Ensign Energy Services Inc
TSX:ESI
Ensign Energy Services Inc
TSX:ESI
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Ladies and gentlemen, thank you for standing by, and welcome to the Ensign Energy Services Inc. Third Quarter 2020 Results Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. [Operator Instructions]I would now like to hand the conference over to your speaker today, Nicole Romanow, Director of Investor Relations. Thank you. Please go ahead, madam.
Thank you, Chris. Good morning, and welcome to Ensign Energy Services' Third quarter Earnings Conference Call and Webcast. On our call today, Bob Geddes, President and COO; and Michael Gray, Chief Financial Officer, will review Ensign's third quarter highlights and financial results, followed by our operational update and outlook. We'll then open the call for questions. Our discussion today 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 materially differ, 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, the ability of oil and gas companies to pay accounts receivable balances and raise capital and any other unforeseen conditions that could impact the use of our services supplied by the company. Additionally, our discussion today may refer to non-GAAP measures, such as adjusted EBITDA. Please see our third quarter earnings release and SEDAR filings for more information on forward-looking statements and the company's use of non-GAAP measures. With that, I'll pass it on to Bob.
Thanks, Nicole, and thanks, everyone, for joining the call today amongst these very challenged times. So the third quarter 2020, it certainly appears the activity trough is behind us as depletion starts catching up to everyone, certainly in North America. Ensign hit a record low of 42 rigs running mid-summer but have ramped up today to 60 to 65 rigs and expect to build up to 80-plus rigs peak in first quarter '21. In the third quarter, we doubled down on our Middle East operation. Ensign completed the acquisition of Halliburton's 40% ownership interest in the joint venture. Ensign now owns 100% of the 5 newer 3,400 and 2,000 horsepower AC super-spec rigs, 2 of which are in Kuwait, 1 in Bahrain and 2 in Mexico. Our International business segment now accounts for worldwide, 33% or 1/3 of our revenue base. With a continual focus on efficiencies, G&A expense dropped 21% year-over-year for the quarter. So for a more comprehensive summary of the third quarter, I'll pass it over to Mike Gray. Mike?
Thanks, Bob. Results for the third quarter of 2020 were negatively impacted by the current operating environment. Global measures implemented in March to mitigate the spread of COVID-19, including stay-at-home restrictions, led to a significant slowdown in global economic activity that subsequently reduced the demand for crude oil and natural gas products over the short term, which severely impacted commodity prices. Although oil markets have just started to stabilize over the short term, operating results continue to be impacted by these events. The easing of COVID-19 restrictions improved oil demand over the third quarter. This, in combination with global supply and production curtailments, led to stabilized commodity prices over the balance of the quarter. However, due to the uncertain industry outlook, customers remain reluctant to ramp up drilling programs, resulting in lower activity year-over-year in the third quarter. Operating days overall were lower in the third quarter of 2020. Canadian operations recorded 686 operating days, a 71% decrease. The United States recorded 1,437, a decrease of 77%, and international operations recorded 790, a 44% decrease. For the 9 months of 2020, operating days were also overall lower, with the Canadian operations experiencing a 38% decrease; United States operations, a 55% decrease; and International operations showing a 26% decrease compared to the first 9 months of 2019. The company generated revenue of $156.9 million in the third quarter of 2020, a 60% decrease compared to revenue of $393.4 million generated in the third quarter of the prior year. For the 9 months ended of 2020, the company generated revenue of $735.6 million, a 40% decrease compared to revenue of $1.22 billion generated in the first 9 months of the prior year. Adjusted EBITDA for the third quarter of 2020 was $39.5 million, 60% lower than adjusted EBITDA of $97.9 million in the third quarter of 2019. Adjusted EBITDA for the 9 months of 2020 totaled $188.8 million, 40% lower than adjusted EBITDA of $317.1 million generated in the first 9 months of 2019. The decrease in adjusted EBITDA for the 3 and 9 months was due to the decrease in activity across global operations. Depreciation expense in the first 9 months of 2020 was $278.4 million, an increase of 3% compared to $269.6 million for the 9 months of 2019. G&A expense for the third quarter of 2020 was 21% lower than the third quarter of 2019. G&A expense decreased as a result of ongoing cost-saving initiatives, wage subsidies and organizational restructuring. Total debt for the third quarter of 2020 decreased year-over-year by $159.4 million to $1.47 billion as of September 30, 2020, from $1.63 billion as of September 30, 2019. The decrease in aggregate debt was partially offset by foreign exchange fluctuations. Net capital purchases for the third quarter was $3.2 million, consisting of $5.5 million in maintenance capital, offset by proceeds of $2.3 million from disposals. Planned capital expenditures for 2020 remains at $50 million, of which approximately $40 million will be maintenance capital. On that note, I'll turn it back to Bob.
Thanks, Mike. Let me start off by addressing the obvious. Business needs a shot in the arm quite literally with the COVID vaccine to get this market coming back. As mentioned earlier, we're running 60 rigs around the world today and have contracts lined up that will see us build to 80-plus in the first quarter. We have over 60% of our active contracted fleets under long-term contracts and we have certain rigs contracted out as far as 2025. Let's start with Canada. Today, we have 20 rigs active with contract visibility to 25 rigs in the next few weeks. This is off a low of 5 rigs back in August. We're expecting to hit a peak in the first quarter of 40-plus rigs active. Well servicing is running plus or minus 10 rigs daily and are finally starting to see some of the SRP or site reclamation plan grant work coming our way. Directional drilling hung in there in the third quarter with just 1 job running and now have 2, with 2 more starting up. So we'll be getting up to 4 here shortly. Chandel Rentals had a tough summer, of course, but see a strong winter with tank farms and manning. Rates have somewhat stabilized as we bid ourselves in the winter work. In U.S. operations, as you know, we operate in all the major basins in the U.S. from California, over the Rockies, North Dakota, down into the Permian and East to the Eagle Ford, Haynesville. With 30 rigs running in the U.S. today, we are up 50% from the trough of 20 rigs in the third quarter. Rates seem to have stabilized now, that bid activity is picking up. Our U.S. full-service business segment is performing extremely well, especially over in California. On the directional drilling front, we have 4 jobs currently underway. Moving to International, the news in the third quarter for International group was, of course, the acquisition of the Halliburton 40% interest in the JV. They have great rigs that are running extremely well and continue to deliver well bores for KOC in the top 10%. These rigs that are under take-or-pay contracts until 2024. Our EDGE controls on these rigs is providing very efficient and highly productive fee rates, pushing us, as I mentioned, into the top decile. Also happy to report our 2 Bahrain rigs received contract extensions on their contracts, taking us from 2022 out to 2023, plus 2 1-year extensions, which could take us now into 2025. Argentina has 1 rig active for a major, which is contracted until mid-2021, and we have bids out on to 3 or 4 operators for a second rig. Australia is steady with 8 rigs active and bid activity increasing as we approach 2021. Should see Australia get to 10 rigs in 2021, again, as operators look to catch up on gas depletion. On the technology front, our EDGE wellsite technology, about 75% of our active AC rigs today are utilizing our EDGE controls technology. Additionally, we just completed the second well of beta testing for our EDGE AutoPilot system. Its ticker prices for $2,500 a day, which suggests it must provide at least a 5% well time reduction to create value. We're already seeing it already deliver at least 10% to 15% fee rate increases. We're also levering off our in-house EDGE control's historic reporting capability to help manage our PBCs, performance based contracts. We have about 20% of the U.S. fleet on a PBC-type contract currently, which provides almost the doubling of our EBITDA of some of those projects. I'll put it back to the operator for Q&A.
[Operator Instructions] And your first question comes from Cole Pereira of Stifel.
As we think about the balance sheet, you guys have previously indicated that issuing $125 million by notes was a possibility. I mean, is this still something you guys are thinking about? Or do you think debt capital markets need to improve before we get there?
Mike, you want to handle one?
Yes. Like I said, it was more from the press release, from a perspective of letting people know that there's that optionality. There hasn't been any, I'd say, process put in place to actually look to execute on that. But it is a possibility that's out there.
Okay. Got it. That's helpful. I mean, as activity starts returning to U.S., can you talk about how -- where you're seeing demand in terms of the different rig classes and whether that's just concentrated in leading-edge super-spec 1,500s? Or a couple of different classes?
Yes. Well, we're certainly seeing the super-spec -- depending on the client, the super-spec rigs, which it would suggest is a [ 3-pump 4-gen ] rig. And then the standard 1,500. We're seeing a little more activity building in the Haynesville area. Of course, gas, $3-plus gas is really helping move that along. The Permian is very steady. I mean, you're very well aware of all the merger acquisition activity, of course, which has put a little bit of a pause in people's plans. And notwithstanding oil struggling to get back to $40-plus. We're seeing some of the double fleet. We have 5 of our rigs, the smaller type capacity rigs, they're working for small independents, small independents can occasionally find profit in $40 barrel oil. So we're seeing some activity there. Generally, it's -- the phone isn't ringing off the hook, but we're seeing more bid activity than we have in the last 6 months. I would say that.
Got it. That's helpful color. So obviously, leverage metrics are elevated across the space here. And one avenue to address this would obviously be through M&A. Can you guys share how you're kind of thinking about that in the current market?
Yes. On the operator side, you're talking about?
No, sorry, I meant specifically for Ensign in the drilling space?
I see. Okay. Yes, the -- I mean, one, there appears to be a lot of rigs around the world capable of drilling a lot of wells, there are arguably too many. So the herd needs to thin out a little bit. And there's 5 contractors that deliver 80% of the wellbores in North America, not one having more than 20% market share. So at some point in time, some M&A activity needs to move. There is a mid-pack of probably 10 contractors that own a 30, 40, 50-type rigs that might need to be consolidated, would have to be consolidated. So yes, it's definitely starting to get interesting on that front. I'm not aware of any rumors, so I can't spread anything.
Your next question comes from Waqar Syed of ATB Capital Markets.
Bob, could you guide us to what your expectation is for shortfall or any contract termination revenues for the fourth quarter and then for maybe even first quarter of next year?
Yes. The -- Mike, do we disclose that anywhere?
We do disclose the type of the contract in an early term. I think similar to your comment in Q2, it was kind of dropping 1/3 and 1/3 and 1/3.
Yes. Yes. So you're probably seeing it in that 8 range, I would suggest in fourth quarter. The challenge is, we have some clients that will have the rig on a standby charge, which is an active charge and then expecting a program to develop in the next quarter. And then it doesn't, and then they call and they wish to terminate the contract and either pay out a different ETF rate through the remainder of the contract or pay the contract out so it's -- our guidance probably is in that 8 range for fourth quarter, Waqar.
Okay. And then have you started negotiations with the lenders on covenant relief? And if could you give any update on how that's progressing?
Mike, you want to handle that one?
So no formal conversations have taken place as of yet.
Okay. And any plans or any expectations, when do you expect to begin those conversations?
Will happen during the fourth quarter.
Okay. Bob, in terms of activity increases in Australia, could you quantify for the next couple of years, how you see activity trends there?
Sure. The -- I mean, one thing in Australia is they're finding that depletion rates are always higher than they expect. Demand, well -- I mean, demand was pulled back a little bit because of COVID. That is starting to come back. We're starting to see some big activity into 2021. As I mentioned in the call, I think, we'll increase another couple of rigs, Waqar, into 2021. And Australia is usually quite a stable market for us. The beta is very low as compared to the North American market because it's so gas driven and utility driven, some LNG driven as well.
Okay. And just one final question, could you maybe provide some hard numbers around what day rate changes could be in the Canadian market and the U.S. market? You made a comment, there's been some pricing pressures?
Yes. I'd suggest that the pricing pressure has stopped, that people are price takers, while they move up the utilization curve, I would suggest we need to see a little more utilization before people will start to be a little more bullish on raising their prices. So I would say -- I would -- I call it the stabilized world of day rates right now, both north and south of the border. We are able to raise our prices where we have contract or where we have operators, I'm sorry, in Canada, requesting certain types of rigs in the first quarter. We're finding that the higher spec heavy tele-doubles and the 1,500 horsepower type AC rigs are very much going to be a little tighter this winter. So we're seeing -- we're testing the market by pushing rates a little bit here. It's November. I mean, we're not too far away from the winter season. We're also suggesting to our clients that they should probably get the rig moved and rigged up and surface hole drilled before Christmas, it's -- we're finding it harder and harder to find good, stable crews to hit the peak, which we usually find in the first quarter of the winter and it will probably be challenged again. We always find people, but we want to make sure we're able to get our right people back. So there's a little bit of a push for -- we'll give you a better rate to the end of the year. But once we get into the new quarter, it's up a couple of thousand dollars a day type of thing.
How about the U.S. market?
The U.S. market, again, still we're price takers. We're not able to move the price at all. In the U.S., it's stabilized. We're not having to drop it either.
Is that in -- for the Tier 1 type rigs, is the rate now in the high teens? Or is it still within that low to mid-20 kind of range?
I would say it's in the high teens.
[Operator Instructions] The next question comes from Keith MacKey of RBC.
I just wanted to start out with the comment you made around performance-based contracts and having about 20% of your rigs, I think, on some kind of performance based. Maybe you can just talk a little bit more about the terms and whether you're seeing more clients investigate this avenue as capital remains constrained amongst producers versus just having to pay that straight high teens day rates these days?
Yes. Well, the PBC contracts are constructed with a competitive base day rate. And then there's upticks from there based on hitting key metrics, penetration rates. Also, there's always a safety component in any of that. Meantime, between failures, slips to slips, how quick we get back to bottom, there's usually 3 or 4 key indicators that we quantify. And we put -- we've got a small engineering team that run -- they're called the Advanced Performance Management Team. Any of these contracts, they focus on with the client. One of the clients is one of the ones who are beta testing our AutoPilot on. So we're getting the benefit of advanced performance while we're testing. So that's working out very well. So it's basically a no risk proposition for the operator. If they get the day rate that they normally would, we decide what technology we want to put on the rig and we're managing it 24/7 in a real-time operating center type of environment.
Got it. Now I'm guessing that there hasn't been a whole lot of opportunity for recontracting and such, given where we are. But has that proposition or pitch that you're giving to the operator, are you finding that they're more receptive to that no risk proposition these days? Or are most still choosing to pick a day rate?
Well, yes, they -- again, it's -- there are always -- the rig is always on a base day rate, and then there's upticks that we charge for when we hit performance. So the challenge is, sometimes the operators acceptance of, "Jeez, if you do too well, I'll be out of a job," and as a drilling manager or whatever. But most these days understand that they are short staffed, that bringing in wellbores with lower cost is consistent with keeping one's job these days. So there are -- now that we're building up a lot more data in different areas. And the data we get from different areas and also similar data from the same area, whether it be for this operator or another operator, helps us build our algorithms and work in our DGS space, which ties into the control of the machine, which completes the circle of the loop for the AutoPilot.
Got it. Okay. And maybe just turning to Canada. The rig upticks you're expecting to activate in the next little bit, do you get the sense that those are just a continuation of operator 2020 capital spending? Or is it some acceleration of 2021?
Good question. Good question. I don't know. I think that the lines are blurred now on annual budgets because everyone's have to -- been so dynamic. I'm not sure of the response.
Got it. Okay. And then just final one for me. You mentioned the SRPs, starting to see a little bit there. Can you maybe quantify what you've seen so far and what you expect? And just your potential impact on hiring and potential inflation that you might expect to see there, if you can't get the people you need?
Yes. I don't think we'll see wage inflation. The fellows are paid well when they work. The problem is they just haven't been working much. So I don't expect any wage inflation. There was a lot of challenges with the rollout at the various governmental levels in the SRP and that frustrated the industry to -- quite extent. It looks like they've -- through regular meetings with industry associations and the government, we've been able to streamline that process, we believe, anyway and to get some boots on the ground working. It's been very dismal in the second and third quarter. Fourth quarter, it looks like we're -- everyone is starting to understand, including the government, how to approve these things. I will expect that there may be some future announcements perhaps by the government, because there was a lot of unused cap or unused grant money that didn't get allocated out that -- so I think we'll be circling back on this. So I think we'll see more of it in 2021, Keith, now that it's -- the process has been streamlined a little bit better.
Your next question comes from Jeff Fetterly of Peters & Co.
A couple of follow-up questions. So on the IBC side, how many rigs on the U.S. side did you have under IBC on average in Q3?
How many rigs. I want to say we probably had -- and Mike, you may have that handy. I want to say we probably had about 10 rigs, somewhere in that range?
Yes, I think that's about right.
Yes. And was there a second part of that question, Jeff?
Where does that number stand today?
I would say it's probably around 6.
Okay. And so the 30 active rigs you referenced earlier for the U.S., does that include the 6 IBCs?
It would, yes.
Okay. And so what is your line of sight in the U.S., both for any of the IBCs being reactivated but also in terms of your overall rig count from the 30 that you're at today?
I would say that the 30 that we're at today, there's probably some room for visibility to 5 more. And those 5 would be new contracts. We're seeing some operators that have contracts where they're paying IBC rate in one area on one of our rigs and operating a rig in another area, come back to swap IBCs on one for another because they want to put the other rig back to work and shut down the other one. Everyone's budgets are tighter than heck, they're not changing at all, obviously. So we are seeing -- and also back up, that's in with the front wind of -- in our face of these mergers, which the Concho, Conoco, the Pioneer-Parsley, we work for all of them. And we know that some of their plans will be reeled in a little bit while they pause and reflect on what their plans are in certain areas, coordinate their efforts and come back at it. So I think that, again, we may see some visibility up to 35 here through 2021. And our IBC contracts are -- they're peeling off every quarter. I would say that we mentioned probably $8 million in the fourth quarter that will probably dribble down to maybe $6 million in the first quarter of 2021 and down from there as we replenish contracts. So it's quite difficult for us to put a term on the contract. The terms these days are 6 months. We're not willing to sign rigs up at these rates for any longer than 6 months, but they do have 6-month turns though.
Okay. And just so I understand, when you say $8 million of -- in the fourth quarter, that's IBC plus early term, and that compares to the $12 million or $13 million in aggregate that you showed in the Q3?
Correct.
Okay. And lastly, on the Canadian side, so your reference to peaking at 40 rigs from the 25 -- or sorry, the 20 today and the 25 in Q4, those incremental rigs going into the winter, what -- generally what style or type? Or where do you expect those incremental rigs to go to work?
Yes. Certainly, the Montney, a couple in the Duvernay, but the Montney would be the most prevalent area. And they'd be the 1,000 to 1,500 AC type class rigs and a couple of the heavy tele-doubles, the heavy tele-double class.
[Operator Instructions] Your next question comes from John Gibson of BMO Capital Markets.
You are fairly active on debt repurchasing in the quarter, and this has continued into Q4. Do you expect this to continue sort of towards the end of the year and into 2021, especially where your bonds are trading at?
Well, we kind of take it day by day. So there won't be a particular plan that we're following. So really can't provide much more color than that.
Okay. Sort of a follow-on then, if we look towards a refinance of the credit facility, what would an ideal refinancing look like. Would it include potentially a higher credit facility and lower amount of notes?
No, I think it's more likely to be, I'd say, sort of covenant relief, and then looking at extending the facility out for a period of time. I think the credit structure or the capital structure we have right now is working. So it would be more of just pushing out the facility probably by a year or so with some movement in the covenants to make sure that we can sort of balance out 2021 correctly.
Okay. Next one, just what are you expecting per Q, then Q4 '20? And then can you remind me, has Australia ended its -- extended its wage subsidies into 2021 as well?
Australia, I believe goes -- go ahead, Bob.
No, go ahead, Mike.
Well, Australia extended it until, I believe, the end of Q1. The Canadian one continues to sort of augment. So I think it's now until June of 2021. So I think quarter-over-quarter, I'd say it's probably going to be similar to what we saw in Q3, maybe slightly lower. And Q1 would probably be similar to Q4. That really depends on how the Canadian government modifies the programs. They seem to be doing that every sort of once a month.
And when you talk about similar to Q3, you're referencing the combined Canadian and Australian numbers?
Yes. So the Canadian Q3 was $4.2 million and Australia was $3.2 million. So it's probably going to be similar in Q4.
Yes. And then sort of just a follow-up on the reclamation work that's started than Q4, is it more preliminary right now? And I guess, so can you provide some guidance on when you anticipate it being more material to your financial results?
Yes. I think it will build, I would suggest, when we enter 2021, I think we'll start to see some good traction on some of the programs. Some of the operators have been a little frustrated with the process and -- put on the back burner, but there's different phases of it, of course. So I would suggest that we'd be looking more into 2021 to see the more larger benefits of it.
There are no further questions at this time. I will now return the call to Mr. Geddes for closing comments.
Thank you, Chris. As the COVID virus runs its course and with the vaccine around the corner, the expectation is that the world will require energy at least back to the level it was pre-COVID, unless we believe the world will not demand low-cost energy as it comes out of this COVID situation. And it's just a matter of time before the world opens back up and the reality of accelerated depreciation becomes a concern. While oil seems locked around $40, what is encouraging is the natural gas price appreciation up over $3 currently. With this, we would see more active natural gas projects come back to life. Ensign continues to stay laser-focused on debt reduction and our push to apply our EDGE Controls wellsite technology onto PBC contracts in order to grow EBITDA and continue to differentiate ourselves from our peer group. Thank you for joining the call, and we look forward to our next call in the fourth quarter. Thank you.
Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.