Ensign Energy Services Inc.

Robert Geddes - President and COO Michael Gray - Chief Financial Officer Edward Kautz - President, US and Latin American Operations Brage Johannessen - Executive Vice President, International-East Operations Tom Connors - SVP, Canadian Operations

Mike Mazar - BMO Nesbitt Burns​ Jon Morrison - CIBC World Markets Ian Gilles - GMP First Energy

Thank you Judy. With us today is Mike Gray, Mike is our new CFO, this was his first quarter as CFO, Tom Connors here in Calgary as well.

Tom as are EVP for Canadian Operations and Denver officer is Ed Kautz, President U.S. and Latin America Operations and in Huston, we have Brage Johannessen, EVP International-East Operations.

Thank you all for joining in today's third quarter 2016 call. As you know Ensign a worldwide energy services company operating over 200 premium ADR type rigs in seven countries around the globe, over 100 oil service rigs in Canada and the U.S., approximately 75 directional drilling kits focused on the Western Canada Sedimentary Basin and in the Rocky presently.

Ed Kautz will chat a little bit more on our directional drilling, strategic expansion into the Permian later in the call. We also have a fleet of over 90 frac flowback units operating both sides of the board and we have 27 core and seasonal rigs that work in oil sand areas in Northern Canada and winter months.

Our revenue mix is about 25% Canadian, 40% U.S., 35% international; this provides us a strong U.S. dollar denominator revenue base and provides a diverse market base in the key markets around the world.

We are also pleased to report this quarter that our ACE team Augmented Control Engineering team based in Huston successfully installed our first Ensign Edge control operating system on our ADR 1500 working for a major in the Permian. The edge control provides critical step in moving towards drilling automation.

It offers on [Indiscernible] on an Ensign platform. It will provide revenue stream opportunities in the future.

We currently have clients requesting it on rigs in the U.S., Canada and Argentina. This is a kind of technology that gets you out on those two-mile lateral horizontal wells consistently and more cost effectively.

As you can see by our third quarter results, our premium ADR fleet contracts with the consistent and active client base in all the active basins worldwide continues to drive dependable results. That level of service quality and our focus on cost control drove our third quarter gross margin results up quarter-over-quarter.

For more details on our financial results for the third quarter, I will turn over to Mike Gray.

Thank you, Bob. I will start with the 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.

With that, I will now start the overview; the continued low oil and natural gas prices have resulted in reduced levels of demand for oilfield services in the third quarter of 2016 compared to the third quarter of 2015. Operating days were down in the third quarter of 2016 with Canadian operations experiencing a 38% decrease; United States operations of 43% decrease; international operations slowing at 20% decrease in operating day compared to the third quarter of 2015.

For the first nine-months of 2016, our operating days were down with Canadian operations experiencing a 35% decrease; the United States operations a 46% decrease; and international operations showing 27% decrease in the operating days compared to the first nine-months in 2015. Adjusted EBITDA for the third quarter 2016 was 42.5 million, 39% lower than adjusted EBITDA of 69.2 million of third quarter of 2015.

Adjusted EBITDA for the first nine-months of 2016 was a 133.5 million or 47% decrease compared to adjusted EBITDA of 253.7 million generated in first nine-months of 2015. The decrease in adjusted EBITDA can be attributed to general industry weakness particularly in North America compared to the same period in the prior year.

The company generated revenue of a 191.3 million in the third quarter of 2016 which is a 41% decrease compared to revenue of 324 million generated in third quarter of prior year. For the first nine-months of 2016, the company generated revenue of 625.7 million or 43% decrease compared to revenue of 1.1 billion generated in the first nine-months of the prior year.

Revenue by geographic area for the third quarter was - Canada was 52 million representing 27% of the total; United States was 72.9 million representing 38% of the total; and international at 66.4 million representing 35% of the total. Gross margins decreased to 52.4 million, which is 31.2% revenue net of third-party for the third quarter of 2016 compared to gross margins of 84.5 million, which is 29.2% of revenue net of third-party for the third quarter of 2015.

The 38% decrease in overall margins from that of the prior year reflects overall reduced levels of operating activity in the third quarter of 2016 versus the third quarter of 2015. For the nine-months ended gross decreased by 173.9 million which is a 31.5% of revenue net of third-party compared to gross margin of 307.1 million which is 31.3% of revenue net of third-party for the nine-months ended September 30, 2015.

The increase in gross margin percentages for the three and nine-months ended September 30, 2016 versus that of the corresponding period in 2015 was primarily due to shortfall revenue earned in Canada and management's efforts since late 2014 of control costs. Depreciation expense in the first nine-months of 2016 was 259.8 million, 21% higher than 214.8 million for the first nine-months of 2015.

Depreciation was higher this year compared to the last year due to the following; ideal equipment depreciation, higher dollar value equipment being utilize, the negative translation impact on the stronger Untied States dollar and a greater portion of the depreciation on assets, depreciated using a straight line amortization asset. General and administrative expense in the third quarter 2016 was $0.35 lower than third quarter of 2015.

Lower expenses is recently completed the rationalization of ore head costs to align with lower activity levels which is offset by restructuring cost together with the translation impact of the stronger United States dollar on expenses incurred outside of Canada. During third quarter 2016, the company reclassified share based compensation that was classified in G&A expenses as of $1.7 million and $2.3 million for the corresponding period of 2015 to their share-based compensation expense line.

This reclassification for the nine-months end of September 30, 2016, was 3.4 million and 4.9 million for the nine-months ended September 30, 2015. We expect normalized G&A expenses to run in a 9.5 million to 10.5 million range per quarter on a go forward basis.

Subjects to variability due in the foreign exchange. Total company debt net of cash balances increased by approximately 5.1 million or 1% in the third quarter of 2016 from 664.6 million at June 30, 2016, to 669.6 million at September 30, 2016 and decreased 84.1 million or 11% in the nine-months ended September 30, 2016 or 753.7 million at December 31, 2015.

Net purchases on property equipment for the third quarter of 2016 totaled 7.7 million down from 25.1 million in the prior year. Net purchases of property and equipment during the first nine-months of 2016 totaled 31.9 million down from 150.9 million in the prior year.

The company's completed one new ADR rig in the first nine-months of 2016 net capital expenditures for the calendar year at 2016 is expected to be between 40 million to 50 million. That reflects the overview and I will pass the call back to Bob.

Thanks Mike. Hopefully, we will turn it over to Tom for a summary of a Canadian operations.

Tom.

Good afternoon everyone. I will start with Canadian drilling.

In Q3, drilling activity in Canada was 38% lower than the same period of prior year. market has improved form the drought that normally occur during the second quarter every year due to spring break up, but it’s shaping up for the overall industry to exit 2016 was roughly 41,000 drilling days, which is a second lowest level of activity since 1977 with only 1992 having a lower level of activity.

Despite the lower level of activity, Ensign has reaped the benefit of disciplined, deliberate and consistent strategy to introduce the right equipment into the right markets at the right time. The addition of several ADR 1500s, 1000 and 850 since 2011 has allowed us to have stronger presence in the more active areas like the Duverney and Montney, even many of our period and a steady committed contracts base, which helps support pricing activity in margins at a time when all are under pressure for the industry.

The ADR 1500s is gaining a recognition in the market as it sets new benchmarks for drilling performance and efficiency. This performs has been recognized by our customers and rewarded us a new contract and extension and/or renewals that will allow us to maintain our steady contract base in the 2017 and beyond.

Due to the performance and successful introduction of our first ADR 850, we have also signed a contract to completed second ADR 850, which was part of the previously halted build program in early 2015 and will be delivered in late Q4 to begin work in Q1 2017. We manage to maintain top quartile market share in most active areas in Q3 such as mountain in Montney, Duvernay and Viking.

However we did lag overall industry realization in the quarter by roughly 3% as sluggish activity level drove some contract at lower prices at or below the daily cost base to maintain some activity and oversupplied the market. So the end of Q3 we did transfer two deeper rig out of the market to fulfill contracts in the U.S.

to meet the demand for expanding work for our Rocky fleet, with 67 remaining listed rigs Canadian fleet. We continue to maintain the third highest market share in the Western Canadian basin and one of the top three drillers by wells drilled in the quarter having drilled 12% wells in the Western Canadian basin, which again speaks the efficiency of our fleet as we've rolled above our market share of 10%.

Included in the revenue in the third quarter is $6.1 million of shortfall payments, the majority of which is related to Canadian drilling; if exclude the impact of shortfall payments the associated revenue and gross margins remain higher than many of our peers as a result of an effective rig mix and focused investment strategy. And the directional drilling business continues to be a highly competitive market with most of our peers experiencing significantly reduced days in pricing.

Pricing trends remained stable during the quarter, while we maintained our market share in the quarter; days decreased 40% in the previous year last year. Having our own proprietary motor design and maintenance facilities has allowed us to benefit of offsetting lower activity with lower operating costs to maintain margins.

Well servicing, and Canadian well servicing, we see 23% utilization in the quarter and 15,216 hours which is roughly 5% higher than the same period last year; while activity levels have stabilized; rates remain competitive; rigorous cost controls and operational discipline continues to sure up margins and generate positive cash flow in the division despite competitive pricing pressure. And our testing business in Canada, it does remain extremely competitive, because it is truly oversupplied, but although we remained strategically positioned to capture business in the more active areas with high pressures such as the Duverney and Montney, pricing has bottomed and the business has been right sized to continue to generate positive cash flow through long cycle.

Our managed pressure business has well remained as active in Q3 2016 as they were in Q3, 2015 with some downward pressure on pricing and continues to identity niche opportunities in key areas. Our rentals business again is in highly competitive market and has experienced significant pricing pressure or sometimes included inside the day rate as part of the competitive offering.

We have equipment located in all key areas of the activity and have maintained reduced healthy margins and positive flow throughout the quarter. Our outlook for the year remains challenged with activity for the drilling industry forecasted somewhere in the 40,000 to 45,000 day range, improving commodity prices may increase cash flows and corresponding CapEx in 2017, but we remain cautious about how much will be directed towards drilling activity versus balance to repair acquisitions et cetera.

With the current volatility in commodity prices operators commitment to CapEx still seems fragile; in 2017 we expect 20% to 25% increase in drilling activity being somewhat offset by 10% to 15% decrease in average pricing net of the effect of shortfall or cancelation payments, as deeper rigs continue to roll off contract and into the spot market in 2016 and early 2017. That's it for Canada.

Bob, I'll turn it back to you.

Thanks Tom, well I'll move down with the U.S. and Ed out of Denver will give us a summary of the U.S.

first and then into the Latin America operations. Ed.

Thank you Bob, and good afternoon ladies and gentlemen; I'll start with the U.S. operations.

At the end of the third quarter 2016, the Ensign United States division operated a fleet of 90 premium drilling rigs. The company also operates 44 well unit and 47 flowback kits in the U.S.

and a directional drilling business with 31 directional kits currently in the Rockies. United States drilling recorded 1,586 operating days in the third quarter of 2016 a 43% decreased from the 2,768 operating days in the third quarter of 2015.

United States well servicing recorded 17,651 operating hours in the third quarter of 2016 a 17% decreased from the 21,188 operating hours in the third quarter 2015. Revenue was down 49% from the third quarter of 2016 compared to the third quarter of 2015.

The company United States operations account for 38% in the company's revenue in the third quarter of 2016 compared to 45% in the third quarter of 2015. The company added one new ADR rig in the U.S.

fleet in the first quarter 2016 on was a contract was a major operator. It also is our first ADR outfitted with the new Ensign Edge controls that Bob spoke of system on it drilling and its drilling in West Texas.

The company has also in the process of moving two ADR 1500s from Canada to the U.S. for a term project.

They are both in the U.S. now and should spud some time in later November.

Our directional business in United States is currently focused in a Rocky Mountains running approximately four jobs on a daily basis. We have opened up an office in the Permian Basin and hired someone to manage that and we will be expanding our directional business model into the active Permian area.

Of the 97 flowback units we have in the company, we are operating in North America. 47 of those operated in the U.S.

and it is a challenging business as Tom spoke of in the U.S. as well.

Activity in the U.S. drilling and well service markets is becoming more active as capital starts to give attractive back into the business.

We are definitely starting to see some signs of price forming up on our ADR 1500 type rates equipped with 75,000 PSI systems across the U.S. Now moving to Latin America.

Ensign international operates total of 17 rigs in Latin America. A company operates nine regions in Argentina while running 45% to 55% utilization and Ensign has eight rigs still in Venezuela, which we are around between 15% to 80% activity on a given day.

We continue to monitor our accounts receivable and a challenging oil market general and our relationship continues to be good with the natural and the mix companies there. As always, the current economic [Indiscernible] in Argentina and Venezuela will continue to play a role in the platform for the industry.

We are currently running between 60% and 70% of our rigs in Latin America. With that Bob, I'll turn it back over to you.

Thanks Ed. Next, we have Brage Johannessen out of Huston.

Brage manages our internationally operations and Huston operations fairly in the fleet. Over to you Brage.

Thank you Bob. The rig count for Ensign international least operation has remained unchanged quarter-on-quarter from Q2 to Q3 with a totaled count of 29 rigs in its Australia and Middle East Africa regions at a utilization rates around 45% in the Eastern Hemisphere operations excluding Libya.

In Australia, we are flat quarter-on-quarter operating six rigs with 30% utilization against an Australian overall utilization rate of 25%. We do not see any signs of significant changes to the overall activity levels in Australia in the next quarter and the first half of 2017.

We do expect though that there will be some changes in activity from one operator to another, which could lead to opportunities that we are well positioned for given our strong asset portfolio in the country. In addition to any new opportunities, we are currently in the final stages of contract extension discussions for 2017 for all of our running rigs in Australia.

Activity levels in our MENA region remained robust as we continue to operate seven rigs on term contracts in Oman. Our superior ADR design has continued to provide strong operational and safety performance for our customers.

But given changes in our customers field development plans we expect to have to lay down two of our ADR rigs in Oman as of quarter one 2017. Although this will have a negative impact on our top line, we do expect to be able to recover some of it as a result of ongoing cost reduction focus and reduction in the pricing concessions negotiated with the customer during the downturn.

In the Middle East in general apart from Iraq, overall activity levels are expected to be flat to slight growth going into 2017; with all upcoming tenders and opportunities for additional work to be heavily contested and competed for. Our total contract backlog for Australia and Middle East Africa regions currently stand at around 20 rig years in total.

The Company's total international operations accounted for 35% of the Company's revenue in the third quarter of 2016 as well as for the nine-months ending September 30, 2016; this compares to 27% of the company's revenue prior to the industry downturn, and is in line with the Company's long term strategy of diversifying our geographical spread by growing our international business with particular focus on growth in the MENA region. And with that, I'll turn it back to you, Bob.

Thanks Brage, back to the operator for questions.

Hey good afternoon. Just a real quick one, it’s not a huge deal, but it sounded interesting.

The Canadian well services hours, the service rig business was very strong relative to the decline we have seen in all the other service lines. Was that something sustainable or was there just kind of a lot of things that happened during the quarter something like that or what did you guys kind of attribute that to.

None of your peers were able to do anything close to that?

I think if you look at where we are positioned in the markets, we are positioned in pretty consistent Mike with where we were last year, a little bit higher. And we expected the activity levels to stay fairly consistent into the future.

So I think it's a question the customers in the markets were positioned in and some of the new products we have introduced in the last few years. Just a market focus we've had.

Okay, that’s great. That’s all I had.

Mike how many rigs were included in the $6.1 million of contract shortfall in Canada and I think Tom referenced that the bulk of it was Canada in terms of the contract short fall, was the balanced for that just in the U.S.?

[Indiscernible] Canada was five rigs.

Of those rigs that ultimately the customer paid out those five rigs, I guess.

[Indiscernible] actually basically a top up its like a take or pay contract in short. So wasn’t a calculation.

In those cases where there was a shortfall payment, were the majority of those rigs continuing to operate on a go forward basis or was it simply that you aren't willing to ultimate the tag on those shortfall days on the tail end of the contract for the next year. I’m just trying to get a sense of whether those rigs were laid down or whether it was just a short fall customer paid and you kind of move forward as well?

Let me give you an example that could be somewhere that 300 rig a day rig commitment this year and they had only meet 80 to 100 days so far. So it was a bit of a top up too.

I think it caught up where they had plans to have work into the futures; they haven't cancelled a rig contract. A rig may be going back to work for example in Q1, 2017 or Q4, 2016.

So just a fact [Indiscernible] in a period of comment. They were short for that particular period time with their contractual commitment.

But the contract still continues on.

Okay so the it's fair to assume that those rigs weren’t laid down and that was the bulk of the contract shortfall payment?

Yes, the rigs were laid down for that period of time, but they are going back to work with that operator. Yes.

Yes, Jon, just to fill more color on that. I mean 40% of our rigs today are on guaranteed day contracts extending way out to 2020.

Okay, Mike can you give more color and what the driver was to reclassify a portion of the SG&A and stock based comp and why you decided to restate that to prior years?

Definitely just because we got a sort of proper G&A number that didn’t have sort of the share market value like [indiscernible]. We disclosed it on our annual reports under a note 11, the share based comp that wasn’t G&A.

so I think just for presentation sake it makes a lot of more sense than all the share based comps, sitting in the share based comp expense line. And then the G&A to be the true cash card.

G&A going forward.

Ed can you talk about how your customer conversations were going in California in both the contract drilling and well servicing side and what is your line of site for development in the market in the front half of 2017 at this point?

It comes back to Jon. Primarily the commodity price and most of the clients that we have their all says we need to be up north of $55 before they start doing much.

We have projected that there will be some uptick and there will be some activity there. But it's a pretty skinny market.

On the well services side, again, there is only three or four major players in the area and we have one top operator that we work for that stayed pretty busy and has projected going to stay. Slowdown some next year, but not a lot.

Okay, so it's fair to assume the front half of 2017 should be astronomically different than what you have experienced of the trailing couple of quarters?

That's correct.

Ed can you talk about the ongoing strikes in Argentina that’s affecting 70 oilfield services sector and was that a major drag to operating days in the quarter at all?

It was not a drag on the quarter per say. I guess, it's nothing new in Argentina I think the different then it's been for the last four, five years, I don’t know five, six years ago.

Bob and I were in Argentina and [indiscernible] and we couldn't get out of town because of a taxi cab drivers strike. So I think that's just a way of doing business and we just need to manage around it some days that we are down for a little bit and most of the time it's business as usual.

[Multiple Speakers]

There is obviously a lot of negative headlines around Venezuela right now, I'm just considering some of the fiscal challenges in the country and I realized that things are fluidng, you don’t want to give too many details but did DSOs change meaningfully quarter-over-quarter?

I don't believe so. No.

Okay. Bob can you talk about how you think about the halted new build program that was in 2014.

And is it something that you're thinking about reactivating as the market starts to turn and get better and where is your head out on buy versus build at this point if you ultimately believe that you are going to need more rigs in the next two, three, four, five years?

Yes, good question Jon, I means I think I would protect at the balance sheet and got after the shutdown quickly. You will recall, we had about 33 rigs at that particular time, 23 ADR 1500s and 10 of the ADR 850s, we ended up delivering one ADR 850 and the second one was going to be delivered by the end of the year; of the other 23 ADR 1500s we ended up delivering nine of which the last one as delivered first quarter of this year.

We have a lot of inventory from that build program that was suspended; and the next rig that we put out of course we could deliver in about four, five months with probably a third of the capital required normally to construct a full rig and then it goes; that [Indiscernible] off from there. We are thinking about certain clients advances, they like the ADR 1500s so much that they have said yes; mid 2017 perhaps, we can entertain that such a deal.

We have not resurrected into that as of today though.

Last, one just from me, Tom on the wells servicing side in Canada was labor availability a major headwind in the quarter and could you be running more service rigs today based on your current staffing levels if the demand was there?

I think labor availability has been a challenge for the last 30 years or so, but I think the biggest challenge right now is when you - obviously a lot of people move to other industries to find work and if the work you have is only for five days, 10 days of the temporary nature, it's a little bit more difficult to attract people to come back. So, it has been a little bit of a challenge in some specific areas, we are just trying to hire people locally.

But I don't think it’s been [indiscernible] challenge it hasn't capped us from going back to work here or taking on more work. but you got to plan for because you got to have crews and you got to try and take up work together obviously to attract people to come back to work.

So, I don't think challenge is any different than what has been any other time in the past, but certainly the challenge being that some people have gone to other industries and you have got to have enough work. I mean three days, or five days where the work is not going to be enough, [indiscernible] together a period of activity to attract them back.

So, it's just going to maybe impede how fast you could ramp up this activity, ramps up that much but we are not anticipating that much of a ramp up.

Perfect. I appreciate the color.

I'll turn it back.

Good afternoon everyone. The U.S.

market share dropped quarter-over-quarter I mean when I look at the rig count increase it was primarily Permian. I mean how do you guys think about slack capacity for Ensign and your ability to fit into additional I guess rig contracts into the Permian right now.

Do you have enough availability that you can go and do that at this point in time?

Yes, Ian good question. We have got five of our ADR 1500 undergoing, 7500 PSI upgrades they are walking rigs already [indiscernible] 7,500 PSI upgrade and we are finding a lot of this contracts require our third pump.

We have got the pumps we are adding that in, it's about a tow month gestation to do that. So you are going to see those rigs of which most of them are already contracted into the Permian here through the fourth quarter and the first quarter of 2017.

And as I think about those upgrades I mean are you getting any commitment from our customer to pay for those upgrades on top of what we would think may be a spot or slightly above spot day rate would be in the Permian at this point in time?

Yes is sense that, I mean we are starting to get a better price. I think there is about $3,000 day bifurcation between rigs that they don’t have the 7500 and the third pump.

On top of that we are successful in the clawing back about another $1,000 a day of the reductions that have occurred over the last three years. So we are starting to get into the upper teen on base day rates.

Okay that's helpful. Turning to the balance sheet, I mean the U.S.

the $100 million coming due I believe May 2017 if my memory is serving me correctly right now. And we have a [Indiscernible] debt markets now for potential rigs and so how is Ensign thinking about dealing with that piece of term debt coming to maturity acknowledging that there is room on the facility right now?

Yes, I think the idea for now is relative facilities and sort of depending on hoping we will approach that when the bridge comes in direct.

And so I guess with that in mind. Do you believe that hampers ability to take an aggressive stand either through acquisition or for build program or upgrade program, should you have to pursue it?

Well I think that trying to predict into the future is always a challenge. I think that acquisitions just a premise of acquisitions is a good question.

Based on the type of rig one might want to go and acquire we have slowly adding capital and you have seen some guidance from us $40 million to $45 million of capital this year probably will be able to too much different next year. We can maintain our fleet and continue to add this 7500 PSI systems and third pumps.

We would probably looking for some type of contract coverage to get into finishing of the next 1500. I think we are getting close to that, but not quite there yet.

Okay, thanks very much. That's all for me.

I appreciate the color.

Thanks Ian.

Thanks, Judy. In summary, from an activity perspective it certainly appears as the bottom is behind us.

The challenge does still lie with only supply drilling rig assets for a while. Where we expect activity to increase the combination of competitors with rigs coming out term in 2016 and the critically ill balance sheets of some competitors will create tight pricing in certain areas and on certain types of rigs.

Fortunately Ensign with its extensive ADR fleet worldwide will be able to claw back some of the pricing concessions that have plagued industry over the last three years. With roughly 63 rigs running today around the world and a healthy utilization rate in our wells servicing group; we continue to see our schedule and move forward with increased activity through 2017.

With activity will eventually come pricing. 70% of our rigs working today are on long-term contracts and as I mentioned before, 40% of our rigs today are on guaranteed day contracts extending up to 2020.

Most interesting and how fast our ADRs are drilling the two mile horizontals, which are becoming so predominant. Our ADR 1500s are a testament of the right equipment on the right projects with the right people can provide meaningful returns for operators with oil in the $50 range and gas in a $3 range.

Look forward to our call on fourth quarter. Thank you everyone.