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Good morning, ladies and gentlemen. Welcome to the High Arctic Energy Services 2020 Q4 Results Conference call. I would now like to turn the meeting over to Mike Maguire. Please go ahead, Mr. Maguire.
Thank you, Justina, and good morning, everyone. Welcome to High Arctic's Fourth Quarter Year-end Conference Call. Today, I'll be providing an update on the press release we issued after market last night, Thursday, March 11. And following my remarks, Chris Ames, our Chief Financial Officer, will be discussing our financial performance for the period. After our formal comments, we'll open the call to answer questions. Before we begin though, 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 are subject to certain risks, which could cause actual performance and financial results to materially vary 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. While I believe that most would agree that 2020 was very trying for the energy industry as the world coped with a global health pandemic and an oil commodity price crisis that took root back in March, High Arctic demonstrated resilience and leadership in mitigating the impacts of an extremely difficult year that was characterized by tremendous oil price instability and record-low customer demand. We set ourselves a target to reduce certain cash outflows by at least $25 million over the prior year to 2019 levels. And crucially, we exceeded on this with a $35.1 million result comprising of $18.2 million reduction in capital expenditures, where our 2020 capital spending of just under $5 million compares to 2019 capital spending of just over $23 million. The necessary downsizing of our workforce, eliminating a layer of executive and senior management by combining our North American and international management teams, reducing overheads and increasing efficiencies, resulted in approximately 45% head count reductions at the executive, management and support personnel levels. This decreased our salary and related costs by $8.6 million in 2020 alone. The suspension of monthly shareholder dividends in March decreased our cash outflows by $8.3 million, and general restraint in the use of our normal course issuer bid until late in the year delivered a $4.3 million reduction in share buyback expenses, helping to preserve our pre-pandemic net cash balance, allowing us to exit the year with $22.6 million of positive net cash at bank. In the fourth quarter, we saw across the board utilization increases in our Canadian Production Services segment, where our Concord Well Servicing fleet utilization rose to 44% in the quarter, compared to an industry utilization of 30%, representing an increased utilization of 16% over third quarter and 40% above the lows experienced in quarter 2. Our High Arctic snubbing fleet utilization increased 71% on the third quarter, and our nitrogen fleet utilization rose 51% on previous quarter. With these, combined with our Canadian Ancillary Services segment to offset a reduction in non-drilling-related activity in Papua New Guinea and finished the year on a positive note, adding $1.2 million of adjusted EBITDA for 2020 -- and for 2020, adjusted EBITDA of $8.5 million in an exceptionally difficult economic environment. Some key achievements in 2020 I'd like to highlight include the renewal of key customer contracts in Canada, where we were proactive in providing solutions to continue with the provision of reliable and high-quality services that were essential to our customers. This success was built on demonstrating an ongoing ability to create a safe working environment, controlling crew movements, maintaining the health and well-being of our personnel and the people that they interact with and a consultative approach where we listen to our customers' needs and pass through achievable cost savings in an environment of low and volatile oil and gas prices. Another key achievement has been the maintaining of our equipment in a state of readiness both in Canada and Papua New Guinea, capable of being deployed by our customers as called upon. But perhaps our proudest achievement has been the consolidation of the people in our varied service lines and diverse geographical locations into one, single, cohesive and efficient working team. This team has universally adopted best practices and embraced a quality-centric operating model where we set benchmarks that accept nothing short of repeatable actions that deliver on customer satisfaction and safe outcomes for all involved. In safety and quality this past year, we continued our total recordable incident-free run in Papua New Guinea and exited 2020 with 4.5 years and 2.4 million man-hours of incident-free work. We were recognized for the fourth time in the past 5 years by the local International Association of Drilling Contractors chapter. We also added to our LTI-free run in Canada with a second lost time incident-free year in a row. And we extended the run of total recordable incident-free years in our Cold Lake well-servicing operation out well beyond 7 years. With that, I'd like to now pass the call over to Chris to discuss our financial results in more detail.
Thanks, Mike. In the fourth quarter, we saw the benefit from our continued focus on overhead cost reduction and associated efficiencies net of restructuring costs incurred, which helped offset the lower activity in both our North American Production Services and our Papua New Guinea Drilling Services segment compared to 2019. Overall, High Arctic generated $1.2 million in adjusted EBITDA during the quarter and $8.5 million year-to-date. This compares to $3.6 million and $19.4 million in adjusted EBITDA for the comparable periods in 2019, which benefited from stronger North American services and Papua New Guinea drilling activity. High Arctic was also eligible for various government subsidies during 2020, which amounted to approximately $6.1 million during the 2020 fiscal year. The corporation will continue to monitor and apply for programs where eligibility criteria are met. However, the continuity of these programs as well as High Arctic's ability to access these may change in 2021, depending on how criteria are established and/or changed. Revenue in our Production Services segment decreased 43% to $13.8 million from $24.3 million in the fourth quarter of 2019. This decrease was driven by industry-wide reduction in hours year-over-year due to the pandemic and the simultaneous commodity price collapse as well as our decision to idle our U.S. operations. The Canadian well service rigs generated $11.7 million in revenue during the quarter on 20,070 operating hours, with an average revenue per hour rate of $581 per hour. Our average fleet of 50 registered Concord service rigs achieved a 44% utilization in the quarter versus the 30% utilization generated by the Canadian Association of Oilwell Drilling Contractors registered rigs in the quarter. Conversely, our cost reduction initiatives and government Canadian employment wage subsidy -- subsidies combined to raise operating margins as a percentage of revenue, which increased to 20% in the quarter from 7% in the fourth quarter of 2019. Canadian snubbing service operating hours decreased in Q4 of 2020 and year-to-date 2020 by 45% and 42%, respectively, compared to the same periods in 2019. For the most part, gas well drilling was subdued during 2020, and customers deferred discretionary spending on well completions and technically complex well workovers. Due to poor market conditions, High Arctic made the decision in the third quarter to idle operations in North Dakota and Colorado. During the fourth quarter of 2020, our idle U.S. operations incurred just under $100,000 in suspension-related costs compared to revenues of $3.7 million in the corresponding quarter in 2019. In 2020, our Production Services segment generated $57.8 million in revenue compared to $92.4 million in 2019. The Production Services segment generated $10.1 million in operating margin, which is a 55% increase from the $6.5 million in operating margin generated in 2019. In 2020, the Canadian well service rigs experienced an average of 43% utilization and 79,683 operating hours. This compares strongly with a 24% utilization generated by the Canadian Association of Oilwell Drilling Contractors registered rigs over the same period. Revenue for our Drilling Services segment declined to $1.6 million in the fourth quarter from $13.5 million in the same quarter in 2019. This decrease was due to the continued cessation of drilling activity in Papua New Guinea. Compared to the third quarter of 2020, revenue decreased 66% as minor services performed for our customers relating to critical activity was completed and travel restrictions relaxed, allowing their own personnel to finally travel into and within Papua New Guinea. During the quarter, Rigs 103, 104, 115 and 116 all remained cold-stacked, whereas during the fourth quarter of 2019, Rig 103 was operating and Rig 104 was partially operational. In 2020, the Drilling Services segment generated $25.4 million in revenue and $6.6 million in operating margin compared to $71.5 million in revenue and $15.1 million in operating margin in 2019. During 2020, the corporation operated Rig 103 for part of the first quarter, whereas during 2019, Rig 103 operated throughout the year and Rig 104 operated throughout most of 2019. Revenues generated in 2020 included the provision of manpower and services to support essential customer operations impacted by travel restrictions on foreign workers and contractors due to COVID-19.Revenue for the Ancillary Services segment declined to $1.7 million in the quarter from $5.6 million in the fourth quarter of 2019. This decline was largely driven by significant reduction in well site work activity in the quarter and particularly in well site associated rentals in Papua New Guinea, including the contraction in the work site matting needs. Operating margin as a percentage of revenue declined to 47% from 52% in the fourth quarter of 2019. In 2020, the Ancillary Services segment generated $9.4 million in revenue and $4.6 million in operating margin versus $24.6 million and $13.6 million, respectively, in 2019. General and administrative costs decreased to $2.7 million in the quarter versus $3.7 million in the fourth quarter of 2019. The overall decrease of $1 million in general and administrative costs for the quarter compared to the fourth quarter of 2019 is mainly due to reduced compensation costs as a result of reduced administration -- administrative personnel in the organization. During the quarter, compared to Q4 2019, gross personnel costs decreased by $1.1 million. Canadian employment wage subsidy reduced general and administrative costs by approximately $100,000. Various other general and admin categories decreased by also $100,000, and this was offset by an incremental $300,000 related to restructuring costs. 2020 general and administrative costs decreased by $3 million over the prior year. Gross personnel costs decreased by $3.2 million. Canadian employment wage subsidy reduced general and administrative costs by $800,000, offset by an incremental $800,000 of restructuring costs and increased legal costs of approximately $200,000 year-over-year particularly related to the 2020 COVID-related Annual General Meeting requirements. As reflected in the reduced -- in the reduction in general and administration costs, High Arctic remains committed to ensuring that these costs are managed and balanced with the overall strategic plan for the corporation. As a result of increased depreciation, adjusted net loss increased to $11.5 million or $0.23 per share from a $2.7 million loss or $0.05 per share in the fourth quarter of 2019. Decreased income tax expense was mainly associated with a decrease in withholding taxes related to intercompany dividends as well as an increase in deferred income tax recoveries. Depreciation expense on property, plant and equipment and right-of-use assets totaled $12.5 million in Q4 2020 and $35.5 million in the full year 2020, compared to $7.3 million and $28.3 million during Q4 2019 and full year 2019, respectively. Increases are due to the corporation's review of its depreciation policy specifically as it related to salvage value estimates. As a result of this exercise, incremental depreciation was recorded to best reflect management's estimates as it relates to higher depreciation policy. High Arctic had a $25.9 million net loss for the year 2020 or $0.52 per share compared to an $8.8 million net loss or $0.18 per share in 2019. We continue to maintain a strong balance sheet and exited the quarter with $32.6 million in cash and $10 million drawn on our debt facilities for a net cash balance of $22.6 million. We also reinforced our liquidity with the extension of our $45 million bank loan facility through August 2023 on favorable terms and achieved cash flow -- outflow reductions of $35.1 million against a $25 million target when compared to 2020 -- 2019 levels. With that, let me turn things back over to Mike.
Thank you, Chris. Building on the things that we have achieved last year, we entered 2021 prime to take advantage of improved market conditions. We have a competent, settled and cohesive team using leaner and more efficient management systems. We opened the year with nearly $45 million in working capital, including $22.6 million of net cash at bank and access to a recently renewed $45 million revolving credit facility. We have not compromised on frontline worker compensation, training, supervision or field QHSE support, and this is aimed at High Arctic being front-positioned for an increase in activity where experienced well-servicing personnel will become a constraining factor. Stabilizing commodity prices have seen oil and gas companies undertaking more well site work during the fourth quarter and into the start of 2021, which, combined with work from the government's well abandonment programs, has improved the utilization of assets in the corporation's Production Services and Ancillary Services segments. Seh' Chene partnership has secured its first projects with a long-term customer of High Arctic's and has added more work sites in the beginning of 2021. The extreme cold experienced across North America in February had the short-term effect of shutting down our operations for several days, but it has conversely also resulted in a meaningful drawdown of oil and gas storage through extreme energy demand and shut-in production. We remain optimistic for a continued increase in activity for all of our Canadian service lines in 2021, driven in the near term by buoyant commodity prices, restoration of shut-in customer production and the well abandonment stimulus programs. Oil and gas activity and investments in the U.S. have recently been increasing, and we continue to watch this market and look for sustainable opportunities to deploy our idled operations in Colorado and North Dakota. We currently view these markets as too unstable to cost effectively reactivate at this time. In Papua New Guinea, recent developments are very encouraging for the progression of the Total Energies-led Papua LNG project. The Papua New Guinean parliament enacted into legislation the key elements of the Papua LNG gas agreement. Further positive developments include the signing of a fiscal stability agreement on February 9, and the renewal of Total Energies and their partners' retention license over the large Elk-Antelope gas field that will feed the LNG plant. The corporation's Drilling Services remain suspended. However, we're still providing skilled personnel and rental equipment to assist our customers in their essential operations. We maintain ongoing dialogue with our major customers in PNG towards planning an effective return to work amid ongoing travel constraints and a second COVID wave, leveraging off of our demonstrated recent and long-term capacity as a Papua New Guinea specialist contractor. That concludes my comments. And I will now turn the conference over to Justina, who will open the line for questions.
[Operator Instructions] And we have the first question.
This is [ Steve Bolton ]. Mike and Chris, just had a quick -- a few quick questions for just more general questions as opposed to what happened in the last quarter. Would you be able to talk -- I guess since High Arctic purchased Concord, we really haven't been in a healthy energy environment in Canada. Can you talk about what type of -- and just generally, what type of operating financial metrics you would expect from the division in a healthy Canadian energy environment, things like utilization, revenue potential, what type of margins in a healthy environment you would look for from that division?
Yes. Thanks, [ Steve ]. Yes, you're right. Our acquisition of Concord Well Servicing was in 2016, and we've -- the Western Canadian industry has been in a longer downturn dating back probably to 2015. We did start to see some increased utilization and some green shoots at the beginning of 2020. We had a lot of optimism for how the Concord unit was going to perform through the year. Unfortunately, macro events well outside our controls managed to dent that somewhat. But I think based on the performance that we did across the year with an amount of 43% utilization, it would not be unreasonable to state that utilization levels of maybe 50% or more higher than that would be expected in a buoyant market. And of course, this has been a sustained downturn. So pricing has been suppressed. We would expect to see pricing lifting potentially in the near future, driven by both a tightening in the market from lack of available and ready-to-work equipment, so we think we're front-footed there; and also availability of skilled and experienced personnel, which we also believe we're well front-footed on. So we see tightening coming. What those margins are able to increase to is unclear at this point, but given that we would have a front-footed position, we'd expect to be in a -- well placed to see our margins lift by a meaningful amount.
That sounds good. And I understand that with such -- we're in such a questionable and uncertain environment that I'm not asking at all for any type of forecast. Could you maybe talk about, historically looking -- so as opposed to the future, but looking back to the past when Concord within a healthy environment, what their margins were like, I'm sure, when the company was looking at it? At Concord, they had a sense of what they thought the division could earn in a normalized-type environment.
I think it'd be fair to say that at the time of acquisition, we definitely had a view that we could do more with Concord Well Servicing than it's proven through the difficult environment over the last 5 years and particularly this year. That said, neither Chris nor I were involved in the acquisition. We've basically picked up the management of the business last year. I don't have numbers to hand and couldn't speculate on what the expectations were at the time of acquisition.
Okay. Understood. If I could shift to PNG, can you -- if you -- and you guys discussed this a bit, but what is the current status? It sounded as though there was some lifting of the restrictions in terms of internal travel. What is the current status regarding travel to the country for contractors and personnel?
Yes. Sure. It's -- these things are always a little more complicated than you just summed up in a few seconds. But the current circumstances in PNG is that the borders are open to travel, but people traveling internationally must have approval of the controller of the COVID emergency. So it is with approval that you can enter into the country. There is a mandatory self-isolation on arrival. And there are some controls in -- provincially in areas where COVID has started a second wave. The second wave kicked off probably only about 7 to 10 days ago, and it is in some key locations in the country. We're uncertain as to what the government may do in response to the second wave. We did see that they closed the borders both externally and internally back in April last year and that, that ran through until September, October. And there's a possibility that they may need to go back that way to control the second wave before they can open up travel further than what it is at the moment. The relaxed travel conditions in the final quarter of last year did see that some of our personnel who had stayed in-country and some of our local citizen workforce who had stayed within provinces of work rather than returning to their home -- we had guys who were finally released after 7 months or more of continuous work engagement as our customers were able to start bringing some of their people back in. It's uncertain at the moment if there will be changes in that in the near term. But with the rollout of the vaccines that we're seeing on a worldwide scale, the commitment of local, regional governments to financially support and financially and logistically support Papua New Guinea and other Pacific Island nations with the rollout of vaccines, we are optimistic that in the mid- to longer term, those travel restrictions will relax to the point where we will be able to deploy -- reliably deploy drilling services again.
Great. That's very helpful. And would you say that the -- obviously, there's a lot going on with COVID and then the energy pricing. Would you say that the -- that there's a suspension of travel that is the major cause currently of the continued suspension of drilling? Is it something that when that lifts again given -- if the market were to -- if LNG and natural gas in Asia were to continue its strength, would you expect there to be a significant uptick in the nearer term once that travel is permitted? Or are there other issues and...
Well, I think the best guide I can take for that is what were we doing in March last year. So in March last year, we were actively drilling on one well site. We were actively moving a rig to drill on another well site, and we're planning for a third location. And in the space of a very short period in March, that went to -- resulted in suspension of drilling in -- mid-well, while drilling the well we were on and the suspension of movement, too, and further activity for wells that were planned to be commenced soon. And that was driven by travel restrictions. The borders were announced that they were going to be closed. We had a very clear understanding that travel would be impossible and that then keeping those activities -- keeping drilling activities alive would not be feasible. So I think when we look back at that, there is a good expectation that we -- or strong expectation we would have that once the travel restrictions are removed, the return to planned drilling activities would also return.
That's really -- that's a great way of looking at it. And more generally, was the drilling -- or I guess looking forward, would your customers generally need that drilling in order to fulfill their delivery commitments? Or is it drilling more for future growth, which obviously is something that they're all working on? Or is it necessary sort of in the near term in terms of just fulfilling the commitments they've already made and planned?
Yes. Good question. Good question, [ Steve ]. In reflecting upon the drilling activities we do with the 4 heli rigs and -- we do a smorgasbord of our drilling activity. Some of it is production maintenance. Some of it is exploration. Some of it is step-out and appraisal. So in general, these drilling needs are very much needed on a long-term basis, short-term basis. I don't have figures to hand, but I know that our customers do publish their production. And I'm sure that if you had a look at some of our customers and Papua New Guinean producers' quarterly reporting and annual reporting, you'd be able to draw a line as to what the impact of non-drilling is having.
Okay. That makes sense. And just one last quick question for Chris, just sort of a technical question in terms of -- you guys have mentioned in your reports over the years that there are tax consequences of repatriating cash from PNG. Just wondering what the -- if -- and this -- maybe it's not a simple answer, but I was wondering if there are sort of a tax rate or some way that we can think about that on withdrawing of cash. Is there a simple way to sort of think that through?
Yes. A great question, yes. It's very straightforward on repatriation. The funds would be dividend-ed out of Papua New Guinea into Canada. And I believe the current rates right now are approximately 15% on dividends flowing out of Papua New Guinea to Canada.
Great. And in Canada, you guys are in a tax loss position. So there would be no Canadian tax consequences of that or...
There'd be very little impact, yes. That's a good assumption.
And we will take the next question.
Patrick Tang here with ATB Capital Markets. Two questions here. So just in regards to the depreciation study that was conducted, should we expect depreciation to be elevated going forward? Or is this more of a onetime catch-up charge?
Great question, Patrick. It was really a onetime catch-up. We've had the opportunity as a new management team to go through our fixed assets, especially in Canada with the acquisition that was made that was referenced earlier in the call. And it is a onetime deal at this point. But we will constantly be looking at our asset base and our policies, but yes, onetime.
Okay. And just apologies because I might have missed some things. But should we expect government wage subsidies to be down materially from Q4 levels into the New Year?
Into the New Year, that -- there will be -- we see them coming rolling off probably late in Q1. They're coming down somewhat as the rules continually change in the metrics when we compare year-over-year, 2021 now to 2020, that we had a significant downturn in Q2 specifically in 2020 that we hope to be above those levels that, yes, those numbers should come down.
Okay. You might have already touched on this, but just looking for a little bit of more of a substantive outlook. So relative to 3 months ago, what does your outlook on well servicing look like? I mean in particular, has the well abandonment program accelerated in line with your previous thinking? Or is it outpacing it or falling behind? How are you seeing that right now?
Yes. A couple of great questions here, Patrick. So I think I'll address just generally the well-servicing activity. Our outlook here is -- into 2021 is good. And based on the quarter-on-quarter growth in utilization that we saw a 16% increase in the number of hours we booked -- billable hours we booked, Q4 over Q3, we're anticipating a similar result coming into Q1. And we believe if -- that subject to the usual seasonal downturn in Q2, we're feeling good about the summer period as well. Talking -- then moving to the question on the well abandonments. So we were frustrated with the pace of award, turning that stimulus program into actual boots on the ground work last year. However, we did start to see an increasing number of approvals coming through in the fourth quarter. We've well over 100 approved wells at the moment that we've got rigs actively working on. We have applications in for -- in excess of 1,000 more wells. And we actually have a high degree of confidence of a substantive number of those 1,000 wells being awarded to us.
Awesome. So the last question from me might be a little hard to say. But from my understanding, and correct me if I'm wrong, the PNG LNG project requires Exxon to negotiate a deal with the government to go ahead. However, is there any possibility of High Arctic taking part in some predevelopment work even before that happens, especially as Total has a gas agreement in place? And separately, also in the region, is there any demand for Rig 102? Or is that still kind of parked right now?
Okay. So a couple of questions there. So let me try and address them in order. First up, the PNG LNG, we need to be clear that PNG LNG and Papua LNG are 2 distinctly separate projects. However, the Papua LNG project contemplates the expansion of the PNG LNG facility to accommodate its processing trains. Slightly different participants in the 2 joint ventures, although there are common participants in ExxonMobil, as you named, and Oil Search, and of course, the state of -- the government of Papua New Guinea. The Total project is expected to proceed just as recently as February when the fiscal stability agreement was signed between Total and its partners and the government. Total CEO, Patrick Pouyanné, told reporters that this is a project that has a priority for the group. So we're expecting that project to progress independent of anything that happens with the PNG LNG. Pausing there and then moving back to PNG LNG. I think your question is based a lot on that PNG LNG has also been contemplating an expansion that would be fed from gas from a different field that's owned by the PNG LNG partners. That agreement -- that gas agreement has not been executed yet. So we don't have any visibility on a time line associated with that expansion. But notwithstanding that, we're still very confident about a doubling of capacity -- of LNG capacity out of PNG through the Papua LNG project. Does that answer that part of your question, Patrick?
Yes. Just a little hard to keep all this straight with such similar project names.
Yes, yes. I think that it's a thing that I'm constantly explaining because they are so similarly named.
Okay. And just the last part there with Rig 102, is there any updates on how demand is looking for that?
Yes. So we were in the midst of an upgrade and refurbishment of Rig 102 when the crisis hit in March and we suspended that work. We have continued discussion with our customers on the work that we were planning to deploy that unit to do. Those projects have not gone away, but they may be changing, being modified and may be -- they may need to accommodate some changes in our customers' outlook and scope. So at the moment, we are not finishing that refurbishment work, but we very much have it on our radar to complete ahead of deployment when we're able to secure an operation for it.
[Operator Instructions] And we will take the next question.
Is this me? I'm not sure. This is Tim Monachello with ATB Capital Markets. It's -- hello?
Hello, Tim.
Yes, we can hear you.
Okay. I'm not sure. It doesn't tell you when it's your line. It's open and just the line's open. Okay. I just had a question to follow up on PNG here, following up on Patrick's question and your sort of explanation around the 2 projects. I guess if you had Papua LNG and the PNG LNG expansion go ahead simultaneously, how would that level of drilling compare to the initial build-out of LNG capacity in Papua New Guinea?
Yes. Great question, Tim. And certainly, if we were looking at a parallel expansion project and similar time lines, then drilling would be occurring in 2 distinctly different locations in PNG, and we would expect to see proportional amount of drilling activity, drilling work in that time period associated with the 2. It'd be my expectation that if both projects were to proceed -- hypothetically to proceed together and on the same time line that with the rigs we have in-country, both owned and leased, that we would have the capacity to be able to satisfy both projects at the same time.
Would you have excess capacity? Or [ is that used ]? Do you think you could get them all working at once?
I would think that would get us to pretty much all of them being active in one capacity or another.
Okay. And then I guess a follow-up to the previous line of question from, I believe, [ Steven ]. Just around the PNG work, you guys haven't -- you guys have cold-stacked for a few months now. And a lot of that work historically, under my understanding of it anyway, is that it was production maintenance and it's a very seismically active area. Do you think there's a backlog of work once you'll be able to get back into the field?
Yes. I think, Tim, it would be reasonable to expect that given there's been no activity for a year now that there will be a backlog that will need to be addressed. When we're able to start executing on that is the thing that's still very difficult to see.
Okay. Switching gears here to the U.S. What do you guys need to see in terms of KPIs to decide to either permanently exit that business or to reactivate?
Yes. Another great question. The thing that we're looking for at the moment is customers that we are happy to go work for. And in that regard, we have some relations from the customer base that we were working for back in the early part of last year. Those customers returning to work with reasonable work programs, that would be -- we would then have confidence to talk with our workforce and to reactivate our rigs. We -- as a reminder, we were providing predominantly Canadian crews to operate our equipment in the U.S. when we were operating before. So we would need to have some confidence with regards to their travel back and forth across the border, which has had some issues and problems for some travelers and less so for others. But we would need to see that there would be a sustainable amount of work that would be worth us investing in the effort as well as the cost to get up and running.
So is that -- I mean crude is $65 a barrel. It's above where it was last year. Is the issue that the customers aren't working yet or that you can't get the crews down there or a combination?
Yes. So what we're seeing at the moment, even here in Canada, is that the broader customer base, even with the buoyant commodity prices, are only modestly increasing their capital spend. So the amount of actual work being conducted is -- while it's better than where it was, it's not at levels that we saw just over a year ago with oil prices at a similar high. We're seeing the same thing happening in the U.S. and in the areas where we work. Customers are probably being a little bit more reserved with regards to deployment of additional drilling return to well-servicing and bringing wells back online that have shut-in production at the moment compared to some of the other basins in the U.S. So we watch particularly the DJ and the Bakken, and we're looking for indicators there with regards to upticks in production and increases in drilling activities.
How much of that work -- before you started operations with production management, how much was sort of D&C-oriented?
I would say the majority of the work we were doing was production maintenance with -- in the Bakken. And in the DJ, it was more completions-related.
Okay. And then last question for you. I'm just curious where your minds are at in terms of capital allocation. Balance sheet is clean. The repurchase program sort of slowed. And so I guess what's the priority through 2021 if you see activity start to rebound? Where does the marginal dollar go?
Yes. A fantastic question. I'm glad you asked it. So in the last quarter of last year, having looked at several potential acquisition opportunities and not progressing on any, we turned our attention more to organic growth. And we have got a large pipeline of potential and very interesting and attractive work to work towards, far too far out from speculating on any success rates and things at this point but -- so that's kind of taken the front of mind at the moment. But we're also conscious that in the last couple of months, we've seen a lot more M&A activity amongst our customer base in the E&P companies. And we feel there's a natural progression here towards more consolidation in the energy services that will follow. And we're keeping our heads up and looking for opportunities that will fit our profile, strategically aligned with our objectives, provide accretive cash flow and potentially bring us into new markets but within the service lines that we specialize in.
Okay. So you're looking within Canada primarily but perhaps new markets outside of Canada. Is that a fair way to think about it?
Yes. I think it would be fair to think that we've got our eyes open where we are today and where are we. We're in Canada, the U.S., albeit idled, and Papua New Guinea in Australasia. And those areas are very familiar with the service lines of what we provide, drilling, well-servicing, snubbing, nitrogen, other energy services lines, our specialty. So we've got our heads up for opportunities in those spaces and in those markets.
[Operator Instructions] There are no further questions at this time.
Well then, I'd just like to wrap up by saying thank you to everybody who participated in the call today and for the good, quality questions we received. Thank you to Justina for being our operator handling the call. That concludes the High Arctic Energy Services Q4 Conference Call.
Thank you. The conference has now ended. Please disconnect your lines at this time, and we thank you for your participation.