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Good morning, ladies and gentlemen. Welcome to the High Arctic quarterly results Q3 conference call.I would now like to turn the meeting over to Mr. Cam Bailey. Please go ahead.
Thank you and good morning, everyone, and welcome to High Arctic's Third Quarter 2019 Conference Call. Today, I'll be providing an update on the press release we issued yesterday on Thursday, November 7. And following my remarks, Jim Hodgson, our Chief Financial Officer, will be discussing our financial performance for the period. After our formal comments today, I'll open the call to questions.But before I begin, I need to remind you that certain information presented today may include forward-looking statements, and such statements reflect High Arctic's current expectations, estimates, projections and assumptions. These forward-looking statements are not guarantee 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, we refer you to our Annual Information Form under the heading Risk Factors.We'll start with a commentary about the industry and talk about some specifics that I hope will deal with a number of questions you may have. Our industry continues to be faced with significant challenges as indicated by a 37% decline in drilling activity in Canada this quarter compared to last year. We expect this muted level of activity to continue into 2020, and until such time, there's resolution of takeaway capacity in Western Canada. The recent PSAC 2020 forecast activity is 4,500 wells. And wells to be drilled down from the 6,948 wells that were drilled into '18 and marginally above the all-time low of 4,300 drilled in 2016.So in Papua New Guinea, activity has continued to be light. And with the prolonged negotiations between the state and the partners of the Papua LNG facility, the proposed expansion of the LNG facility expected to double LNG exports. And Papua New Guinea and -- project partners have indicated they're still targeting timing for the commencement of shipments to take place in 2024.Now based on exploration license, while commitments and increased optimism ahead of the LNG expansion, we expect activities to ramp up in the second half of 2020, which is pushed back from our estimates of [ to '19 ] this year, where we expected fourth quarter activity to see much improved drilling activity.But managing in a difficult environment requires individual vigilant attention to reducing costs, minimizing capital spending to preserve and improve our strong balance sheet, and we have made a difficult decision to reduce our support workforce by 10% and to spend capital spending to only those essential items.Notwithstanding continuing -- continuation of challenging industry fundamentals in Canada and the lull of activities in PNG, I'm going to point out some of the highlights High Arctic experienced during the quarter. We're somewhat fortunate that while service assets are on wheels, and we can drive to anywhere in North America where there's work. Our Production services division actions increased -- experienced a 2% increase in revenue quarter-over-quarter just by the deployment of equipment into the DJ and the Williston basins. Our U.S. operations experienced much improved utilization, giving us a pathway to meaningful contribution to our financial performance.As previously -- as mentioned previously, we have achieved solid reputation with operators in the DJ and the Williston basin, earn consistent and predictable work for the equipment and now starting to see the rewards. We have been exceeding more than USD 1 million a month of revenue from U.S. operations.We remain focused on continuous improvement of our service offering. And on September 30, we issued a press release describing our safety and operational performance, and that consisted of in PNG completing 3 years, 2 million man-hours of the Total Recordable Incident Frequency free. Canadian operations have achieved 1 year of Lost Time Injury free. And in Cold Lake, we've actually recorded 6.2 years, 1.5 million man-hours or Total Recordable Incident Free. And in recognition of our work in Papua New Guinea, High Arctic received the International Association of Drilling Contractors Safety Statistics Award for 2018, which is -- which High Arctic also won in 2017 and 2015.Utilization for High Arctic is 56 registered Concord rigs or 54% year-to-date versus an industry average utilization of 36%. We continue with a strong financial position, $12.1 million of cash and undrawn credit facilities of $45 million and positive working capital of $38.2 million.We remain the sole drilling contractor that's active in PNG, with 103 and 104 active throughout the year. And drilling plans from what I would see will continue -- we're continuing to see an active break through 2020. And our rental and support business continues to benefit from active drilling and payment of Oil Search, and we expect to continue that through '19 and, again, in 2020.Our customers considering offers with regard to Rig 104, which we had mentioned has been demobilized and is now prepped for -- being prepped for other work -- potentially other work. However, the rig is actually being considered to improve its capabilities, and we're somewhat uncertain at this point. It's time to return to work. And to the extent that it is being upgraded, it does create opportunities for 115 and 116 to fill the void that it would otherwise would have taken on. Rigs 115 and 116 are actively maintained and can continue to work immediately without any delays and ready for possible drilling by operators requiring hold acreage with looming lease expiries, which need to be held with drilling activity. Furthermore, we expect reasonable utilization of our Rig 102 to perform abandonment and well workover activities in 2020.So I'm going to turn the call over to Jim to take us through some of the financial matters.
Thanks, Cam. The performance of our Production Services segment and our PNG operations resulted in consolidated revenue of $49.6 million in the quarter, which generated $6.3 million in adjusted EBITDA. This compares to $54.7 million and $17.4 million in revenue and adjusted EBITDA, respectively, in the third quarter of 2018, which experienced higher contracting revenue and activity from our PNG drilling operations.Revenue in our Production Services division increased 9% to $24.3 million from $22.2 million in the third quarter of 2018. This was supported by higher snubbing activity year-over-year with 4,679 hours in the quarter versus 2,500 hours in the same period in 2018 in the North American operations.Concord rigs generated $16.1 million in revenue during the quarter on 26,482 operating hours with an average revenue per hour of $608, whilst achieving a 51% utilization in the quarter versus 36% utilization generated by the CAODC-registered rigs.Operating margins as a percentage of revenue was 12% in the quarter versus 18% in the same period of 2018. This margin decline was due to lower revenue per hour, down 1% year-over-year, slightly higher repair and maintenance costs during the quarter. The strategy to diversify into new markets generated 2,068 hours of service rig activity and 1,868 hours of snubbing hours work in the United States in the third quarter of 2019, representing approximately 9% of the quarter's revenue.Revenue for our Drilling Services segment decreased to $18.7 million in the quarter from $25.5 million in the third quarter of 2018, primarily due to the expiry of the take-or-pay contract for Rig 116 on November 2, 2018, which accounted for $6.2 million of EBITDA in the same quarter in 2018. As Cam mentioned, Rig 103 will operate continuously on infield work during the quarter, while Rig 104 will continue demobilizing to Moro, which was completed late in the quarter. Rigs 115 and 116 are preserved in cold stack during the quarter and are ready for immediate redeployment.With expected drilling activity in the quarter and no contribution from the take-or-pay contract in Rig 116, the Drilling Services segment generated $3.8 million in operating margin. And the percentage of revenue, operating margin decreased to 20% in the quarter from 45% in the third quarter of 2018.Revenue for Ancillary Services segment was lower at $7.4 million in the third quarter of 2019 compared to $8.1 million for the same period of 2018. Revenue, international rentals were lower in line with lower drilling activity, and nitrogen was below last year's activity during the quarter. This was partially offset with higher Canadian rentals activity.Operating margin as a percentage of revenue decreased to 54% from 68% in the third quarter of 2018 primarily due to reduced contribution from higher-margin divisions in the quarter.General and administrative costs increased to $4.3 million in the quarter from $3.8 million in the third quarter of 2018, and that's primarily due to a $400,000 receivable when a customer entered into receivership. The company is pursuing recovery out of that receivable.The adjusted net loss for the quarter -- in the third quarter of 2019 was $1.5 million or $0.02 per share compared to adjusted net earnings of $7.7 million or $0.15 per share in the third quarter of 2018. We continue to maintain a strong balance sheet and exited the quarter with $12.1 million in cash, nothing drawn under $45 million credit facility and positive working capital balances of $38.2 million.So with that, let me turn things back to Cam.
Okay. Thanks, Jim. The Canadian service business continues to outperform the industry, providing superior quality of service, highest standards of safety in very difficult industry conditions. Even with continued the headwinds looking into -- looking out into 2020, we expect our key clients to maintain activity levels through 2020, consistent with the activity levels experienced in 2019. Our advantage is that 86% of our Canadian well service business is tied to contract arrangements.We have turned the corner with our efforts to gaining market share in the U.S. and now seeing a rewards through the contribution to our financial performance. We're poised to reap the rewards of the ramp of activities in PNG and could see a return to those years experienced through '15 to '16 as operators delay the start of development activities, which results in bumping up against [ services ], meaning the growth in drilling commitment obligations.We continue to maintain strong balance sheets, offering considerable financial flexibility, allowing us to be somewhat patient in exploiting growth opportunities to consider consolidation opportunities.And that concludes my comments, and we look forward to your questions. I'll turn it over to the conference operator. We'll open the line for the questions.
[Operator Instructions] The first question is from Greg Colman from National Bank Financial.
I just have a couple of quick ones here. I'd like to start with a focus on sort of actuals in the quarter before I ask a few things about your outlook. In the quarter, can you give us a bit of a tighter understanding of how active Rig 104 was? I understand it completed its program in June. Began -- which is the end of Q2, began moving back to the Moro base to be stacked and fill the next well, and that next well was completed within Q3. So it feels to me that Rig 104 had sort of this undelay in quarter. There was a move at the beginning of the quarter. And then a well was included intra-quarter and then a period at the end of September where it wasn't working. I'm just trying to understand how much contribution in Q3 Rig 104 actually gave?
Thanks for the question, Greg. So the -- if we're actually paid for 104 right up until mid- -- almost the beginning of September. Yes. So we have a skeleton crew that manages the stacking process and the maintenance required, but not significant by any stretch. At this point, we're essentially waiting on our clients to determine its next assignments for potentially improving the [ utilization ].
So that's good information on the outlook. But I'm actually talking about quarter 3 itself. How many days the Rig 104 will work?
So it would essentially right up until...
End of the quarter?
Not quite at the end of the quarter, but it was right up to the mid-September period.
So even during the period where there was moving back and forth from the Moro base it would still -- you would have still revenue-generating days or higher?
Correct. That's right. That's right. [ We're changing ], whether it's drilling or moving. So...
So it's something like -- maybe not 90 days, but like 70 to 80, something like that? We can make some assumptions, but that's the approximation?
That's correct.
Got it. And now just taking stock of the 4 major rigs you've got in PNG, excluding 102 for a minute. So Rigs 115 and 116 remained cold stacked, ready to be redeployed, check that box. Rig 103 works continuously through the quarter, expected to do so into 2020, check that box as well, pretty easy to understand. Rig 104 demobilized in mid-September, and you're awaiting its next assignment to a short period. Do you have any additional views as to how long that short period could be? Is it just sort of a 2019 thing where we should just remove it from our numbers in Q4? Or could that stretch out into 2020 as well?
Unfortunately, we just don't have great clarity of where our clients going with it. There is -- and we've experienced this circumstance before where literally, within weeks, we could be back mobilizing that rig out to a growing activity. And I think just to give a little bit of perspective on that decision-making. At this point, we have the Elk-Antelope portion of the expansion, which is driven by Total. That part of the grass agreement struck with the government for the most part.The second part of that equation is the expansion. So that's 2 dedicated trains for the expansion. The last train is intended to service the new discoveries that took place in north of the Hides area that is operated by ExxonMobil. And that part of the gas agreement has not been finalized.The expectation that we're getting from operators is that, that will be completed before year-end. And Total will not advance their program until such time as the agreements for the third train has been finalized. And it's important with regard to ensure that 3 trains is going to provide some synergies with regard to cost versus just 2 trains being added. So that's a bit of a complication of advancing programs right now.
So it sounds to me with that complication that it's highly unlikely that anything other than Rig 103 is operating in Q4 in PNG.
Can't really provide much more color than what's -- what I've given. So that's a bit of speculation on your part, but I just -- I can't really give you much more direction than we have great uncertainty of its return to work.
Got it. Okay. I guess more than just -- it's a bit of a hypothetical, but just trying to understand on the Rig 104. If you were to get a call from the owner, the operator, that it was time to go back to work for it, or if there is an opportunity for it to go back to it. Is there any reason that it couldn't? Staffing, equipment, anything like that?
No. Not at all. Not at all. And like I said, there is consideration for it to be upgraded. And to the extent that, that decision has taken place, then the -- any work that takes place that would be in addition to 103 would default to 115 or 116.
So this would increase the probability of 115 or 116 getting work, if the 104 was unable to do the work, there was...
That's correct.
And when do you think we can get clarity on the regulatory side. Is that something that you internally are expanding capitals before year-end? Or do we just not have clarity on the time line either?
We do -- what we have is Oil Search and Peter Botten has been -- has made public announcements that his expectation is that the agreement would be finalized before year-end. That is his expectation. There is a PNG Energy Conference, energy and mining conference, that takes place in December. And quite often, the government will make significant announcements, and that could be a key time. That's the first week of December that's taking place.
Got it. Okay. And then just one last one for me. Sorry to keep harping on this, I'm just trying to understand some goalposts here with Rig 104. You mentioned that -- you said that there's -- in the past, sometimes you can get a call and it's in a couple of weeks. And there's no reason that we can't go back to work if that was to happen. So we understand the near-term goalposts, which is -- could be as early as the end of this month or early December. That's the other end of the goalpost there. If there was an upgrade, if there was time sitting on the sidelines, how long could it take in sort of the other end of the spectrum, if it was not just right around the corner?
The -- I think the key question is how much drilling are we going -- is there enough drilling, is there expectation of drilling that's going to take place beyond 103 in 2020. And our belief is that we will see that, and it will be back half of 2020.
The next question is from Elias Foscolos from Industrial Alliance Securities.
I've got of a couple, maybe one follow-up question. And perhaps I missed it or didn't interpret it right. You do see 103 being relatively active throughout 2020 and with the possible possibility of another rig back half of the year. Is that correct? Or is that reading a bit too much?
Elias, no, that is exactly right. That is our expectation.
Okay. Now when we're talking about the other rig, I want to sort of flip to 102 because 102 has not -- was that -- is that comment exclusive of Rig 102, because 102 would be doing different work?
Yes, it is.
Okay. Good. So focusing a bit on 102. I can't remember the last time that it was used, we're probably going back 3 or 4 years. So you do see the possibility of 102 coming back for workovers or something like that at some point in time? It was a contributor, way back when?
Correct. And we spent a year for reconditioning that to ensure that it is ready for service. And our expectation is anywhere between 4 and 9 wells need to have service work done to it. And it'll be a combination of both abandonment because we've got 100 wells in-country -- or sorry, more than 100 wells in the country but that require abandonment and workover work. And there's approximately 60,000 barrels of production that comes of oil production and mostly from Oil Search that is in-country that is -- requires service work.
Yes. Yes. I know. Okay. So we've got the possibility of that coming in. I'll pivot away from Papua New Guinea for a moment and go back to -- if I can find that the comment you made about U.S. in Production Services, and it's very visible in the financial statements, if my calculations are correct. You did about $4 million in Q3 out of the U.S., and that was a big pickup from Q2. Should we continue to expect a tick-up in the U.S.? Or have we hit a plateau at this point, given some softness in the U.S.?
I -- the expectation, I think I provided a little bit of guidance in that respect that we were doing in excess of $1 million a month of revenue, and that is continual increasing utilization of both the 2 rigs that we have. And combining, we've controlled our cost by being at the combiner services of snubbing and our drill-out of the package that we have operating in the DJ Basin. So we're -- we continue to monitor activities and seeing some slowdown and -- slowdown of activity in both the Niobrara, probably less so in the Williston and trying to monitor that to determine what other equipments that we can deploy -- safely deploy. Our experience to date has been build it, they will come. It's not a good business model, but its establishing franchise work is absolutely key to be able to ensure that you have utilization that you can make money on.
Okay. So with the contribution on the revenue side, I know you don't segregate to this level, and I haven't punched numbers through yet. Are you seeing EBITDA contribution from the U.S. activity that is positive now?
Yes. Yes.
Okay. One last question, and it has to do with the cost reduction or the head count reduction. Did we see any of those costs in Q3? And can we make the assumption going forward that, that might translate through to lower G&A costs?
The answer is yes. So it will come in 2 forms. So our fixed operating costs, there's a component that exists there, and there's a component that exists in G&A. So both of which translates into an improvement of EBITDA margins. And the -- they took place, those initiatives took place late in the quarter. So we captured some of it for the month of September, but fairly negligible.
[Operator Instructions] The next question is from Patrick Tang from AltaCorp Capital.
A few questions here. So in regards to Rig 104, if it goes down the upgrade route, how long would these upgrades take? And are there any specific customer conversations that have based on 115 and 116 to fill that void? Or is that just [indiscernible] at this point?
Patrick, these are -- you're asking some very specific questions around what the plans are for the owner being OS to all of the rate that we're operating. And we just -- there is great uncertainty regarding exactly what is required, and so in terms of rig back within the country. To the extent that there is an upgrade in its potential hook capacity and horsepower, it drives well designs around that particular rate, but not -- there's been no void of requirements in the four -- 1,500 horsepower rigs, power 2 rigs, plus the Oil Search, 2 rigs. No void of your deficiency of the capabilities of one particular rigs. So it's a bit of a weight of a nice to have versus a necessity. And those are the, I think, part of the decisions that leave us with uncertainty of -- and the necessity of actually going through that upgrade process.
Okay. Just switching gears to the U.S. Do you think the U.S. operations to service rigs and snubbing units is a great place right now for the level activity you're seeing in the U.S.? Or is there any opportunity? Or are you guys just seeing any opportunities to grow that business, whether you're moving equipment from Canada or leasing acquisitions?
Yes. So 2 parts to that question. So there's 2 services that we see as quite distinct with regard to service rigs and our snubbing equipment. And our -- the service rig package that we have that's operating is a quite a robust 300,000 hook with 1,500 horsepower pump that's behind it, doing drill-out work. So basically plug drill-outs after removing those after frac.Following that is our snubbing equipment goes in. So on a multiwell pad, that may be as much as 26 wells on a particular pad. We keep a rig assist, snubbing units in place to be able to follow every 4 days, we wound up snubbing in the production tubing that takes about 1.5 days to complete, and then back to another well for the drill out. So that's -- that is an area that we believe to be quite robust and continue to be very robust.However, there's very little equipment in Canada that can be moved to fill that requirement. And most of that activity taking place in the U.S. is new build work that those new builds starting in approximately 2012 to deal with the longer lateral rigs, higher pump horsepowers. So we're carefully examining that and how we hope to capture more of that work.The production work is some of our heavy doubles that we have in Canada, and they're well suited to move into -- certainly the Williston Basin, where there's much more well activity for oily or activity and aging wells that exist, that needs a need -- now need work with wells that are well in excess of 5 years of age. Our goalpost become mandatory. So that's the key place that we're looking at for moving more of the Canadian equipment.
Okay. Just one last question for me. Just in terms of capital priorities, that the repurchase program expiring here soon in this month, do you see programs being renewed and pursuing more repurchases? Or is capital going to go to more of the organic growth opportunities you see?
We will be renewing our NCIB, then the decision is what are we going to be repurchasing shares. That's a decision yet to be made.
There are no further questions at this time. I would like to turn the meeting back over to Mr. Bailey.
Okay. Well, ladies and gentlemen, thank you very much for joining the call and look forward to following up any other questions that you may have. Both Jim and myself are available for the calls. Thank you.
Thank you. The conference has now ended. Please disconnect your lines at this time, and thank you for your participation.