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Good afternoon, ladies and gentlemen. Welcome to the High Arctic Energy Services 2021 Q3 Results Conference Call. I would now like to turn the call over to High Arctic Chief Executive Officer, Mr. Mike Maguire. Please go ahead, Mr. Maguire.
Thank you, Omar, and good afternoon, everyone. Welcome to High Arctic's third quarter conference call. Today, I'll be providing an update on the press release we issued before market this morning, November 12. Following my remarks, I'll hand the call over to Lance Mierendorf, who on the 1st of October consented to a permanent appointment as our Chief Financial Officer following a 6-month period performing at an acting capacity. Lance will be discussing our financial performance for the third quarter of 2021. After our formal comments, I will open the call to answer any questions that you may have. 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 they're 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's discussion and analysis and the 2020 annual information form under the heading Risk Factors. While with the continued 2021 rally in oil and gas prices, I believe that the market and our corporation has reached an inflection point. Commodity pricing above pre-pandemic levels continued through the third quarter and reached new highs in the fourth quarter. Most analysts are now predicting prices to remain at or above pre-pandemic levels through 2022, with the sentiment being supported by the futures market. There are strong fundamentals for High Arctic to expect substantial activity growth in 2022 across all its segments and geographies. Despite some remaining travel constraints and supply chain challenges, I'm pleased to report that the meticulous planning in Papua New Guinea for the various activities associated with the mobilization of our Rig 115, both of the camps and all of the support equipment is well underway and has kept us on schedule for a commencement of operations prior to year-end. The camps are now established and occupancy levels are increasing as personnel continue to mobilize and the main rig equipment progresses towards the well site. The physical location of the work site positions our rig well for additional work on exploration commitment wells in nearby license blocks. However, as yet, further drilling plans have not yet materialized. One of the ongoing challenges faced is COVID-19, which continued to hamper activity for the corporation during the third quarter. This was especially noted in High Arctic's Canadian operations where significant operating hours were lost due to confirmed COVID cases, and the enacting of subsequent protocols agreed with our staff and customers to minimize transmission and maintain compliance with government rules. Having already established a vaccination requirement in Papua New Guinea earlier in the year. In September, we implemented a similar program in Canada, which requires all employees to provide proof of vaccination or negative COVID-19 antigen test in order to access any of our work sites. To date, we have experienced strong cooperation from staff and we continue to monitor compliance with an intent to simplify the program once effective complete vaccination is realized, while customer and governmental COVID-19 rules change. We expect these actions will substantially reduce the risk of future site shutdowns in Canada and Papua New Guinea. We saw across the board, utilization rates of High Arctic services in Canada increased this quarter. However, the result was subdued somewhat by the operating hours lost to COVID as well as soft utilization under one of our key well servicing contracts. In Production Services, our Concord Well Servicing fleet utilization was 41% in Q3, versus industry utilization of 38%, and better than the 39% utilization rates in the same period last year. Our High Arctic snubbing package utilization increased to 22% in the third quarter, up from 17% during the third quarter of last year. We have engaged in dialogue with this key well servicing customer as we have with all customers on pricing increases, more efficient use of our services. And if appropriate, the release of rigs for redeployment elsewhere. We have generally found customers receptive to reasonable price increases with many increases agreed through the third quarter, providing contribution late in the period. I'd also like to mention that activity in the nitrogen pumping line of our Canadian ancillary services segment was up 85% on last year's third quarter and the catwalks that we acquired in the beginning of the quarter made their first contribution to earnings in the same segment. We expect the catwalk contributions to increase this quarter with the deployment of upgraded units at higher prices and further contribution growth is expected in 2022 as High Arctic takes full control and realizes the full income. Throughout 2021, it has been pleasing that income from our Canadian operation has been able to offset the losses from Papua New Guinea and maintain a healthy cash balance with rig activity recommencing in PNG, we took the decision to distribute some of our surplus cash balance, an amount carried since 2019, back to our patient shareholders by way of a special $0.20 dividend. That followed the repayment in Q1 this year of the $10 million we drew down on our revolving loan facility following the declaration of the COVID-19 pandemic. High Arctic will continue to develop its technologies, including our patent pending E-Rig design. We will also continue to explore opportunities to make acquisitions like our catwalks that strengthen our service base and enhance value to shareholders. With our strong balance sheet position, we will carefully review strategic mergers that strengthen both parties. With that, 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. I plan to briefly discuss the key performance results of High Arctic's third quarter activity. As Mike mentioned, we saw rig mobilization efforts to get underway in Papua New Guinea after unplanned and unavoidable delays that took place earlier in the year. In Canada, we saw growth in demand across all of our service segments, but did experience headwinds in the quarter that we are endeavoring to overcome as we head into 2022. On a consolidated basis, High Arctic's Q3 revenues were $18.7 million, and the corporation generated EBITDA of $1.3 million. This compares to revenue of $18.5 million and $2.9 million of EBITDA for the same period in 2020, during which the company received an additional $1.8 million of government subsidies. At 20%, the company's maintained relatively consistent operating margins throughout 2021, but this 20% is lower compared to 2020, when we were more active in our Papua New Guinea operations, which contributed higher margins to the company's consolidated results. In our Production Services division, revenues were marginally higher in Q3 2021 relative to Q3 2020 and was constrained by COVID-related well site shutdowns and lower-than-anticipated demand under one of our main well servicing contracts. Across High Arctic's operations throughout Alberta, we increased our engagements and discussions with existing and potential customers on expanding our services. This correlates with improved market conditions and sustained higher commodity prices. Q3 2021 segment operating margins as a percentage of revenue was 15% in the Production Services division, a decline from 30% achieved in the prior year, which was materially impacted by wage subsidies related to oilfield services salaries. In the third quarter, the company's Canadian well service rigs generated $11 million in revenue on 18,175 operating hours, with an average revenue per hour of $602. Our average fleet of 49 registered Concord service rigs achieved 41% utilization rate during the quarter, 3 percentage points higher than in utilization than the CAOEC registered rigs. In Q3, Canadian snubbing packages generated revenues of $2.1 million on 1,569 operating hours, which is 20% higher compared to Q3 2020. Snubbing utilization improved across the fleet as we actively enhanced our marketing efforts to potential new clients. Due to the challenging market conditions in target areas in the United States, no activity was undertaken in the United States during 2021. The company is currently in the process of relocating marketable equipment to Canada and determining the most appropriate exit strategy. Moving to our high-margin ancillary services segment. Revenue increased to $2.8 million in the quarter, up from $1.2 million in the quarter of the same quarter of the previous year. On a year-to-date basis, both revenues and operating margins within this segment were generally consistent with the prior year as increases in Canada offset lower revenues from PNG. Higher quarterly revenues were due to the demand for High Arctic's nitrogen services rig in Canada and rental revenues related to pressure control equipment and catwalks. As a result, the company achieved solid operating margins of 57.8% in this quarter versus 45.5% in Q3 of 2020. Our Drilling Services segment revenue is generated from our activities in PNG, where activity is now showing definite signs of increases as we head into the fourth quarter of 2021. We commenced the initial stages of mobilization for Rig 115 in the quarter, and as Mike mentioned earlier, drilling operations are scheduled to commence before the end of the year. Our other rigs, Rig 103, 104 and 116, all remain cold stacked, whereas during the first half of 2020, Rig 103 and 104 were operational. From a consolidated perspective, year-to-date G&A costs decreased $2.7 million or 26.6% compared to 2020. The overall decrease is mainly due to reduced compensation costs as a result of targeted reduction in corporate administration personnel that took place during the first half of 2020, and we're realizing the results as of today. As reflected in the cost reduction in G&A, High Arctic is committed to ensuring these costs are managed and in line with expected operating levels of activity. The company incurred a consolidated net loss of $4.8 million or $0.10 per share in the quarter, compared to a loss of $6.1 million or $0.12 in the comparable period in 2020. The noncash impact of depreciation and amortization of our property and equipment had the largest impact on the net losses incurred by the company during the past few years. In October, as Mike mentioned, we did declare a special dividend of $0.20 per share with a total cash distribution of $9.7 million, which was made in earlier in November. As Mike mentioned, the Board and management determined it was prudent to reward patient shareholders and return surplus cash in the form of a dividend. During Q3, we saw a minor level of activity within our NCIB program, where we repurchased and canceled 78,000 shares of High Arctic. Lastly, at September 30, 2021, we have a strong balance sheet position with $20 million in cash, no debt, a working capital ratio of 4:1, and we continue to main financial -- remain -- maintain, sorry, a financial liquid position post dividend. The company's $45 million bank facility expired -- which expires on August 2023. We currently have access to $8.7 million based on trailing 12 months EBITDA, but we expect this to improve in the coming quarters. Regarding spending on capital assets, a total of $2.7 million was spent during the quarter primarily related to catwalk purchases in Canada and the cost to reactivate and recertify Rig 115 in Papua New Guinea for its mobilization. With that, I'll turn it back over to Mike.
Thanks, Lance. It remains my belief that High Arctic's commitment to Papua New Guinea will in time provide significant upside for our shareholders. I'd like to walk through some of the recent developments that have occurred in Q3 that encourage us to expect drilling activity increases in Papua New Guinea from 2022. The PNG-LNG partners approved the Angore field development in the highlands as backfill to support the current LNG production levels. The Papua LNG project team remobilizing ahead of progressing pre-feed activity towards the project FID in early 2023. Arran Energy announced their intention to make a final investment decision on their Stanley Gas Condensate Development in early 2022. The PNG government and the PNG-LNG operator ExxonMobil signed a heads of agreement for a P’nyang gas agreement. The development of the P’nyang field has long been seen as a possible catalyst to expand the existing LNG plant for some years now. And the Santos Oil Search merger is progressing towards shareholder votes in December following completion of due diligence and the first PNG regulatory approval hurdle having been achieved. In the near term, in addition to the work with Rig 115, we have been receiving requests for rental equipment and skilled manpower to support customer production maintenance and optimization activities. I believe that we are also at an inflection point with the COVID-19 infection. The commitment of our employees to our vaccination program is our collective contribution towards realizing our expectation that the next phase for our communities is to learn to live with COVID, just like the cold and the flu. Here in Canada, we have started realizing higher prices and increased activity levels. As a result, we have commenced plans to make targeted investments in the recertification of our equipment in 2022, implementing strategies to attract and retain field employees to operate that additional plant and equipment, and monitoring our financial assets for signals that reinstatement of a sustainable dividend policy is appropriate. I'd like to close with a thank you to our employees as well as our patient shareholders. The past 18 months have been challenging as we dealt with the impacts of the COVID-19 crisis and the oil price collapse. We have confidence that the significantly improving market conditions in our business fundamentals will provide for appropriate rewards in the near future. That concludes my comments, and I'll now turn the conference over to Omar who will open the line for questions.
[Operator Instructions] And the first question is from Patrick Tang.
Just want to start in the Canadian services segment. Are you able to give a sense or quantify how many hours were lost to COVID-related site shutdowns versus the hours lost to your key customer being less active? Or was the key customer being less active, really a function of their own COVID-related site shutdowns?
Fair question. Okay. So estimate on the hours lost to COVID, we'd estimate that up to 1,000 hours across our entire Canadian operation were lost to COVID with 600 to 700 of that in well servicing alone. When it comes to the activity levels of this key customer, no, it does not appear to be related to COVID and we quantified the estimate to what -- the amount of hours that we're down with that customer this last Q3 between 3,400 and 3,500 hours, compared to last year.
And is this key customer expected to pick that activity back up? Or is this something that's longer lasting? And are you over the COVID-related disruptions on your own sites at this point?
Yes. So I'll take the second part first. Yes, so we believe that the program we've implemented there with the vaccination requirements and proof -- or proof of a negative antigen test has already stemmed the amount of site shutdowns that we saw, which particularly peaked in September. So we think we've taken appropriate action there and not too dissimilar to many of our peers to minimize the risk to have any future shutdowns. When it comes to activity levels from that customer, we continue to remain engaged in ongoing dialogue with them regarding both the utilization of our services as well as pricing for those services and the possibility that if they do not intend to raise their utilization for the release of some of the contracted rigs for us to redeploy elsewhere.
Okay. With the rates that you're getting on your service rigs, do you anticipate that could move up quarter-over-quarter and be the strongest in the year? Or is there still a lot of stickiness to that price level right now?
No aside from that one customer. We've realized pricing increases with all of our customers across Canada in Q3, and we expect our pricing for services in Q4 to be the peak for 2021.
Okay. So shifting gear to the U.S. service operations that are exited. Is the leaning right now for the related assets to be relocated to Canada or sold? And if it is sold, do you know, as a percentage, how much do you think you can recover on these assets relative to their initial purchase price?
Yes, fair question, again. So we have commenced relocation, and we anticipate to relocate back somewhere around 1/4 to 1/3 of the equipment that is sitting there. We believe it's quite -- has a lot of hours left on certification and is quite marketable in Canada to fulfill some of the increased demand that we're seeing from customers. The remaining 2/3 of equipment, we have not made a final decision on what is the best way to monetize those assets. We would expect that if we had to sell them fair market value compared to their original purchase or construction costs, somewhere in the order of around 20% to 30% of the original purchase cost would be recouped.
Pretty good color. And I was just wondering, with the PNG developments, I was just wondering if you could give me a little bit more color with the timing here. So with the Angore field, I just want to clarify that you said that cycles ahead development activities to start in 2023. And if that's the case, how many wells would be drilled? And what's the magnitude of the development? Like would you expect this to -- if you were awarded the contract, provides you with about a few quarters of reactivity from a single rig?
So the announcement is only just recently been made by the partners, Patrick and in that announcement, they did not disclose what the potential start timing for drilling activity or the number of wells would be. So it would be inappropriate for me to speculate that at the moment on the call. But I certainly take heart from the announcement that we could expect further inquiries for drilling services coming to us in 2022.
Okay. And then just squaring this up here. With the Stanley Gas Development, have you been in contact with the operator yet to maybe get maybe a conditional award on a possible FID? Or is that still something that hasn't quite been discussed yet?
Yes. This is one that's moving fairly quickly. So Arran Energy acquired these assets last year. They already have a development license -- approved development license, so they can move quite quickly. They put out an expression of interest in the last quarter. We responded to the expression of interest, and we expect to be invited to bid or to tender on services there, not just drilling. We expect it would be the tender on services associated with provision of rental equipment, our well site mats, and I say, a large sway that the service offerings we have in Papua New Guinea. What that looks like is, it will materialize, I expect early in 2022 as they've stated their intention there to make their final investment decision.
[Operator Instructions] We have no further questions at this time. Back to you, Mr. Mike Maguire.
Thanks, Omar. I'm going to take that as that the people on the call are quite satisfied that Lance filled them in with all of the details and the color during the call. I'd like to thank everybody for their time this morning or this afternoon, I should say. This morning my time, I'm on the other side of the planet, for joining us, and wish you all a great day.
Thank you. The conference has now ended. Please disconnect your lines at this time, and we thank you for your participation.