it was a year ago and we’re going through it twice as fast because, we’re drilling twice as fast with higher ton miles on it.
So that’s just one anecdote, on a supply chain area that has had rapid inflation. And we’re seeing probably 10% year-over-year inflation on some of the major components. But it seems, to have settled out a little bit. Shipping is moving things are getting around. We’ve got some pinch points in some areas, but not too much concern.
Waqar Syed
Okay. Great. And then just one final question. In terms of provision of low emission solutions to your customers, how has the conversation changed? And if you could maybe highlight how — what you guys are doing in that respect?
Bob Geddes
Yes. 30% of our rigs that we have running today, are running on a low emission either highline power or natural gas power. We have a lot more conversations now, with respect to, the natural gas engines with battery energy storage systems. We’ve got one large client in Canada, where we’re starting to turn the fleet over on to natural gas engines, where the capital is fully funded by the operator. They’re getting the benefit of the emissions reduction. And we have the benefit of not having to go out and buy natural gas engines. We just have to look after them, without a reduction in our day rate. So, that is continuing to get addressed with the majors. The mid-cap and the smaller guys, really not so much.
Waqar Syed
Great. Thank you, very much.
Bob Geddes
Thanks, Waqar.
Operator
Thank you. Your next question comes from John Gibson from BMO Capital Markets. Please go ahead.
John Gibson
Just wondering where leading-edge day rates would be including all of your ancillary apps for things like Ensign EDGE? And then maybe including all these things where we’re leading edge field margins be at?
Bob Geddes
On the high-spec triples, it would be 35% and on the high-spec doubles, it’d be closer to 25%.
John Gibson
Yes. And then last one for me, just on the CapEx increase. Is it fair to say that your outlook for rig demand has improved quite substantially relative to your last call? And does the full $165 million assume you’ll get to that 150 rig total you’re talking or spoken to?
Bob Geddes
Yes, yes exactly. A lot of this was identified earlier in the year. It takes three or four months to upgrade and reactivate a rig. And as I mentioned earlier in the call, we had — plus some weather in the second quarter. We had eight rigs in Canada for example already upgraded, reactivated, ready to go to work, but we were delayed on weather almost 1.5 months. They hit the ground in July. We’re having a very strong July already in Canada. It just muted the second quarter results.
John Gibson
Got it. Appreciate the color. I’ll turn it back.
Bob Geddes
Thanks, John.
Operator
Thank you. [Operator Instructions]. Your next question comes from Waqar Syed from ATB Capital Markets. Please go ahead.
Waqar Syed
Hi. Just a follow-up question I might as well ask. I know, it’s still early, but directionally could you point to where you think CapEx could be for next year?
Bob Geddes
Yes. Maintenance CapEx and there’s going to be less growth upgrade CapEx because most of that’s kind of been done in 2022, Waqar. I would think of 2023 as being no more than 2022. The maintenance CapEx usually between recertifications and notional upgrades on current active fleet, it’s usually $800,000 to $1 million a rig. So if we’re running 150 rigs, it would be about $150 million. Am I right Mike?
Mike Gray
Yes that would be.
Waqar Syed
That’s great. Thank you very much.
Operator
Mr. Geddes, there are no further questions at this time. Please proceed.
Bob Geddes
Thank you. Just to wrap up. So it’s clear that with the Ukraine more risk premium trading off and coupled with hints of a recession that oil is down. But the important note is that WTI remains strong and is essentially trading at pre-invasion pricing. One could argue that with prices coming off to the pre-invasion pricing that reduced demand chat will be muted.
Also, the price of the fuel of the future natural gas which will be required to generate the electricity into the future is rising steadily. I’ll point out we rarely see strong oil and gas pricing occurring at the same time. This will create even more demand for our rig fleet globally. I’m also happy to report that we continue to do our part reducing emissions by converting more rigs over to cleaner burning fuels such as natural gas. Currently we have 30% of our active fleet today on either high line or natural gas power.
In fact we are involved in a venture where we will drill a zero emissions well. We will use green hydrogen with hydrogen fuel cell engines to power one of our rigs to drill a zero emissions well. More on that on our next call in three months’ time. Anyway we continue to be price makers in the market. We continue to focus on debt reduction while being opportunistic on quick six-month-or-less payout on incremental upgrades and most importantly our professional crew has continue to operate at the highest levels of safety. Thank you and look forward to our next call.
Operator
Thank you. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.
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