Good morning, ladies and gentlemen, and welcome to Ensign Energy Services Inc.'s Second Quarter 2025 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. If at any time during this call you require immediate assistance, please press the star zero for the operator. This call is being recorded on Friday, August 8, 2025. I would now like to turn the conference over to Nicole Romanow, Investor Relations. Please go ahead. Thank you, Ludi. Good morning and welcome to Ensign Energy Services' Second Quarter 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 losses, the ability of oil and gas companies to pay receivable balances, or other unforeseen conditions which could impact the demand for services supplied by the company. Additionally, our discussion today may refer to non-GAAP financial measures such as adjusted EBITDA. Please see our 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. Thanks, Nicole. Good morning, everyone. The second quarter was a little bumpy as we witnessed a higher concentration of repairs and maintenance expense, specifically in our Canadian business unit, as rigs came off their busy winter programs with work scheduled for right after breakup. In addition, we had a few rigs come down unexpectedly in Latin America due to OFAC sanctions, which negatively impacted the end of the second quarter. Generally, though, we continued to deliver through the second quarter, executing on key points, those being we further reduced debt in the quarter, and we expect to deliver on the CAD 600 million debt reduction we targeted by the end of 2025. We held a tight rein on maintenance CapEx through the quarter, aligning with the challenging macro environment. We grew our market share in Canada by 3%, whilst industry was down 9%. We maintained market share in the U.S., in a market where industry activity dropped off 4%. At the very end of the second quarter, we transferred out of Canada one of our largest rigs, an ADR 3000, down into Wyoming for a major on a long-term contract there. Our Middle East team successfully closed the deal for two additional ADRs in Oman with a major on a five-year deal where the operator sponsored the upgrade and reactivation costs. We continue to expand our drilling technology solutions at penetration by 25% year-over-year, and we ended the quarter with our best safety performance in the company's history. Over to Mike for a financial summary of the second quarter. Over to you, Mike. Thanks, Bob. All-time oil prices and geopolitical events have reinforced producer capital discipline over the near-term, impacting certain operating regions. However, despite these short-term headwinds, the outlook for oil field services is relatively constructive and has supported steady activity in several other regions. Overall, operating days were slightly down in the second quarter of 2025 in comparison to the second quarter of 2024. The company saw a 1% increase in the United States to 2,943 operating days and a 2% increase in Canada to 2,494 operating days. The offsetting increase was a 14% decrease internationally to 1,081 operating days. For the first six months ended June 30, 2025, overall operating days declined, with the United States recording a 5% decrease and international recording a 13% decrease in operating days. Offsetting the decrease was a 5% increase in our Canadian operating days when compared to the same period, 2024. The company generated revenue of CAD 372.4 million in the second quarter of 2025, a 5% decrease compared to revenue of CAD 391.8 million generated in the second quarter of the prior year. For the six months ended June 30, 2025, the company generated revenue of CAD 808.9 million, a 2% decrease compared to revenue of CAD 823.1 million generated in the same period of 2024. Adjusted EBITDA for the second quarter of 2025 was CAD 81.4 million, 19% lower than adjusted EBITDA of CAD 100.2 million in the second quarter of 2024. Adjusted EBITDA for the first six months ended June 30, 2025, totaled CAD 183.7 million, 16% lower than adjusted EBITDA of CAD 217.7 million generated in the same period of 2024. The 2025 decrease in adjusted EBITDA was primarily a result of lower revenue rates and one-time expenses related to activating, deactivating, and moving drilling rigs. Offsetting the decrease in adjusted EBITDA was a favorable foreign exchange translation on USD denominated earnings. Depreciation expense in the first six months of 2025 was CAD 164.7 million, a decrease of 4% compared to CAD 170.8 million in the first six months of 2024. General and administrative expenses in the second quarter of 2025 were 17% lower than the second quarter of 2024. G&A expenses decreased primarily as a result of non-recurring expenses incurred in the prior year. Offsetting the decrease was annual wage increases and the negative translation of converting USD denominated expenses. Interest expense decreased by 27% to CAD 18.6 million from CAD 25.5 million. The decrease is a result of lower debt levels and effective interest rates. During the second quarter of 2025, CAD 19.7 million in debt was repaid, and a total of CAD 42.9 million was repaid during the first half of 2025. The company is on track to achieve its stated debt reduction target of CAD 600 million from the period beginning 2023 to the end of 2025. The remaining amount of debt to be repaid to achieve this target is CAD 119.8 million. If industry conditions change, this target could be increased or decreased. Total debt net of cash has decreased CAD 68.5 million during the first half of 2025 due to debt repayments and foreign exchange translation of converting USD denominated debt. Net purchases of property equipment for the second quarter of 2025 totaled CAD 49.2 million, consisting of CAD 13.3 million in upgrade capital and CAD 37.4 million in maintenance capital, offset by disposition proceeds of CAD 1.5 million. Our 2025 maintenance CapEx budget is set at approximately CAD 154 million and selective upgrade capital of CAD 30.5 million, of which CAD 19.0 million is customer funded. The increase in upgrade capital expenditures in 2025 is due to a recently awarded five-year contract for two rigs in the company's Oman operating region, as well as a rig being relocated from Canada to the United States. On that note, I'll pass the call back to Bob. Hey, thanks, Mike. I'll start with an operational update. As mentioned earlier, we have seen a slow climb out of the Canadian breakup as a result of the heavy rains. Globally today, we sit with 95 drill rigs and 34 well servicing rigs active. We will be increasing rig count and rig a week globally through into the fourth quarter and expect to hit roughly 105 drill rigs by the end of the year. In our well servicing group, we expect to see an increase in our rig count there from 45 currently to 55 well servicing rigs by year end. Let's focus specifically on Canada for a moment. Our Canadian drilling team, which operates a high-spec fleet of 86 rigs, continues to gain market share quarter-over-quarter and year-over-year with a 3% increase in market share, again while industry saw a 9% drop. We hit a peak of 55 rigs in the first quarter and peaked at 34 rigs over breakup, a 50% increase over breakup from last year. Today we sit having exited breakup with 48 active today with contract visibility to 50 + in the third quarter. Over breakup, we had five of our ADR high-spec super singles, which are fully booked in the shop for repairs and recertification, which pushed the R&M expense up for the quarters, as I mentioned before. We typically don't see that many ADRs coming into the shop at once, but because they all have immediate work to go to, it was urgent that they be cycled through the shop quickly while breakup was upon us. Over breakup, we also upgraded a couple of our high-spec super single ADRs to higher capacity units and tied them up on two-year contracts to feed the very active Clearwater Mandeville play. We're also seeing operators already contract their preferred rigs out up to two years into spring of 2027, with rates in the high 30s. Those would be the high-spec triples, of course. Our fleet of roughly 20 high-spec triples in Canada are expected to be fully booked through the winter of 2026, and we have roughly 95% of the high-spec single fleet booked through into the second quarter of 2026, with some contracts taking us into 2027. The high-spec single ADR market has really tightened up for us. We have a few more idle ADRs that can be upgraded to fill into this need. Of course, we continue to look for multi-year contracts and rates of those rigs into the mid to high 20s all in. Notwithstanding, day rates remain well below any new build metrics. Rates need to be in the CAD 50,000s, high CAD 50,000s, before we will see new build super spec triples. For the high-spec singles and high-spec doubles, rates need to be in the very high CAD 30,000s before investment could be made in new builds with a reasonable rate of return. We are also seeing continual growing interest in our EDGE AUTOPILOT in our Canadian business unit, with specific apps such as the automated drill system, which we call the ADS, which charges out at CAD 1,000 a day, and soon our Auto Driller Max, which provides higher penetration rate increases, will be finished its beta testing in the U.S. and is about to start beta testing in Canada next month. That provides upside of about a CAD 1,500 a day margin at the rig level. Our well servicing business in Canada, which operates a fleet of 41 well servicing rigs, including cement rigs and an automated well servicing rig, which we call our ASR, had an active breakup with roughly 11 rigs operating. The OWA work is starting to get going again, which will provide visibility to 19 well servicing rigs running at the end of the third quarter. Our rental fleet of tubulars, tanks, and other high margin ancillary equipment continues to grow as more and more specialty equipment is called for, usually high torque tubulars to attach to our high-spec ADR drilling rigs. Moving to international, we have a fleet of 26 drill rigs that operate in six different countries around the globe, of which 11 are under contract and active today. In the Middle East, we have 90% of our high-spec ADR fleet actively engaged on long-term contracts, and with half of them on PBI contracts now, we are able to get paid for the performance our high-performance drilling team provides when coupled with our EDGE AUTOPILOT drill rig control systems. We have three rigs currently active on our long-term contracts in Oman. As pointed out earlier, our Middle East team successfully negotiated a five-year contract with a major to reactivate and upgrade two of our ADRs in the country. The first of these two rigs should get on the payroll in December, with the second not far behind in January 2026. In Argentina, we had one of our two rigs come down right at the beginning of the third quarter for some unplanned repairs, and we fully anticipate that rig to be back up and running in mid-September. We see a building market for our high-spec 2,000 hp rigs in this area. We had two rigs active in Venezuela through most of the second quarter, only to see OFAC shut everything down on May 27. There were some costs that hit the second quarter related to the shutdown, along with the loss of a month of revenue on the two rigs, which negatively impacted second quarter results. We are awaiting instructions from our client as to the current OFAC directive, which suggests release and startup potentially in mid-September. We'll wait and see what transpires. Australia seems to be stuck in neutral as we currently still only have four of our 13 rigs in the country active today. We have a line of sight on one, possibly two going back to work early fourth quarter. Moving to the United States, we have a fleet of 72 high-spec ADRs in the U.S., stretching from the California market into the Rockies and main focus back down in the Permian. We have held market share through the second quarter and sit at, give or take, 7% today, while industry fell off, or, I'm sorry, 4% in the quarter. We are sitting at 37 rigs today active, and we are expecting to add a few rigs to this count between now and the end of the year. It's interesting to start hearing from operators that the geologic headwinds are stronger than the tailwinds from technology and operational efficiency gains of the last five years. When we look at the generally flat production output of the U.S. over the last few years and the flattish rig count and low debt count over that same period, and putting that last statement into context, more rigs will need to start coming back on if the goal is to hold production. Our U.S. business unit continues to expand its PBI contract base and now has over half the fleet on a PBI contract to some degree that builds off our high performance and highly trained field teams, coupled with our EDGE AUTOPILOT drill rig control system technology. Not only do we get a superior rate for our EDGE AUTOPILOT technology, we capture the upside value generated to the operator through performance metrics. Everybody wins. The operator delivers ball bores for lower costs, and we help de-risk that with our PBI contract form at higher margins. Our U.S. business unit, our well servicing business unit specifically, is focused primarily on the Rockies and California well servicing market, and they continue to enjoy high utilization north of 70%, and they delivered a quarter slightly below expectations due to temporarily reduced activity in those areas, although we are seeing some signs of positive activity growth in California, if one can imagine that. Our directional drilling business, which is essentially a mud motor rental business that utilizes proprietary technology, continues to provide some of the best motors with high quality rebuilds and the longest runs in the Rockies. We're expecting another solid year in that business unit. Going to our technology suite, our EDGE AUTOPILOT drilling rig control system. In our last call, we reported that we successfully beta tested our Ensign EDGE ATC auto two-phase control in conjunction with a directional guidance system. This paves the way for seamless control of automated directional drilling from those operators who utilize remote operating centers and utilize in-house DGS systems. I'm happy to report that we're now commercial with our EDGE ATC and are charging that on four rigs today with the possibility of placing that on a fifth rig for the same operator. We also continue the beta testing of our enhanced auto driller called the Auto Driller Max, which will further increase P rates and be charged out with a base daily rate of CAD 1,000 a day, plus a variable per meter or per foot cost, so that we can start capturing the upside in the cost and operational efficiencies that our technology enhancements provide. We continue to grow and deploy EDGE AUTOPILOT onto our active rigs across the globe with a 25% year-over-year growth rate. This high-tech component of our business continues to grow at a rapid pace and with 100% efficacy, with reduced bulk times and increased P rates, it helps differentiate Ensign from our competitors. With that, I'll turn it back to the operator for questions. Thank you, and ladies and gentlemen, we will now begin the question and answer session. To ask a question, you may press star followed by the number one on your telephone keypad. If you're using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star followed by the number two. Once again, please press star one to ask a question. Your first question comes from the line of Aaron MacNeil with TD Cowen. Please go ahead. Hey, morning all. Thanks for taking my questions. I noticed that many of the contracts currently in portfolio are shorter duration in nature, which I'm sure is also typical of your peers. I just wanted to focus on the U.S. market. Can you speak to contract churn, pricing dynamics, and ultimately what your strategy is here in terms of whether you're prioritizing price or utilization? Right. It's, yeah, we've got a couple of things, a couple of dynamics happening globally. We increased our forward contract book by approximately CAD 250 million over our last call. We now have close to CAD 1 billion of forward revenue booked under contract. Now, we break that down into segments. To your question specifically on the U.S., I would suggest that the U.S. is probably engaged more in six-month contracts, which is fine. We start to see when operators in troughs start to ask for longer-term contracts. That's when we start to sense that they feel that the market has troughed out. We're starting to get to the edge of that. We're probably maybe a few months away from that firming up a little bit more. Generally, most of our contracts, we've been able to hang on and gain market share again while industry has dropped by going and doing one or two wells for different people. Our client base has expanded. We've also expanded our rig count with a couple of majors as well on top of that. I would say the macro in the U.S. is still a very competitive market, but it feels like we're not having to drop the price like we had in the first half of the year. Makes sense. Maybe one for Mike. Do you see any issues as it relates to your sort of regular cadence of step-downs on the credit facility, or are you sort of happy with the progression there? Is debt reduction still the target once you hit your CAD 600 million goal? Yeah, the cadence we're quite happy with. I mean, we made the adjustment back in Q1. Of course, the step-downs into Q3 and Q4 as well. We're happy with that, how that's progressing. As to what happens after a CAD 600 million target, I think we'll continue to de-leverage. I mean, our debt to EBITDA ratio is getting better and better, and it should be 2x in 2026. We'll continue to, I think, continue to de-leverage. When you look at opportunities to deploy capital in the industry right now, the best deployment's probably towards the balance sheet, as we see it right now. We'll continue focusing on that. Great. Thanks, everyone. I'll turn it back. Thanks, Aaron. Your next question comes from the line of Keith Mackey with RBC. Please go ahead. Hey, good morning. Bob, can you just take us around some of the international regions a little bit more? I know that you added a couple of contracts in Oman, but there certainly are some areas where your rigs, I would say, are underutilized. Can you just talk through what you're seeing over the next six months in terms of tendering and potential activity that might get the regions to be a little bit more normalized? Do you think that there certainly are some areas that will just do better than others over the next 6- 12 months? Yeah, yeah. Let's start with Argentina. As I mentioned, we had some unplanned repairs on a rig there that shut us down for a few months, back up and running here mid-September. You'll see that, with some talk of a third rig, perhaps coming into that area in 2026. Venezuela is, I can only talk to what we know today, because that may change tomorrow. That's, you know, plus or minus two rigs. When the rigs are running, we make good money. When the rigs are not running, we have a few costs that we go down to a minimal skeleton crew there to keep things going. Shifting into the Middle East, Bahrain, we have one of the two rigs down. It's being bid out to a couple of places right now in the Middle East, with probably high success rate that that rig goes back to work in the fourth quarter. Oman, we touched on all of our rigs in Oman are currently busy, and we're adding two more, and that was operator-funded upgrades and a five-year contract generating over CAD 120 million of revenue over its term. Australia's challenge. Australia seems to have some overcapacity, and although the bid activity was a little rapid in the last quarter, it seems to have settled off again. A lot of tire kicking, but Australia is our focus area for improvement for sure. Got it. Understood. Kuwait, just to finish the lap, Kuwait is, we've got our two rigs recontracted well into 2026 and talk of that going even further. Kuwait is, those two big rigs are just cranking along. Got it. You touched on it a little bit in the last question, I think, but your U.S. outlook is relatively, I would say, constructive for the back half of the year with rig count increasing. We certainly are seeing a bit of divergence amongst operators in terms of rig counts in the next couple of quarters. Can you just talk about what's driving your expectations to increase your U.S. rig count over the back half of the year? Yeah, we've got a couple of increases with a couple of our major accounts. We're finding that operators are continuing to take the opportunity to high-grade their fleet. You probably saw the Enverus report of the 25 top rigs in all of the United States. Ensign has 12 of the top 25. We get to sweat into that benefit. We're also seeing California. Newsom has suggested that if you cap a couple of wells, you can go drill a well. That will help us on both the well service and the drilling side as well. We're already starting to see some chatter of increased activity there. We think we'll be adding a couple of rigs between now and the end of the year in our California business unit as well. Plus, as we mentioned, we're seeing Wyoming get busy for the big rigs. These are our 3,000 hp rigs. We transferred one from Canada, which had been down over five years, down to the U.S. I don't think there's going to be a rapid migration. First of all, that one's the biggest rig in Canada. There's not very many of those types of rigs, and those are CAD 60+ million rigs to go build. That kind of manifests itself into the comment where we see us building up one or two rigs from now to the end of the year. Got it. Okay. Super helpful. That's it for me. Thanks very much. Thanks, Keith. Your next question comes from the line of Waqar Syed with ATB Capital Markets. Please go ahead. Good morning. Bob or Mike, you mentioned that the margins were impacted in Q2 because of some of the payers and maintenance costs. Is there a way to quantify the impact, the cost impact on margins? That's probably, I mean, 200 basis points maybe. I feel like at Q1, our margins were about 23.45%. We're sitting at 21.84%. Yeah, I'd probably say around 200 basis points. Okay, you expect them to go back to that 23%, 23%- 24% kind of level in Q3? As activity starts to pick up, we believe that's where they should be probably headed towards. Okay. That's right. Sounds good. Bob, on the drilling rig pricing side, day rate side, are you seeing stability? For your own fleet, do you see that this big 3,000 hp rig, once this starts working, does it move the needle on average day rates for the U.S., or is it just on the margins, some positive impact? Yeah, I think that 3,000 hp rig is maybe perhaps a little unique because of its rig type. The answer lies in the rig types because the super spec triples that can rack 30,000 ft of pipe are generally hanging on to prices. We're in the, you know, all in, we're in the lower CAD 30,000s. In Canada, same situation. The high-spec triples, we're quickly running out of them into the winter of 2026. We've got a couple of clients going after one rig, so pricing opportunity there. We're in the mid-CAD 30,000s, all in, easily with those. Now we're starting to look for term. This is what we just started introducing in the last couple of weeks, an operator group that are willing to accept that conversation as well. The high-spec triples, yes. I would say stable pricing in the U.S. In Canada, I would say stable to slightly upward pricing. On the high-spec singles, same situation. In Canada, of course, the high-spec singles in the U.S. aren't as a dynamic rig type demand as it is in Canada. In Canada, we're basically sold out of our high-spec singles. They're in the low to mid-CAD 20,000s. We've got a couple more rigs that we basically call our idle rigs that have been cold stacked, that aren't part of our active fleet that could be upgraded for not a lot of capital. We'd be looking for the operator to either fund that or to give us a longer-term contract where we see payout of our capital within a year. Again, being conscious of our debt reduction targets continuing into the future. That's continuing to be our goal. Hold maintenance CapEx and growth CapEx, of course, we look to be funded by the operator or paid for within one year at EBITDA. That's kind of the marching order. On doubles, of course, we don't have that many in the U.S. We've got a few singles, conventional singles in California that still work, and they still generate positive EBITDA quite nicely. In Canada, the conventional doubles and conventional singles are a very, very competitive market. There's some smaller players that are trying to hang on to business, but that's a very small part of our EBITDA proportion in Canada. The rest of the world, I could touch on that if you want, but I think you know the metrics there. That makes sense. Just on the Canadian market with this Canada LNG now up and running, that creates some incremental demand for natural gas. On the other hand, storage is pretty full in Canada for natural gas. When do you see the start of the project having an impact on activity of natural gas drilling activity? Yeah, good question. I think that, I mean, gas is a very scalable product in the area that we drill. I mean, they know what they can get out of every well that they want to add if they add it to your point. There is some backup there. I think the bigger question is, when does the second pipeline come? You know, that would be at least three years out. I see the demand starting maybe in 2027 for that type of construct, for LNG. I'm seeing our demand on the high-spec triples in 2026 and through the rest of 2026 as not being directly related to that comment you made about LNG growth. I see that's further down the road. That's good. Thank you very much. I appreciate all the comments. Thanks, Waqar. If you would like to ask a question, simply press star one on your telephone keypad. Your next question comes from the line of John Gibson with BMO Capital Markets. Please go ahead. Morning all. Just had one on debt repayment here. Obviously, you've done a really good job of meeting your targets over the past few years, but the cadence of repayment appears to have slowed here in the first half of the year. I'm just wondering, maybe can you walk through some of the puts and takes to get you to that CAD 600 million number by year end, just as we're thinking about the back half of the year? Yeah, it's about CAD 120 million left of that goal to be achieved. We have about CAD 105 million of mandatory repayments with the term loan as well as the step-down. When we look at activity, working capital, and the additional factors on the balance sheet, we're confident with that step-down and with that target. Like I said, things could change drastically. I mean, if the industry, if CAD 50 oil hits us and something like that in Q3, Q4, that target could definitely be down a little bit. From what we see right now, we're confident. I think we're going to get those. We look at the interest expense. I mean, it continues to decline. We're running about CAD 18 million a quarter, which was down from CAD 20 million in Q1, down from CAD 25 million in Q2 2024. The operations do decline a bit. We do have a bit of a pickup just with the interest rate deductions and reductions that we've seen, as well as the debt reductions over the last couple of years, helped generate some free cash flow. Okay, great. I'll turn it back. I appreciate the response. Thanks. Great. Thank you. I'm showing no further questions at this time. I would like to turn it back to Bob Geddes, President and COO, for closing remarks. Thanks for joining the call this morning. Let me just close out by saying the last few months have been a roller coaster with the global markets unsettled with tariff negotiations. Looking forward, we continue to execute the plan of reducing debt whilst delivering the highest performing operations safely around the world. We increased our forward contract book by roughly CAD 250 million and now have close to a billion dollars of forward revenue booked under contract. With that, we expect to continue the steady run rate of 100- 105 Ensign drill rigs and roughly 50- 55 well service rigs operating daily both sides of the border. One third of our drill rigs under contract are on long-term contracts with contract tenure of about one year, and roughly 30% of those contracts are on a performance-based contract base. With that, we have excellent visibility for sustained free cash flow with consistent margins, a very predictable maintenance CapEx plan, and expected redundant real estate disposals in 2025, all of which will provide the ability to continue executing on our debt reduction plan of clipping off CAD 600 million over the three-year period ending 2025. Again, the focus continues to be to maintain our debt reduction goals into some short-term headwinds for the drilling and well servicing business globally. I'd like to thank our highly professional crews and all of our employees in the field, along with our customers, for helping Ensign achieve the performance and industry-leading milestones that industry recognizes us for. Look forward to our next call in three months' time. Stay safe. Thank you for joining us. Ladies and gentlemen, this concludes today's conference call. Thank you all for attending. You may now disconnect.