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Good day, ladies and gentlemen, and welcome to the High Arctic Energy Services 2022 Q1 Results Conference Call. I would now like to turn the meeting over to High Arctic's Chief Executive Officer, Mike Maguire. Please go ahead, Mr. Maguire.
Thank you, Paul, and good day to everyone. Welcome to High Arctic's First Quarter Conference Call. Today, I'll be providing an update on the press release we issued after market yesterday, May 12. Following my remarks, I will hand the call over to our Chief Financial Officer, Lance Mierendorf. Lance will be discussing our financial performance for the first quarter of 2022.
After our formal comments, we'll open the call to answer any questions that you may have. Before we begin, though, I'd like to remind you that certain information discussed 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 they 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 management discussion and analysis and the 2021 annual information form available on our website or on SEDAR where you should look under the heading Risk Factors.
While the energy roller coaster continues, the events in Ukraine continue to unfold and the sanctions against Russia are driving a substantive shift in global energy trade relationships. Then there's the continued rebound in energy demand, the inability of OPEC to meet its production quotas, shortage of skilled labor in developed economies, rising inflation, a slowdown in China, ongoing COVID-19 variations and large volumes of people clambering to travel again, just to mention some of the things that are happening right now and over the past quarter.
It's no surprise that commodity prices, the share prices of energy companies, our customers and the share prices of the companies who service them, including High Arctic, have all been volatile recently. But putting all this noise to the side, there remains the fundamental fact that substantial underinvestment in the energy sector over the past 7 years has created an energy deficit for supplying the growing global population's appetite for cooling, heating, transportation and the charging of their phones.
The sanctions imposed and under consideration against Russia has Europe rapidly moving to source supply of LNG from North America and Middle East suppliers. While Russia may find willing markets in China or in the subcontinent, the pivot by Europe creates opportunity for Oceania to increase LNG supply to the other growing Asian consumer markets, including Japan and Korea.
Papua New Guinea is ideally positioned to expand its LNG export capacity. The PNG LNG project, which commenced shipments in 2014 has derisked Papua New Guinea and established it as a supplier of choice for low cost, high quality and reliable supply of LNG. And we sure are pleased by the successful and safe return to rig operations on Rig 115 in our PNG Drilling Services segment.
The legacy exploration well was professionally capped and abandoned, fulfilling a key ESG commitment and adding to High Arctic's record of over 5 years of recordable safety incident free work in Papua New Guinea. We look forward to increasing activity there, where we anticipate activity levels in the coming years have the potential to exceed our past peaks. We expect further announcements about the advancement of the Papua LNG project and the development of P'nyang and other PNG LNG fields to support an expansion of the PNG LNG export facility among other projects to increase oil and gas production there.
In Canada, certain large infrastructure pipeline projects are positive for our oil and gas industry. Following the Enbridge Line 3 replacement project, which entered service October 1 last year, there has been an increase in export oil volumes to the U.S. The LNG Canada pipeline project and the Trans Mountain expansion, both under construction, will, upon completion, provide long-awaited tidewater access to Asian markets.
Additionally, in the near future, political focus on oil imports from countries outside North America may turn back towards the security of increased domestic supply. High Arctic's Canadian-focused Production Services segment stands to benefit from the stimulus to drilling activity that will follow. This will be through the resulting well completion work, ongoing well production maintenance and end-of-life abandonment works. The Canadian services market is severely labor constrained, a result of years of low activity with stagnant wage rates, change in generational priorities and ongoing infrequent COVID-related crew shutdowns. This crew constraint has led to increasing demand-supply imbalance.
And whilst measures are in place to respond, it will take time as both sustained utilization and better compensation unnecessary to attract personnel to our industry. Of a positive note for High Arctic, the current and projected services market imbalance has led to meaningful price increases, including the announced key contract renewal with improved pricing and more favorable terms coupled to a high volume of contracted work. High Arctic expects the pricing increases to continue throughout 2022 and into the New Year until crew supply meets demand on an industry-wide level. The challenge for us is to continue to manage the corporation's resources such that we keep a control on costs, maintain readiness to deploy and increase pricing at a rate in advance of cost inflation. I would now like to pass the call over to Lance to discuss key financial highlights from the quarter in more detail.
Thank you, Mike, and good afternoon or good morning to those listening in on the call today. While High Arctic experienced a substantial 60% increase in consolidated revenue during the quarter compared to Q1 of 2021, operating margins were slightly lower at 18.5% of revenue and the company incurred a quarterly net loss of $2.7 million, which is equivalent to $0.05 per share. A significant increase in drilling operations and the provision of rental equipment and auxiliary equipment and services to customers in Papua New Guinea increased this region's share of consolidated revenue to more than 40%, up from 10% during the Q1 of 2021. Completion of a one well abandonment program supported by [indiscernible] and High Arctic's team of operation's personnel and the subsequent rig move off location generated more than $10 million of revenue during the quarter.
Combined, drilling and auxiliary services in PNG generated approximately $3.5 million of operating profit during the period. By contrast, in Canada, there was marginally lower activity during Q1 compared to the first 3 months of 2021 in terms of revenue, well servicing and Snubbing operating hours and rig fleet utilization in the Production Services segment. High Arctic's faced several challenges during the quarter which had a noticeable impact on our ability to expand utilization of the services offered to our Canadian customers. Lingering effects of COVID-19-related rig shutdowns and isolated poor weather conditions forced several rigs to be idle for short periods of time. In addition, a shortage of field personnel to crew rigs prevented High Arctic from meeting growing customer demand and therefore stifled growth in operating hours.
Also, the company felt the emerging effects of cost pressures that started building during Q4 of 2021. Wage inflation, driven by a shortage of skilled rig hands and increases in cost of retaining staff; overtime pay; and the company bearing cost of adding personnel to fully staffed rigs for the purposes of training and creating new crews, all combined to increase field personnel expenses. Essential operating costs such as fuel, equipment and supplies have seen upward pressure from the supply chain disruptions, and we experienced onetime noncapital costs associated with repairing equipment to return to service.
Combined, these challenges reduced operating margins within our Production Services segment to 1.6% compared to 15.7% during the Q1 of 2021. The company has taken several actions to address these challenges experienced during Q1, including working alongside key customers on pricing and the impact of input cost inflation and a need for margin expansion to justify further investment in the energy services sector.
In early April, High Arctic announced that it has agreed to terms with a key customer to renew significant contract in Canada for the provision of well servicing rigs in auxiliary equipment. Key features of the renewal included a 20% increase in the base hourly rate increases to auxiliary equipment and service pricing, provision for fuel and field service adjustments, and alignment of other parameters to current market conditions. Other key customers of High Arctic are also demonstrating a willingness to address the current market conditions in a similar and collaborative manner.
Moving to auxiliary service segment. While first quarter revenue of $4.7 million represents approximately 15% of our consolidated revenue, operating margins are robust at 63%, up from 47% experienced in Q1 2021.
As I've noted earlier, activity increased in PNG in support of drilling operations, while in Canada, High Arctic saw modest improvements in the provision of nitrogen services, rental, revenues related to pressure control equipment and deployment of refurbished and upgraded catalogs to customer sites. From a consolidated perspective, general and administrative costs remained relatively flat at $2.4 million compared to Q1 2021. And this spending represented 8.5% of revenue generated during the quarter.
High Arctic remains committed to controlling costs and analyzing administrative overhead for effectiveness and efficiency while ensuring the level of support aligns with our operating activities throughout the organization. The company generated EBITDA of $2.9 million or 10% of revenue during the quarter, up substantially from $1.2 million generated in Q1 of 2021, a period during which $800,000 of government subsidies were received.
Capital spending was limited to $1.6 million during the quarter and was partially funded from $1 million of proceeds generated from ongoing sales of highly and fully depreciated and unusable property equipment. At March 31, we have maintained a strong balance sheet with $11.4 million of cash on hand and a working capital ratio of 3:1. Based on trailing 12 months EBITDA, the company has access to $16.7 million of a $37 million revolving credit facility, which remains undrawn at the quarter close -- at quarter end.
And lastly, given the current financial position and positive outlook we see for both our Canadian and PNG businesses, we reinstated a monthly dividend of $0.005 per share with payments beginning this month.
With that, I'll turn the call back over to Mike.
Thanks, Lance. Our Q1 results reflect the market inflection. Revenue per operating increment is up across our segments. Drilling Services segment results reflects the early stage of return to work in Papua New Guinea. In Production Services, weak margins reflect the commencement of pricing increases that will be more evident in the second quarter and beyond as well as some cost inflation and opportunity loss from COVID shutdowns and extreme weather events, expenditures aimed at expanding the number of deployed revenue-earning equipment packages and our ancillary services segment results demonstrate the margin growth we expect to continue through 2022 as we deploy more upgraded catalogs into services.
I'll now turn the conference call over to Paul, the operator, who will open the line for questions.
[Operator Instructions] The first question is from Josef Schachter.
Mike and Lance, a big question for me is really on the Canadian side with your comments here about the large contract renewal and upgrade in the prices. Utilization was 45% versus 48%, rates that were up to $658 an hour versus $600. Are you looking for a gradual improvement through Q2, Q3 into Q4? And are you hearing having discussions with customers that are wanting to lock in more equipment? And where in terms of the mix of work do you see the best upside for your business?
Yes. Thanks, Josef. I'll attempt to address each one of those points. So firstly, Q2 looks like being similar to last year, more active than cyclical activity of prior years where we would have seen a substantive downturn in activity levels, just the breakout period. We have seen an impact from breakup, but similar to last year, it's much more reduced. So we would expect activity levels in Q2 not to be substantively below Q1. And we expect to continue to raise pricing through this quarter, and we'll see the impact from that contract you mentioned really hitting in Q2 as it took effect from April 1 and contributing to improved margin performance in Canada.
We are seeing a change in behavior from customers more towards security of access to equipment, well servicing, snubbing, nitrogen, rental equipment, all across the board, in light of surging demand and an increase in unavailability of crews to perform more work. So yes, seeing customers prepared to pay standby if necessary to keep a rig rather than let it go back on to the spot market and not have access to it again for some time.
Okay. And on the snubbing, which seems to be a tougher business, utilization rate down, what specific work do you need to have come back on to get that business providing adequate returns?
Yes, we're starting to see a little bit of a change in completion methodology that's bringing back some work towards snubbing as it moved -- the pendulum swung and have moved away over the last 4, 5 years. So we're expecting to increase some activity through the latter part of Q2 and into Q3, Q4. We don't expect it to reach levels of anywhere near historical highs, but we do expect to come off what we now believe are historical lows. When it comes to snubbing, High Arctic is the premier service provider in Canada and has the best fleet of equipment and we believe that we have a strong argument for engagement of our services ahead of any of our peers.
And what is snubbing particularly used for again, just to brief me on that?
So snubbing is to work on an existing well under pressure without having to kill the well and work it over in a traditional manner, but it also can be a highly efficient method of pushing in completions without having to bring on a service rig and make sure that well is dead before they come on board. And it can be used to conduct work on wells or to recover wells that may have downhole complications which have complex issues or a reservoir that may be susceptible to damage during a traditional workover activity.
Okay. So is the lead time on this something where somebody is at a well and they have problems and then you get a quick call? And then -- how long does it take to get the equipment in and how long will the equipment stay on site?
Yes, highly variable. So there is some routine equipment -- routine deployment in the completions market that is relatively stable and ongoing. And we do expect an increase, a small increase, in that activity through the rest of the year. But that emergency type work, the recovery of a well that's got a downhole problem or the need to work over a high-producing well that might be offline because of an issue and trying to avoid damaging that well, those calls come through, and it is deploy as quickly as you can.
And we are in a position where we have a large fleet of equipment that is ready to deploy on short notice. Again, crew constraints are the challenge in snubbing just as they are in well servicing and all other energy services across Western Canada. So the ability to deploy quickly is dependent mainly upon personnel. But the equipment is designed to go to site and assemble very quickly. It's highly modular. And the duration that it may be over such a well is determined by how complex the downhole issue is within the well.
The next question is from Tim Monachello.
Question just on the rates as well for well servicing. I understand that you've got the contract renewal with rates going up 20% from previous contract. In Q1, I've seen rates for well servicing that are up 30% year-over-year in some instances. And so I guess I'm curious, how much of your fleet is under this contract? And how much of it would be able to participate in spot market rate increases, which seem to be probably pretty twirly throughout the rest of the year here.
Yes. Thanks, Tim. Good question. And we'll attempt to address those in 3 parts. The rate adjustments and the rate -- pricing increases that we have seen outside of that key contract have also been of substance and substantially higher than 20% and vary across our customer base. That contract is the largest contract that we service in North America. The estimated volume of our fleet deployed at the moment under that contract would be roughly 1/3. So it's a high-volume contract with a steady commitment -- and a growing commitment of work. So that customer does get a little bit of preferential treatment.
But the other piece that's important with that contract renewal was that there's 20% on the base rate, but there's also been a lot of adjustment on ancillary equipment pricing, including the separation of some ancillary equipment that previously had been brought under the base price for contracts. So that's beneficial to us. And the net effect on our bottom line is more than 30% from that contract renewal. The other piece that's important to note too is the contract renewal included now: provisions for adjustments for fuel surcharges, wage changes, et cetera.
Would the ancillary revenue on that contract fall under the Production Services segment or is that going to the Ancillary segment?
Yes. Fair question. So given that the contract that's in play that calls out that ancillary equipment means that while we do provide it from our Ancillary Services segment flows through the contract and we end up netting that out. So the numbers that you see for our ancillary services segment are for -- include the provision of the ancillary equipment that flows through those contracts.
Okay. Got it. And then is there -- can you remind me how long that renewal is, first of all? And is there opportunities to increase the base rate throughout that contract?
The renewal period is 3 years. Yes, there's opportunities, too, but no guarantees so that would require negotiation.
And could you back out of the contract if there was no increase in rate?
Sorry, I stepped on you. Tim, do you want to repeat that?
No, I was just saying like market rates are significantly higher by the time the renewal opportunity comes up and they don't want to increase pricing. Like, do you have any options to put that fleet to work at a higher rate somewhere else?
We can't so much, I guess, back out of the contract, but what we also can't do is supply them if we can't acquire them. So if the market is demanding provision of services and we have customers elsewhere that will pay for crews and pay higher rates for deployment, we will focus our attention on deploying to customers that will provide us with the best return for our business. Notwithstanding, we've signed a contract here because we're determined to provide the services to that customer.
[Operator Instructions] The next question is from Patrick Tang from ATB Capital Markets Inc.
I think Exxon has been pretty quiet recently, and we haven't seen a ton of news flow out of PNG. But just wondering if you could provide us an update on how the negotiations are progressing in the country. And give us a little confidence on the expectation for rigs to go back to work by the end of the year or even beyond that?
Yes. Thanks, Patrick. PNG is a passion of mine, so I'll try not to go on too long. Exxon is not being that quiet. They've signed the gas agreement for the P'nyang field development. That was a substantive -- that was a substantive development in the first quarter, and I think I did mention now at our last earnings call back in March. So that's -- and the agreement under that gas agreement with the state has provided to the people of Papua New Guinea the best terms that they have signed for any natural resources project contemplated in Papua New Guinea when it comes to the net beneficial effects of -- from a contract, including an increased stake in the participation in the P'nyang field by the state-owned oil company, Kumul Petroleum, it's a 30% stake they have now, as well as commitments for aggregation of gas from stranded fields in the same province, a dedicated pipeline.
So it would be separate to the existing PNG LNG feed pipeline, so a separate pipeline, guaranteed offtake provisions as well as use of gas or electricity generation. So it's a fantastic agreement.
I think it's timing is perfect for ExxonMobil and their partners and a fantastic agreement for the benefits of the people in Papua New Guinea. So drilling for that project would not be contemplated for another year or more, I'm sure. But I also believe that we will see further announcements, not just for that project but the ongoing development of the Total Energy's led Papua LNG project over the coming months. It's our expectations that both of those projects will be fast tracked as fast as possible towards the final investment decision. There is also discussions that we are having with customers who I can't name, but certainly, there's some big customers of ours in Papua New Guinea, the most people we are familiar with, the discussions we're having with them towards the recommencement of another drilling rig in the latter part of this year.
There is also a discussion about activity that would require us to deploy another rig in the first half of next year, and further discussions that would see us possibly deploying one of possible or maybe even 2 more rigs by the end of 2023. So I think our outlook in Papua New Guinea is buoyant. We were positive on it last quarter. We're feeling that the events of this quarter have only continued to move in the direction that supports fast tracking LNG development and the appraisal and exploration for further gas sources to backfill not just the existing LNG project but the new ones that are contemplated to come on stream as well. High Arctic believes that we've got our best years in Papua New Guinea firmly in front of us and could be realized within the next 5.
Okay. Just moving on to that service contract renewal. It now includes a provision for increased fuel costs. And I was wondering if that was something that wasn't typically standard in the industry before. And I mean, if it was standard, then is there any chance to go back to the customer to have any retroactive adjustments for that increased fuel cost?
The terms of that contract doesn't give us provision for retrospective increases, but it certainly now gives us the ability to talk to them immediately upon further changes and fluctuations in fuel costs. As we're all feeling, the cost of fueling up our vehicles, the cost of purchasing diesel, particularly has become quite expensive in the last 6 months. And despite efforts by governments, including our own, here, in Alberta to try and minimize that impact and despite efforts by governments, like the U.S., releasing from their strategic petroleum reserve, we see this as a double-edged sword. Like on one side, it hurts us in the provision of services and our customers are now not worth the outlying contract for us and now providing us with support with fuel surcharges.
But on the other side, like, they are also the ones who are benefiting from the current good pricing and have the capacity then to increase the amount of work that they will increase the amount of production, that they provide on their crude products, which means an increase to services for us, which also then adds to the pressure from the demand side, which will help to drive further pricing improvements.
And just one last one for me. Just looking at the G&A in the quarter, it averaged 8.5% of revenue. Just thought it would tick up a little bit with the increased activity. But could you just give a little bit of color on the cost structure that you have in the overhead level and if we should be expecting that run rate to tick up in the coming quarters?
Yes, we're laser-focused on cost and have been ever since the COVID downturn. So we've been very, very measured in any additional costs in our overhead or our G&A. And while we have made, I think, prudent decisions to increase our sales teams and some of our support personnel, as we've deployed more equipment and personnel into the field, over the last year or so, these have been very measured and have been done on a basis of a need -- on a needs basis.
We've also taken the opportunity through this period to digitize a lot of what we do. And through the digitization there, we've seeing that we're able to be more conservative with that overhead of G&A expansion with increased activity, and we hope to continue that trend through what we believe will become higher utilization, higher hours in Canada, higher days in Papua New Guinea through the second half of 2022 and certainly through 2023.
There are no further questions registered at this time. I'll return the call back to Mr. Maguire.
Thanks, Paul. I'd like to close with a thank you to those who joined us today. I thank you to our employees whose dedication through a very tough period is on the cusp of paying off in this new positive period for energy and energy services. And I also like to thank our shareholders with a particular shout out to those who joined us yesterday at our AGM held at the Calgary Petroleum Club. It was nice to meet and have the opportunity to talk with you in person for the first time since 2019. Let me wish you all a good day. Thanks very much.
Thank you. The conference has now ended. Please disconnect your lines at this time, and we thank you for your participation.