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Good morning, ladies and gentlemen. Welcome to the High Arctic Energy Services 2021 Q1 Results Conference Call. I would now like to turn the meeting over to Mike Maguire. Please go ahead, Mr. Maguire.
Thank you, and good morning to everybody. Welcome to High Arctic's first quarter conference call. Today, I'll be providing an update on the press release we issued after market last night, Thursday, May 13. And following my remarks, Lance Mierendorf, who's filling Chief Financial Officer duties on an interim basis, will be joining us to discuss our financial performance for the period. After our formal comments, we'll open the call to answer questions. Before we begin, I'd like to remind you that certain information presented today may include forward-looking statements. Such statements reflect High Arctic's current expectations, estimates, projections and assumptions. These forward-looking statements are not guarantees of future performance, and are subject to certain risks, which could cause actual performance and financial results to vary materially from those contemplated in the forward-looking statements. For additional information on these risks, please take a look at our annual information form under the heading of Risk Factors. And with that, we'll begin. We navigated the difficult past 12 months with a keen focus on safe and effective operations and maintaining our reputation for superior quality service. High Arctic is emerging from the global crisis with a strong balance sheet and is positioned well to drive the improved market conditions with which 2021 has begun. With oil and gas prices having sustained a return to pre-pandemic levels, we find our customer bases considering opportunities to expand their business activities. Sequential quarterly increases in utilization of our services in Canada has been achieved, and I believe we're well placed for high potential growth in the Canadian -- as the Canadian market strengthens. Since that we've withstood the depths of the economic lows, driven by last year's oil supply crisis and ongoing health pandemic, so High Arctic returned to the bank the $10 million of debt we drew in our facility last year as a precautionary measure, which reflected our history of conservative financial management. In PNG, a COVID-19 case spike that occurred in March put stop to almost all our activities during the quarter, resulting in a short-term drain on our earnings as we continue with our equipment preservation efforts to maintain operational readiness. We expect to benefit from this readiness later in 2021 as government and industry COVID prevention strategies take hold, travel restrictions are relaxed and business activities increase. In addition, we were recently reminded by Total Energies and the Papua New Guinean government of the importance of the Papua LNG project to both the project JV partners and the people of Papua New Guinea when they announced remobilization to complete project pre-feed, which is a key step on the pathway to a final investment decision. It's my belief that High Arctic's commitment to PNG will, in time, provide significant upside for our shareholders. In the quarter, we saw across the board utilization increases in our Canadian Production Services segment, where our Concord Well Servicing fleet utilization rose to 48% in the quarter versus industry utilization of 39%, representing an increased utilization of 10% over the previous quarter. And our High Arctic snubbing fleet utilization increased 18% and our nitrogen fleet utilization rose 25% on the previous quarter. A key achievement for High Arctic in this quarter has been the finalization of work on a practical process to convert existing Concord Well Servicing rigs to a reliable, efficient and inexpensive electric drive. We're very pleased to announce that patent is pending on the design, and we plan to identify industry partners to further test the technology this year. We see tremendous opportunity for deployment in Western Canada, particularly in thermal well applications where existing supply of electrical power of adequate capacity is already available. Crucially, at this stage of development, the upgraded service rig maintains its ability to self-propel down the highway. The upgrade is estimated to reduce carbon dioxide emissions of a well service rig when over the wellbore by more than 35% compared to current diesel-powered rigs. And with that introduction, now I'd like to pass the call over to Lance to discuss our financial results in more detail.
Thank you, Mike. As Mike said, I'll discuss the key highlights during the quarter for High Arctic. In the first quarter of 2021, High Arctic continued to see the benefits from our continued focus on overhead cost reductions and improvements in operational efficiencies. On a consolidated basis, high Arctic generated $800,000 of adjusted EBITDA during the quarter which is marginally lower than the $1.2 million generated in Q4 and is approximately 1/3 of the $2.7 million of adjusted EBITDA in Q1 2020. High Arctic accessed $900,000 of various government subsidies during the quarter and continues to monitor and apply for programs where eligibility criteria are met. Revenue in our Production Services division increased 12% over Q4 to $15.4 million but declined approximately 30% compared to Q1 2020 when the negative impacts of COVID-19 pandemic had yet to take hold. A concerted focus on cost control throughout 2020 without compromising the quality of our services, led to improved oilfield service operating margins. We achieved margins of 14.3% or $2.2 million during the quarter compared to 6.9% or $1.5 million during the first quarter of 2020. While downward pressure on pricing is abating as industry conditions gradually improve, hourly revenue has only marginally been experienced below the comparable period in 2020. The company's Canadian well service rigs generated $12.7 million in revenue on 21,120 hours with an average revenue per hour rate of $600. Our average fleet of 49 registered Concord service rigs achieved 48% utilization in the quarter, versus a 39% utilization rate generated by CAODC-registered rigs. Cost reduction initiatives and government CEWS wage subsidy combined to generate operating margins of $1.9 million or 15% of revenue in the quarter. Canadian snubbing service operating hours decreased by 21% compared to the pre-pandemic Q1 2020 to 2,009 hours in the first quarter. Recently, we experienced high quarter-over-quarter activity as the steady -- steadily increasing gas well completion work takes hold within an overall improving business environment. Q1 snubbing services were 18% higher compared to Q4, while revenue reached $2.7 million during the first quarter. Due to continued challenging market conditions in target areas in the United States, our activities remain idle in our U.S. operations and expenditures are being maintained at a minimum level. Moving to the Ancillary Services segment, revenue increased to 2.1 million -- $2.2 million, sorry, in Q1, up from $1.7 million in the fourth quarter but well below the $4.5 million achieved in Q1 2020. The decline was largely driven by a reduction in wellsite work activity, and in particular, in wellsite associated rentals in Papua New Guinea, including a contraction in wellsite matting needs. Operating margins as a percentage of revenue reached 50% compared to 58% in the first quarter of 2020. Revenue for our Drilling Services segment continues to be impacted by the ongoing cessation of drilling activity in Papua New Guinea, thus limiting our revenue potential to minor services related only to critical activities. The rigs 103, 104, 115 and 116, all remains cold stacked during the quarter, whereas the first quarter of 2020, rigs 103 and 104 were operational. On a consolidated basis, general and administrative expenses declined 46% to $2.5 million in the quarter versus $4.6 million in the first quarter of 2020. The overall decrease of $2.1 million is mainly due to reduced compensation costs as a result of the targeted reduction in corporate administration personnel that took place over the past 12 months. In addition, CEWS government support reduced G&A by $0.1 million during the quarter. As reflected in the reduction in G&A, High Arctic remains committed to ensuring these costs are maintained and balanced within the overall strategic plan of the corporation. The lower -- the low -- sorry, excuse me, the lower level of operational activity led the company to incur a consolidated net loss of $5.2 million or $0.11 per share during the quarter compared to a loss of $2.2 million or $0.04 in the comparable quarter in 2020. Decreased tax expense was mainly associated with a decrease in withholding taxes related to our intercompany dividends as well as decreases in deferred income tax recoveries. We continue to maintain a strong balance sheet and exited the quarter with $21 million of cash on hand and a working capital ratio of 4:1. During the quarter, the company repaid its outstanding balance of $10 million which was drawn on the $45 million debt facility, which was recently extended to August 2023 on favorable terms. Funds provided from operations were $400,000 in the quarter, while capital expenditures were limited to only $800,000 in the quarter. With that, I'll turn it back over to Mike.
Well, thanks very much, Lance. The rally in oil and gas prices in markets around the world continued throughout the first quarter of '21, despite some challenges and the price rally continues to this date. Benchmark indices, including Brent and WTI, the Western Canadian Select, JKM LNG, Henry Hub and the Alberta Natural Gas, all reach peaks not seen since pre-pandemic period in Q1 2020 and have been recently trading in elevated stable bands. Utilization of High Arctic services in Canada has continued to rise through the quarter as our customers sought to raise their production. To date, producers have been conservative with their capital, with many prioritizing balance sheet improvement over capital investment. But the prospect of sustained commodity prices has High Arctic expecting further increases in demand for our services throughout the rest of the year. In the U.S., COVID-19 infection rates have slowed markedly as vaccinated populations grow. There are strong indications of economic recovery there that buoyed both consumer and capital markets. In Canada, as vaccination rates climb, a relaxation of social and economic restrictions are expected to take place with the corresponding improvement in business and travel confidence. In turn, this should drive increases in domestic energy demand during the second half of 2021 and beyond, matching the current momentum we see in the U.S., who still remain the largest buyer of exported Western Canadian crude oil products. High Arctic has already seen a busier second quarter in 2021 here in Canada, following an early spring breakup, and we are seeing improved interest in our services. In Papua New Guinea, the recent spike in COVID-19 cases has seen travel bans imposed by near neighbor countries, particularly Australia. The Australian travel ban has the result of shutting down the primary source of skilled expatriate PNG workers. The result for High Arctic has been a continuation of the cessation of all drilling and exploration activity and the deferral of our customers' nonessential plant and maintenance and project activity. Reliable travel routes to PNG are essential for projects to recommence. High Arctic has taken steps to ensure that our capability as the specialist PNG energy services contractor will be preserved. We maintain regular dialogue with our customers, employees and industry and government representatives. We expect a modest return to work later in 2021 as the COVID-19 prevention strategies take hold and are optimistic of more meaningful activity increases in the medium to longer term. Last week's announcement by Total Energies and the PNG government on the remobilization of Papua LNG project teams and other required resources to complete project pre-feed on the pathway to a final investment decision, follows others from the PNG government in recent months that indicate a change in tone towards both foreign investment and resource projects and the importance of LNG expansion to the people of PNG. That concludes my comments. I'll now turn the conference over to Roxanne, who will open the line for questions.
[Operator Instructions]We will take the first question.
Josef Schachte. 2 areas for me. One, in terms of the outlook for business later in Canada for the service rigs, the snubbing units, et cetera. Have you been in discussion with clients? And do you see a meaningful pickup? And where do you see it? Is it more related to activity and in terms of service rig activity for thermal oil? Or are you seeing more in terms of the natural gas side? And then the second question is, given your comments about Papua New Guinea, maybe pickup a little bit in later the year because of COVID. When do you see really the activity picking up for drilling? Is it going to take into 2023 for the FID? Or do you see people looking to start drilling to get gas ready before that?
Excellent. Thanks, Josef, and thanks for joining us on the call today. I'll start with the first question, Canadian service rigs. Yes, we have been in discussion with our customers. And we are expecting, in general, across the board continuation of activity, both in the thermal and heavy oil where we have a substantive presence. And in gas, we see the gas market improving in the Montney area and the Deep Basin, Clearwater. We're expecting increases in activity out of which we would operate out of our central facility at Acheson, just west of Edmonton. And we also expect to see continued activity from the site reclamation programs. In Q1, we achieved 11% of our activity from the SRP programs, and we expect that to continue to increase through the year. I hope that addresses the first question. I'll move to the PNG question. PNG, it's always a good question, not always a straightforward answer, complicated place to do business. Our expectation at this point in time is to start to see a return to some drilling activity early next year. We would not expect it to be substantive until the following year as the lead times associated with projects in PNG will require a substantive forward-period customers to prepare. But we are in discussions with our customers there, and customers are talking about drilling.
Okay. Going to the first part of it that I was asking about. In terms of pricing, how far do you see utilization rates having to go up before pricing power will start coming back? When you talk to people in the frac side, they said, they don't get rates higher than they are. They're not going to bring back fleets. And anybody who wants to meet pricing at lower levels, they'll stack their -- they will bring them back into the yard. Is there a certain level where you start seeing pricing improving for service rigs and snubbing rigs? And how far does that utilization rate have to get before you see some upside there?
Yes. Good questions, again. So I see rate increases commencing almost immediately. But the first rate increases is going to be about compensation at a higher rate to compensate the workers in our sector. People are already becoming a constraint to activity, although to date, High Arctic has not experienced any substantive effects of that. But we've -- we, along with our colleagues or our peers in the CAODC, are lifting our rates for our workers at the beginning of June. And those first increases will end up in the pockets of our employees and won't be any material benefit to the contractor. Coming to the point you make. Yes, we agree that current rates will not support the investment in equipment required to return long-idled and hour-out equipment back into service. Expect that the utilization rates are going to have to increase, only a small amount until we get to that point across the sector. I could only speculate as to what that amount is, but I would -- I'd be speculating towards the 10% to 15%, not towards the 60% to 80% range. I hope that's helpful.
Yes. One more for me, if I can. M&A activity, do you see any possibilities of tuck-under acquisitions within your core businesses? Do you see any distressed opportunities where some -- where privates may want to have a public entity and some liquidity to their investment?
Yes. We've actually said, I think, in our last call as well that we expect to see more movement in this space in the energy services sector, having followed now 6 months of consolidation amongst our customer base. We have not seen that level of desperation yet or significant financial distress that has presented obvious tuck-in opportunities. We have looked at acquisitions, and we -- but we certainly haven't been able to conclude -- close any. And I do believe that part of the story as to why that's not occurring is about government subsidies. While the subsidies are in place, I think that many companies are hoping to continue to operate through what is still a depressed market compared to what it was pre-pandemic and compared to what it was prior to pre-'15 downturn and hoping to come out the other side of it and trade their way into better condition. We still have our eyes on potential acquisitions. We still think the market will have -- will be of a condition which would led itself to support the underlying theory of further consolidation in the energy services sector, and we expect to play a role in that.
[Operator Instructions] We will take the next question.
Tim Monachello with ATB Capital Markets. My question just revolves around the electric service rig opportunity that you guys are pursuing. I'm curious, what do you think the implementation cost per rig would be. And have you had any conversations with customers around this? I'm curious how you got to the point where you started developing this internally? Is this a customer-driven initiative or is this internal on a sort of a speculative basis?
Yes. I'm glad you asked the question. We're excited to be talking about our e-rig and the current patent pending condition we have there. As far as the -- what the cost of doing it, that would be telling, and I think that maybe I'd rather keep that in my pocket for now. But we -- when we're looking at the second part of your question and what has initiated it? This is something that High Arctic identified with the rise in ESG focus more than 2 years ago. Conceptually, we're discussing it through 2019. We used the period of 2020 in the lower activity then to further progress the engineering behind it. Got to a point where we had engaged with a couple of key customers on concept and the way in which we were looking to progress it. It's being favorably received by them. We progressed all the way through then to finalization, concept design and the application for patent. We expect application to mostly be dominated early in thermal oil, where having a substantive number of pumping -- electrically powered pumping units on 1 well pad means that the access to reliable electricity for service rig to tap into is already there. And recognizing that in more frontier completion activity or in the gas completion area where there's a little bit less of that pad work and a little bit -- and less reliable access that we would expect that sector would take longer for us to get rig utilization in.
Got it. Okay. And then, I guess, it's probably pretty early days here, but just to sort of follow on. One of the last questions is, like would you be willing to deploy this in the fleet on a speculative basis? Or would you need customer commitments and higher pricing, I imagine as well to sort of justify that investment?
Yes. So a couple of answers to that question. One, we see that potential savings for our customers in the reduction in diesel usage and in the -- as well as the good corporate citizen aspect of being able to report on lower emissions from well servicing activities is appealing to our customers. So we would expect that we don't need a substantive increasing pricing to justify the investment in the e-rig. Coming to the concept of contracted versus speculative. I think here in the earlier stages, it's something that's going to involve working collaboratively with customers. It's not simply a matter of just having a power source available, but ensuring that the power source available is adequate for the needs of service rig, which I think means that we're in a dialogue long before deployment and in being in that dialogue well before deployment, we'd have an expectation of the comfort that the unit will be well utilized. That may, in turn, turn towards more speculative implementation on service rigs. And given that electric power can be remotely generated, if necessary, I see little risk in that regard.
Okay. Great. And then just wondering if you could talk a little bit about the gives and takes and your expectations for timing when you should be able to be back in PNG operating?
Yes. We're encouraged at the moment that the COVID spike that led to the shutdown of travel, particularly the shutdown initiated by Australia and a couple of other countries is turned quite markedly down to less than 10% of the daily case reported at the moment than what they were back at the late part of March, early April. So we're encouraged by that, and we expect then that those governments will allow those routes to reopen again soon, albeit access to travel into Papua New Guinea is still by basis of a permission from the emergency controller there. But prior to that, to that event in late March, we were not seeing any declines on essential oil and gas workers rotating fly-in fly-out workforce. So we are expecting that, that will mean sometime in the very near future here that, that travel routes will open, customers will -- and they will be able to get people rotating back and forth into the country. We will be able to do so, too. We would expect a modest increase in activity there, very modest in the next, say, quarter. But in the latter quarter of the year, I would expect that to become a more substantive increase in activity for us. And while not back to pre-pandemic levels, I would expect it to be substantively more than what we've seen over the last couple of quarters, and we would expect that early next year, in absence of any other unexpected events, a return to some drilling activity.
[Operator Instructions] And there are no further questions registered at this time. I would like to turn the call over back to Mr. Maguire.
Thanks, Roxanne, and I'd like to thank Tim and Josef for their questions and everybody who's joined us here today. And without having any further comments, I'd like to let you know that the call is concluded.
Thank you. The conference has now ended. Please disconnect your lines at this time, and we thank you for your participation.