Ensign Energy Services Inc.

Robert Geddes - President, COO & Non-Independent Director Ed Kautz - President of U.S. & Latin American operations Michael Gray - CFO Mike Nuss - EVP U.S.

& Latin America Operations Tom Connors - EVP of Canadian Operations

Ben Owens - RBC Capital Markets Jon Morrison - CIBC Capital Markets

Thanks Shantel. Good afternoon, everyone.

Thank you for joining us. With us today, we have our executive management team consisting Ed Kautz, President and U.S.

and Latin American operations, Mike Gray, Vice President and CFO, Michael Nuss, EVP U.S. and Latin American Operations and Tom Connors, EVP Canada and International East Operations.

Before we get going too far, just want to say that Michael Nuss will be managing most of the call today on the notes. Mr.

Kautz will be retiring July 01, after close to 25 years with the company, Ed as you know well has been instrumental in helping build our U.S. platform into what it is today.

He has contributed over 50% of the revenue included in the entire company. So, Mike will be talking to the U.S.

and Latin American operations on this call. So just expand on that though, Mike will be expanding his role as of July 1 to look after the entire U.S.

business consisting mostly of a growing assets, but also our directional drilling, well servicing and testing lines of business. Mike Nuss will continue to look after closer to Latin America and South American business as well.

So, fourth quarter 2017, no question [indiscernible], behind the sector as all our year-over-year metrics reflected strengthening drilling and well servicing business climate worldwide, supported by a more solid $60 WTI environment. That being said, we started to see some bifurcation in certain markets, mostly driven by geopolitical issues.

The U.S. where we do over half our business, we saw regulatory obstacles reduce through 2017 all while in over-regulated Canadian market and we saw oil and gas companies trim budgets reflecting their reduced cash flows, the result of necessary product discounts caused by infrastructure and tax issues.

In our other areas of business 2017, we saw a stabilize Australia activity worth knowing that while Ensign is arguably the news in Australia, 30% of the country's fleet, we enjoy over 50% market share for active rigs running. In 2017, Argentina is playing out according to plan as our investment in adding 2,000 horsepower rigs into the Neuquén area is serving us well.

All these rigs are on long-term contracts and we just mentioned installed our Edge operating system and controls on one of the rigs down there and since four months, the rig was drilling record wells in the area and doing consistently. While we operate in Venezuela we only have a few rigs operating, all of which are with the mix to the companies.

Mike Nuss will expand into a little more detail on that later. Our Oman business operates about three of the eight rigs in the country on a daily basis and these three rigs are tied up on long-term contracts out into 2020.

As you know Ensign operates a fleet of 170 high spec drill rigs with a high concentration in the most active areas of the U.S., Canada and South America, Australia and Oman markets. In 2017, the company added three new build ADR drilling rigs to Australian fleet in the Canada and U.S.

markets and modified eight of our U.S. ADR 1500s super spec rigs, all of which are committed to long term contracts.

The company also added one new build well servicing rig into the U.S., a long reach horizontal completion rig. Of the 70 rigs in our fleets, 70% are Tier-1 type ADR rigs, of varying horsepower, 70 of those are AC ADR type Tier-1 rigs, all capable of having our Ensign Edge controls installed on them, and 41 of those 70 are the high demand ADR 1500s.

Eight of these are what the industry calls super spec. Super spec quite defined as three pumps, four [gens] blocking capability 75 PSI and extended fracking capacity for the 2.5 mile laterals.

Dovetailing nicely with our drilling rigs, is our direction drilling business and our newly created wellsite technology business line. After the well is drilled, we have our testing business in the well service business service come onto location after the rig is completed its work to have maximize our revenue opportunity with every wellbore drilled.

2017 also was a groundbreaking year for Ensign. We saw Ensign commercialize its new state of the art Edge control system.

The edge system lays the ground to more complex direction, guidance advisory and provides a platform for evolving applications. We bought the Edge controls, from concept to commercialization and last two years and did that complete with organic internal resources on a small agile tactical development and testing.

Rigs with Edge controls are now attracting 25,000 to 30,000 a month fees for the enhanced controls platform. And in almost all cases the operator is being charged for install cost.

We are also in the trail of developing apps like royalty optimizer and fuel miser to name a few which can be downloaded on to any of our rigs with the edge operating system. This platform operates -- I am sorry, platform opens with applications to generate incremental revenue opportunities.

Today we have our Edge control systems on 24 of our rigs in North America and Argentina. We have plans to implement the Edge controls on most of our other rigs around the world over the next few years, as the March demand continues to develop.

With that, I will turn it over to CFO, Mike Gray for a more detailed summary of the year followed by area of summaries from Ed, Mike and then Q&A afterwards. Thank you, over to you Mike.

Thanks Bob, I'll start with the usual disclaimer. Our discussion may include forward looking statements, based upon current expectations and involve a number of business risks and certainties.

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 their account receivables balances and raise capital or other unforeseen conditions which could impact the use of the services supplied by the company. The modest price recovery of crude and oil and natural gas prices resulted in increased demand for oilfield services in the fourth quarter of 2017 compared to the fourth of 2016.

Operating days were up in the fourth quarter of 2017 with Canadian operations experiencing a 30% increase. United States operations a 48% increase and international operations showing 8% decrease in operating days compared to the fourth quarter of 2016.

For the years ended December 31, 2017, operating days were up with the Canadian operations experiencing a 50% increase. The United States operations a 53% increase and international operation showing a 7% decrease in operating days compared to the year ended December 31, 2016.

Adjusted EBITDA for the fourth quarter of 2017 was $54.8 million, 6% higher than adjusted EBITDA of $51.7 million in the fourth quarter of 2016. Adjusted EBITDA for the year end of December 31, 2017 with $201.8 million, a 9% increase compared to adjusted EBITDA of $185.2 million generated in the year ended December 31, 2016.

The 2017 increase an adjusted EBITDA can be attributed primarily to increase demand for oilfield services caused by a modest price recovery of crude oil and natural gas commodities prices compared to the same period of the prior year. The company generated revenue of $270 million in the fourth quarter of 2017, a 15% increase compared to revenue of $234 million generated in the fourth quarter of the prior year.

For the year ended December 31, 2017 the company generated revenues of $1000.7 million, a 16% increase compared to revenue of $859.7 million generated in the prior year. Gross margin decreased to $63.3 million, 26.1% of revenue net of third party for the fourth quarter of 2017 compared to gross margins of $63.7 million, 31.2% of revenue net of third party for the fourth quarter of 2016.

The 1% decrease in overall margin from that of the prior year was a result of nominal shortfall revenue earned in the fourth quarter of 2017 compared to $5 million in the fourth quarter of 2016. The reduction in shortfall revenue was offset by increased levels of operating activity in the fourth quarter of 2017 versus the fourth quarter of 2016.

Gross margins increased to $241 million, 27.6% of revenue, net of third party for the year end 2017 versus that of the corresponding period in 2016. Was a direct result of increased demand for oilfield services, resulting in higher equipment utilization rate, which was offset by lower revenue rates at $1.3 million in shortfall revenue being earned compared to $17.1 million in 2016.

Depreciation expense in the year was $325.8 million, 7% than $349.9 million for the prior year. Depreciation was lower this year compared with that of last year due to certain operating assets now being fully depreciated, in which case no further depreciation expense is required on such assets.

G&A expense in the fourth quarter of 2017 was 30% lower than that of the fourth quarter of 2016. General G&A expense for the year ended December 31, 2017 was 25% lower than the year ended December 31, 2016.

The decreases in G&A expense resulted from the company's continued initiatives to reduce costs. Total debt net of cash balances increased by $7.6 million or 1% in the fourth quarter of 2017 from $700 million at September 30, 2017 to $707.6 million at December 31, 2017 and increased $19.9 million or 3% from the year ended December 31, 2016 from $687 million of that of the prior year.

Net purchases of property and equipment for the fourth quarter of 2017 totaled $25.2 million compared to net purchases of $2.8 million in the corresponding period of 2016. Net purchases of property equipment during the fiscal year ended 2017, totaled $117.7 million compared to net purchases of $29.1 million in the corresponding period of 2016.

The company added three new ADR drilling rigs and one service rig in 2017. The rigs were partially assembled from equipment that were part of the rig build program that the company halted in 2014 to preserve the balance sheet in a declining market.

On that note, I will turn back to you Bob.

Thanks Mike. So, let's go to the other Mike for a summary of the 2017 highlights in our U.S.

and Latin American business following with some outlook into we see the 2018 year shaping up. Over to you Mike.

Okay. Thanks Bob.

Good afternoon everyone. I will start out with the U.S., United States recoded $459.5 million in revenue in 2017 comprising of little 40% of the total revenues for the company.

That a was a 36% increase of $338 million revenue recorded in 2016. U.S.

well service fleet also recorded a 36% increase year-over-year in operations and also saw a 25% increase quarter-over-quarter. U.S.

drilling rig utilization ended up at right around 60% at the end of the fourth quarter of 2017 to 63% increase from the 30% utilization in the fourth quarter of 2016. Through 2017, we super spec an additional eight of our ADR 1500s and also added a new build ADR 1500 with our state of the art, Edge Controls and rig operating system.

We now have a fleet of 20 super spec rigs operating in the Permian, all contracted. Our directional business in the U.S.

is currently focused in the Rocky Mountains and is running five to seven jobs daily. We tend to focus our directional drilling on more turnkey work, where we can easily integrate the operation and generate higher returns in an IPM type model.

We are also starting to see quarter-over-quarter growth in our frac fallback business unit as fracking utilization ramps back up. The company's three main operating areas in United States; the Rockies California and the Permian Basin have all seen increases in activity in the second half of 2017.

As of December, '17, there are 10 rigs running in the Rockies, 11 in California and 19 in the Permian. Of these rigs over half are on longer term contracts and about a third of the active rigs are on guaranteed contracts going out as far as 2020.

There is still a somewhat tighter market in the West Coast and Rockies, however pricing increases in the Permian for high spec walking rigs are putting spot rates in the plus or minus $23,000 to $25,000 range with the Edge, Ensign Edge controls product suite. Moving over to Latin America, Ensign's international division operates a total of 16 rigs in Latin America with approximately 50% to 60% utilization on any given day.

The company operates eight rigs in Argentina while running between 50% and 60% utilization, continuing to focus on the Neuquén gas play working for international major oil companies. As I am sure, most of you are aware, the guaranteed $4 of $7.50 per million unconventional gas pricing continues to drive Neuquén investment.

Ensign also has eight rigs in Venezuela of which we are running 40% to 50% activity. Here we are continuing to manage our accounts receivable in a challenging geopolitical environment.

We are strategically moving our contracts to mix of companies to segregate our accounts receivable challenges and for clarity, a mix to company’s we have a partnership between the national oil company over 60% in the IOC, insurance 40%. And with that, I'll turn it back to you Bob.

Thanks Mike. So, we'll move to Canada and the international business.

Tom Connors looks after both of those with Canadian and international business unit. Tom will fill us in on the significant events in 2017 for each of these business units and performance what we've been seeing in the areas for the first part of 2018.

Over to you Tom.

Good afternoon, everyone. And I'll start with Canadian drilling and Ensign maintained the utilization premium of 39% in the quarter versus an industry average of 34.3%.

Our fleet of 1500 to one thousands and eight 50s continues to provide performance capabilities demanded by our customers in a competitive market and in many cases, and are further enhanced by our Edge technology platform, which is expanding our capability and revenue generation opportunities. As contracts roll over on to new contracts, rates continue to improve particularly for higher spec rates and deeper classes, while rates for specific classes continue to improve from the trough of 2016, the overall average rate increase for the entire fleet was somewhat flat with a modest increase in Q4 versus the same quarter in 2016 excluding the impact of any shortfall payment.

Late in November and early December, the impact of a deteriorating gas market and higher differential that began the delay the start of winter drilling programs will cause reductions in levels of activity that were previously anticipated. Corresponding activity in Q1 looks similar to activity in Q1 2017 with perhaps slightly slower activity in March on a year-over-year basis.

On our directional drilling business, directional had a similar Q4 to the same period last year and was negatively impacted by start-up costs and preparation for a more active Q1 and 2018. Q1 continues to be a relatively active quarter as the two strips have truly become integrated.

In our well servicing business, Canadian well servicing activity in the quarter was slightly lower than the previous year, but as a general market -- sorry, as a general market slowdown into the Christmas break, attracting crews return to work remains a challenge, however rates have been improving slowly and steadily, which is a trend we continue to expect through the remainder of 2018. Our testing business has had challenges with rates and activity for the previous two years, but beginning in Q4 of 2017, we began to see improved rates and increasing levels of activity, which is a trend we expect to continue again through 2018.

Our rental business, our rental rates and activity continue to improve in Q4. We expect a relatively flat to modest growth in 2018 versus 2017 as the market for some of these services are on the drilling rig competitive for certain assets.

Our overall outlook for the Canadian business, we expect overall industry activity in Canada in 2018 to remain fairly flat with similar or slightly less days in 2017, while demand for deeper higher spec rig types remains relatively healthy, average price for the overall fleet is expected to remain fairly flat with somewhat potentially modest growth to the upside as some rigs roll over on to new contracts. Our Australian business as Bob alluded to, we are the largest drilling contracted in Australia and we 50% of the days with 30% of the fleet.

While activity remained flat through 2017, we are anticipating a slight improvement in drilling days with an approximate increase of 10% to 15% in activity in 2018 due to demand for drilling related to domestic gas supply. Pricing has also stabilized and is beginning to improve, particularly for equipment and personnel as demonstrated performed capability.

While pricing is expected to improve, the overall increase for the fleet average will be modest due to the longer-term nature of most contracts in the area. And in our MENA business, which activity bottomed to three rigs as Bob eluded to earlier in Oman in 2017 with those rigs remaining on long term contracts with slightly improved rates over 2017.

The outlook continues to improve as the demand for existing rigs improves with some anticipated or active open tenders that maybe potentially awarded by well increase, the active rig count in the region late in 2018 or early 2019. And with that, I'll turn it back to you about you Bob.

Thanks Tom. So, we'll put it back to the operator for Q&A.

Hey good afternoon, guys.

Hi Ben.

I had a question about the account receivable in Venezuela, you just mentioned in the press release that you are assuming a even collection over a five-year period. Is that because it's structured as kind of a promissory note that pays back over five years?

Fair, so what we’ve done is looked at, sort of how long it's good for us to actually collect the balance and most likely it looks like it's going to be over a five year period. So, there is no dispute on the invoices that we have.

With that base it's more just the collections of the U.S dollars. We do collect these throughout the year from them.

So, we took the approach that, it's really sort of source of financing for the bases there for collectable over the next five years.

Okay. Got it.

I appreciate that. Switching gears, a little bit, you guys talked about leading edge day rates in the Permian up around $23,000 to $25,000 a day.

And then you mentioned that includes the Ensign Edge system. I was just curious how of that day rate was being contributed by the Edge control system?

Sure, sure. No, good question.

So, Ben, as any new technology roles out the adaptation by the operator always starts off building along the way. So, I would say that, either probably think of it as a $1,000 a day somewhere in that range.

Maybe as much as $1,500, but probably more like a $1,000 a day. But as we have the platform now to add, I touched on a few apps, in the few miles into the RP optimizer things like that, these are -- these are apps that we’re building with another party that should be able to push out to any of our rigs and those will be extra incremental paths that the operators wants to turn them on.

They'll probably be charged out at $300 to $400 a day type of thing.

Okay. Got it.

And last question for me, I think guys mentioned total of 40 rigs, running in your three main markets in the U.S. currently.

Just kind of curious on if you guys had a lot of sight through the first quarter, second quarter on any other further rig activations coming in the U.S.?

Yes Mike, do you want to talk to that a little bit where we're seeing some increased demand and maybe touch to California Rockies, and the Permian a little bit.

Yeah, I think there will be some mid to late second quarter increased demand in all three areas. And we have, some additional product.

California is probably the best area where it's just still sitting on the ground ready to go. The other two areas will depending on what people are looking for, some of it have to be upgrades or refurbishments, but there's other potential plays where we still have existing assets that would be fit as is.

Okay. Got it.

Appreciate it guys. I will hand it back.

Thanks Ben.

Good afternoon, all. Can you talk about your pricing outlook in Canada and do your comments on the tightness in the EC 1500 triple market in the U.S hold in Canada?

Or would you expect pricing for even leading-Edge rigs to be fairly flat from here on?

Yeah, I think it's a good question. I think that what you're seeing is the super spec rigs in the Permian will lead the charge on the mid 20 rigs in Canada because, that market -- and Tom could talk to it perhaps a little bit that market is running 80% utilization.

So those rigs are in a strong market where you can move things a little bit. Tom do you want to expand on the Canadian market little bit on the 1500s particularly?

Yeah, just following on Bob’s comment, if you look at that class of rig in Kansas currently running about 80% utilization. So, it does have a little bit more pricing traction and then particularly you start throwing in the bundling and things like Edge and again, it allows you to charge for that and get incremental revenue over and above the day rates.

So as those rigs roll off contract and on to new ones, we have been signing them at higher rates and expect to see some movement, but I would say, if you look at the average for the overall fleet, I think because you still have a lot of singles and doubles in other categories, which are moving as well, but I would say the increase looks more modest. But certainly, traction for that portion of the fleet is still relatively healthy for Canada and the rates not a lot different than the U.S.

market, not quite moving at the same pace as the Permian, but still fairly healthy for that class of rigs.

So, given that commentary, it would be fair to say that you're now looking at redeploying any of your deeper, higher spec Canadian rigs to the U.S. at this stage?

Well it's a good question. We've seen some of the competitors, we've moved a few into U.S.

quite early on. I would say that our client base is filling our needs for the asset base that we have currently in Canada.

It's always an option, but right now we have no definite plans to move any rigs from Canada down into the U.S. So, we have them all contracted.

We don't have any available. As Tom pointed out, day rates are starting to move into the low 20s and that type of rig in Canada and currency agnostic it's starting to be similar to what we're seeing in the U.S.

When you think about contracts to roll over in the U.S fleet and the momentum that you've mentioned, the pricing side, would you expect your U.S. revenue per operating day to migrate higher in the next few quarters.

I'm just trying to get a sense of whether there's anything in Q4 that put that number to be artificially high and we shouldn't be thinking about that being sustainable or expandable go forward?

Yeah. There is nothing special in the fourth quarter Jon that on a sequential quarter basis would lead one to believe that it's not repeatable.

We're seeing, Mike and his team down in the U.S. are turning our contracts.

We signed six-month contracts in the U.S. Some guys jump up on the tables and signed a two-year contract.

But how it works, it's on a longer-term contract, you are letting off some day rate

Bob does the tightness in the high spec market in the U.S. right now make you contemplate doing new builds and how far apart is leading Edge pricing and contract duration opportunities that you're getting today away from where you would need to see it to quote and build more ARS at this point?

Yeah, I think there's two things happening Jon in the Permian, we're seeing the rate of pace of increase slow down. We're also seeing our clients, the people that know our clients, looking more towards the yield than they are towards their per day increases.

But I would say that basically on a new build, we need to see probably closer to $30,000 a day before a $20 million to $25 million new build starts to become attractive again and there's a little bit of space between those two numbers right now.

Next one is probably for Mike Nuss. Can you give a regional update on what you're seeing in California right now?

Obviously, there are large concerns about LATAM heavy volumes potentially falling off given what's going on in Venezuela, but yet work capacity constraints in Canada, so do you see any potential for that being a bright spot for activity in the coming year and are your customers having any conversations about getting ready for more active '18?

Yeah, with oil prices in the $0.60, that works more favorably in California. So, we are seeing increased demand and also better stability of what we do that running.

So, we are activating another couple of rigs. So that area looks pretty solid.

Okay. Would you expect to ramp up much more meaningfully from where we are today?

I don't know exactly what you mean by meaningful. I think there will be some increased activity, but I think it will be somewhat conservative when you just look at the client base out there.

There is still quite a few independents and clients out there are somewhat of a conservative nature still. So, the increases there I don't know that they will be overly robust at this time.

I think it will be conservative growth.

Okay. Just in terms of the Argentine and Middle Eastern tendering opportunities, can you give more color on the size of those tenders and what are those opportunities would require new builds and what your appetite is to build more rigs and put them in those markets at this point?

Yeah in Latin America of course, it looks like Argentina, it seems to be a quite a steady market. I don't think that we will have to put any new rigs in the market.

I don't think the market is demanding that right now. In the Middle East, Middle East is kind of interesting animal.

Oman, which we know very well of course, all these Middle East and areas offer new build contracts every year. There weren’t a few of them and basically the prices that they're willing to pay there just seems to be big spreads there between that.

So, we're seeing a lot of people take that up. We are seeing some consolidation in the business.

You probably saw that this morning in the Oman area, but still a very tough market over there, but the Oman market is a market that we've done very well and that showing technology with our smart ADRs and Tom and his team are working on some new opportunities attracting, I wouldn't say new builds, but fairly new rigs that could be deployed in the area and make the margin that we would expect of them.

Next one is just for Mike Gray; how do you think about rightsizing the right terms. Are you tuck in Venezuela and is it fair to assume that if you look at the total PP&E and receivables that you could infer a lot in the country based on what you put out in the release, that your total cap on the country is around $50 million?

Yeah, that number would be correct as for any of the write down, we still think the amounts are collectable as the time, value and money over the next five years, the big thing for us it's more sided. So, it goes back to where it is our paid invoices and we are collecting full of ours, but it's more of the U.S.

dollars flowing in that is slowing down the big reason for the discount over five years.

Okay. And is it fair to think about the receivables being a combination of next gen [Acer]?

No, the discount is strictly on front of Acer, the remainder is a mix of companies of which we do not foresee any issues on the collections.

Okay. And one just for me, your comments on Venezuela are obviously more cautious than past quarters, which makes a ton of sense.

Is your line of sight that you have right now, just based on what the mix of companies are telling you, is going to look like the next few months or do you have extended visibility or an extended view on that?

Mike Gray, do you want to take that?

Sure, no I think the visibility I think is a little more cautious just with the sanctions that came out and people trying to understand how the sanctions are going to be sort of applied, but for the most part, I think the visibility is kind of as expected and similar to what we had in prior quarters.

Okay. Appreciate the color.

I'll turn if back.

Thanks Ian.

Thanks Shantel. So, to wrap up our comments on the 2017 year, I just want to say that Ensign has always been a steward of our shareholder's equity and has despite how tough the business has been, managed to continue to pay our shareholders of dividends since 1995.

We continue to find that as we integrate more of our advanced Ensign Edge controls on our rigs, and when that is coupled with our optimization team, we find a more collaborative environment developing. With that, we find that we are in most cases negotiating rates and new contracts rather than being subjective to the three bids and the buy process.

As we look into the year ahead, we are definitely seeing strong demand continue for our Tier 1 super spec fleet with rates solidly in the mid-20s since we pointed out. The utilization on the fleet, we are generally expecting a 5% to 10% year-over-year increase and operating days at our premium fleet yields continue strong demand.

All our other lines of business are also seeing strengthening business, since we move through '18. As previously mentioned, our CapEx guidance for 2018 remains in the $65 million to operate and maintain the high spec fleet through 2018.

Notwithstanding, I'll point out that Ensign over the past 10 years, a decade in which we had the financial crises havoc and the commodity prices in the oil and gas market fall apart, we generated $1.30 EBITDA for every dollar of CapEx invested, a buck per EBITDA for every dollar CapEx invested. So, I'll leave it at that.

Thanks for joining us today and we look forward to sharing our first quarter 2018 results with you in about three months. Thank you again.