Good afternoon, ladies and gentlemen, and welcome to the Ensign Energy Services Inc. first quarter 2023 results conference call. At this time, all lines are in listen-only mode. Following the presentation, we will conduct a question and answer session. If at any time during this call you require immediate assistance, please press zero for the operator. This call is being recorded on Monday, May 8th, 2023. I would now like to turn the conference over to Nicole Romanow, Investor Relations. Please go ahead. Thank you, Joelle. Good morning and welcome to Ensign Energy Services first quarter 2023 conference call and webcast. On our call today, Bob Geddes, President and COO, and Mike Gray, Chief Financial Officer, will review Ensign's first quarter highlights and financial results, followed by our operational update and outlook. We'll then open the call for questions. Our discussion today may include forward-looking statements based upon current expectations that involve several business risks and uncertainties. The factors that could cause results to differ materially include, but are not limited to, political, economic, and market conditions, crude oil and natural gas prices, foreign currency fluctuations, weather conditions, the company's defensive lawsuits, the ability of oil and gas companies to pay accounts receivable balances, or other unforeseen conditions which could impact the demand for the services supplied by the company. Additionally, our discussion today may refer to non-GAAP financial measures such as adjusted EBITDA. Please see our first 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, everyone. I'll just start with a quick summary before Mike gets into some of the details. A strong quarter with increasing margins year-over-year and quarter-over-quarter as tightness in certain rig type classes continues to support the rate increases that industry realized through the back half of 2022 and into the first quarter 2023. Every one of our operational areas, U.S., Canada, and International, delivered significant operating day increases. The quarter had a few timing drags for projects that were scheduled to start in Q1, have been delayed until the second quarter. EBITDA margin jumped another 5%, and gross margins on our high-spec rigs jumped about 15%. Ensign continues to manage its balance sheet, spending only CAD 41 million in planned maintenance capital to maintain the high-spec fleet in the first quarter. The target for CapEx maintenance and upgrade is still around CAD 157 million for the year. The focus is reducing debt by CAD 600 million over the next three years. I'll turn it over to Mike for a detailed summary of the quarter. Thanks, Bob. The outlook for oilfield services continues to be constructive despite fluctuating global energy commodity prices and macroeconomic headwinds. Recessionary pressures, inflationary concerns, financial sector stress, and the potential for slowing economies continue to weigh on commodity prices over the short term. However, oilfield services activity and revenue rates continue to be steady year-over-year. Ensign's first quarter 2023 results reflect meaningful operational and financial improvements year-over-year, with it being our best first quarter since 2014. Operating days were up in the first quarter of 2023, with Canadian operations experiencing a 2% increase, U.S. a 25% increase, and international operations showing a 26% increase compared to the first quarter of 2022. The company generated revenue of $484.1 million in the first quarter of 2023, a 46% increase compared to revenue of $332.7 million generated in the first quarter of the prior year. Adjusted EBITDA for the first quarter of 2023 was $127.3 million, an 82% increase from adjusted EBITDA of $70 million in the first quarter of 2022. The 2023 increase in adjusted EBITDA can be primarily attributed to improved industry conditions, increasing both drilling and well servicing activity. Depreciation expense in the first three months of 2023 was $77.9 million, 11% higher than $70 million in the first three months of 2022. The increase was primarily driven by a year-over-year increase in the United States dollar. G&A expense in the first quarter of 2023 was CAD 3.4 million higher than the first quarter of 2022. G&A expense increased due to support of increased operational activity, annual wage increases, and higher foreign exchange rate on the United States dollar translation. On a per operating day, G&A was up about CAD 200 per day year-over-year. Net capital purchases for the quarter were CAD 49.7 million. The purchases consisted of CAD 8.3 million in upgrade capital and CAD 41.6 million in maintenance capital, for a total of CAD 49.9 million, offset by sales proceeds of approximately CAD 200,000. Total debt net of cash was reduced by CAD 29.1 million since December 31st, 2022. Our debt reduction for 2023 is targeted to be approximately CAD 200 million. Our target debt reduction for the period beginning 2023 to the end of 2025 is expected to be approximately CAD 600 million. If industry conditions change, this target could be increased or decreased. Regarding the refinancing of the balance sheet, we do not have any additional news to share. Our commentary and views are similar to the last quarter discussion. We continue to look at several options that will best serve the company on a go-forward basis. Overall, our debt metrics continue to improve substantially. At the year-end 2021, our total net debt to EBITDA was 5.98, decreasing to 3.76 in 2022, and has further decreased to 3.18 as of March 31st, 2023. We'll continue to see this decrease to levels we have not seen in many years. On that note, I will turn the call back to Bob. Thanks, Mike. Let's walk around the world with an operational update. Most of you on the call are well aware that Ensign operates a high-spec fleet of 232 high-spec drill rigs and over 90 well servicing rigs, which employ over 4,000 highly trained crews in eight countries around the world, the U.S., Canada, Kuwait, Bahrain, Oman, Australia, Argentina, and Venezuela. Let's start with the U.S., which provides over half of our EBITDA. We continue to run 55-60 rigs in the U.S. with a strong position in the Permian with 45 rigs active today. With the Haynesville play softening due to gas prices, the sales team has been very active, churning rigs over onto new contracts. In most cases where rigs have come off 2022 contracts, we have been able to raise prices to current market prices, a bump of approximately $2,000 a day on the contract turn. The margin run rate for the second quarter will be marginally above the first quarter run rate in the U.S. In some cases, and on more current negotiations, we are more likely to hold rates for a six-12 month term. Our California business unit continues to get frustrated with ongoing challenges with drilling permits in that state. Our U.S. team has plans to pull a few of these rigs over into the Rockies for surface hole projects. These light, agile, highline capable electric rigs are great for those type of projects. We maintain a 7% market share in the lower 48 and see this stabilizing over the rest of 2023, albeit the negotiations are tougher today than they were six months ago. We also see the Permian rig count stable at around 350 drilling rigs active. We're also starting to see operators drill more into their Tier 2 acreage, which means that to maintain production, not grow, just maintain production, they will need to drill more wells. We have close to 25% of our active U.S. fleet on an Edge emissions reduction strategy, which is a combination of highline powered rigs and also natural gas engine rigs with BESS systems, battery energy storage. With the arbitrage between diesel fuel and gas, the argument becomes more compelling. As a result, we'll continue to see expansion in this area, which not only reduces emissions, it provides Ensign a high-margin incremental revenue stream. Our U.S. well servicing business had one of the slowest starts out of the gate in 2023, purely due to operator project timing, but we are back up to 85% utilization today and look to stay strong through the rest of the year with no rate degradation. Our directional drilling business, mostly Rocky-centric, continues to deliver with steady work on numerous projects. Turning to Canada. Canada had a strong operational quarter but fell short of expected days as the team pushed rates hard into the fourth quarter, which impacted the first quarter activity. We'd expected to get closer to 65 rigs active in the first quarter. The second quarter is already looking much stronger as we will maintain 22 of our high margin, high-spec rigs over breakup. Then grow that to 50 into July. Our high-spec triples are running well over 70% utilization, which provides continued strong pricing. We're starting to see most of the high-spec doubles attract work after breakup with no rate degradation. We also signed up two of our high-spec triples, one coming off contract in U.S. Rockies, onto two take or pay contracts in the mid-30s. That's a base rate. Our Canadian well servicing business unit is expecting to get back up to 18 rigs active after breakup. A few of those will be 24 operations. We still have for sale roughly CAD 30 million-CAD 40 million of redundant real estate in Nisku, which when sold, will go towards debt reduction. International is steady as she goes, generating steady, predictable free cash flow and long-term projects. We just commissioned our third rig in Oman onto a five-year contract. The other two started up later in 2022. All three rigs are performing well out of the gate. These rigs are all on performance-based contracts. Kuwait and Bahrain, where we have four of our largest rigs, continue to execute in the top decile of our contracting peer group in these countries. Australia's first quarter results were frustrated with the delay of two large projects that were delayed until the second quarter. This affected the first quarter results, but will benefit the second quarter results. In Argentina, we have two super-spec triples on long-term contracts with day rates moving 10%-15% on their next turn mid-year. The situation in Venezuela changes daily, we're expecting that we may have one of our workover rigs and a drilling rig working by the end of the year, but don't hold your breath. On the technology front, our Edge Drilling Solutions product line continues to expand. With a lot of the supply chain issues behind us with respect to computer hardware access as a result of the pandemic, we're in the middle of deploying and commissioning another 10 of our Edge drilling control systems on our high-spec rigs. This attracts roughly $1,000-$1,500 a day of incremental high-margin technology to the rig. We will have EDGE actively engaged on most of our super-spec and high-spec triples by the third quarter. With the obvious arbitrage between diesel and natural gas, notwithstanding the obvious emission reductions when using highline or natural gas power, we are seeing growing demand for Edge emissions reduction strategy. The product offering ranges from the highline power substation, which rents for CAD 2,000 a day, to the standalone BESS for about the same rate, to the full-blown natural gas power system with BESS and EMS, engine management system, for around CAD 5,000 a day. These are all high-margin opportunities and they help reduce emissions by as much as 50%. We have about 10% of the North American fleet on one of these strategies, and when we include dual fuel applications, we have roughly a quarter of the fleet on an emissions reduction strategy. Our ADS, or automated drill system, which delivers consistent slips-to-slips and automates the routine for the driller, has been fully tested and is now commissioned on 10 rigs in the U.S. The ADS charges out for about $1,000 a day, à la carte. I'll turn it back to the operator for some questions. Thank you. Ladies and gentlemen, we will now begin the question and answer session. If you have a question, please press star followed by one on your touch tone phone. You will hear a three-tone prompt acknowledging your request, and your questions will be pulled in the order they are received. Should you wish to decline from the polling process, please press star followed by two. If you are using a speakerphone, please lift the handset before pressing any keys. One moment please for your first question. Your first question comes from Aaron MacNeil with TD Cowen. Please go ahead. Morning. Thanks for taking my questions. Bob, I can appreciate you have no meaningful U.S. gas exposure, but, you know, several of your larger competitors do, and many, I think if not all, have all pointed to a declining rig count throughout Q2. I guess, you know, do you see your rig count declining at all in Q2? Are you at all concerned about the knock-on effect of heightened competition for rigs in the event of a decrease in activity? I guess maybe finally, what might be your approach to pricing if that does play out? Yeah, no, fair question, Aaron. I mean, we started seeing some impact three or four months ago. Some of those rigs in those areas are tied up on term contracts, you know, with the kind of a Tier 1 contractors, maybe having some ETFs, things like that. We've been able to in the last two to three months anyway, turn over about 20 of our rigs onto other contracts. We got ahead of it, termed them up a little bit more. As you know, we had very little gas exposure, it did provide a defensive situation, which means we weren't able to raise rates much. We did have some contract turn where from the prior contracts, we were able to move them up a couple CAD 1,000 a day to more of a leading edge. I would suggest that the, you know, the leading edge has probably degraded a little bit, and people are looking for some term as a defensive strategy. California is a little bit of a unique situation all by itself. I mentioned, you know, we've got at least one rig, one of our electric ADRs, smaller rigs moving over into the Rockies to do some shallow surface hole projects. Who knows when or if California will start to straighten up. It is steady, I'll say that in California, but we're probably down about four or five rigs from where we expected to be in the first quarter, which, you know, had some effect on our first quarter results. Understood. Mike, maybe one for you. I realized there was nothing specific in the disclosures, but on the prior conference call, you did suggest that you were going to kick off a debt refinancing following Q1 results. You know, maybe just a bit of an update there. Is that still the case? Can you walk us through the potential timeline and maybe what we can expect from you over the coming weeks or months? Yeah, for sure. No concrete sort of additional information to share. We will definitely look at reaching out to the different areas and looking at what's gonna be the best approach going forward. Like I said, our debt metrics really have improved quarter-over-quarter as well as year-over-year. We think that's gonna be a strength going into this type of market. But yeah, I know we continue to look at a bunch of different options, and we'll select the options that give the company the best maneuverability going forward. Not to pin you down to a specific timeline, Mike, but, like, do you think I'll be asking the same question on the next conference call, or do you think you'll have something else? I can't say for sure. I mean, the facility we'll have to deal with something by at least October. I would say in the next few months for sure, we'll be moving things along, but I can't commit to a firm timeline. Fair enough. All right. I'll turn it over. Thank you, guys. Thanks, Aaron. Your next question comes from Keith Mackey with RBC Capital Markets. Please go ahead. Hi, good morning. Thanks for taking my questions. Maybe to start out in the international, Bob or Mike, can you kinda just give us a bit more color on the impact of the delays in Australia? What you think a good run rate for Q2 will be given those projects starting up as well as the Oman rig? The Australian projects probably affected Q1 by $2 million, so that'll push into the Q2. The third Oman rig was it came on stream on as scheduled. The first quarter results weren't necessarily too impacted by that, although we thought we may have got going a month earlier. We were ready to go, but the operator wasn't. You know, we've got a good steady run rate in the second quarter. I'm not sure, Mike Gray, if you wanna expand on what effect that has. Well, in Oman, you're gonna see one additional rig for the full quarter, pretty much the full quarter of Q2, and then we should see sort of two more rigs start up in Australia over the next month or two. From an operating standpoint, I mean, there should be probably 1.5-2 kinda net new additional rigs for Q2 of 2023. Okay. Got it. Thanks for that. Maybe just a little bit on Canada. Operating days didn't really grow much from 2021 to 2022 or, sorry, 2022 to 2023 in Q1. You mentioned pushing rates hard in Q4 as part of the reason for that. Can you just give us a little bit more detail on the discussions that you've had then with clients and what that'll mean for the second half of the year? Right. Right. I mean, the first quarter is always prefaced by what happens in the October, November bidding cycle before that. As we started pushing rates and holding rates into the, you know, first quarter on certain rig categories, we found some of the competition not as aggressive on pricing, and we lost eight to 10 bids basically, which put us down about seven or eight rigs into the first quarter. It's hard to claw that back when you're going into the first quarter. That was a bet we made. Of course, the other rigs benefited from, you know, our fleet benefited from that, hold on rates or a push and depending on the rig category. We're down at 22 rigs currently. We've got contracts that will take us to 50 rigs by July. You'll see us go from about 100 rigs currently to back up to about 125 here quickly into July. We're, we're not gonna be reducing the number of rigs that we have active when we look at the end of the first quarter as compared to the end of the second quarter. We're back up real quick as compared to some of our peers who may see some degradation. We're seeing some clients, who use some other or other contractors, through the winter coming back to us and saying, "Hey, you know, we went with the lower price for the winter. Have you got this rig available after breakup?" They're, you know, they weren't, I guess the performance wasn't as expected in the first quarter with some of the other contractors. Anyway, we'll be back up to 50 again by July here. Got it. Just maybe to follow on that, what are you seeing now in the Canadian market? Is most of the competition... I know it's always price, but has, like, it's, you know, price clearly impacted how things went in Q1. Has the conversation shifted at all from, you know, customers looking for the lowest price to, okay, now it's more about operational execution and availability? Or, you know, are you still finding that, you know, whatever work there is, you're losing a similar portion due to price? Yeah. Well, we're, you know, we're always price sensitive. Obviously, we misread the market in certain rig categories going into the fourth quarter for first quarter pricing. You know, we're definitely seeing, you know, price is always a factor, but operational excellence and performing with less downtime is always the key. You know, we represent less than a third of the operation on a daily basis, so the operator is willing to, you know, take a lower price sometimes, but not always. It depends on the performance that he picks up. It's a combination of both. I would suggest that, you know, we've been able to now get our price in the second quarter that we're bidding into the fourth quarter, which created some first quarter frustration. The market's kind of coming back to us. Here's an example. In the last 10 bids, we've won eight of the last 10 bids here in the last two weeks. Okay, thanks for the color. I'll turn it back. Your next question comes from Cole Pereira with Stifel. Please go ahead. Morning, all. Bob, you talked a little bit about U.S. drilling margins improving into Q2. You know, a lot of your U.S. peers have talked about their margins sort of flattening out from there. Is that kind of what we should expect with Ensign, just given some of the dynamics in the current market? I think that's fair. You know, a lot of it has to do with contract cadence there, Cole. We're certainly not able to push pricing. In some cases, you know, you're having to throw a few things in to hold the market, because you've got a Tier 2 contractor, kind of nipping at your heels there. Generally, I would say that, you know, we will see some rate progression because of the contract turnover from the first quarter into the second quarter, but it'll probably normalize through the third quarter, and we'll see what happens in the fourth quarter. Got it. Thanks. Can you just add some commentary around what you're seeing in the pricing environment for super-spec rigs in Canada, just in terms of the supply and demand fundamentals and how rates are moving as a result? Yeah. The, you know, there's a big bifurcation, of course, the high spec triples are very tight markets still. Those rates are not going down at all on any contract turnovers. We're seeing that go up $3,000-$5,000 a day in some cases. It depends on the number of rigs that are being offered. On the high spec doubles, as I mentioned before, we're starting to see the price that we put out there in the fourth quarter that felt some resistance now get traction because operators are going, "You know what? We want that kind of rig." On the more conventional rigs, it's a very tough and tight business still. Got it. Thanks. Mike, just on the, on the interest, expense side, I mean, cash interest costs relatively high this quarter. Anything one-time in there, or is that kind of a reasonable run rate for the credit facility? How should we also be thinking about lease payments for 2023? For the interest, we've dropped about 100 basis points, starting in Q2, on our facility. We saw sort of a full, fully priced facility in Q1. We should actually see our interest costs start to trend downwards. I wouldn't probably use that as a full run rate. I'd probably include probably 100-150 basis points decrease overall for 2023. For lease costs, we expect that to normalize kind of in Q2 and Q3 to historically what we had. We had some leased equipment that we had in Q4 and Q1, that's gonna normalize for the remainder of the year. Okay. Perfect. Thanks. Just one last quick one. I mean, what are you guys seeing in terms of the impact of wildfires on your operations so far? Yeah. Yeah. It's having some effect. We've got three rigs that have been evacuated, four rigs on watch. Of course, all the rigs are on standby without crews. We're monitoring it hour by hour. It is cooling off, and there has been some rain. Let's knock on wood. The worst is probably behind us. No incidents with respect to personnel. At this point, no impact on any of our rig assets. Got it. Okay. That's all for me. Thanks. I'll turn it back. Thanks, Cole. Your next question comes from Waqar Syed with ATB Capital Markets. Please go ahead. Thank you. Bob, you mentioned that there were 10 bids that you've won the last two weeks. Could you maybe talk about what the rates were for these winning bids versus the rates that they realized in the last quarter? Yeah. They're, as I mentioned, they're the same. They haven't gone up or down. On the high-spec triples, they went up by about $3,000 a day. Our average run rate for the high-spec double and the high-spec doubles, specifically are about the same. The conventional rigs have probably stepped down a little bit. Okay. Then you mentioned. I missed a little bit. You said owing to the wildfires, there were three rigs that were evacuated, and then there was how many? One rig on watch, or what did you exactly say? Yeah, we had three rigs evacuated and four rigs, on watch, where the. Okay. the fire is within 50 km. They're. That's kind of a radius that they, depending on the winds, of course, they keep an eye on. Any thoughts on how many rigs have been affected, industry rigs have been affected because of wildfires? Good question. If you look at the map of where all the wildfires are, it seems to be where all the industry activity is. That's kind of an interesting situation. There's, yeah, I would say probably half of them. Okay. The wildfires are spotty all over, west and north of Edmonton and, north and west of Calgary, more north and west of Grande Prairie, I would say, yeah. Okay. Then in terms of California outlook, you mentioned a few things. You're moving one rig. You have now, what, five or six rigs working in California? What's the number? Correct. I know it's California, it's always very difficult to predict where the rig count could go, but anything changing from a permitting perspective? Are you seeing any progress there, or anything that you could add? Not really. You know, just as soon as something changes, it ends up in the appellate court, I'm sorry. Everything stops again, right? Yeah, it's stop, go, stop, go, stop, go. The well servicing side got hit hard in the first quarter. California didn't come out of the gate as hard as we thought. We're back up to 85% utilization with our well service rigs. That part is coming back strong. At the same kind of pricing level as before? Oh, yeah. As it come- We haven't had to reduce our pricing at all. Now, in California, it's always been an issue with permitting. Is it particularly bad now, or is it getting worse, or is it just like, you know, the periodic issues that you see every couple of years? The permitting, the operators are building a construct of if we can drill the well emissions free, can we accelerate our permit? That's getting some traction. All of a sudden, you know, rigs that have highline capability or, perhaps, you know, our hydrogen emission free project may get some momentum again. Nicole's on top of that. We'll see. It is California. All right. Thank you very much, Bob. Appreciate the call. Thanks, Waqar Syed. Ladies and gentlemen, as a reminder, should you have a question, please press star followed by one. Your next question comes from Josef Schachter with Schachter Energy Research. Please go ahead. Morning, Bob Geddes, and Mike Gray and Nicole Romanow. Going a little more on the wildfires, if something happens and the ones that are on watch, how quickly do you need to, you know, get the equipment taken down and moved? Is that something that you guys have, you know, plans for that and places where you would move the rigs to? Have you got those kind of- Yeah. contingency plans? Yeah. We have an emergency response plan and truckers on standby for our, you know, high-value loads. The challenge is always access to the rig, and forestry will shut down roads and not allow any access into it. That's the situation on three of our rigs. Every morning, we're able to get a chopper or a small plane in the air, along with the operator to kind of take a look at what's going on in the site. It seems that the worst is behind us because it's gotten cooler, a little wind, and we've had some rain. You know, that's the situation. As I mentioned, we haven't had any of our assets affected by any degree. A couple of shacks here or there on the peripheral perimeter, but that's about it. Good. The safety of all the crews and the manpower. Correct. Absolutely. First and foremost. On the number of marketed rigs, you've gone from 247 - 232 down to 15. Are those rigs now, ones you've sold or, are they being, taken and used parts for other rigs? What's, is this a permanent decline of 15 rigs? The, it's been an evolution of a move towards upgradable high-spec rigs as we work through the market. You know, every year we decommission, you know, roughly, you know, 5% of the fleet, if you think of a rig having a 20-30-year actuarial lifespan. You know, 15 rigs, they get decommissioned, spare parts get harvested. We generally cut up the masts and subs, so they basically have no further use, and they don't end up on the market in a Tier 2 or Tier 3 application that we may compete against somewhere else in the world. They serve their useful life, and they just get decommissioned. Okay. That's it for me. Thanks very much. Thanks, Joseph. Your next question comes from Waqar Syed with ATB Capital Markets. Please go ahead. Thanks for getting me back in the queue. I forgot to ask you, Bob, in terms of the you know, if the rigs are evacuated with because of wildfire, how does the contract work? Do you still get paid for those days when the rig is down or customer can declare force majeure and not pay? How does it work? Yeah, it's, it generally starts off standby without crew. It can turn into a position where it's force majeure. You know, generally the client works with us and it's standby without crew. Of course, the rigs are fully insured, we're hoping we don't get to that position. Sure. Okay. Thank you very much. All right. There are no further questions at this time. Please proceed. Thank you, operator. Just to wrap up, the macro construct for the oil business remains strong for the back half of 2023. For gas, it'll be well into 2024 before we see demand for gas wells increasing again. The slip in commodity prices has generally put a pause in activity growth and rate momentum in general, certain rig type classes still remain very tight and no rate degradation, especially in Canada. Ensign expects to be running around 125 rigs and 50-60 well service rigs into the third quarter and remaining part of the year. Ensign has seen leading-edge price stabilize, we continue to build out term to help de-risk the future and reinforce our debt reduction targets. Ensign has CAD 1.6 billion of contracted revenue forward, with 60% of the fleet tied up under contract and over 30% of the active fleet on long-term contract of six months or greater. The weighted average contract tenure is about one year. The average age of the fleet is roughly 11 years old, with another 20 years of economic life ahead of it. Ensign is fully committed to the target of quickly delevering and reducing CAD 600 million of debt over the next three years. We'll look forward to our next call in three months. Thank you. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and-