Ensign Energy Services Inc.

Robert Geddes - President, COO and Non-Independent Director Michael Gray - CFO Tom Connors - EVP of Canadian Operations Mike Nuss - EVP U.S. and Latin America Operations Brage Johannessen - EVP of International East Operations

Jon Morrison - CIBC Capital Markets Ian Gillies - GMP Jeff Fetterly - Peters & Company

Thank you, operator. With us today, we've got Mike Gray, our CFO; Tom Connors, EVP of Canadian Operations.

In Houston, we also have on the line Mike Nuss, EVP U.S. and Latin America Operations and Brage Johannessen, an EVP in International Operations.

So today we'll go through a little bit of opening, some financial summaries by Mike and some operational updates with the other team members here. And then we'll be going back to the operator for Q&A, and then I'll wrap up with a closing summary.

So here's a little bit of the opener today. A few years back, we made the statement, never let a crisis go to waste.

The goal was to build an organization with the right rigs, the right people, and the right size for the long haul. Over the last couple years, we've quietly super spec'd 2/3rds of our U.S.

southern fleet now, moved our IT systems onto a new platform that is much more efficient. And we managed to kick out a few newbuilds with contracts for specific long-term clients.

With the sense that the worst is behind us and with cash flow generation sufficient to fund CapEx plans, we cancelled the drip, and it increased CapEx margin with the addition of two new ADR rigs, which will be commissioned in the third quarter, and a heavy service rig also for the Permian. Today we have about 75 to 80 drillings rigs running, or roughly 50% of our worldwide fleet.

We also have a steady well-servicing business on both sides of the border, also running at about 50% utilization, which is about 50 out of 109 well-service rigs in North America. In addition, we also have about 15 directional drilling jobs on any given day, and we're seeing higher unit utilization in our rentals division.

Today, 2/3rds of our fleet are active on long-term contracts, which is about 50 of the 75 that are active today. 50% of those are on guarantee take-or-pay contracts.

So to run you through the second quarter financial details, I'll turn you over to Mike Gray.

Thanks, Bob. So let's go through 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 the 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 account receivable balances and raise capital for other unforeseen conditions, which could impact the use of the services supplied by the company.

Now for an overview of the quarter, the modest price recovery of crude oil and natural gas resulted in increased demand for oil field services in the second quarter of 2017 compared to the second quarter of 2016. Operating days were higher in the quarter, with Canadian operations experiencing a 69% increase, United States operations a 61% increase, and International operations showing a 2% decrease compared to the second quarter of 2016.

For the first 6 months of 2017, operating days were higher with the Canadian operations experiencing a 55% increase, the United States operations a 38% increase, and International operations showing a 7% decrease compared to the first 6 months of 2016. Adjusted EBITDA for the quarter was $44.3 million, 37% higher than adjusted EBITDA of $32.2 million in the second quarter of 2016.

Adjusted EBITDA for the first 6 months was $94.4 million, a 2% increase compared to adjusted EBITDA of $92.8 million generated in the first 6 months of 2016. The 3 and 6 month increase in adjusted EBITDA can be attributed primarily to increased amount for oil field services caused by a modest price recovery of crude oil and natural gas compared to the prior year.

The company generated revenue of $232.2 million in the second quarter of 2017, a 32% increase compared to revenue of $175.9 million generated in the second quarter of the prior year. For the first 6 months, the company generated revenue of $483.5 million, an 11% increase compared to revenue of $434.4 million generated in the first 6 months of the prior year.

Gross margin increased to $55.1 million, which is 26% of revenue net of third party, compared to gross margin of $45.4 million, which is 29% of revenue net of third party in the second quarter of 2016. The 21% increase in overall margin from that of the prior year reflects overall increase in levels of operating activity in the second quarter of 2017 versus the second quarter of 2016.

Gross margin decreased to $115.7 million, which is 27.5% of revenue net of third party for the 6 months ended June 30, 2017, compared to a gross margin of $121.6 million which was 31.7% of revenue net of third party for the 6 months ended June 30, 2016. The decrease in gross margin percentages for the 3- and 6-month ended versus 2016 was attributed to lower revenue day rates and shortfall revenue earned in 2016 versus no shortfall revenue earned in the same period in 2017.

Depreciation expense in the first 6 months of 2017 was $154.9 million. This is 12% lower than $175.9 million for the first 6 months of 2016.

Depreciation was lower this year compared to last year due to certain operating assets being fully depreciated. G&A expense in the quarter was 18% lower than in the second quarter of 2016.

The decrease in G&A resulted from the company's continue initiatives to reduce cost. We expect normalized G&A to run on a $9.5 million to $10.5 million range per quarter on a go-forward basis, which would exclude share-based compensation and is subject to foreign exchange movements.

Net debt increased by $5.3 million or 1% in the second quarter of 2017 from $709.1 million at March 31, 2017 to $714.4 million at June 30, 2017. It increased $26.2 million or 4% in the first 6 months ended June 30, 2017 from $688.2 million at December 31, 2016.

The increase was mainly due to increased capital expenditures over the year. Net purchases of property and equipment for the second quarter of 2017 totaled $46.1 million.

Net purchases of property and equipment during the first 6 months of 2017 totaled $75.6 million. The company added 1 newbuild ADR drilling rig to the expansive tier 1 fleet and 1 service rig in the first 6 months of 2017.

Net capital expenditures are currently targeted between $90 million to $95 million for 2017. With that, I'll pass it back to Bob.

Thanks, Mike. So for a summary of the Canadian area lines of business, which include drilling-well servicing, directional drilling and [indiscernible] rentals; over to you, Tom.

Good afternoon, everyone. I'll start with Canadian drilling.

Relative to Q2 2016 and Q2 2017, this had a fairly robust activity with 69% year-over-year increase in days. Although spring break-up is typically a slower time for the industry, our fleet and customer mix allowed us to consistently maintain a utilization premium of 5% to 10% utilization versus the industry average in the quarter in any given week throughout the quarter.

ESI average utilization for the quarter was 24% versus the industry average of 17%. Base spot market rates in every rig category are higher in 2017 than those seen in the trough of 2016.

However, the impact of rate increases is offset by the effects of contract rollover that occurred in 2016 and the absence of shortfall payments in 2017. With growing uncertainty in the commodity price environment, further rate escalation is unlikely.

And with the visibility we have for now, it appears rates will normalize or remain flat at current levels, which minus the effect of contract shortfall payments, results in overall total revenue per day of approximately 5% to 7% lower for 2017 versus 2016. Despite the challenges in the current environment, the majority of our AC triples and our heavy doubles remained active during the quarter with the result and impact of our top quarter EBITDA and gross margin versus industry remaining relatively stable year-over-year, net of the effect of shortfall payments.

Our new AC ADR 1000, introduced on previous conference calls, has been contracted and will begin working in the deep basin area beginning mid-August. In our directional drilling business, the rapid advancement of drilling advisory software is expected to expedite the further integration of directional drilling with drilling rigs.

The combination of the evolving technology with Ensign's high reliability, high torque motors and industry-leading meantime between failures will make it increasingly difficult for independent directional drilling contractors to differentiate themselves with the corresponding margin compression they are experiencing which is expected to continue into the future. Our well-servicing business and Canadian well services activity improved slightly or 11% versus the same period last year, with activity for the year expected to improve 25% to 30% for 2017 versus 2016.

Rates have gradually improved 5% to 10%, but are expected to remain relatively stable for the remainder of the year. Our testing business is a highly competitive space, or it operates in a highly competitive space, with low barriers to entry, and as such has little pricing traction.

However, activity for testing is expected to increase in Q3 as previously drilled wells are completed. In our rental business, rental rates have gradually been improving with particular product lines like matting, experiencing increased demand and helping to drive improved performance in the division on a year-over-year basis.

In Canada, the general outlook is that our recent uncertainty in commodity prices may threaten the strength and pace of activity for the second half of 2017. However, current visibility into bookings and contracts will continue to suggest an approximate 50% or greater increase in activity in 2017 over 2016.

Spot market rates have improved, but are expected to remain flat going forward with these ranges expected as a normalized range for the next few coming quarters. And that's it for Canada.

Bob, I'll turn it back to you.

Thanks, Tom. So next we're going to talk about our International East business.

We have a very strong international presence in both Australia and our MENA region, where we have a combined fleet of 29 rigs. To tell us more about that is Brage Johannessen.

Thank you, Bob, and good afternoon to everyone. As Bob mentioned, the available rig count for Ensign's Eastern Hemisphere operations is 29 rigs, and it has remained unchanged quarter on quarter, with a combined utilization rate between Australia and Middle East North Africa regions at around 35%.

In Australia, operations were stable during the quarter, operating 6 rigs with utilization north of 30% and slightly above the market utilization. All our active rigs in Australia are contracted through 2017 or beyond, and we expect activity levels to remain flat with potential additional work in late fourth quarter '17 or early first quarter of 2018.

Given Ensign's strong market position in Australia, we feel confident of our chances in an otherwise highly competitive market for that potential work. Activity levels in second quarter in our MENA region was flat.

We were operating 4 of our 8 rigs in Oman. With our activity levels down compared to prior year, we continue to exercise diligent cost control in order to minimize the overall impact on our margins, as well as continue to actively market our idle rigs.

The general market activity level in the MENA region is expected to be flat for the remainder of 2017, with a possible uptick in overall activity in the second half of 2018 as a result of tender activities in the region. All upcoming tenders and opportunities for additional work will continue to be heavily competitive.

Our contract backlog for our Australia and MENA regions currently stands at around 15 rig years. And we expect the overall active rig count to remain flat at 10 rigs for the remainder of 2017.

The company's total International operations inclusive of Latin America, accounted for 31% of the company's revenue in the second quarter of 2017. And with that, I'll turn it back over to you, Bob.

Thanks, Brage. Next we have Mike Nuss sitting in for Ed.

Ed is away this week, Ed Kautz. Mike Nuss manages both our U.S.

and Latin America operations. So Mike is going to give us a summary of those areas.

Mike?

Thanks, Bob. Good afternoon, everyone.

U.S. at the end of second quarter 2017, we're operating a fleet of roughly 70 premium drilling rigs.

The company also operated 45 well-service rigs and 47 frack flow-back testing units and a directional drilling business with 31 directional kits currently in the Rockies. United States drilling recorded 2,590 operating days in the second quarter of 2017.

That's a 61% increase from the 1,690 operating days second quarter 2016. U.S.

well servicing recorded 21,594 operating hours in the second quarter of 2017. This was a 42% increase from 15,229 operating hours second quarter 2016.

Revenue was $110 million, up 51% in the second quarter of 2017 compared to same quarter 2016. The company's U.S.

operations accounted for 47% of the company's revenue in the second quarter of '17. The company added 1 new ADR drilling rig to the U.S.

fleet in early 2017, with a contract with a major. It was also our first ADR outfitted out of the gate with our new Ensign Edge control system.

It is drilling in the Permian and is currently setting records. Through 2017, we also upgraded 6 of our walking ADR 1500s to super spec rigs, and they are all on contract.

We are also currently in the process of completing another 1500 ADR, and it will be due out third quarter 2017. Our directional business in the U.S.

is currently focused in the Rocky Mountains and is running approximately 5 to 7 jobs daily. Of the 97 frack flow-back units in the company we operated in North America, 47 are operated in the U.S.

This business is essentially getting back to market share quarter-over-quarter. In the U.S.A., the Baker Hughes rig count at July 21 this year decreased by 2 to a total of 950, which is still up 488 drilling rigs from previous year, same quarter or same type of year.

The rig count in the U.S. appears to be flattening out with expectations that it could remain flat for the balance of the year, signalling a floor to oil prices.

Today, we currently have 39 rigs operating in the U.S. under contract, or roughly 55 utilization and beating industry average.

The company's 3 main operating areas in the United States includes the Rockies, California and the Permian Basin. All have seen an increase in activity from the second half of 2016.

There are 11 rigs currently running in the Rockies, 8 of which are ADR 1500s. 6 of those have been recently upgraded to super spec rigs.

There's 9 operating in California, 18 in the Permian Basin, with 1 running in the Marcellus in the Northeast. We also have another 2 rigs coming on stream in the Permian, and should be up to 20 rigs operating in that area by the end of the year.

Of these rigs, 25 are under long-term contract or roughly 2/3rds of the active fleet. There's still a tight market in the West Coast and the Rockies.

We are seeing pricing increase in the Permian for super spec walking rigs, with all-in rates in the 20s. Our well-service division in both California and the Rockies are enjoying better than industry utilization, and we have also added a new heavy well-service rig into the Permian for a specific client.

And with that, I'll turn it back to you, Bob.

Okay, Mike. I'll turn it back to you for Latin America.

All right. Thank you.

Latin America, we operate in 2 countries, Argentina and Venezuela. We have a total of 16 rigs in Latin America, 4 of the 8 operating in Venezuela and 4 of the 8 operating in Argentina.

Argentina has become a very active area for our AC 2000 horsepower class in the Vaca Muerta region, and currently enjoy strong demand for our ADR type rigs, along with our Edge control technology there, working primarily with various IOCs. Venezuela, a bit of an enigma right now, but when you get past some of the news, the energy business is still a necessity.

Most of our contracts are with mixtas, and we believe sanctions on oil are unlikely. We see Venezuela business not being adversely affected.

But nonetheless at the same time, it will become more challenging. There's never a dull moment in Venezuela.

But we've been here for a long time, and it's a file that we know very well. So that's all I had.

Back to you, Bob.

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

Hello, Jon.

Afternoon, all. Mike Nuss, can you talk about Venezuela.

You said that you have 4 rigs running right now. Has that held fairly constant over the last couple months?

Yes, it's held constant through the year.

Okay. And is your view - I realize it's really hard to forecast things.

But it's obviously a topic of conversation right now. If there were any large worker strikes, is your view that the mixta companies would be less affected than perhaps PDVSA at this point?

I think so. We've been working with the mixtas and the IOCs for quite some time now and it's been a fairly stable market.

Okay. Mike Gray this time, are you willing to share what Ensign's total payables outstanding in Venezuela are at this point and give us any sense of what PP&E in the country is?

Nothing specific on that. With the accounts receivable, we do have a balance with PDVSA that we did take a discount in 2016 on, of which we really focused on most of the contracts with the mixta companies.

And we are receiving U.S. dollars from them.

I mean we just received a fair chunk of U.S. dollars in the last couple weeks out of Venezuela.

So for the most part, we still have the same belief that we had before that it's just a matter of timing of when we'll get paid. It will probably be a bit more prolonged.

But for the most part, we don't really foresee any issues on that long term, I mean only the short-term sort of effects that we see right now. And then as for the PP&E, I mean you'd have 8 rigs that are in country, a little bit older style rigs.

So we're not really talking a significant amount of PP&E in that country.

Okay. And it's fair to assume that any potential debt issue with PDVSA shouldn't tie into you guys that much, just based on customer exposure right now?

It shouldn't be material.

Okay. You talked about the ongoing price momentum in the Permian right now, and how you can still see some pricing gains unfold.

Do you guys have incremental rigs that you can put back to work in that market right now or are you fairly tapped out and high spec rigs currently in the Southern U.S.?

Yes, we've got - right now we have 18 running, Jon. And we've got 2 more coming on stream.

That will give us the 20. Of course quarter-over-quarter we've been turning our contracts, they've been on kind of 6-month actuarials that we're turning those over.

So quarter-over-quarter, I think we'll start to see that moving up in third quarter. Fourth quarter, probably start peaking off in the fourth quarter on a quarter-over-quarter basis in the Permian.

But to answer your question, we've got 2 more getting added. And we've been at this for a year and a half, almost 2 years now.

We've probably put about close to $100 million of new rig and upgrades into the Permian for super spec rigs. So we got ahead of it a little bit ahead of our competitors and that's why we've got quite a high utilization.

There is a few other rigs that could be modified. But right now we think that the Permian is rigged up, and right now it's kind of harvest time.

Mike Nuss did point out that in our Rockies area, we've got 8 of our ADR 1500s, and 6 of those are super spec rigs that we've upgraded over the last year as well.

Bob, is pricing differential across markets and demand strong enough that you'd actually think about relocating certain rigs at this point, or to your point earlier, you just harvest what you have?

Yes. I think moving rigs at this point, I mean we've been moving rigs again over the last year and a half.

I think it's getting too late to start moving rigs around, quite frankly. If you haven't done it by now, you may have missed your opportunity.

Most of the clients are locked down. We've got good operations with them.

They're well on the learning curve, good drilling record wells. There's very little likely chance that someone's going to come in.

And there's very little increase in incremental demand of the super spec rigs in certain areas. So I would say that if one is thinking that, they may be a little late to the party.

We've been doing that. We've moved rigs back to the U.S.

starting about a year and a half ago, a couple of the 1500s.

Tom, can you talk about how your average Canadian day rates looked year-over-year or on a sequential basis in the quarter? In your preamble you said you're off the bottoms on a spot market basis.

But you obviously had contracts rollover. Would that imply they're fairly flat year-over-year?

Well if you…

Like we track revenue per operating day. I just - I don't know if that's always a perfect proxy.

Yes. I mean there's a couple different ways to look at it on the revenue, your total revenue per operating day or base day rates.

And I'll just speak to base day rates, well, probably hit their lowest in about June or July at the end of Q2, being a Q3 2016. And there you saw singles probably sub $9,000 a day, as low as $8,000 a day, I mean basically operating cost for most people.

Those have moved up probably 20% from there. So they would be operating at $10,000-11,000 a day, let's say, somewhere in that ballpark today.

Doubles have moved up from a bottom of kind of 12 to 13, are more in that kind of 13.5 to 15.5 plus range today. Triples of course bottomed about 16 are all around that kind of 20-ish range today.

So everything has moved up. I think the point being that year-over-year, if you net the effect of shortfall payments and contract rollover, rates have moved off bottom.

But the ability to continue to move them through the rest of the year is going to be difficult with activity looking like it may flatten out.

Okay, so it's fair to assume that from here on a sequential basis, you're not expecting any real changes positively or negatively for Canadian day rates based on current customer conversations and demand?

That's exactly the point, yes.

Okay. Can you give any more color on what prompted the decision to remove the drip at this stage?

Well, I mean we've seen our CapEx slow down, and we're able to fund our plans. I mean that's what drove it.

We think most of the big lumpy part of the business is behind us. We think that there's enough rigs in the world.

It's just a matter of making sure that they're right kind of rigs. So it's a little bit of the-worst-is-behind-us thinking.

Okay. So was it mechanical in nature that you hit a certain trailing payout ratio, or it was just more a broad feel of the market?

No. It's just a broad feel.

A broad feel and a good understanding, generally, that you're going to see, for us anyway, you're going to see CapEx slow down into the future. We've kind of taken our bite in the market, upgraded a little bit earlier than most people and gone after the overhead reduction.

And we've added about 50% more days’ year-over-year without having to add anyone to our overhead from the bottom of '16. So I think that talks a little bit to the efficiency.

So, yes, we see, as I would say, we're still in choppy waters. But we're seeing more blue sky on the horizon.

Okay, last one just from me, Bob, how are you thinking about acquisition opportunities right now? I realized that you've been heavily focused on organic builds over the past decade.

But there's a ton of high-quality rigs trading at a material discount to what it would cost you to build the ADRs that you're constructing today. Is there any desire to go back to your formative past and start consolidating some of the space?

We look at opportunities as they present themselves. And yes, the market is starting to look interesting.

But we think that there's probably another chapter to come with certain groups. But, yes, we're hunkering down.

We're building up the balance sheet. You can read into that a little bit.

Okay. Appreciate the color.

Good quarter.

Thanks, Jon.

Good evening, everyone.

Hello, Ian.

With respect to the Canadian contract book, with pricing not moving much higher, but are your customers wanting to lock in rigs for greater than 6 months right now, or have they even stepped away from wanting to do that at this point?

It seems like every time we hit a trough, we have that conversation with customers wanting to lock in take-or-pay contracts for multiple years. And so having been through that conversation a few times before, we would tend to steer more towards shorter term contracts.

So a 6 month duration, no more than a year, but generally you would have a stipulation to renegotiate the rates at 6 months, particularly if you're signing at the trough, kind of 2016. We do have some conversations with people today continuing to want to renew rigs or extend contracts, and we've done that.

But they were for the existing contract rate. So really our contract mix in terms of the percentage of the fleet that is contracted is the same.

And I would say we would still look at a 55-rig fleet. We've still got roughly 35 rigs under some sort of contract currently, so about 60% of the fleet contracted.

Okay. That’s helpful.

The other comment you mentioned was that you think the Canadian business, the gross margins would be top quartile amongst your peers. Given that you don't disclose gross margins in Canada, are you able to share who the peer group is so we're able to get a better understanding of who you are comping yourself up against and where you may be shaking out from that perspective?

Yes. We would look at all the public Canadian-based contractors.

Okay. Thank you.

And then with respect to CapEx this year, it's obviously been bumped. I mean are you able - and it's with it mostly being spent now, are you able to share, I guess, how many rigs have been upgraded and how many rigs are left to be upgraded?

Yes. Of course we kicked out a new rig right in January out the door, we've upgraded 6 or 7 of the ADR 1500s since then.

We are going to deliver here September 1 another new ADR 1500S, and an ADR 1000 into Canada. Some of those we're using some of the components from the shelved newbuild program from a few years back, not all of it, obviously, but some of it.

And we brought a new well-service rig, a heavy well-service rig into the Permian. So we're basically, we added about $30 million of CapEx, which included those components I just mentioned there on top of what we had planned for 2017.

And that was a result of being able to see the business come to us with the clients we're working for, and seeing our half-cycle economics pay that out in the year, basically. So you've heard some people talk about 2.5 year or half cycle economics.

We've been able to do that with 1 year half cycle economics.

Okay. And with respect to the prior cancelled newbuild program, is there any assets left within Ensign to build more rigs or has that largely been exhausted at this point?

Yeah, good question. I would say the next one is probably running us about 80%-85% new.

The one after that starts to get around 90% to 95%. And probably the one after that is very close to 100%.

There's some equipment where we've got a pretty good long position with some assets and inventory. So we're probably out the fourth or fifth rig, I think, before we will get the full cost.

Now we were getting these rigs down to about 10% below where we originally had planned to build them. And not much has moved in the manufacturing space.

So we're pretty confident on the numbers, but we're waiting. We're not about to build a rig into spec into this market.

We're waiting for a contract and a serious conversation with a client before we get to that point.

Okay. And I guess moving along a bit of a different path, in California activity is probably quite a bit stronger than it has been, I guess, over the last 12 months.

And at what oil price do you start to worry about some degradation in your active rig count in that area?

That's a good question. Mike Nuss, do you want to give us a little color on that?

You know the number.

Yes. I think, like every other area, people figured out how to get their costs in line.

I think it would have to get down below $45 and where prices are at today there's been a decent uptick in activity.

And then last one from me, with respect to the balance sheet, obviously the accordion has been exercised to create a bit of additional financial flexibility. But are there other additional steps that need to be taken to create some additional flexibility either in case of additional CapEx or for working capital commitments or any of the above really?

Just to clarify, the accordion hasn't been exercised. It was just finalized.

So it's sitting there to be exercised. Right now we're sitting around $20 million is sort of availability or liquidity.

So I guess on that, I mean we're going to be -- we sort of take it quarter by quarter, and sort of assess what our CapEx and what our needs are. We're going to be living within our operating cash flow for the year, and look to do the same in 2018.

So it really comes down to if there's a bigger project or some bigger needs for additional CapEx then we'll look at doing something potentially. But for us, we want to keep our costs low, so we don't want to have the standby fees that would be incurred for having available liquidity just to have.

Okay. Thanks very much.

I’ll turn back over.

Thanks, Ian.

Good afternoon, guys.

Hey, Jeff.

Just to circle back, so in terms of rig upgrades, how many are planned for the capital program this year?

For the whole year or going forward?

For the full year.

For the full year, there would have been 7 and 2 ADR 1500 newbuilds and 1 1000 ADR newbuild, and a well-service rig, yes.

And so can you help me understand the $30 million increase in capital spending? So when I go back to last quarter, the 3 newbuilds were included in the $61 million.

You indicated that 10 to 15 rigs were being upgraded over the course of the year. You've incrementally talked about the 1 service rig for the Permian.

But what else would contribute to a $30 million increase in capital spending, of which 80-plus percent of that's been spent so far?

So I think some of the -- in the prior $60 million, there was the 1 1500 that got kicked out in January, which was planned. Since then, we've added a 1500, added a 1000, added the well-service rig, and some capital upgrades; that all totalling about $30 million, getting us to the 90.

Does that make sense?

On the U.S. side, do you expect like your comments from a macro standpoint about the land rig count remaining fairly stable in the next couple of quarters.

Do you expect your rig count to remain fairly steady, absent those two additions you mentioned going into the Permian?

Yes, I think so. We are seeing some opportunities develop as land has turned over, let's say, in the Rockies.

It's starting to get coordinated and people are starting to get active in that. We're dealing with a new client here just this morning.

So I think we'll see a marginal increase, certainly a couple that we've talked about in the Permian that we know for sure being planned. California might have a little bit of risk if oil slips down closer to $45.

But the Rockies has been a little bit of a slow grind up as land has turned over and you've got new people running it. And now they're starting to drill it a little bit here and there.

So yes, I wouldn't see it being too much though, Jeff.

Okay. Great.

Thank you. That’s all I had.

Okay.

Thanks, operator. So in closing, with the Permian reaching its steady state now, Ensign, we feel perfectly timed our $100 million super spec upgrade program which we started almost a couple years ago, and which at the end of August will be fully complete.

We'll peak out at about 20 super spec ADR 1500s, and as Mike Nuss pointed out, we also have 6 of 8 ADR 1500s on top of that in the Rockies now to super spec and all contracted. With most of our super spec upgrades under our belt, you'll see CapEx slow down into the future years, again, one of the reasons behind eliminating the need for a drip plan.

Canada also built up a fleet that covers all the active basins in Western Canada and should enjoy better-than-industry utilization going forward. Our International business also looks steady through the rest of the year.

On the technology front, our directional drilling group continued to expand its client base, alongside Ensign rigs and our Edge control technology, should be out on 20 of our rigs by year end. Ensign, with its directional drilling Edge control technology continues to push the envelope on drilling advisory systems, and very close to what we're calling an autopilot system which will move the process from advisory to real automation.

Again, as we've always professed, the world does not need more rigs. It just needs the right kind of rigs.

We'll look forward to our third quarter call in the fall. Thank you.