Good afternoon, ladies and gentlemen, and welcome to the Energy Services Second Quarter 2024 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. Instructions will be provided at that time for you to get up for a question. If anyone has any difficulties hearing the conference, please press star 0 for operator assistance at any time. I would now like to turn the conference over to Nicole Romanow, Investor Relations. Please go ahead. Thank you, Jenny. 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 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. Thanks, Nicole. Good morning, everyone. I'll provide some introductory commentary. The second quarter was one of the strongest quarters in Ensign's history, buoyed by strong and increasing demand for our Canadian rigs, especially our high-spec singles, doubles, and triples, which provided a 15% increase year-over-year for the quarter. We also saw a year-over-year increase in our highly active international business unit, where we operate in six different countries and where we saw marginal year-over-year increases in activity. In contrast, our U.S. business unit is seeing reduced activity across the board as M&A activity sorts itself out through the rest of 2024. With steady margins and solid activity levels generally around the globe, we have been able to address another CAD 80 million of debt reduction in the quarter and stay on the path to reduce CAD 600 million of debt over the next three years with a solid cash flow stream into a building book and increasing margin construct. I'll pass it over to Mike to expand on that. Thanks, Bob. Customer consolidation in the U.S. has impacted Ensign's operating and financial results over the short term. However, despite this short-term headwind, the outlook for oilfield services is constructive, and the operating environment for the oil and natural gas industry continues to support relatively steady demand for services. Overall, operating days declined in the second quarter of 2024 due to a 32% decrease in the United States to 2,912 operating days. Partially offsetting this decrease, Canadian operations recorded 2,451 operating days, an increase of 15%, and international operations recorded 1,255 days, a 1% increase compared to the second quarter of 2023. For the first six months ended June 30, 2024, overall operating days declined, with the United States recording a 32% decrease, offsetting by a 5% increase in Canada and a 9% increase in international when compared to the same period in 2023. The company generated revenue of CAD 391.8 million in the second quarter of 2024, a 9% decrease compared to revenue of CAD 432.8 million generated in the second quarter of the prior year. For the first six months ended June 30, 2024, the company generated revenue of CAD 823.1 million, a 10% decrease compared to revenue of CAD 916.8 million generated in the same period of 2023. Adjusted EBITDA for the second quarter of 2024 was CAD 100.2 million, 14% lower than adjusted EBITDA of CAD 116.6 million in the second quarter of 2023. Adjusted EBITDA for the six months ended June 30, 2024, totaled CAD 217.7 million, 11% lower than adjusted EBITDA of CAD 243.9 million generated in the same period in 2023. The decrease in 2024 is due to year-over-year declines in drilling activity. Depreciation expense for the first six months 2024 was $170.8 million, an increase of 12% compared to $152.7 million in the first six months of 2023. General and administrative expenses in the second quarter of 2024 was $15.5 million, up from $14.6 million in the second quarter of 2023. G&A expenses increased primarily as a result of the annual wage increases. Interest expense decreased by 19% to $25.5 million from $31.6 million. The decrease is the result of lower debt levels and reduced effective interest rates. During the second quarter of 2024, $78.9 million of debt was repaid, and a total of $90.3 million was repaid for the first half of 2024. From January 1, 2023, to June 30, 2024, a total of $307.9 million of debt has been repaid, leaving $292.1 million of the $600 million debt reduction target expected to be achieved by the end of 2025. Net purchases of property and equipment for the second quarter of 2024 totaled CAD 40.3 million, consisting of CAD 2.4 million in upgrade capital, CAD 46.1 million in maintenance capital, offset by a disposition proceeds of CAD 8.1 million. Gross capital expenditures for 2024 are targeted to be approximately CAD 147 million, primarily related to maintenance expenditures and selective growth projects. On that note, I'll turn the call back to Bob. Thanks, Mike. So let's start with Canada operational update. First off, we're seeing a nice macro construct building in our Canadian business unit. The combination of expanded pipeline capacity, both for oil and natural gas, the tightening differential, and with the low Canadian dollar, the net effect is that more drilling will occur in the Western Canadian Sedimentary Basin moving forward. It's safe to say that the demand for our high-spec singles and high-spec triples is at the highest it has been in quite some time, at least a decade. This has also helped to drive the high-spec double market to enjoy utilization of about 60%. 60% is a typical threshold where contractors are able to raise pricing and have it stick. Almost a third of Ensign's Canadian fleet is high-spec doubles, so we have lots of product to feed into this construct. Our fleet of high-spec singles and high-spec triples are essentially booked well into 2025, and we have some discussions going on with operators to mobilize some underutilized and fungible assets out of the U.S., where the operator will cover the full ride and any costs required to get onto their first location. We are currently already back to the same peak level we saw last winter, which rarely occurs in the Canadian market so soon after breakup. We expect to also add a few more rigs between now and year-end. As mentioned, we have almost 90% of the current active fleet contracted until the end of the first quarter of 2025, and in most cases, we have ratcheting rate increases compounding as we move through the fall season and into the winter drilling season. Our well-servicing business in Canada has a strong schedule ahead for its rigs in the heavy oil area and in the back half of the year, and is expected to pick up as we capture more of the OWA work. 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 drill rigs. With accelerated wear, an issue on tubulars as a result of their high penetration rates, it is becoming the norm for tubulars to be charged separate from the rig rate. Moving on to our international business unit, lots of exciting news in this area. We have a fleet of 30+ drill rigs that operate in six different countries around the globe. In the Middle East, we have 100% of our high-spec ADR fleet actively working on long-term contracts, and with half of them on performance-based contracts, we're able to get paid for the performance our high-performance drilling team provides when coupled with our EDGE Autopilot drill rig control systems. In Argentina, we're running at 100% utilization with both our 2,000-horsepower high-spec ADRs operating under long-term contracts. We have one of our drill rigs working in Venezuela with another ready to start up in the next month. There are obviously some daily developments in Venezuela, which are captivating the world, but so far we have seen no impact on the operation in the field. Australia is staying steady with little change. Moving to the United States, we have a fleet of 77 high-spec ADRs in the U.S., stretching from the California market up into the Rockies and with a main focus on the Permian. We operate roughly 37 rigs today and expect little change through the rest of 2024. The challenge in the U.S. is that in addition to the depressed natural gas prices, we saw $500 billion of M&A activity in the last 18 months occur, which has manifested itself into less work in the short term. The natural gas story may take a bit longer to correct itself. The good news is that we have mainly been an oil-focused driller in the U.S. market. Coming back to the effects of M&A, until the combined entities get through a budget cycle and start addressing decline rates, we don't expect solid improvements in the U.S. market until early to mid-2025. Our U.S. business unit continues to expand its PBI contract base and now has over half the fleet on a PBC contract that builds off our performance driller team, coupled with our EDGE Autopilot drilling rig control technology. Not only do we get a rate for our EDGE Autopilot technology, we capture the upside value generated to the operator through performance metrics. Our well servicing business unit, which is focused primarily on the Rockies and California well-servicing market, continues to enjoy high utilization in the upper 80s. Our directional drilling business, which is essentially a mud motor rental business, continues to provide some of the best motors with high-quality rebuilds in the Rockies. Moving on to our EDGE Autopilot drilling rig control systems, we continue to deploy EDGE Autopilot, which employs algorithms and AI on new rigs and continues to expand the EDGE Autopilot platform on each of the rigs that already have our EDGE Autopilot drilling rig control technology. This part of our business continues to grow at a rapid pace year-over-year and delivers results with reduced well times and increased Penetration rates with reduced well tortuosity. With that, I'll move to questions. Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press the star followed by the one on the touch-tone phone. You will hear a three-tone prompt acknowledging your request. Questions will be taken in the order received. Should you wish to cancel your request, please press the star followed by the two. If you are using a speakerphone, please lift the handset before pressing any keys. Once again, that is star one should you wish to ask a question. Your first question is from Aaron MacNeil from TD Cowen. Please ask your question. Hey, good morning. Thanks for taking my question. Bob, the debt repayment commitments don't leave a ton of wiggle room for growth capital. I think you've spent maybe $4 million today. In your view, are you having to turn down organic capital opportunities with good returns that your customers are asking for, or do you think you're generally keeping pace with what your customers need? Oh, yeah, no, for sure we're keeping pace. And any conversations we have the because we are drilling wells faster, the operator is willing to help invest in any upgrades in that growth CapEx side. So the market continues to absorb that conversation well. Sort of switching gears here, we've seen H&P do a big international deal and sort of indicate they may move rigs to international markets. I guess, what's your appetite to engage in that, given that you already have such a big international presence? Yeah, yeah. Well, as you know, we started that movement 20 years ago with the OD&E acquisition and have expanded that, running 30+ rigs. And we operate in six different countries outside of North America. It is a challenging business, for sure. International comes with its own interesting challenges. I would say that we've been feeding rigs out of North America. For instance, our Argentinian rigs are rigs that we bought through the Rowan acquisition that were upgraded by the client and shipped to Argentina. So we've been quietly doing this for some time. We shipped 10 ADR, smaller ADRs out of Canada when the coal seam gas fell apart, and we shipped them to Australia. So I'm glad to see another contractor understand that you need to get outside of North America. H&P is a strong, well-run company, so I'm sure they'll do well. And again, I guess maybe the better question to ask is, what's sort of the checklist that you'd have to or the wish list you'd have to go through to maybe move a rig in your fleet to an international market? And then where do you think would represent the best opportunities for the fleet? Well, that's a good question because it's a dynamic process. We look at Australia as being a pretty static business with small and steady growth as they develop natural gas into their utility grid. The Middle East is steady. Bahrain, we have two rigs. Those are well contracted. Same with Kuwait. Oman, we've got three ADRs there. One is coming down here for a short period of time. We already have another operator saying they'd like to pick it up, plus add a few more to it. So I'm not worried about when you perform, you always find work. So those rigs are continuing to work. But we're not interested in going into new countries. We are always interested in expanding our footprint in the countries we're in. That makes most sense for us. Okay. Thanks. I'll turn it back. Thanks, Aaron. Thank you. Your next question is from Waqar Syed from ATB Capital Markets. Please ask your question. Thank you for taking my question. Bob, so you mentioned that you have 37 rigs running in the U.S. right now. How does that number compare to the average in Q2? You mean in historical Q2s? Is that what your question is regarding? Yeah, that's correct. This Q2 2024, what was the average number of rigs running? In all of the U.S., is that what you mean? Yeah, yeah. We're hanging on to about 7% market share. We're down year-over-year for the quarter by about, oh gosh, 10 rigs year-over-year for the quarter in the U.S. Okay. Now, your revenues quarter-over-quarter in the U.S. were flat at around $208 million. Your rig count was down. So what's the gap? Is it all well service? Hours were up 35%. Did that kind of help the quarter-over-quarter revenue comparison, or there was something else as well? Their rates went up, or what was the cause of flat revenues? We saw the increase in well servicing. Then we also just the increase, as Bob was talking about, of drill pipe being outside the contract now. So it was some ancillary add-ons, and then well servicing would be the largest contributors to that gap. Is that sustainable into the subsequent quarters as well, Q3 and Q4? Outside of contract, there is that you're seeing revenue pickup as well as well servicing hours in Q3? For sure. Things like the drill pipe, for example, have manifested itself from the accelerated penetration rates and the use of floc water versus oil-based mud systems. In a lot of these cases, it tears drill pipe apart pretty quickly. We used to get 6-7 years out of drill pipe. We get maybe 2-3 years max out of drill pipe, in some cases less than that. And every contractor is feeling that same push. Everyone's drill pipe costs are up about 3 times what they were 5 years ago. And that's why the move to put it outside the contract to get a rate for it. In some cases, we have the operator provide the pipe, and we just manage it for them. And then we've got the other end of the extreme. We'll give them a rate as high as $8,000 a day for managing the pipe, handling the destruction, and the replacement of the pipe through the process. So it's somewhere in between. But it will continue to be a charge as we continue to have these high penetration rates in these 4-mile, 3-and-4-mile laterals. It's not going away. That makes sense. And then could you talk about asset sales? So Mike, there was a $40 million real estate portfolio that you were interested in selling. We saw $8 million of asset sales in Q2, $3 million in Q1. What should we be expecting for the second half? We're working through it. We have two properties up in Nisku that are actively marketed right now. We're working through a process in the U.S., so I would expect movement of that in Q4. Not the whole balance, but a portion of the balance I believe will be closed in Q4. Okay. That makes sense. And then the CAD 147 million CapEx number that remains unchanged, do you see anything on the horizon that could move it up or down? I think there's, I mean, with the U.S. muted activity, that will probably put, I think, a cap on some of the CapEx that was required for the U.S. But also, I mean, there's some international opportunities here and there. So for the most part, that should be fairly steady. If anything, if it does increase, it's usually tied to an EBITDA event, so net positives to the balance sheet and the income statement. So once again, if it's a positive impact, then we'll definitely look at stuff, but it should be fairly steady around there. Yeah. We won't invest in any CapEx that doesn't pay for itself in less than a one-year period. Right. That's good. And then just one final question on the pricing side in the U.S., just the data environment, what do you see right now? Well, it seems like it's bottomed. It depends on the area and the type of rig. But I would say that it feels like it's hit bottom. We've been catching the falling knife in the last quarter as the markets have moved. The Permian is still running 304, but it's not going up, but it isn't going down. So as operators merge together, of course, the first thing they do is they remove a few rigs, get to the end of the year, put together a new pro forma budget on the consolidated business, and then walk into 2025. So we kind of expected all of a sudden the activity would provide that result, so it's not a surprise. But I would say rates have stabilized at the bottom end. With drill pipe outside now and part of the total gross rig rate, we're still in the low 30s on a gross basis. Okay. And on these M&As, you've seen a number of these big mega mergers. Where do you stand with respect to your exposure to the acquirers versus the target company? Well, we're on the right side of that equation on probably 80% of our portfolio, which is a nice place to be. The other nice place to be is to have industry reports showing Ensign is the highest penetration rate driller of the top six in the U.S. So we're in conversations with companies that are the acquirer where the acquiree we did a lot of work for, and they're going, "Hey, we want to hang on to those rigs. That's great. Well, thank you very much. Thanks for the answers. Thanks, Waqar. Thank you. Your next question is from Keith Mackey from RBC Capital Markets. Please ask your question. Hey, thanks. Just a question about your debt repayment target. Maintain the CAD 600 million to 2025. And of course, you always note that industry conditions could move that up or down. But based on prevailing industry conditions we see now with rig counts where they are, if that stays flat from here, do you see any risk to that CAD 600 million debt repayment target? No. When we look at the interest savings year-over-year, that's starting to decrease quite a bit. I mean, it was down almost 20% year-over-year. So you have some buffer being built in on the P&L from interest savings. If activity remains sort of steady as is, your CapEx is going to remain kind of in that CAD 150 range. So consensus for 2024 is CAD 450-ish, 2025. I mean, who knows where that's going to be, ±. But when you look at that with CAD 150 in CapEx, CAD 90 or less in interest expense, there's about CAD 210 of free cash flow to go towards repayments. And then we do have some non-operational stuff like asset sales and some working capital movements to kind of aid in that. So yeah, when we look at it, I mean, if everything kind of remains steady, we foresee this being quite easily to be achievable. Yeah. Okay. Sounds good. And just a question on your—you mentioned the free cash flow number. There's also some mandatory debt repayments and liquidity reductions forthcoming. At the end of the year and into Q1 next year, if the street consensus is right, what kind of breathing room do you foresee having in terms of liquidity? We never get into specifics. I mean, we'll have ample liquidity to continue to run the business as we've had in the past, so. Fair enough. Fair enough. And just one more question on your maintenance CapEx per rig in the U.S. What approximately is that running these days? Oh, good question. We like to think of an operating rig on an annual basis requiring about $1-$1.25, depending on the type of rig it is. Got it. Is that Canadian or U.S.? That'd be U.S. For U.S. and CAD for Canadian. Yeah. Got it. Got it. Okay. Thanks very much. That's it for me. Thank you. Thank you. Once again, please press star one if you wish to ask a question. Your next question is from Josef Schachter from Schachter Energy. Please ask your question. Good morning, Bob, Mike, and Nicole. Challenging day to have your conference call given what's going on in the market. I wanted to ask a macro question. November 5th is a big day in the States, and the energy industry could have a 180 difference in terms of go-forward strategy based on what happens that day, that night. Are you getting any commentary from companies saying that we'll keep what's going on into Q4, but Q1 is up in the air depending upon the results of November 5th? That's a good question, Josef. I think that what we're seeing is the macro fundamentals of demand play out. Not to get into too much of the politics, but we saw one of the contestants suggest that they've changed their platform on fracking, and they're okay with fracking now. So we're not getting any feedback from our operators. A lot of them are saying, "We're certainly not going to accelerate drilling in the fourth quarter." And I think that's driven more so not by the election, but by, I guess, the staying with their plan to deliver shareholder return, not to accelerate CapEx, and just staying disciplined. So I don't think the election has much impact is what we're seeing. Thanks for that. That's it for me. Thank you. There are no further questions at this time. Please proceed. All right. Thank you, operator. Closing statement. Looking forward, it's an exciting time for Ensign with robust Canadian and international market fundamentals and improving long-term outlook in all of our U.S. markets and excellent visibility for sustained free cash flow with growing margins to continue executing on our debt reduction plan. With the application of EDGE Autopilot combined with an expanding performance-based contract base backed up with our superior performance drilling teams in the field, Ensign is delivering value to operators, which supports rate increases moving forward. Again, the focus continues to be accelerating debt reduction into a steadily improving construct for the drilling and well-servicing businesses globally. I'd like to thank our professional crews and our employees along with our customers for helping Ensign achieve the performance and industry-leading milestones that industry does recognize us for. I look forward to our next call in three months' time. Stay safe. Thank you. Thank you. Ladies and gentlemen, the conference has now ended. Thank you all for joining me while I'll disconnect your lines.