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Good morning, ladies and gentlemen. Welcome to the High Arctic Quarterly Results Q4 and Year-end Conference Call. I will now turn the meeting over to Cam Bailey. Please go ahead, Mr. Bailey.
Thank you. Good morning, everyone. Welcome to the High Arctic Fourth Quarter and Year-end Conference Call 2018. Today, I'll be providing an update on the press release that we issued last evening on March 14, 2019. And following my remarks, Jim Hodgson, our Chief Financial Officer, will be discussing our financial performance for the period. After the formal comments, we'll open the call to answer any questions 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 and projections and assumptions. These forward-looking statements are not guarantees for 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 the risk factors, please take a look at our annual information form under the heading Risk Factors. So notwithstanding a very difficult environment in the Canadian energy industry, there are some notable accomplishments that we'll be touching on in the call today. The surplus of crude oil production caused by the pipeline constraints caused many of our customers to significantly reduce field activities in the fourth quarter. Although crude prices have recovered due to the Alberta government mandated apportionment, the takeaway constraints remain and have significantly reduced the outlook for field activities leading into 2019. Our pressure services business is also affected by the continuing low natural gas prices in Western Canada and the reduced natural gas drilling activity. High Arctic achieved 51% utilization of its well service fleet in the fourth quarter versus industry utilization of 37%. Now our utilization is down from 55% in the fourth quarter of 2017, and it's down from the 56% that we achieved throughout the 2018 year. On a positive note, High Arctic was able to increase its market share, with total operating hours increasing 3%, while industry experienced a 2% reduction of operating hours year-over-year. During the third quarter, we highlighted the expansion of our pressure services business into the United States by way of the acquisition of Powerstroke, where we now have 4 snubbing units operating in the DJ Basin and expect to move additional equipment in the near future. The transportation, preparation of equipment and crews required a substantial investment, which was incurred in the fourth quarter, substantially affecting our overall financial performance in the quarter. Now that we have a reasonable market share, we've established -- we are highly confident our investments in the [ initial ] will provide some attractive returns in the near future. The planned expansion of the PNG LNG facility with the addition of 3 additional trains continues to progress and on track for completion in 2023. The greater certainty around the PNG LNG facility expansion has resulted in a number of operators firming up plans for drilling activity in advance of the completion of the expansion. So at a minimum in 2019, we see 2 rigs operated and increasing into the latter half of 2019 and certainly thereafter in 2020. At the beginning of November, Rig 116 came off its take-or-pay contracts, and we're closely monitoring the ramp-up of activity for its possible use and reexamining other markets where it can be redeployed. High Arctic ended the year with $31 million of cash balances and total working capital of $56 million, which is $1.15 a share. We continue to be active in examining acquisition opportunities and have noticed a shift in valuation expectation coincident with the industry downturn, which High Arctic is in a position to take advantage of. We have and will continue to move surplus equipment -- surplus underutilized equipment to supplement our expanding service offering in the U.S., where prices and activity remain robust. Now that the critical mass has been established, expansion activities are expected to provide much better financial returns than those experienced today. With that, I'm going to turn the call over to Jim to discuss the financial details in more -- results in more detail.
Thanks, Cam. Strong performance of our Production Services segment and a decrease of $4 million in PNG drilling operations revenue resulted in a consolidated revenue of $47.8 million in the quarter, which generated a $6.6 million adjusted EBITDA, compared to $51.5 million and $12.4 million in revenue and adjusted EBITDA, respectively, for the fourth quarter of 2017. For the year 2018, High Arctic generated $203.3 million in revenues and adjusted EBITDA of $51.6 million versus $210.2 million and $58.3 million, respectively, in 2017. Revenue in our Production Services division increased 2% to $21.4 million from $20.9 million in the fourth quarter of 2017. This increase was driven by increased activity year-over-year and higher revenue per hour rates. The Concord rigs generated $16.7 million in revenue during the quarter on 27,161 operating hours with an average revenue per hour of $616. Our 58 registered Concord service rigs achieved a 51% utilization in the quarter versus 37% utilization generated by the CAODC registered rigs. Operating margins as a percentage of revenue decreased to just above 0 for the quarter from 24% in the same period in 2017. This decrease was due to startup costs amounting to about $2 million in the quarter related to Powerstroke acquisition and other associated operating costs. For the year, our Production Services segment generated $84.9 million in revenue versus $81 million in 2017. From this increase in revenue, the Production Services division was able to generate $11.6 million in operating margin, which is a 4.6% decrease from the $16.2 million generated in 2017. For 2018, the 58 average registered Concord service rigs experienced a 58% utilization on 117,395 operating hours for the year. Revenue from our Drilling Services segment decreased to $20.8 million in the quarter from $24.8 million in the fourth quarter of 2017, primarily due to Rig 116 coming off its take-or-pay contract in November. With 103 continued operations at IST3 until December 12 and then mobilized to IDT21 for its next well. Rig 104 spud its well at Muruk 2 in early November and continued drilling through the year-end. Rig 115 was cold stacked during the quarter, and Rig 116 was stacked in Port Moresby during the quarter. Activity was lower in the quarter. The contribution of the take-or-pay contract to 116 allowed the Drilling Services division to generate $5.7 million in operating margin. As a percentage of revenue, operating margin decreased to 27% in the quarter from 33% in the fourth quarter of 2017. This decrease was driven by decreased portion of our revenue from Rig 116 standby fees versus Rigs 103 and 104 during the quarter, which incur a lease expense charge if they're not incurred on High Arctic's owned rigs. Drilling Services segment generated $93 million in revenue and $36.9 million in operating margin in 2018 versus $105 million and $43.2 million, respectively, in 2017. Revenue for Ancillary Services segment was lower at $6.4 million in the fourth quarter of 2018 compared to $6.6 million for the same period in 2017. It's driven by growth in Papua New Guinea rental operations and offset by decreases in Canadian rental operations, nitrogen services and engineering activity during the quarter. Operating margin as a percentage of revenue increased to 69% from 50% in the fourth quarter of 2017 due to higher contributions from the corporation's rental operations in the quarter. For the year 2018, the Ancillary Services segment generated $29.1 million in revenue and $19.3 million in operating margin versus $27.4 million and $16 million, respectively, in 2017. General and administration costs increased to $4.4 million in the quarter from $4 million over the fourth quarter in 2017. Adjusted net earnings decreased to a loss of $2.3 million or $0.04 a share from $3.5 million or $0.06 a share in the fourth quarter of 2017. For the year 2018, adjusted net earnings were $12.2 million or $0.24 a share compared to $20.3 million or $0.38 per share in 2017. We continue to maintain a strong balance sheet and exited the quarter with $31.5 million in cash, nothing drawn on the $45 million debt facility and a positive working capital balance of $56.8 million. So with that, let me turn things back over to Cam.
Thanks, Jim. Our PNG business continues to provide solid, stable profitable contributions to High Arctic at a time of relatively low activity in the country. As to the PNG activity benefits, there were continued strong Asian LNG prices. High Arctic is well set up to take advantage of significant growth of activity in the country, driven by the PNG LNG expansion. The core of our Canadian service business is underpinned by the strength of our customer base, characterized by large multinational entities; the ability to provide a high level of employee satisfaction, with steady work and incentives for safe work practices; a strong balance sheet aligned with continue to grow and consolidate in a difficult and challenging market; and continuing to deliver a superior quality of service with the high standards of safety. We're continuing to review acquisition opportunities to grow our business operations both in North America and internationally.That concludes my comments, and we'll turn the conference over to the operator, who will open the line for questions.
[Operator Instructions] We'll take our first question from Michael Robertson with National Bank Financial.
You reported adjusted EBITDA of $6.6 million for the quarter. If I do a simple calculation of revenue less operating expenses and G&A, I get to $5.8 million. This is the methodology we have previously used, and our calculated EBITDA always has aligned with your reported adjusted EBITDA. I'm wondering if maybe there is a noncash item in either OpEx or G&A during the quarter that's driving that delta. Does that make any sense on your end?
Mike, we're going to have to do a little bit of work to come back to -- to give you some specifics on that.
Okay. One other quick one for me. In the outlook, you've mentioned that Rig 104 will continue with additional delineation work before commencing work to fly the rig off the well site. Do you have a ballpark estimate of when you would expect that mobilization to occur?
Yes. So we're finishing off one of the delineation wells that -- and moving up to the next well. So I'm just wondering about what specifically -- yes, we expect 104 to run continually throughout the year as with 103 as well, and it will be a combination. And right now, they are focused on the delineation work, and we'll continue to do some more appraisal activity as we mature through the year.
Would that like be like a Q2 occurrence, you think, or Q3?
Sorry, with respect to an additional well? So yes, as soon as we finish, the current application just moves to a new location where it will continue to drill. But we don't see any interruption. Bottom line is we don't see any interruption in the activities at 103 and 104 throughout the year.
And next, we'll move to Josef Schachter with Schachter Energy Research.
Just going to Papua New Guinea, 103, 104 are working. You mentioned in here -- in the commentary that in March -- at the end of March, you're expecting the LNG gas agreement to be signed. How quickly do you expect tenders to go out for additional activity? Is this something that takes 3 months, and then potentially, you might start by the end of 2019, with potentially 115 and 116 going back to work? Or is this 2020?
Thanks for the question, Joe. We don't really see the signature of the actual gas agreement to be a constraint around people's planning and starting to request tender offers. So we've actually submitted one yesterday in anticipation of the execution of the gas agreement. We have -- the parties have publicly stated that they have a heads-up agreement that has been executed, and this is just really a -- truly a formality with respect to the last details of the agreement. So don't -- both us and the rest of the industry don't expect it to be a real monumental -- really monumental in terms of engaging or incentivizing guys to start to begin work at that time. So it's ongoing. The work is in planning stages or ongoing. And yes, the tender work that we have just submitted to is something that is going to provide a minimum of a year and up to 3 years of drilling in the future.
So when is the deadline for the bids? And when do you expect to hear back?
We've been working through the tender submission, so the cycle time of -- the time of notification is approximately 2 months of lead time, and it is about a 2- to 3-month period of decision. And we're right in the middle of that process right now.
Okay, good to hear. With your -- you mentioned earlier that acquisitions are looking a lot more reasonable in terms of price expectation. Do you want to focus on building up not only snubbing in the States but also the service sector in the States? How do you make that trade-off in terms of capital allocation versus your NCIB? What are you thinking there?
Good question. So we're looking at other service acquisitions, and not just snubbing. We haven't -- our MO to date has been moving surplus equipment in the snubbing side down to the U.S. Much of the Canadian service equipment is not completely configured for operations in the States, so what we're looking at in the States is more work revolving around completion. That requires heavier uploads and higher pump capacities to be able to do that work. That's been the most profitable, highest margin work for our service rigs in the U.S. And that's what we're targeting. And that's a lot of our rig assist work goes on those rigs and for the last stage of completion.
Okay. And on the Ancillary Services, which held in margin very well during the 2018. Is that something that you can build on? Or is that -- how do you see that in terms of growth in 2019?
Well, our Ancillary Services essentially encompasses our rental business. And in Papua New Guinea, our rental business is really a function of the utilization of the drilling equipment. In Canada, about 55% of our rental business is actually internal. And it's used quite -- there's a heavy emphasis on the pressure services business, less so on the regular well service part of the business. So we're continuing to try to expand it into third parties. And at this point, we've -- it's 55% internal, as we said, and hope to see that start to diminish with more third-party activity.
So if we saw a contract on one of the other rigs for Papua New Guinea, should we then look at bumping up Ancillary Services by 30% or 40% for any single rig being put to work for a year or 2?
Absolutely. And so the -- one thing that we don't own the 2 rigs that are currently active in the country, being 103 and 104. We have the service contracts. However, all of the Ancillary Services that's supporting those rigs is owned 100% by High Arctic. So the mobilization of 115 and 116 would have an equal -- disproportionate amount of Ancillary Services that will be associated with it, and it would be operated with better profitability than what we have with respect to the 103, 104 contracts.
[Operator Instructions] Next, we'll move to Elias Foscolos with Industrial Alliance Securities.
I have a couple of questions. I guess, the first one would be a follow-up on Joe Schachter's question. The tender that you mentioned, is that specifically for Rig 115 or 116?
No, it's not. So just to be clear on that, and I'm not going to provide a lot of details with respect to the tender because it's -- so the tender itself is -- the most suitable rig for that activity would not be one of 103 -- 115 or 116. And the reason I even mentioned the fact that the tender is out there, it really addresses the question that was asked around the gas agreement. And so just demonstrating that there's very -- we have advance planning and tender work that's ongoing at this point. So I don't mean to get too specific around this particular tender or the importance of it for our business.
Okay. Understood. So sticking with Drilling Services, take-or-pay for 116 kind of came to an end for most of the quarter. The revenue number that we are seeing for the quarter, given that we kind of have 2 rigs working, 103 and 104, along with the margin that we saw, is that what we could kind of expect as sort of a baseline going forward into 2019, may be given a slight downtick in margin? Is that sort of a reasonable assumption looking ahead?
I think it is, yes. Yes, I think we can confirm that. And one of the things we did -- there was sort of an ancillary benefit with respect to the earthquake, and it's seizing a lot of the drilling -- stopping a lot of the drilling activity. But our rentals in Ancillary Services continue to support a lot of the activity that was out in the field and also provided some support to the relief effort.
Okay. Shifting gear to Production Services and a few questions on that. First one, and maybe I missed something in the financials, but I did see U.S. revenue. I think, it was 2.7 million for 2018. Was all of that or almost all of that in Q4?
It would all have been captured in Q4, yes. There was 4 or 5 weeks' worth of revenue that would have been generated in August, September just immediately after the acquisition, and that was all captured. The bulk of that was carried in the fourth quarter.
Okay. And I think one last question for me. You mentioned in your comments and in the financials, in the press release that there was maybe about a $2 million hit to margin because of ramping up U.S. activity. So are we going to continue to see another drag the next quarter as you begin to ramp up and maybe move more snubbing units down into the U.S? And the second part is, even if we look at adding back the $2 million, margin looks like it was a relatively large -- it's still down. So are we looking at a new base level of margin from Production Services? Or were there some other factors in the background that might have been suppressing it for 1 quarter?
Yes. So we can kind of segregate the question. And with respect to the Canadian part, I'll speak to that first, so margins are for the most part holding. And now we're saying that we're seeing price pressure, what we're concerned is going into after a spring break-up and what margins may look like at that time. And what we saw -- I'm not saying that we kept prices relatively flat in the first quarter, there were a lot of -- there was an erosion generally of market share by most of the public companies, larger service providers. And we saw a migration of that market share going to some of the smaller operators, driven by cost considerations. So we were able to hold for the most part our prices. Labor costs, being the largest component on our well servicing side, have not changed. They haven't gone up in costs but certainly not have come down in costs. So we're at a very sort of critical part where margins will be very much affected by our activities. And that call is too early yet to make with respect to what that looks like for the balance of the year for 2019. So part of the question that you asked was our hit in the states. And one of the phenomena that took places for us to gain market share, to establish our utilization, it required some cutting of prices to be able to ensure that we have regular and reliable activity. And so that quite dramatically cut into our margins and our expectations. So now that that's essentially established, we can start to move our pricing upwards to ensure that we start to make better returns on our investment.
Great. I guess what you're saying is as someone new in the segment, you have to prove your value, so you have both the top line and a cost impact that were in that quarter.
That's correct, yes.
And there are no further questions at this time.
Okay. Ladies and gentlemen, thank you very much for your attendance. And Jim and I are both available for any follow-up questions that you may have.
And that will conclude today's call. We thank you for your participation.
Thank you.