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 listen only mode. Following the presentation, we'll conduct a Q&A session. If at any time during this call you require any assistance, please press star and number zero for the operator. This call is being recorded on Friday, August 5th, 2022. I would now like to turn the conference over to Nicole Romanow. Please go ahead.
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 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 see our 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 and thank you for joining in on our call today to 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 CAD 40 million. Where these rigs were all contracted at rates with CAD 5,000 a day bumps on average. Most importantly, these are all projects where we would have payout on our incremental capital within six months of commissioning. Again, the goal is to make sure we have payout 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 will 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 U.S., 49 in Canada, 14 internationally. We have visibility to give or take, get up to 150 rigs by year-end, 65-70 in the U.S., 60-65 in Canada, and 15-20 internationally.
We have guided with CapEx for the year close to CAD 165 million, of which CAD 115 million is attributed to maintenance CapEx and nominal reactivation costs on, excuse me, on the additional 50+ rigs, which will be reactivated through 2023 to feed the uptick in the market. The other CAD 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 mobilization fee. I'll point out that in all cases, with respect to the approximate CAD 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.
Finding that delicate balance of 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. 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, and which will 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+ rigs active in the back half will all be at much higher rates. I'll turn over to Mike for a more deep dive into the analysts or into the results. Mike?
Thanks, Bob. Despite the recent pullback in commodity prices, the operating environment for oil and natural gas industry continues to support demand for oil field 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 2022. Canadian operations recorded 2,369 operating days, a 124% increase from the prior year. U.S. 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 CAD 344.1 million in the second quarter of 2022, a 62% increase compared to revenue of CAD 212.3 million generated in the second quarter of the prior year. For the first six months ended June 30th, 2022, the company generated revenue of CAD 676.8 million, a 57% increase compared to revenue of CAD 430.9 million generated in the same period of 2021. Adjusted EBITDA for the second quarter of 2022 was CAD 68.3 million, 50% higher than adjusted EBITDA of CAD 45.6 million in the second quarter of 2021. Adjusted EBITDA for the six months ended June 30th, 2022, totaled CAD 138.3 million, 45% higher than adjusted EBITDA of CAD 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. Depreciation expense in the first six months of 2022 was CAD 138.7 million, a decrease of 1% compared to CAD 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 increased 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 CAD 50.1 million. The capital budget for 2022 is estimated to be now CAD 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 CAD 83 million since December 31st., 2021. On that note, I'll turn the call back to Bob.
Thanks, Mike. Let's run around the world and do an operational update starting in the U.S. We have upgraded and reactivated nine rigs since our last call, which brings our current active rig count today to 61 rigs in the U.S. 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 $5,000 a day to the operator. We're also pushing services that do not attract a margin back over to the operator in the contract.
This would be items like trucking, et cetera, high dollar amounts that are a drag on our cash and generate no margin. Our well servicing division in the U.S. is running close to 40 rigs, that's 80% utilization, and continues to expand their 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 to Canada, we have 49 rigs on the payroll with visibility to 55 by September and 60-65 by year-end. As mentioned previously, of the nine rigs that are being upgraded, four of them were commissioned in the last month of the quarter, June. 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-spec triples. The high-spec triples are, of course, highly utilized and are getting north of CAD 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 type 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 shallower 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 CAD 5,000 a day.
The remaining 20+ 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 five to 10 of our high-spec doubles going back to work before year-end. We're already getting calls to book into first quarter 2023. 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 year-end. 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 moving pricing. On 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. The roughly CAD 5 million in CapEx required to reactivate and upgrade the 2 rigs will all be recovered via upfront mob fees, which will occur late in fourth quarter. The team also successfully recontracted our two rigs in Bahrain and has recontracted both our rigs in Argentina that are currently operating, both with $5,000 a day rate increases. In Australia, where we see the effects of COVID-related issues, we recontracted 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 mobilization 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 increases in the $3,000 per day range. With that summary, I'll turn it back to the operator for Q&A.
Thank you. Ladies and gentlemen, we will now begin the Q&A session. Should you have a question, please press the star followed by the number one on your touchtone phone. You will hear a three-tone prompt acknowledging your request, and your questions will be pulled in the order that they are received. Should you wish to decline from the polling process, please press the star followed by the number two. If you are using a speakerphone, please leave the handset before you press any keys. One moment please for your first question. Your first question comes from Aaron MacNeil from TD Securities. Please go ahead.
Hey, 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.
Mm-hmm.
You know, what would an Oman rig, like, what would the capital cost be for a rig like that?
We've got two types of rigs in Oman, the 1500 HP 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 a Marmul project in Oman on three- to five-year contracts, minimum three with two one-year options. The rates are in, you know, 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.
Understood. 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? You know, what's your daily margin for that, a rig in that asset class?
Through the summer, we've been careful not to contract our high-spec doubles past October first. We're already starting to see traction in the low 20s on those. If you think of a high-spec double as needing a five-man crew at CAD 8,850 a day and let's say CAD 3,000 a day of R&M, you're at you know CAD 11,500. You've got about a CAD 10,000 a day margin. The point is of course when we bought Trinidad we went after it mostly for its high-spec double market in Canada. They had the biggest portion of high-spec doubles in Canada at the time.
The Cardium fell apart, everything else fell 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. The high-spec doubles are coming into play. The point is that we've got 32 of these, only 11 of them are running today, and none of them are contracted purposely past October because we're raising rates. 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.
That's very helpful. More than I thought I'd get from you on that question. Mike, maybe I'll ask you one too.
Sorry, Aaron.
It's all good. Mike, year-to-date debt reduction of CAD 83 million is noted, but you know, 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 gonna have to direct some cash towards working capital in the back half. You know, do you think we'll see Ensign add a little breathing room on the line of credit in the near future? Or can you maybe just give us a sense of how you're looking at capital allocation and debt reduction as we look ahead?
Yeah, sure. I think, I mean, we see in the first half of the year, we had about, well, about CAD 80 million worth of capital, of which now those rigs are gonna be generating free cash flow going into Q3 and Q4. I think we'll see that, liquidity on the facility, continue to increase, for the remainder of the year. When we look at our accounts receivables and everything like that, I think, we'll see more and more liquidity being added onto the balance sheet for the remainder of the year. I think that will continue to expand. We'll definitely continue to expand into 2023. I think from operational cash flow, we'll see continued deleveraging.
Thanks, Mike. I'll turn it over.
Aaron.
Thank you. Now your next question comes from Keith Mackey from RBC Capital Markets. Please go ahead.
Hey, good morning, and thanks for taking my questions. Just wanted to start out on the gross margin in the second quarter. How much 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?
We would have saw probably 200 basis points maybe on sort of the margin compression on the reactivation. I mean, you have a lot of costs just to the rehire, getting people drug tested, people associated to the rig and everything like that. We would have saw an increase in labor that we won't see going forward with lots of our reactivations coming up pretty quick. I'd 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 recontracting taking place. 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.
Definitely, in Q2, you would have saw a bit of a decrease, and then you'll see that increase going into Q3 and Q4.
Perfect. Thanks. Thanks, Mike. Just to maybe follow up on the labor. How many of the rigs you expect to get out in the second half of the year? Have you already got staffed up? Maybe if you can just talk a little bit about staffing trends in general, that'd be helpful too.
Sure. Yeah. 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's been significant increases at the field level on pay over the last six months. You know, roughnecks can make about CAD 90,000 a year now, either side of the border. We're starting to fill those gaps on an as-needed basis. We're also seeing the turnover slow down on both sides of the border. Australia has always been a little bit of a challenge.
They're still kind of caught up in COVID fever, excuse the pun, but you know, there's a lot of industry and mining and offshore attracting personnel. It's a little tighter. We're able to find the crews. In the U.S., in a period of two months, we ramped up nine rigs, and each rig requires about 20 guys. So, there's a couple of 100 people that we're able to successfully go out and acquire. 1/3 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 some of our competitors in that regard. You know, people always like to work with safe companies. We've got a rigorous training.
It almost mimics a trade program called our Noble Skill Standards. When we introduce people, we bring them up the ladder relatively quickly, with great competencies. We're not, it's tough, but it's not causing us any operational concerns.
Perfect. I'll leave it there. Thanks very much.
Thanks, Keith.
Thank you. Your next question comes from Cole Pereira from Stifel. Please go ahead.
Hi. Yeah, good morning, everyone. Sounds like you have visibility to add an additional nine rigs in the U.S. 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-$35,000 a day range. Have you had many conversations in the U.S. with regard to 2023? Just any color you can share on how those have been going would be helpful. Thanks.
Yeah. Probably half of the nine rigs would be the high-spec triples. The other half would be, for instance, in California, their rigs that don't require any upgrades. They're the mid-size type. The other ones in the Rockies and the U.S. Southern area would be not our super-spec triples, but our high-spec triples, which are getting in the CAD 25,000s, CAD 25,000 per day. The back half of your question, I'm sorry, was again related to?
Just what visibility you have regarding 2023, and if you've been having?
Right.
Any customer conversations with that? Just any color would be helpful.
Yeah, absolutely. We've already started some conversation in the Rockies and Southern with clients. They've got some visibility in their 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 to that they're willing to pay for. Those are the kind of conversations. We've been purposely contracting as we've moved up the ladder on pricing in six-month intervals, sometimes in four-month intervals.
We're now starting to, you know, 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.
Okay, great. That's helpful. Thanks. Maybe building on Keith's question a little bit. 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?
Just the latter, 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 thinking of their program. Plus, September, things get very dry, and it's easy to start to access the land. You know, so to speak, everyone gets back to school and gets at it.
I think we'll see the usual third quarter bump and then people hanging on, maybe a few people wanting to get on their winter programs in late November, perhaps ahead of the first quarter, just so they get the rigs that they want. The key point was that we've got lots of capacity in the high-spec doubles, which is becoming, you know, the next hottest market.
Okay, great. That's all for me. Thanks. I'll turn it back.
Thank you.
Thank you. Your next question comes from Waqar Syed from ATB Capital Markets. Please go ahead.
Thanks for taking my question. Bob, Mike, you know, even if the leading-edge day rate does not increase here in the U.S., by when will all your rigs have repriced to be at leading-edge rates?
I would say certainly, into the fourth quarter, they will have all been reset.
Following up on an earlier question on the gross profit margins, I believe they were about 23.4% in Q2. You mentioned, Mike, that you expect a substantial bump. Is substantial in that 400 basis points kind of range, would that be substantial enough or not substantial enough for you?
I think that would be substantial enough. I could 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. We're not seeing the sort of start-up costs that we've seen with recruitment and getting the rigs out the door. I'd agree with that number.
Okay, great. Thank you. Bob, in terms of supply chain challenges, you know, if you think about like, you know, normal 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?
Yeah, 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. 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 U.S., which a year ago we might not have seen. 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, get rebuilt and bring them back into service. We're not worried about engines. Mud pumps, we've got a program where, you know, 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 our Tier 2 fleet that can be accessed. It's the consumable things like drill line is a perfect example where a 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.
That's just one anecdote on a supply chain area that has had rapid inflation. We're seeing, you know, probably 10% year-over-year inflation on some of the major components. It seems to have settled out a little bit. You know, shipping is moving, things are getting around. We've got some pinch points in some areas, but not too much concern.
Okay, great. Then just like one final question. In terms of provision of low emission solutions to your customers, how has the conversation changed? If you could maybe highlight how, you know, what you guys are doing in that respect.
Yeah. About 30% of our rigs that we have running today are running on a low emission, either high-line 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 onto 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. That is continuing to get addressed with the majors.
The midcap and the smaller guys, really not so much.
Okay. Thank you very much.
Thanks, Waqar.
Thank you. Your next question comes from John Gibson from BMO Capital Markets. Please go ahead.
Morning, all. 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 would leading edge field margins be at?
On the high-spec triples it would be 35, and on the high-spec doubles it'd be closer to 25.
Last one for me. Just on the CapEx increases, is it fair to say that your outlook for rig demand has improved quite substantially relative to your last call? Does the full CAD 165 million assume you'll get to that 150 rig total you've been talking about or spoken about?
Yeah. Exactly. A lot of this was identified earlier in the year. It takes three or four months to upgrade and reactivate a rig. 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 a month and a half. They hit the ground in July, so we're having a very strong July already in Canada. It just muted the second quarter results.
Got it. Appreciate the color. I'll turn it back.
Thanks, John.
Thank you. Ladies and gentlemen, as a reminder, should you have a question, please press star followed by the number one. Your next question comes from Waqar Syed from ATB Capital Markets. Please go ahead.
Hi. Just a follow-up question, 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?
Yeah. Good maintenance CapEx, and there's going to be less growth upgrade CapEx cause 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, you know, between recertifications and notional upgrades on current active fleet, it's usually CAD 800 thousand-CAD 1 million a rig. So, if we're running 150 rigs, it'd be about CAD 150 million bucks. About right, Mike?
Yep.
Yeah.
That would be.
Okay. That's great. Thank you very much.
Thanks, Waqar.
Mr. Geddes, there are no further questions at this time. Please proceed.
Thank you. Just to wrap up. It's clear that with the Ukraine war risk premium trading off and coupled with hints of a recession, that oil is down. 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, a reduced demand shock 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 in 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 emission well. We will use green hydrogen with hydrogen fuel cell engines to power one of our rigs to drill a zero emission 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. Most importantly, our professional crews continue to operate at the highest levels of safety. Thank you, and look forward to our next call.
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.