Ensign Energy Services Inc

TSX:ESI

Earnings Call Transcript

[Operator]

Good afternoon. My name is Jody, and I will be your conference operator today. At this time, I would like to welcome everyone to the Ensign Energy Second Quarter Results Conference Call. [Operator Instructions] Thank you. Bob Geddes, President and Chief Operating Officer, you may begin your conference.

[Robert H. Geddes, President, COO & Non]

Thanks Jody, and welcome, everyone. Now with me today, I've got Mike Gray, CFO here in Calgary along with Tom Connors, EVP for Canada and International East Operations. In Houston today, we have Mike Nuss, EVP for U.S. and our Latin American Operations. So let's get started. Thanks again for joining. A solid beat in the quarter. Revenue is solidly up and margin is up as clients continue to engage contractors with high-spec rigs. Our U.S. high-spec fleet continues to lead ahead of industry utilization with 60% activity and essentially full utilization in the Permian. We've seen some operators pull back their plans, but we have been able to quickly recontract the rigs as other operators look to grab the opportunity to high grade their fleet with Ensign high-spec and super-spec type ADR rigs. Also Australia and Oman also had strong operational quarters and while Canada had 2 of its ADR-1500s down over breakup and one of its ADR-1500s transferred to the more lucrative U.S. market, Canada's is beating industry utilization consistently through third quarter and is not having to drop price to obtain utilization. Tom will expand a little bit more on that and Mike on the U.S. Our net CapEx expenditures are coming in right on budget with a target of $65 million right on plan. Operationally and safety excellence continues to be a cornerstone for the Ensign brand. And in the second quarter, we saw a downtime drop in safety metrics drive even lower. Also in the second quarter, we had 30 Ensign rigs now that have our edge control system installed and generating incremental revenue. So for a more detailed summary of the second quarter, I will turn it over to Mike Gray.

[Michael Gray, Chief Financial Officer]

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 could impact the use of the services supplied by the company. Now for an overview of the quarter. The modest recovery of crude oil and natural gas prices resulted in increased levels of demand for oilfield services in our United States operations in the second quarter of 2018 compared to the second of 2017. Geopolitical factors and limited access to markets continues to hamper Canada's ability to take advantage of the increase in prices. Internationally, certain rigs in 2017 rolled off long-term contracts reducing the 2018 results. Operating days overall were higher in the second quarter of 2018 with the Canadian operations experiencing a 27% decrease, the United States operation a 25% increase and the International operations showing a 5% decrease compared to the second quarter of 2017. For the first 6 months of 2018, operating days were overall higher with the Canadian operations experiencing a 20% decrease, the United States operations a 27% increase and International operations showing a 10% decrease compared to the first 6 months of 2017. Adjusted EBITDA for the second quarter of 2018 was $53.1 million, 20% higher than adjusted EBITDA of $44.3 million in the second quarter of 2017. Adjusted EBITDA for the first 6 months of 2018 was $105.4 million, a 12% increase compared to adjusted EBITDA of $94.4 million generated in the first 6 months of 2017. The 3 and 6 months of 2018 increase in adjusted EBITDA can be attributed primarily to increased demand for oilfield services and increased revenue rates caused by a modest commodity price recovery. The company generated revenue of $263.1 million in the second quarter of 2018, a 13% increase compared to revenue of $232.2 million, generated in the second quarter of the prior year. For the 6 -- first 6 months of 2018, the company generated revenue of $521.5 million, an 8% increase compared to revenue of $483.5 million generated in the first 6 months of the prior year. Gross margins increased by 18% to $64.8 million, or 27.9% of revenue net of third party for the second quarter of 2018 compared to gross margins of $55.1 million, or 26% of revenue net of third party for the second quarter of 2017. Gross margins increased to $127.9 million or 27.9% of revenue net of third party for the 6 months ended June 30, 2018 compared to gross margins of $115.7 million or 27.5% of revenue net of third party for the 6 months ended June 30, 2017. The increase in gross margin in the 3 and 6 months ended was primarily attributed to higher revenue rates in the current period. Depreciation expense for the first 6 months of 2018 was $199 million, 29% higher than $154.9 million for the first 6 months of 2017. The increase was related to change in accounting policy that took place in Q1 of 2018. General and administration expense in the second quarter of 2018 was 8% higher than the second quarter of 2017. The increase in G&A is due to timing of certain expenses and increased activity in The United States operations. The company continues to focus on initiatives to manage costs as activity begins to recover. Total company debt net of cash balances increased by $22 million, or 3% in the second quarter of 2018 to $748.6 million, an increase by $41.1 million or 6% in the 6 months ended June 30, 2018. Net purchases of property and equipment for the second quarter of 2018 totaled $21.8 million. Net purchases during the 6 months of 2018 totaled $37.3 million. The company has added one new service rig to its United States fleet, and is currently constructing 3 new service rigs for the U.S. market. Net capital expenditures for the calendar year remain unchanged from the prior quarter. The company has also received approval from the banks to increase their global facility to $600 million with a 3-year term. On that note, I'll pass it back to Bob.

[Robert H. Geddes, President, COO & Non]

Thanks, Mike. So let's turn to Mike Nuss for a second quarter summary of U.S. and Latin American. Starting with U.S. Mike?

[Michael Rudy Nuss]

Thanks, Bob. Good afternoon, everyone. Starting out with the U.S., which recorded $148.1 million revenue, Q2, 2018, that's an increase of 34% from the $110 million recorded in the second quarter of '17. The company's U.S. operations accounted for 56% of Ensign's total revenue in the second quarter, up from 31% in the second quarter of 2017. Drilling rig operations days increased to 3,228 days in Q2, 25% increase from the 2,590 recorded in Q2 '17. Our well servicing activity recorded a 33% increase in the second quarter of '18 to 28,722 operating hours, up from 21,594 Q2 of '17. U.S., we currently have 47 rigs operating, 20 in the Permian, 15 in California, 12 in the Rockies. Continued tightness in the high-spec AC 1500 class is placing upward pressure on day rates for that asset class. We've also seen improved activity in California and currently carry 45% of that market. During Q2 of 2018, we also deployed an ADR-1500 super-spec rig from Canada to the U.S. and also deployed one service -- one new service rig in the second quarter to meet increased demand. We're also planning on 2 more new builds in the third quarter, followed by a fourth first quarter next year, all designed for long-reach horizontal completion work. Our directional business is also up year-over-year, currently have 8 units operating in Colorado and Wyoming. Moving over to Latin America, Ensign's international division, we operate 16 rigs in Latin America operating at approximately 50% utilization. Argentina, we are operating in the Vaca Muerta with 3 super-spec AC 2000 walking rigs and working for IOCs. Additionally, we have 2 legacy rigs working there as well. In Venezuela, we continue cautious activity with mixed companies [ who ] actively manage our AR in a challenging geopolitical environment. With that, I'll turn it back to you Bob.

[Robert H. Geddes, President, COO & Non]

Thanks, Mike. So let's move to Tom Connors for a second quarter summary and the great quarter we had in Canada and the International East areas. Tom?

[Tom Connors]

Good afternoon, everyone. I'll begin first with our drilling services area, which comprise our Canadian drilling, directional rentals and managed pressure businesses. Due to the high demand and activity levels for AC pad triples and edge technology, our Canadian joint division generally kept pace with the industry average activity and was the third most active driller in the quarter. Additionally, the strength of our ADR singles and the benefit of a balanced fleet mix helped with the strong rebound in activity in June and a premium-to-industry average utilization of 4-plus percent so far in Q3 and as high as 7% on particular days during the period. The premium versus industry average utilization is expected to continue throughout the quarter thus erasing any slight deficit remaining from the first quarter and bringing us in line with the industry average utilization of 34% on a year-to-date basis. Overall, industry activity in Q2 2018 was less active than Q2 2017. Ensign had an exceptional Q2 2017 for activity levels with several operators opting to continue working through the quarter with no shutdowns, which are typical at spring breakup. 2018 activity levels reflect a pause in operations for spring breakup this year for some key operators that did not occur last year and that transferred one of our deeper rigs, which was active last year to a more active U.S. market during the quarter. Despite the overall trend in activity levels in the second quarter, rig mix and year-over-year base day rate improvements averaging between $500 and $1,000 a day contribute to higher revenues, gross margins and EBITDA on a per day basis than the previous year. That trend is anticipated to continue through Q3 and Q4 with steadily improvement fundamentals for most rig classes. With several rigs moving out of the country to more active markets, demand for the remaining fit for purpose triples and heavier doubles is expected to be tight in Q4 2018 as the market ramps up for Q1 2019 activity. With motors and MWD technology focused on more active areas and targeting the appropriate customer base, our directional drilling business was 50% more active in Q2 2018 than Q2 2017 with rates averaging $600 per day or roughly 7% higher than the prior year. The strength and activity is continuing into Q3 and is expected to remain relatively robust versus 2017 for the remainder of the year. Our rentals business continues with similar margins to last year, but experienced lower activity in the quarter than the previous year. Rates and utilization levels for certain product lines are expected to improve as the year continues. Our completion and services division includes our well servicing testing and wire line businesses. And in our well servicing business, hours for the industry were flat to modestly improved for this quarter versus the same period last year. Our Canadian well servicing division exceeded the utilization of many of our major competitors in the quarter and had improved gross margins and EBITDA due to contractual adjustments to offset direct cost, a strategic approach to rigs startups and repairs and changes to customer mix. While activity was relatively stable on a year-over-year basis, general incremental rate increases between 5% and 10% are anticipated in early Q3 with further potential adjustments expected in Q4 as the industry slowly and steadily improves. Our testing business experienced similar activity to last year with substantially improved revenue rates due to a combination of equipment and job mix and steady spot market price increases as things continue to improve from trough pricing activity levels experienced in 2016 and early 2017. Our overall outlook for the Canadian market and we expect overall [indiscernible] activity in Canada in 2018 to remain roughly flat to slightly lower than 2017 with the industry achieving 67,000 to 70,000 days in total. Incremental improvements in rates among different product lines and a tighter demand on deeper rig classes is anticipated as the industry ramps up in Q4 into a potentially busier Q1 2019 than Q1 2018. In Australia, our steadily improving fundamentals also occurred in our Australian business with days in Q2 2018 increasing by 17% over Q2 2017 and changes in contract and customer mix resulting in improved revenues with improved gross margins and EBITDA over the same period last year. The pattern is expected to continue through the remainder of the year with activity up year-over-year 15% to 20%, total revenue improving 5% to 10% along with similar increases to gross margin dollars in EBITDA. 2019 looks to continue the trend of improving activity in rates as demand for local gas supply and improving market conditions provide the backdrop for further year-over-year incremental improvements. And in our Oman business, activity remained steady on a year-over-year basis with the active rigs remaining under long-term contracts. There continues to be a discussion of potential opportunities in the area that may lead to an increase in activity in early 2019. And that's it from me. Bob, I'll pass it back to you.

[Robert H. Geddes, President, COO & Non]

Thanks, Tom. So back to the operator for Q&A.

[Operator]

[Operator Instructions] Your first question comes from the line of Nicole Tullo of Macquarie.

[Nicole W. Tullo, Vice President and Private Placements Analyst]

Could you just give us a little more details on the new credit facility?

[Robert H. Geddes, President, COO & Non]

Mike, go ahead.

[Michael Gray, Chief Financial Officer]

So it's $600 million with similar terms that we had with the previous facility on a 3-year term. The only changes would be $100 million increase and a 3-year extension.

[Nicole W. Tullo, Vice President and Private Placements Analyst]

With the same covenants that were on your old facility?

[Michael Gray, Chief Financial Officer]

Correct.

[Operator]

Your next question comes from the line of Jon Morrison of CIBC Capital Markets.

[Jon Morrison]

Tom, can you talk about day rate expectations for the balance of the year in Canada? And do you expect spot market rates to exit the year higher than where they sit today?

[Tom Connors]

Well, I'll start with '18 versus '17. Yes, they are up again in that $500 to $1,000 a day range. We are seeing that in the actual revenue base day rate rates differences in Q2 this year versus last year. And I would expect to continue that although slow and steady push. I wouldn't say it's going to be a big step but a slow and steady push into the fall as activity ramps up into kind of Q4 and Q1 '19, yes.

[Jon Morrison]

We're approaching about 15 deeper rigs having now left Canada in the last, call it, 6 months. Based on your line of sight, do you expect all of your higher capacity triples in Canada to be largely spoken for? And do you expect there to be any sort of pending shortage of triples in Canada over the next 18, 24 months?

[Tom Connors]

I think even last year before the 15 rigs had left in Q1, that rig class -- what I would call, higher spec triple or doubles, but 199 in Canada, and they ran at about 85% utilization or so in Q1 last year. So that's before 15 left so I would expect pretty tight demand for them even if activity is flat in Q1 2019. So short answer is yes, I do think there is going to be -- most of them are spoken for and the ones that are not currently or don't have firm contracts on them are expected to be fairly tight demand on them, particularly kind of starting in that October timeframe.

[Jon Morrison]

And would you expect there to be an opportunity to push rates in that rig class at a much more meaningful clip as a result? Or utilization will just largely be paid?

[Tom Connors]

That's, no. Certainly, we would see movement even at current rates versus what would have signed. For that class versus what was signed last year and the year before, there has definitely been day rate improvements. So in terms of the scale, I think it would be moving back towards what -- for an ADR-1500, last year, you would have been -- the numbers would have been below 20, now you're talking above 20 in that kind of 22-ish and north of their type of range and it would be similar kind of movements. So you're at 10% plus increases for 1,000-horsepower AC rigs as well and rigs in that kind of class. So that gives you a bit more color.

[Jon Morrison]

Perfect. That's very helpful. Bob, you made a number of comments around a potential slowdown in the Permian in the coming period. Just a point of clarification, are you actually seeing some of your active rigs in the Permian be laid down and moved over to different customers? Or is that more of a high level comment of just wanting to flag it as a possibility?

[Robert H. Geddes, President, COO & Non]

Yes. I think there is -- we always have some contract turnover in the Permian as contracts move around. We've talked about our cadence being about 1/4 of our fleet, turning over every quarter, so to speak, on 6-month or annual contracts, and those are usual take or pay contracts like every day is pay day, but I think it's topical. The Permian has had some bottlenecking and everyone is talking about debottlenecking, and what the effect of that is. And we've -- on any given quarter, we probably have 4 rigs that might turn over. We've been able to recontract those rigs at higher rates. And I guess, the point was that it's -- while most are looking for a little bit of a turn down in the Permian, I would suggest that for the higher spec rigs, it's more of a leveling off and an opportunity for other operators to high grade their fleet. So we haven't seen much of any turndown as a result of that yet.

[Jon Morrison]

Okay. That's helpful. Just in terms of California, is the line of sight to put incremental rigs to work throughout the balance of the year at this point, where you could actually see another 2 or 3 rigs go to work in that market before year-end?

[Robert H. Geddes, President, COO & Non]

Yes. Mike Nuss, do you want to answer that?

[Michael Rudy Nuss]

Yes. We've got at least a couple more contracted. I would say, there's 2 on the horizon anyway, and that's about where we're at the moment. But almost all of our higher spec AC, we've got a dozen -- over a dozen AC rigs, some of them are singles, some of them are triples. I think all but 2 of those are working, one is still on term. So we've seen the uptick in some of the SCRs and mechanicals as well.

[Jon Morrison]

Perfect. This one is maybe best for Mike Gray. Your international revenue per operating day witnessed a pretty solid uptick quarter-over-quarter from Q1. Can you help us understand the drivers of the sequential increase? Was it largely just rig mix and pricing? Or was there anything one-time in nature that would have drilled that revenue number per day at a fairly healthy clip?

[Michael Gray, Chief Financial Officer]

It would just be rig mix and pricing. There would be no one-offs that would have increased it.

[Jon Morrison]

Okay. In terms of the Australian outlook, you guys talked of it being flat to up, but given where gas prices are, there is a number of producers out there raising capital to put -- to have a higher development program in that market. Is there any chance that, that market could surprise to the upside decently in the next 12 to 18 months?

[Robert H. Geddes, President, COO & Non]

Yes. I think that there are some positive wins building in our sails. Nothing turns very quickly in International, Australia included. But I think you hit on some relevant points there that we are seeing more bid activity in that area than we've seen in the last year or so. That will -- bear some fruits absolutely.

[Jon Morrison]

Okay. Last one just for me. Mike, in terms of the credit renewal, with it now behind you, is it fair to assume that the current financial flexibility that you now have in the balance sheet is about the dry powder that want to have on a going forward basis?

[Michael Gray, Chief Financial Officer]

Yes. That'd be correct.

[Operator]

Your next question comes from the line of John Bereznicki of Canaccord.

[John Mark Bereznicki, Analyst of Oil and Gas]

A quick question for me. It looks like your U.S. well servicing business saw a pretty decent sequential uptick in activity. Just wondering if you could give us a little bit more color on that dynamic?

[Robert H. Geddes, President, COO & Non]

Yes. Yes. Mike, why don't you fill that in.

[Michael Rudy Nuss]

Sure. I think the biggest dynamic is that the rollover from what historically, just like with the drilling rigs, was a vertical type well service rig. And once the world turned horizontal, these long-reach horizontals, the legacy service rigs don't have the capability to do the completion work. So that's where the growth is, is the long-reach high-capacity completion rig.

[Robert H. Geddes, President, COO & Non]

Yes. If you just want to add to that John, in the first quarter. Go ahead, Mike.

[Michael Rudy Nuss]

Yes. So the one new build we did last year and the 4 coming this year and into the first quarter and any type upgrades, that's the better market you're looking towards.

[Operator]

[Operator Instructions] Your next question comes from the line of Ian Gillies of GMP.

[Ian Brooks Gillies]

I just wanted to follow on John's line of question in International and what occurred from Q1 to Q2, acknowledging rig mix and pricing played a part, but are you able to highlight perhaps any specific geographies that may have helped lift that? And just maybe give us some help there?

[Robert H. Geddes, President, COO & Non]

Well, I mean, the whole harbor went up. We saw movement in Australia with at least one more rig running. In Oman, we had solid operating with some drop in cost. And Argentina, there was another rig and one more rig than planned. In Venezuela, we had a strong quarter, of course, with another rig operating there, albeit Venezuela with its AR challenges, and that's not lost on us for a moment.

[Ian Brooks Gillies]

Okay. In California, I mean, you noted some of the rig tightness perhaps in your own fleet and given your sizable market share there, are you beginning to see the ability to start moving day rates at a meaningful clip, call it $500 or $1,000 a day, maybe at a steady pace over the next 12 to 24 months, you're just -- given how few competitors there are in that region?

[Robert H. Geddes, President, COO & Non]

Yes. Mike Nuss, do you want to talk to that?

[Michael Rudy Nuss]

Yes. I think that's fair. We've had some movement already. And I think -- I don't know that it will be as robust as the Permian has been, but I think there will be some more movement.

[Ian Brooks Gillies]

Okay. And last one on Australia, I think, if I heard the commentary correct is you guys are expecting activity to be up 10% year-over-year, revenue kind of up somewhere between 0 and 5%. And so with that in mind, is that a rig mix factor? Or is bidding getting more competitive? Or are you using some of your peers trying to encroach into some of the areas where you've historically had a strong presence?

[Tom Connors]

No. It's just basically -- it's Tom here. It's just a change in contract and customer mix, with just the types of contracts. As opposed to previous years, you might have had some contracts with more, let's call it third-party type items in, some have been higher revenue, but more expenses inside the contract rate. Some of that's changed with different contract structure with different customers this year. So activities for the year looks like it's going to be up 15% to 20%. Revenue rates are also up about somewhere between 5% and 10% right now. And correspondingly EBITDA and gross margins also looking like it's going to be somewhere up in the -- a similar range of 5% to 10%. With 2019 looking, as Bob noted earlier, to kind of continue to build off that momentum, particularly driven around the gas, the demand for local gas supply. So effectively, it's customer and contract mix is what's changed really.

[Ian Brooks Gillies]

This one's probably for Mike Gray. But with respect to the debt maturities, I guess, '19 being next. I mean, how are you thinking about that in terms of refinancing, I mean, given the yield curve keeps on creeping up. Would the preference be to use the credit facility and upsize it again or are rates inexpensive enough now that you may look to put out another small piece of term debt?

[Michael Gray, Chief Financial Officer]

No. We look to use the existing facility.

[Operator]

There are no further questions in the queue. I'll turn the call back over to Bob Geddes for final remarks.

[Robert H. Geddes, President, COO & Non]

Thanks, Jody. For a summary, again, while the Permian debottlenecking has caused some angst amongst operators, it has created opportunities for other operators to high-grade their contract or fleet. With essentially 50% of our active rigs in the U.S. being super-spec type rigs, we have extremely high recontracting rates. Also over half of our active rig fleet are on long-term contracts and 1/4 of our U.S. fleet will turn over in third quarter and contract at higher rate sequentially. This quarter, we signed up an additional half dozen rigs around the world in long-term contracts, and we expect to be running about 10% to 15% more rigs in the second half of '18 than the first half of '18, all at higher margins. We also see our well servicing business growing sequentially as more and more wells require production maintenance. In Canada, there is no doubt that the ADR-1500 type rig will be tight. And as a result, we'll see rates in the mid- to high-20s in the norm, as Tom pointed out. We also continue to see expanded interest in our edge controls and analytics technology as we move down the road of active applications development with ultra-long-reach horizontal wells starting to become the norm. At least for Ensign, having a sophisticated controls platform is critical to drilling reproducible record wells with reduced tortuosity and lower well costs for our clients. So to wrap up, we believe the strong macro price and demand fundamentals will drive us forward, and we will continue to find ways to excel through the little headwinds that present themselves along the way. And through all that, our business model will continue to create free cash flow and reward shareholders with dividends. We look forward to reporting on our third quarter in 3 months' time. Thank you for listening in.

[Operator]

This concludes today's conference call. You may now disconnect.