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Good afternoon. My name is Adam, and I'll be your conference operator today. At this time, I'd like to welcome everyone to the Ensign Energy Services Inc. First Quarter Results Conference Call. [Operator Instructions] And now I'd like to turn the call over to Bob Geddes, President and Chief Operating Officer. You may go ahead.
Thanks, Adam. Good afternoon, everyone. This evening or this afternoon, we have with us Mike Gray, VP and CFO. We also have Mike Nuss, calling in from Houston. Mike's our EVP for U.S. and Latin American operations. We also have Tom Connors here in Calgary, EVP Canadian and International of East operations. So the first quarter of '18, we can summarize it, a lots of moving parts this quarter, as we see the bifurcation develop between the U.S. and Canadian markets widen. In this quarter, we saw Canada drop both in days and EBITDA year-over-year for the quarter. This, of course, is a symptom of a larger macro geopolitical problem from why we've decided to contract one of our idle Canadian ADR 1500s down to the U.S. on a full carry term contract in the mid-20s, earning about double the EBITDA. The U.S. is exactly the polar opposite, as we saw activity increase year-over-year by 30% for the first quarter and EBITDA increased 21% for the same period. We're also seeing rates move $1,000 to $2,000 a day quarterly, depending on the rig type, and we have about 70% of our U.S. fleet on long-term contracts with escalation provisions. First quarter results were somewhat muted by a few one-time events. Let me just mention a few those. Australia had about 3 weeks of lost revenue and downtime expenses due to a top drive failure. We had a couple rigs that came off contract in Oman in the quarter. We had one-time reactivation expenses for 6 U.S. rigs, which are feeding into a busier U.S. market, and will generate incremental EBITDA going forward. Our U.S. well service client base had a delayed start into the new year, but that ground is quickly getting made up in the second quarter, as we enjoy 70% utilization. Also point out, we just received the first of our 4 new long-reach horizontal completion multi-service rigs for our U.S. well servicing division. Some inactive days in first quarter U.S. as a result of contract realignments that high-margin work, also were one-time events, and we also moved to a straight-line depreciation policy, effective January 1, which Mike Gray will expand on more. So for more detail on our first quarter, over to you, Mike Gray.
Thanks, Bob. Usual disclaimer. Our discussion may include forward-looking statements based upon current expectations that involve a number of business risks and uncertainties. The factors that could cause results to differ materially include, but are not limited to: political, economic and market conditions; crude oil and natural gas prices; foreign currency fluctuations; weather conditions; the company's defense of lawsuits; and the ability of oil and natural gas companies to pay accounts receivable balances and raise capital or other unforeseen conditions, which can impact the use of our services supplied by the company. Now to start with the overview of Q1 2018. The modest increase in oil prices resulted in increased levels of demand for oilfield services in our United States operations in the first quarter of 2018 compared to the first quarter of 2017. Geopolitical factors and limited access to markets hampered Canada's ability to take advantage of the increase in oil price. Internationally, we saw certain rigs long-term contract that were not renewed. Operating days were flat for the first quarter of 2018 overall, with Canadian operations experiencing a 16% decrease; the United States operations, a 29% increase, and international operations showing a 14% decrease in operating days compared to the first quarter of 2017. Adjusted EBITDA for the first quarter of 2018 was $52.3 million, 4% higher than adjusted EBITDA of $50.1 million in the first quarter of 2017. The 2018 increase in adjusted EBITDA can be attributed to higher revenue rates across oilfield services equipment fleet. This was despite a year-over-year weakening of the United States dollar against the Canadian dollar that negatively impacted the United States international financial results on translation to Canadian dollars. The company generated revenue of $258.5 million in the first quarter of 2018, a 3% increase compared to revenue of $251.3 million generated in the first quarter of the prior year. Gross margin increased to $63.1 million or 27.8% of revenue net of third party for the first quarter of 2018 compared to gross margin of $60.6 million or 29% of revenue, net of third party for the first quarter of 2017. The 4% increase in overall margin reflects higher revenue rates, while maintaining cost control. Depreciation expense in the first 3 months of 2018 was $98.6 million, 24% higher than $79.4 million for the first 3 months of 2017. The increase in depreciation expense was the result of the company reviewing useful life estimates for all rigs and related equipment, and determined that using a straight-line method versus operating days, would more accurately reflect the future economic benefits related to these assets. These adjustments were applied perspectively, and as such has caused an increased depreciation expense in 2018. General and administrative expense in the first quarter of 2018 was 2% higher than the first quarter of 2017. The consistent general and administrative expense has been reduced substantially in recent years, and reflects the company's continued initiatives to reduce cost. Total company debt net of cash balances increased by $19 million or 3% in the first quarter of 2018 from $707.6 million at December 31, 2017 to $726.6 million on March 31, 2018. Net purchases of property and equipment for the first quarter of 2018 totaled $15.4 million. The purchases of the property and equipment relates predominantly to maintenance capital for certain drilling rigs, and the construction of 4 service rigs for the United States. Net capital expenditures for the calendar year 2018 remain targeted at $64 million. During the quarter, the company announced the closing of a non-brokered private placement of unsecured subordinated convertible debentures for gross proceeds of $26 million. Subsequent to March 31, 2018, an additional $11 million was issued. Also, as a result of the company's adoption of IFRS 9 related to financial instruments on January 1, 2018, the company has a residual undiscounted accounts receivable related to the company's international operations it provides and Venezuela was provisioned for us. On that note, I'll pass the call back to Bob.
Thanks, Mike. So next, we'll move to Canada International East. Tom will give us a summary on that.
Good afternoon, everyone. I'll start with our Canadian operation, and then move on to our Australia and our MENA operation. In Canadian drilling, while Ensign trailed the industry average utilization in the quarter by 2.1%, the continued performance of our premium assets in the most active plays resulted in a 10% share of total industry days in the quarter with 8.9% of the fleet. While days for both Ensign and the industry decreased marginally on a year-over-year basis, average revenue rate per day remain neutral with some rates increasing on some portions of fleet, offset by some contract rollover on deeper rigs in mid-2017. Spot market rates for 2018 are expected to remain roughly flat until later in the year. However, as new contracts are signed, they are rolling over onto contracts with improved rates over the previous 2 years. In our directional drilling business, we maintained market share in the quarter with slightly higher day rates, as the same quarter as last year. Our well servicing operation -- Canadian well servicing followed the trend experienced by many in the industry, with slightly lower hours in the quarter. However, higher rates in Q1 last year and fewer rig reactivation costs resulted in slightly higher year-over-year EBITDA. Our testing business achieved significant improvement in activity levels for Q1 last year, and continues to rebuild from the trough of 2016. Our rental activity -- our rental business activity continues to improve with some product lines being completed sold out in Q1. We expect to continue to see an improvement in the rates for specific product lines, as we continue to move through 2018. And our outlook for Canadian operations in general, we expect overall industry activity in Canada in 2018 to remain relatively flat to 2017, with the industry trading somewhere from 67,000 to 70,000 days in total. While visibility to 2019 is limited, we expect basic fundamentals to continue to slowly improve. In our Australian operation, days in Q1 2018 were relatively the same as Q1 2017, with revenue being slightly lower, as some rigs rolled over onto new contracts. While days were slightly lower than Q4 2017 due to breaks in between contracts and operators, activity for the year is expected to increase by 5% to 10%. The outlook for EBITDA for the year remains somewhat flat to modestly positive on a year-over-year basis, as the improvement in activity is somewhat offset by some contracts experiencing rollover at slightly lower rates. And finally, our MENA operation. As Ensign technology continues to set new benchmarks in the area, activity remained at 3 rigs in the first quarter 2018, with some discussion on [ approved ] potential activity in Oman later in 2018 or early 2019. And with that, Bob, that wraps up my portion. I'll pass it back to you.
Thanks, Tom. So Mike Nuss will give us a summary of the U.S. operations in Latin America. Over to you, Mike.
Thanks, Bob. Good afternoon, everyone. I'll start out with the U.S. The United States recorded $125.5 million of revenue in Q1, an increase of 28% from the $98 million recorded Q1 2017. The company's U.S. operations accounted for 49% of Ensign's total revenue in the quarter, up from 39% in first quarter '17. Drilling rig operations days increased 29% to 2,904 days; Q1, up from 2,253 days, Q1 of 2017. Our well servicing activity, albeit getting off to a slow first quarter starts still recorded a 12% increase, first quarter of '18 to 22,406 operating hours, up from 20,081 operating hours, Q1 of '17. In the U.S., we currently have 43 rigs operating, 20 in the Permian, 13 in California and 10 in the Rockies. Continued tightness in high spec AC 1500 horse power class is placing upward pressure on day rates for that asset class. We have also seen improved activity in California and currently carry 40% of that market. Additionally, we are relocating an ADR 1500S rig from Canada to the U.S. Rockies on a term contract full carry. Our directional business is also up year-over-year, and currently has 7 units operating, 2 of which are on our turnkey projects. Our well servicing group has 4 newbuilds coming, as Bob alluded to. One is already here, the other 3 coming in second and third quarters. Those are all designed for completion work on long reach horizontals. Moving over to Latin America. Ensign's Latin America division operates a total of 16 rigs, operating at approximately 50% utilization. In Argentina, we're operating in the Vaca Muerta with 3 super spec AC 2000s that are working for IOCs. Additionally, we have had 1 to 2 legacy rigs working there as well. At Venezuela, we've continued cautious activity with mixed companies, and are actively managing our AR in a challenging geopolitical market. With that, I'll turn it back over to you, Bob.
Thanks, Mike. So back to the operator, Adam, for Q&A, if we could.
[Operator Instructions] And our first question comes from Ian Gillies from GMP.
Can you guys, perhaps, elaborate a little bit on what the strategy may be over the next kind of 12 to 24 months from a, I guess, build versus buy scenario for your U.S. rig fleet, because, I mean, given that activities have been relatively stagnant over the last number of quarters?
Yes. The -- good question. The -- what we're seeing in the U.S., we've got about, arguably, 17 super-spec rigs. We've probably got another, let's say, 10 or 12 rigs that -- for probably in the range of $4 million to $5 million could be modified into super-spec rigs. We've just been letting the market move up here. Obviously, the industry is a little ways away from newbuild. I think we need to see numbers in the high-20s before you start to develop newbuilds. $22 million ADR 1500S type rigs are probably closer to $24 million to $25 million now, which perhaps tells you that you have to definitely be up in the higher 20s before you can make any sense of that. So the market is feeding into that. Our goal this year is, of course, is to continue to improve the balance sheet or pay down some debt and see what comes forward.
And I suppose if you were to move past those 29 rigs because there's still some triples in your fleet, do you think -- is there a dollar amount you could maybe perhaps put around to what you think some of those rigs would cost to upgrade to turn them into super-spec rigs? Or is it not even possible, given the way they're configured today?
Yes. Well, I think -- I think as a bigger question there, is not every rig in the U.S. into the future, as oil prices move up, will be needing to drill 2.5-mile lateral horizontal wells. The basins are different in the U.S. and in Canada, and a fleet mix is required to tag those. There's no question, in the Permian, the super-spec rig is the desired rig of choice, and that's why all of us are working, where some of our competitors are not. So anyway, I think one has to be mindful that there's a fleet of rigs that manage drilling wells and not just one specific type.
And as you think about the rig upgrades, I suppose, whether it be for those next 12 rigs that are $4 million to $5 million or you move further than that, are you able to outline some of that payback scenarios you'd be looking for? Because some of your peers have obviously been quite aggressive in moving along those lines. And so, I guess, you just -- do you need better terms than some of your peers are seeing to move forward?
Yes. I think that internally, we always drive to a 20% after-tax internal rate of return on new capital. So we continue to do that. And it obviously -- I mean, you saw us a few years ago get ahead of the super-spec rig craze, and we started upgrading our rigs ahead of the market. Those are being done for 1 to 2.5, maybe the highest most recently, 3. The next phase, obviously, you're doing the easiest ones first, and you're doing the tougher ones as the market increases, and that's what you're seeing happen now.
Okay. And one last one with respect to the U.S. What does the opportunity set look like right now in California relative to say, 3 or 6 months ago, given the strength in the WTI quote?
Yes. Mike Nuss, you want to handle that one?
Sure. The -- yes, we've had a couple customers that had good results and with increased JV exposure, have increased their budgets quite a bit. And so I think at these product prices versus 1 year ago, most things in California become quite economic. So you get their balance sheet healed up. You get some JV-type money coming in, and there's a lot more projects that come up and our rigs go back to work. And then that's a particular area, as Bob alluded to, where the super-spec rig in California isn't a 1500 ACS walking rig. It's still our -- it's our AC hydraulic single that can do all the high spec work, but is still nimble enough to get into all those crowded California fields. And still, it's a -- those are shallower zones, but they're still doing horizontal works. So to me, the bulk of California work is a -- the super-spec there is our electric AC hydraulic single. It still is a pad moving rig, but it's a unique configuration, given the 1- to 5-acre spacing that you're moving around in some of those areas. And -- but we are -- additionally, we do have some AC 1500 walkers in there working as well, as that market picks up. So there's a breadth from the typical mechanical single to the high spec AC hydraulic, also having some work come up in the 1,500-horsepower range. So -- but all that being said, it's a 50-rig market. It's not a 400-rig market like the Permian.
Okay. Internationally, days were down, call it, 12% sequentially. Can you just provide a bit more of a recap of what happened there? I mean, did -- was it mostly rigs coming off in Venezuela? Or was there -- were there issues in other parts or in other operations, and do you view it as transitory? And I guess, the active rig count bounces back in through the remainder of the year? Or is it -- is that Q1 number representative where you think that business is going to be for the next number of quarters here?
Mike, why don't you take the Venezuela component of that, and then Tom, the other component of that?
Yes. In Venezuela, we did slow down a couple of rigs. Again, as I put it, we're continuing cautious activity and mindful of the mix between making sure you can collect AAR versus what opportunities there are. So we are continuing to collect AAR, but with some of the turnover in personnel in the mixed companies and some of the turbulence, there's a couple of rigs that just made sense to idle for a period of time until those situations got worked out.
So in Australia, although the number of days in a quarter about the same as first quarter last year, they were down slightly from Q4 2017. And that's just simply a matter of moving from a little bit of break moving from one operator onto another, as they move onto the new contracts, so there was about 100 days less in Q1. Overall, for the year for 2018, we'd expect to be up about 10% on days in Australia versus where we were in 2017. And in MENA, there are really no change in activity, 3 rigs running continuing steady through. So Australia about 100 days down versus Q4, but we expect to make that up over the course of the year with some improved -- expected improved activity.
Okay. Last one for me, guys. With respect to the balance sheet, obviously, a lot of the debts come current. Could you maybe just provide a bit of an update on what the plan is through the remainder of the year? And perhaps, what the strategy was behind issuing the converts earlier in the quarter rather than doing some other means of financing and why that was something you chose to go and do?
Sure. So for the balance sheet, we do have the notes coming current in February 2019, and then the facility will be expiring in October. So we're currently in negotiations with the bank on the facility. Ideally, we'd like to upsize the facility to give us some more room to take out the notes until 2019. For the convertibles, it was really just giving us some additional liquidity. I mean, that's one concern I think a lot of people always had was the -- how much liquidity we did have. So we thought it was a good point in time to get some additional liquidity, as we go into negotiations with the bank.
And your next question comes from Ben Owens of RBC Capital Markets.
On the one-time items that you guys called out for the quarter, just curious, how much of an impact did the 6 rig activations have in the first quarter from the U.S. business?
Oh, not more than a couple million.
Okay. Not more than a couple of million dollars, is that what you said?
Correct, correct, yes.
Okay, great. Helpful. And then on the contract book for the U.S., I think you guys said in the press release that there's 13 rigs that are contracted for longer than 6 months. Just curious what's the average term on those 13 rigs?
Yes. Actually, we have 30-year or 70% of our fleet tied up on term contracts that are 6 months or greater, going as far as 3 years. The interpretation of that may not have been correct, but in any case, we have 70% of the U.S. fleet that are tied up and turning over on a 6-month contract cadence.
Okay. So it was 30, not 13?
Correct. Sorry about that.
Okay, understood. And then on the well servicing side, when you guys talk about extended reach horizontals rigs, just curious, how many of Ensign's new well servicing rigs fit into that extended reach horizontals spec category, versus how many, I guess, legacy rigs? And I guess, what's -- also, what's the difference in utilization and day rates for the 2 different classes of rigs there?
Yes. Mike, Mike, did you want to take that?
Sure. Again, there's probably a little over half of the fleet is in California, and so that fleet doesn't need to have the long reach capabilities. So keep that part in mind. The 4 new ones we have coming in all have that capability. We did a new build last year, which had that capability, and probably have another 0.5 dozen before that, that was doing more of the long reach. Although long reach continues to be reinvented, right, from 1 mile to 1.5 miles to 2, and now 2.5 to 3. But what those typically tend to be is 24-hour operations. So you're not only getting the better rate and adding some more equipment, but you're on 24-hour operation, if you will, so it's a combination of all those things. But in the -- so for the Rockies/ Texas market, probably 2/3 of the rigs then would be doing more towards those kind of operations, as well as we always still do production work and P&A work.
Okay, that's helpful. Is there a significant difference in the day rates on the extended reach rigs versus the other ones?
Yes, extended reach 24-hour operations would be significantly different from routine [ piece ] legacy well -- vertical well production work is.
And your next question comes from Mike Mazar from BMO Capital Markets.
Just a quick question here on the balance sheet. You guys have a line item, inventory investments and others. It's more or less doubled here in the last couple of quarters. I'm just wondering if -- and you also changed the name of it. I'm wondering if you can just remind us what's in there. And maybe what's in there now that wasn't a couple quarters ago that precipitated the change of name of that line item? Maybe I'm reading too much into it or maybe there's something in there that precipitated that name change.
Mostly, from time-to-time, we'll look at certain things that we consider to be investments of what spend that we have invested in, therefore have to change the line from inventory investments and other. And then we also did have a bit of a buildup with inventory, as the international operations are going to start to increase in 2018.
Okay. So would these be securities?
Maybe investments of security type, but wouldn't be cash or cash equivalent type.
[Operator Instructions] Our next question comes from Daine Biluk from CIBC World Markets.
On Venezuela, can you share if there's been any meaningful change to DSOs? And potentially, how many rigs do you have running in the country right now?
We -- well, DSOs, Mike -- there's been...
Yes, on the DSOs there's probably been in a bit of detriment, just given the sanctions. So the United States came out with some clarification on collecting of accounts receivable over 90 days, where you have to get an OFAC license. So we're in the process of getting those OFAC licenses for the accounts receivable between August 2017 to March -- I believe, it's March 14, 2018. So with some of that, you'll see some aging on that side. Our invoices under the 90 days, there's no issues on collections on that. So there's, I'd say, a bit of a degradation, but it's really related to some of the sanctions that we have in place.
Got you. Okay. For some of the larger international tenders out there, what has been the root cause of why we haven't seen some new deals signed yet in the market? Are processes getting delayed or are terms with contractors not where they need to be?
Yes. I would say that a combination of both. You're seeing a lot of -- a little bifurcation between the Tier 1, Tier 2 contractors. Some of the -- some of them are very tough to compete against the -- where the specification -- technical specification hasn't been determined too tightly. Where the specification has been determined tightly, and for instance, we're shortlisted currently on large 5-year contract in Oman for ADR-type rigs. That will be coming out here probably late 2018. There are -- as you know, the gestation on contracts in the international period is a lot different than it is in North America. And I mean, we said this quite sternly, is that we're not interested in engaging in any new countries at this point in time, but we're fully focused on enhancing our current footprint in the countries we are in at this point.
Understood. That's good color. Switching gears a little bit. For you to move more rigs to the U.S. from Canada, what do you need to see to trigger that, whether that be contract term? Is day rates there? And then do you need to see the customers pay the mobilization fees?
Well, I think our latest move, saw the customer move the -- or pay the move for the rigs, so that's a proxy on a couple of things. It shows the desire to have our ADR-type spec rigs into that market. I think that it's certainly I think the elephant in the room is by May 31, we're going to have some sort of understanding of where Canada is at for pipeline. And not that Canada is defined by that, but certainly, it has some impact. There are lots of customers across the Canadian basin making a good living off of the current commodity price. So I do think though that the rest of our fleet here in Canada is fully utilized, and we'll see what happens here over the next 3 months.
Understood. And then last one for me. In the U.S., you guys have talked about the tightness in the AC 1500 triple market for a few quarters now. Are you starting to see stronger demand trickle down to lower spec rigs at all? Or is it really the case where you need to see the upgrades on those to get that advantage?
Well, I think the whole harbor floats all boats, of course, and it's picking up all the rigs behind it. But there's no question for the client base that we work for, they demand the best. They're also willing to pay for it as well. Our rigs with Edge Controls, they're also drilling wells for less cost per footage hole drilled. So even though they're paying a higher price, they are getting their value in it, but it does trickle down, absolutely.
And we have no further questions. At this time, I will turn the call back over to Mr. Geddes for closing remarks.
Thanks, Adam. So just to wrap up, again, a lumpy quarter, but clear sailing ahead, as we reactivate more rigs in the U.S. as rates continue to improve significantly into the mid-20s for our super-spec ADR 1500-type rigs. In South America, our focus, as Mike has pointed out, has obviously been in Argentina, where our new ADR 2000s with our Edge system are drilling record wells in the Neuquén field. With only a few rigs running in Venezuela, we've de-risked that business unit to a large extent. While Canada was somewhat muted in the second -- or in the first quarter, we have a strong book through breakup and expect to benefit with higher utilization then our peers through the second quarter and beyond. We'll also see more activity in Australia, as local gas supplies start to tighten up there. We continue to roll out our Edge Controls technology both in the U.S. and Canada. We also expect to have our Edge Controls in our Oman ADR rigs by the year-end. I'd also like to point, we now have our basic Edge Controls platform in over 25 of our ADRs, most of those in U.S. and are currently installing Edge in some of our Canadian ADR 1500s. Keep in mind that we purposefully designed our Edge Controls rig operating systems, so it could easily and cost effectively be installed on our entire fleet into the future, both electric and hydraulic ADRs. The commercial platform for the Edge reflects a charge of about 30,000 a month for Edge Controls with our APM, that's the Advanced Performance Management support team. We're currently working on new apps for Ensign Edge operating system, things like the ROP optimizer and the auto tuner, both of which drive further drilling efficiencies and margin expansion. So with a lumpy first quarter behind us, we're set to grow EBITDA into this growing demand for our ADR rigs and our other lines of businesses as our U.S. business expands and our Edge technology continues to drive commercial benefits. Thank you, and we'll look forward to talking with you in August.
And this concludes today's conference call. You may now disconnect.