Ensign Energy Services Inc. (OTCPK:ESVIF) Q4 2016 Earnings Conference Call March 6, 2017 4:00 PM ET
Bob Geddes - President and COO
Mike Gray - CFO
Tom Connors - EVP for Canadian Operations
Ed Kautz - President U.S. and Latin America Operations
Brage Johannessen - EVP International-East
Jon Morrison - CIBC World Markets
Jeff Fetterly - Peters & Company
Good afternoon, ladies and gentlemen. My name is Sally, and I will be your conference operator today. At this time, I would like to welcome everyone to the Ensign Energy Services Inc. Fourth Quarter Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session [Operator Instructions]. Thank you.
I will now turn the conference over to Mr. Bob Geddes, President and COO. Please go ahead.
Thank you, Sally and thank you, for joining our call today. With us today we have in Calgary Mike Gray, our CFO; Tom Connors, EVP for Canadian Operations. In Denver on the call, we have Ed Kautz, President U.S. and Latin America Operations and in Huston we have Brage Johannessen, EVP International-East.
Let me start out with little bit of a forward here. Ensign finished off a very tough 2016 for the industry by delivering a strong fourth quarter ahead of expectations. There is no question the worst appears to behind industry as the oil bounces above 50 since 2009. Ensign has decommissioned roughly 200 rigs and has invested over $3.5 billion to retools fleet into one of the most modern and competitive fleets of business today.
Over the last three years, we’ve reduced overhead cost to 70% and have driven operational efficiency to new highs. Through all this, we’ve continued to maintain a cumulative net positive free cash flow, which has allowed us to continue to pay dividends, maintain the fleet and also occasionally add new rigs. So, never to let crisis go to waste, what we have now for 2017 forward is a solid company built around right rigs, right markets, right capital structure and the right people. There is no question that rates are moving upward at different cliffs and different areas around the world up to thousand dollars a month in some areas. With that operator also expect operational efficiency gains, which Ensign rigs are providing them. We’re typically drilling wells now with our ADRs and half the time we were a few years back.
We continue to introduce technology advances into our rigs, most frequent with our Edge control technology. We have this control technology now in roughly 15% of our active fleet, and anticipate will have our Edge controls on roughly 25% of the fleet by year-end. This is a a nice complementary high margin cash flow streams that dovetails nicely with our ADR rigs and direct and drilling business. With demand for ADR 1500 as in the Permian attracting rates in the low-20s now, we will be completing the construction of the next ADR 1500 at which will be ready for deployment into the Permian by the end of third quarter. This was one of the rigs that was helping construction few years back.
We also will be constructing an ADR 1000 AC heavy TELE DOUBLES that Tom will talk later about for the Canadian business unit. This ADR was out of the AC rig will set the new bar to heavy TELE DOUBLES in Western Canada. These two projects are planned projects within our previously disclosed $60 million CapEx guidance for 2017. So, let’s dive into the numbers now. Mike?
Hi Bob. The usual disclaimer, our discussion may include forward-looking statements based upon current expectations that involves a number of business risks and uncertainties. And 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 unforeseen conditions, which could impact the use of the services supplied by the Company.
Now, to get to the recap, the persistent low oil and natural gas prices resulted in reduced levels of demand for oilfield services in the fourth quarter of 2016 compared to the fourth of 2015. Operating days were down in the fourth quarter of 2016 with Canadian operations experiencing a 21% decrease, the United States operations a 14% decrease and international operations showing 12% decrease in operating days compared to the fourth quarter of 2015. For the year ended December 31, 2016, operating days were down with the Canadian operations experiencing 32% decrease, the United States operation a 40% decrease and international operation showing 23% decrease in operating days compared to the year ended December 31, 2015.
Adjusted EBITDA for the fourth quarter of 2016 was $51.7 million, 31% lower than adjusted EBITDA of $75.3 million in the fourth quarter of 2015. Adjusted EBITDA for the year ended December 31, 2016 was $185.2 million, a 44% decrease compared to adjusted EBITDA of $329 million generated in the year ended December 31, 2015. The 2016 decrease in adjusted EBITDA can be attributed to the general industry weakness, particularly in North America compared to the same periods in the prior year.
The Company generated revenue of $234 million in the fourth quarter of 2016, an 18% decrease compared to revenue of $283.9 million generated in the fourth quarter of the prior year. For the year ended December 31, 2016, the Company generated revenue of $859.7 million, a 38% decrease compared to revenue of $1.391 million generated in the prior year. Gross margin decreased $63.7 million or 31.2% of revenue net of third-party for the fourth quarter of 2016 compared to gross margins of $88.8 million or 35.2% of revenue net of third-party.
For the fourth quarter of 2016, the 28% decrease in overall margin from that of the prior year reflects overall reduced levels of operating activities in fourth quarter of 2016 versus the fourth quarter of 2015. Gross margin decreased $237.7 million or 31.4% of revenue net of third-party for the year ended 31, 2016 compared to the gross margin of $396 million or 32.1% of revenue net of third party for the year ended December 31, 2015; the decrease in gross margin percentages for the year ended December 31, 2016 versus that of the corresponding period in 2015 was a weaker commodity price. The Company has reduced its revenue rate and operating cost structure and have made changes to reduce the cost of administrative and supervisor restructure as a reaction to the current economic environment.
Depreciation expense in the year was $349.9 million, 4% higher than the $335.5 million in the prior year. Depreciation was higher this year compared to last and due to ideal equipment depreciation; the impact of the higher dollar value equipment being utilized; the negative translation impact of the stronger United States dollar on non-Canadian domicile successes; a greater proportion of deprecation on those assets were depreciated using a straight line amortization, which is all partly offset by the overall decrease in operating activity this year when compared to the prior year.
General and administrative expense in the fourth quarter of 2016 was 11% lower than the fourth quarter of 2015. The lower expense in the recently completed quarter related to the rationalization of supervisory and other overhead costs to align with lower activity levels, offset by servants and other costs to implement the changes together with the translation impact of the stronger United States dollar on expenses incurred outside of Canada.
During 2016, the Company reclassified its share based compensation that was included in general and administrative expense of $7.9 million for the corresponding period of 2015 to the share based compensation expense. Total Company debt, net of cash balances, increased by $18 million or 3% in the fourth quarter of 2016 from $669.6 million at September 30, 2016 to $687.6 million at December 31, 2016, and decreased $66.1 million or 9% in the year ended December 31, 2016 from $753.7 million at December 31, 2015.
Net purchases of property and equipment for the fourth quarter of 2016 totaled negative $2.8 million in 2015 that was $8.2 million. This is due to proceeds from disposals of property and equipment exceeding purchases in the fourth quarter of 2016. Net purchases on property and equipment during the fiscal year ended 2016 totaled $29.1 million in 2015 that was $159 million. The Company completed one new ADR drilling rig in 2016.
On that note, I will turn the call back to Bob.
Thanks Mike. Now for an operational review of the quarter and the year, and also some insight to what we see coming in the different years, starting with Ed Kautz, U.S. operations. We can cover the U.S. drilling testing and directional drilling, and then Latin American operations Venezuela and Argentina, Over to you would you, Ed.
Thank you, Bob and good afternoon, ladies and gentlemen. I’d like to start off with the United States. At the end of fourth quarter 2016, the Ensign United States division operated a fleet of 84 premium drilling rigs. The Company also operated 44 well service units and 47 flowback testing units in U.S. and a directional drilling business with 31 directional kits currently working in the Rockies.
United States drilling recorded 2,057 operating days in the fourth quarter of 2016, a 14% decrease from the 2,417 operating days in the fourth quarter of 2015. For 12 months ending December 31, 2016, our drilling days increased 40% to 7,152 drilling days from 11,895 days for the 12 months ending December 31, 2015. United States well servicing recorded 18,976 operating hours in the fourth quarter of 2015, a 6% decrease from the 20,192 operating hours in the fourth quarter 2015.
For 12 months ending December 31, 2016, well service activity decreased 15% to 56,212 operating hours from 78,586 operating hours. Revenue was down 30% in the fourth quarter of 2016 compared to the fourth quarter of 2015, the Company in United States operations account for 39% of the Company’s revenue in the fourth quarter of 2016 compared to 46% in the fourth quarter of 2015. United States operations accounted for 39% of the Company’s revenue in 2016.
The Company added one new ADR drilling rig into its U.S. fleet in 2016 on a contract for a major operator. It was also our first ADR outfitted with our new Edge controlled system on. It’s drilling in West Texas and doing very well. The Company has also moved two ADR 1500s from Canada to the U.S. for terms projects, they are both up in running. We’re also in the process of upgrading six of our ADR 1500s to 7,500 PSI, which will be done in the first and second quarter of 2017. Our directional business in United States is currently focused in the Rocky Mountains running approximately between five and seven jobs daily.
We have opened an office in the Permian Basin and we’ll be expanding our directional business model into the Permian area. Of the 97 flowback units in the Company, we operate North America 47 of those operated in the U.S., primarily in the Colorado, North Dakota and the Permian are up in our Marcellus area. Activity in our U.S. drilling and well service markets is becoming more active as capital starts get attracted back into our business. We are definitely starting to see signs of price firming up on our ADR 1500 type rates equipped with 7500 PSI systems across the U.S.
Now, moving to Latin America. Ensign’s international division operates a total of 17 rigs in its Latin American division. The Company operates nine rigs in Argentina, while running between 45% and 55%. The rigs that we are running, we have focused on major international oil companies. Also, Ensign operates eight rigs in Venezuela, of which we’ve been running anywhere from 50% to 80% activity. We continue to monitor our accounts receivable in a challenging oil market and the relationship continues to be very good with the national oil and mix to companies. We’ve also secured a labor maintenance contract for one of the national oil rigs working or mix the company and working on a second contract.
The mix of company is made up of a partnership between the national oil company, which owns 51% and the international company which owns 49%. As always, the current economic and political climates in Argentina and Venezuela will continue to play a major role in the path forward for the industry. Overall, in Latin America, we’re currently running anywhere between 60% and 70% of our rigs at any one-time in Latin America.
With that, Bob, I’ll turn it back over to you.
Thanks, Ed. We’ll turn next to Tom Connors, EVP for Canadian Operations. Tom?
Good afternoon, everyone. And for Canadian drilling, while utilization in the quarter trailed the industry average at 2% to 3%. In the quarter, utilization for our fleet tracked the industry average of 19% for the year and [zoning] metrics exceeded the industry utilization for the first quarter of 2017 with Ensign weekly utilization numbers ranging from 50% to 58%. Pricing for the market troughed due to 2016 with competitors’ pricing for some shallow rigs approaching daily operating cost level rigs with an average debt capacity above 45 to 100 meters remain the most active, but also experienced pricing reductions as courses of fleet rolled off long-term contracts and after the spot market were into extensions that lower pricing.
Excluding the impact of shortfall payments, average daily drilling revenue for 2016 decreased 1.7% for the previous year. The trough market spot pricing for mid-2016 carry into 2017 with the expectation of pricing will return to more historic norms if the rebound in activity continues throughout the year. The overall effective of spot market pricing in 2017, excluding the effect of shortfall payments, will be a net decrease to average total revenue per day in the 5% to 10% range, being offset by more than 50% year-over-year increase in activity.
As the market continues to transition so does our fleet. And then as such, we’ve recently removed 12 rigs from our actively marketed lists for our current total of 58 marketed rigs. We’ve also added a second ADR 850 beginning in Q1 2017, which is currently under contract, and are working today. And as Bob alluded to earlier, we’ve recently approved a second ADR 1000 AC heavy double, which we believe will help set the benchmark for this style of rig and will be under contract for the time the rig is finished construction.
The remaining fleet represents the mix of rigs and matches the mix of types of rigs required by different rigs in the Western Canadian Sedimentary Basin. Having inventory of equipment from decommissioned rigs provide the significant capital advantage and will also allow us to deploy new equipment into the market have substantial lower cost in our peers once or if the market conditions warrant investments.
Revenue in 2016 included $17.1 million in shortfall payments, the majority of which is related to Canadian drilling. If we exclude the impact of shortfall payments, the associated revenue and gross margin and EBITDA margins remain top quartile for performance for our Canadian drilling peers.
And directional drilling in Canada, while the directional drilling market overall experienced reduced days and competitive pricing, we continue to see a trend that the customers that remained active through 2016 recognizing the performance benefits of integrated one project mindset through the combination of both services. Our well servicing business achieved 29% utilization in the quarter and 8,967 hours, which is roughly 20% higher than the same period last year. While activity levels had improved, pricing remains competitive and with activity improving, labors is approving a constraint, particularly for this line of business as sometimes short term nature of the work provide the challenge to attract people back into the industry.
In our testing business with fewer wells being drilled in 2016, the testing industry activity dropped dramatically. Our strategic position and higher pressure equipment have allowed us to remain relatively active players versus our peers, and with activity expected to further improve the Q2 '17 and as operators complete the wells drilled in Q1.
The rental business through 2016 and continues as a high margin less labor intensive complementary business to drilling. The market for rentals is highly competitive through the year with many contactors, including rental items inside their day rates to make the bids more attractive. As with drilling, the market for rentals began to improve in late Q4, and the pricing for specific rental items is expected to improve if the increase in activity is prolonged.
The outlook for Canada for 2017 looks to be about 50% more active than 2016 with the industry in Canada estimated to retain between 65,000 and 70,000 days or 29% utilization versus the roughly 46,000 days and 19% utilization in 2016. Pricing has started to move up bottom as rigs renew contracts, but it will take two or more quarters with elevated utilization levels to gain traction on pricing. Deeper rigs or rig categories experiencing 60% or more utilization for two or more quarters in a row will have the best opportunities to move pricing upward.
And with that, I'll turn it back to you Bob.
Thanks, Tom. I will next move over to the International East Operations, Middle East and Australia. Brage?
Thank you, Bob and good afternoon, to everyone. The rig count for Ensign's international operations has remained unchanged quarter-on-quarter from Q3 to Q4 with the total count of 29 rigs in its Australia and Middle-East Africa regions at a utilization rate at around 45% in Eastern hemisphere, excluding Libya. We closed on the sale of our Libyan assets at the end of fourth quarter, and are currently executing on our country exit plans.
In Australia, we are flat quarter-on-quarter operating six rigs with 30% utilization against an Australian overall utilization rate of around 25%. Although, there is expected to be some movement in activity from operator-to-operator, we do not see any signs of significant changes to overall activity levels in Australia in the first half of 2017. At the end of fourth quarter 2016, we secured multiple year contract extensions for two of our ADR 1500s for large Australian operator in the Cooper Basin. We also secured a contract award for a rig in a Queensland CST play with the same operator with we’re commencing in second quarter of 2017.
Rates continued to be under pressure for all upcoming work, given the large number of idle assets in a highly competitive Australian onshore market. However, given Ensign’s strong position in Australia, we will be in a favorable position to take advantage of any uptick inactivity.
Then over to our MENA region, the activity levels were also flat in fourth quarter of 2016 compared to the prior quarter. As announced during our Investor Day, in February, rig terminations in Oman that came into effect in January will impact activity levels, and top line results in current quarter and for 2017 as a whole. The impact of these terminations will be partially offset with protection from ETF payments and reduced contract discount mechanisms. We also expect to recover some of our margins from continuing to exercise diligent cost control.
In the Middle East market, in general, the activity levels are expected to be flat in 2017 with some minor corrections due to the OPEC price cut agreement. All upcoming tenders and opportunities for additional work in the region will be heavily contested with rates continuing to be under pressure, which is in line with the international and general, and seeing that there is a lag compared to North America.
Our contract backlog for Australia and MENA regions currently stands at around 20 rig years in total. The Company’s total international operations, inclusive of Latin America that Ed covered, accounted for about 35% of the Company’s revenue in the fourth quarter of 2016, as well as for the full 12 months ending December 31, 2016. This compares to the 27% of the Company’s revenue prior to the industry downturn, and is there for inline with Company’s long-term strategy of diversifying our geographical spread by growing our international business.
And with that, I will turn it back to Bob.
Thanks, Brage. Operator, we’ll move into Q&A then.
[Operator Instructions] We have a question from the line of Jon Morrison from CIBC Capital Markets. Your line is open.
Mike, can you give me color on what specifically underpinned the decision to retire the rigs that you did, and how confident are you that all of the retirements at least from a near term perspective are largely behind the Company?
Yes. Let me take that on. I mean you know how we came together with. We’ve acquired a couple hundred rigs we decommissioned the 200 rigs since 2009. Actuarially, if you think of the fleet, I mean, we have always built rigs and always decommissioned rigs every year. I think that we’ve settled into, and I’ll use word settled into a fleet size around 170 rigs. We don’t see very many aggressive decommissions that did normal course, decommissions and additions into the future Jon.
Do you think of needing to replace those rigs or ultimately way for market to recover and think about having to ultimately get full utilization on your asset base and looking at adding more units?
I think that couple of things been happening. Of course, the market has been moving little bit in some areas like 1500, so you need a third pump and 7500 PSI. I mean, recall, we’ve been building pad rigs for 25-30 years now, I mean that’s how the Company started with two pad rigs. But as far as how we look at the market, we also have 29 reserve rigs on top of the 170, and those are rigs that -- if the market gets flurried again, they can get put back to work with very little capital at all.
Tom, can you talk about how you’re thinking prioritizing market share versus the recent cash margins in Canada right now. You obviously slip a little bit on utilization side relative to industry average, but talk about getting back towards within the outlook section?
Certainly in Q4, we did like about 2% to 3% or by early Q1, we’re at or above industry utilization. Again, that’s largely because our deeper rigs were already contracted through 2017. And depending on the customers we’re working for in Q4 and when they picked up work, some guys started earlier in the Q4 than others did, but buy everything. By the time everything got up and running, our fleet was at or above industry utilization. So, those rigs went to work of course, where heavy TELE DOUBLES or light AC triples and then deep base in Montney area. And that’s where lot of the activity went, and certainly, we got our share of that.
But as far as the outlook goes, we would expect, particularly with the removal you’ll look at, you see most of the rigs that we did reserve were either light or triples or -- light or doubles or old style triple. So, I think the fleet certainly is at a point to reflect the market activity. So, again, I would say that if you wanted a proxy for activity in the Canadian Basin, just take a look at the Ensign fleet and we would expect to track or exceed into utilization to the rest of the year changes we’ve made and the addition of the two rigs we talked about.
You referenced for growing momentum in the higher spec triples, and I’m assuming that’s both the Canadian and U.S. comment. Can you talk about how you’re thinking about pricing unfolding on some of your shallow or less -- high spec rigs, or is your heavy double fleet Canada as an example?
I think every rig segment, I mean, if you look at trying to claim in the trough for pricing at least in Canada and like that U.S. as well, there’s probably about June or July of last year where everything really was the lowest spot market pricing you could imagine. And as we start to move, as activity starts to improve in late Q4, I think every rig segment started to -- and as far as spot markets go, the ones that are on contract of course don’t change. But a lot of rigs will go off contract.
So, I would say that in June or July you would have signed a heavy TELE DOUBLES up probably in the 11,000 to 12,000 base area range, and towards the end of the year guys are moving more towards the high 12s, high 13s and 14s. And I would say moving back towards more historic norms. So, as you -- depending on when you sign the contract, I think activity is allowing do that; singles you would have seen in the pretty low -- some guys were bidding in the 8,000 and 9,000 a day range pretty much close to cost. I think those are moving up again probably closer to 10,000 to 12,000 a day for the market going forward for rigs that are getting signed now; and triples are moving back more into the low 20% from where they were probably in the '17 and all over the map.
But I guess generally you’re looking at 10% maybe 20% for rigs that are signed new contracts. But keep in mind you still have rigs under contracts at lower pricing. So, I would say the impact overall for the year is year-over-year, particularly the daily rig revenue for 2016 compared that to 2017, it looks like probably 5% less range overall just the net impact of more spot market contracts.
On the international side was there any one-time payments or shortfalls that came through, specifically in Q4, that would have inflated your revenue per operating day. It was just a fairly nice uptick quarter-over-quarter, but it seems that been spot across the majority of regions that are out there. So just trying to figure out what's driving that.
Yes, nothing in particular. There is no shortfall or pickups in Q4.
So rig mix would have been the biggest factor of that in the quarter?
Yes. And Brage, do you agree with that?
I think, it's a result of the diligent cost control, because as we all know the international market is predominant long-term contracts multiple years in many cases. So it's been diligent and focused on driving cost out of the system, and adapting to the new market conditions where the rates are under pressure. But there are no one-offs or anything like that changes in activity that had an impact in Q4. I think it's more full impact of the cost control measures coming-in in Q4.
And just in the US on the well servicing side. Are you starting to hit labor challenges in that market at all?
I would say, yes, to a degree we still have some people that work for us in the past. But as we move equipment around in California, for example, we have not seen a big issue there. It's been pretty stable out there. The place, I guess, I would say we see -- most will be in the DJ Basin where activity has been up and down a little bit. But we have seen a little bit of pressure on that, but not a lot.
Mike, on the receivable write-down, you took in the Venezuela in the quarter. Can you give any color on what ultimately led you to write-down the amount that you did?
Actually is in the write down, what we did was a discount in terms of finance charge. So, we looked at the collectability and settle off it's going to be longer term receivable. So, it's going to be potentially three years is what we came down with collecting one-third, one-third and one-third and then discounted around 8%. So, we’re expecting full collectability and we're doing our present value of that collectability over three years.
Do you think about reducing activity for that customer to try to accelerate that payment, or you’re happy to collect it along those timelines that you laid out there?
Jon, the plan has been of course we’ve moved more to, as Ed pointed out, working with the mix of companies directly, which doesn’t take you necessarily away but it provides a more continuous on the receivable. But we do have a few rigs, service rigs and labor contracts with PDVSA. So, they’re still an active client, not as active on receivables side as we were in the past for the percentage base.
[Operator Instructions] Your next question comes from the line of Jeff Fetterly with Peters & Company. Your line is open.
Quick question on the new-builds, you said the ADR 1500S to be frac to the Permian is likely to be the third quarter of 2017?
What sort of rates or economics do you think that works under? I know you mentioned mid 20s, if I heard that correctly for rate?
We’ll probably be in the low 20s. By the time we get there, it's a little higher, but we’ve already got a couple of clients addressing package. This is the next one in line from our soft build program. So, there is some capital into it already, so it’s like a half cycle economic discussion, another half of the total CapEx is required to finish it off, so it make sense. Recall back a few years ago to make sense out of $20 million rig, one needed to be in upper 20s to get a reasonable rate of return on that in the upper teens as an after tax internal rate of return base.
So it’s a combination of rates are moving. We’ve got some clients that prefer our style of rig with the Edge controls on it, and then we’re just taking the opportunity slowly, whereby no means jumping on a new-build program of any sort. And both the rig in Canada and the U.S. fall within the confines of our $60 million CapEx program for 2017.
Do you see the ADR receive that 1000 you mentioned. Was that also partially built as part of the previous program?
It was part of the -- we had 10 on the original program. We canceled or shut paused -- program on pause after the first one. We completed the second one, we started to work here in Q1 2017, is under contract. And this will be the third one. And again with the advantage of, we already have with a lot of the parts and pieces. So capital cost put this together is a lot lower than once we’re cautious but one together new.
And that was the ADR 850 you mentioned in your prepared remarks, Tom?
Yes, that was one ADR 850 and this is the ADR 1000 AC, heavy TELE DOUBLES.
Where do you expect the 850 and the 1000 to work?
The 850 is working in Montney and the 1000 we expect will either be Montney or perhaps Duvernay spending on, which customer -- there is a couple of customers interested in right now. But it will be Montney or Duvernay.
That will be one of the highest powered heavy TELE DOUBLES year you will find in the market.
There are no further questions at this time. Mr. Geddes, I’ll turn the call back over to you.
Thanks, operator. As always, Ensign is most concerned with efficient deployment of capital and mindful returns. We purposely focused on the right type of rigs in different regions of the world. And while sometimes that maybe at the expense of market share, particularly for a period of time, we play the long game, Ensign’s reengineered retool with a strong and efficient capital structure in order to take advantage of the market activity moving forward. And with 60% of our active rigs today tied-up in long-term contracts of six months or greater, half of those on take-or-pay contract, reaching out to second quarter 2020. Ensign is a solid growth story, take a nice dividend. So we look forward to the next call and talk about first quarter ’17 results. Back to you, operator.
Thank you, ladies and gentlemen, for your participation today. This concludes today’s conference call. You may now disconnect.
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