Good afternoon, ladies and gentlemen, and welcome to the Precision Drilling Corporation 2014 Third Quarter Results Conference Call and Webcast. I would now like to turn the meeting over to Mr. Carey Ford, Vice President, Finance and Investor Relations. Mr. Ford, please go ahead, sir.

Thank you. Good afternoon, everyone. I'd also like to welcome you to Precision Drilling Corporation's Third Quarter 2014 Earnings Conference Call and Webcast. Participating on the call with me are Kevin Neveu, our Chief Executive Officer; and Rob McNally, our Executive Vice President and Chief Financial Officer. Also present is Gene Stahl, President of Drilling Operations. Through news released earlier today, Precision Drilling Corporation reported on the third quarter 2014 results. Please note that the financial figures are in Canadian dollars, unless otherwise indicated. Some of our comments today will refer to non-IFRS financial measures, such as EBITDA and operating earnings. Please see our press release for additional disclosure on these financial measures. Our comments today will also include statements reflecting Precision's views about future events and their potential impact on the corporation's business, operations, structure, rig fleet, balance sheet and financial results, which are forward-looking statements. We caution you that these forward-looking statements are subject to a number of known and unknown risks and uncertainties that could cause actual results to differ materially from our expectations. Please see our press release and other regulatory filings for more information on forward-looking statements and these risk factors. Rob McNally will begin the call with a brief discussion of the third quarter operating results and a financial overview. Kevin Neveu will then provide a business operations update and our outlook. Rob, over to you.

Thanks, Carey. Earlier today, we reported a strong quarter with record third quarter revenues and EBITDA of $585 million and $199 million, respectively. We also announced a quarterly dividend of $0.07 a share, which is an increase of 17%, reflecting our confidence in the business. Revenues were up 20% versus the same quarter in 2013, primarily due to higher activity and pricing in our Drilling segment. Third quarter 2014 EBITDA of $199 million, which was 45% higher than the third quarter of 2013. The higher third quarter results primarily reflect increases in U.S., Canadian and international drilling activity and increased margins versus the third quarter of 2013. EBITDA margins were 34% this quarter versus 28% in the third quarter of 2013. In the United States, during the third quarter, margins were up about $2,100 per day over the third quarter of 2013, primarily due to higher average pricing of over $2,000 per day. Precision's drilling activity in the U.S. improved by 20% year-over-year with an average of 97 rigs running during the quarter versus 81 in the third quarter of 2013. Today, we have 100 rigs drilling or moving in the United States. Year-over-year, EBITDA generated in our U.S. drilling business is up over 70% in a market that had activity gains of less than 8%. This performance reflects the high-quality Tier 1 rig fleet in excellent operational execution. Costs in the United States were flat versus the third quarter of 2013 and up about $1,300 per day sequentially. The cost increase in the second quarter is due to a few items: crew training expenses for new build rigs that are coming on, start-up costs related to stacked rigs being reactivated and a workers' comp rebate that was recorded in the second quarter. In Canada, drilling margins declined by $200…

Thank you, Rob. Good afternoon. We are pleased with our third quarter performance and particularly pleased that our strong results are demonstrating the value in our long-term strategy. But like most, we are mindful of the commodity price volatility, particularly while our customers are in the midst of developing their 2015 capital budgets. Now we also know that commodity price uncertainty drives our customers to focus on rig performance and rig efficiency. It's often said that the best rigs are the last to be laid down. Notably, the greatest performance gains have been delivered by pad-style drilling with walking rigs drilling a series of wells on a single pad. In addition to the reduced mobilization time, operators are able to optimize the drilling plan and develop efficiency improvements as the rig moves down the pad. It's our view that most unconventional development drilling will migrate to multi-well, pad-style drilling. Of all the new builds we will deliver -- rather all of the new builds we will deliver to North America this year and all the rigs to be delivered next year are walking rigs for optimized pad drilling. At Precision, we've been a leader in pad drilling operations since the mid-1980s, and we believe our experience and capability is an important element of our competitive advantage. Now before I discuss our regional views, I'll like to draw your attention to several other strategic achievements during the quarter. Year-over-year, we've increased our U.S. activity, as Rob mentioned, by almost 20%. And if you roll forward, by mid-next year, we'll add a further 20% growth through new build deliveries to Precision's U.S. operations. I could not be more pleased with how our strategy is succeeding as we continue to build this U.S. market position. However, it remains very important for Precision to…

[Operator Instructions] The first question is from Dan MacDonald with RBC Capital Markets.

Just wondering if we could kind of look here at the environment in Canada, Kevin. And are you getting any pushback on passing the labour rate increase through here for the winter? Or is it a little too early to tell? Or possibly are you even able to get a little bit more here despite what's gone on with the commodity of late?

Dan, it's a pretty sensitive time for me to comment on final pricing negotiations with customers, but I would tell you that our sales teams are highly confident that labour inflation will be passed through to our customers.

And then just staying on the Canadian side, have you got any feedback from your customers? Or do you see any potential concerns where maybe guys might run out of budget money here a little bit earlier than, say, they did last year and you could see a bit of a slowdown heading into year-end before the winter ramp-up? Or have you not had that feedback?

Dan, a little hard to say right now. It almost always sort of plays itself out in December, but I'll throw a couple of comments out. Some weather delays during the third quarter may have delayed a bit of spending. And we know that our customers, if they have a budget, they will spend it. So I don't expect to see anybody crimp back a 2014 budget, but I also don't expect them to see -- to see them pull forward any 2015 money into late 2014. So I expect them to spend all their budgets. Hopefully, some of the weather delays we've seen earlier this quarter play themselves out and let us smooth the load throughout -- up to Christmas.

And then just lastly, on the Duvernay. Kevin, I guess, can you kind of maybe characterize on a high level your kind of clients' mindsets when they're looking at '15? Have you seen like a reasonable increase in optimism on higher activity for that play, specifically?

Dan, it's hard to talk about optimism, but what I will comment on is there's been an awful lot of kind of front-end engineering work done, a lot of rigs sort of spec-ing work done. I mean, there's no question, the Duvernay looms large as a 2015 program, but it's probably a bit early for us to really forecast activity levels next year. But I can tell you, there's a lot of work going in by drilling departments that are active up in the Duvernay right now. And I'm really encouraged by the work we're doing up there. Having 2 rigs on 1 pad is a great way to very quickly get the pad drilled out and then very quickly go back and frac that pad. And then when you combine that with some of the work we're doing with the Schlumberger alliance to really reduce those drilling times, I think we're in a very good path right now to get the Duvernay drilling costs and completion costs down to the targets our customers have set. And we both know that the fluids that they're producing there are rather -- relatively just unattached from the oil price. They're generally producing diluent for heavy oil and that need hasn't been reduced yet. So early to be enthusiastic, but I think the things we're doing are all pointing to the right direction.

The next question is from James West with ISI Group.

Kevin, if we go into next year and let's say that the commodities are in this level or maybe a little bit lower, you've got a pretty good buildup programs still scheduled for the U.S. Would you ratchet that back some? Or would your intention be to just continue forward, given there's probably going to be a -- if you were in a flattish rig count environment, there'd be a flight to quality towards your rigs?

Yes. So James, a couple of comments relative to that question. These are all -- the 15 rigs we have -- being delivered in 2015, 1 is international -- sorry, 16 rigs, 1 is international, the balance are for the U.S. Those are all pad-configured rigs. We've got customers lined up on all those rigs. Those rigs will go to work. Beyond those 15 rigs for the U.S., it's fair to say that we're going to be very careful and make sure we don't get over our skis. We always keep a lead time program running at Precision so we could sustain deliveries into Q3 and Q4 if we see customer demand emerging later this year, early next year. But if these prices discourage our customers from expanding activities, we can throttle right back down to 0 rigs, if we chose to. And we've done that -- we did that in 2013 -- as recently as late 2013, even early 2014. So we can do it again. It is a little painful going up and down like that, but it's just core to our strategy. I commented earlier that having the ability to respond quickly up and quickly down to that Canadian market is something we've built into our operations really around the world. Now kind of philosophically speaking, I think even in a soft commodity price environment, the likelihood that our customers push for better efficiency and better reduced cost doesn't go away and that may still drive demand for additional pad-type rigs. Whether those are conversions to our Tier 1 rigs or whether they're new builds, I think that demand could stay strong through 2015 even in light of softer commodity prices. Certainly, the lowest-spec rigs and lower-tier rigs should be concerned.

The next question is from Brad Handler with Jefferies.

Couple different areas of questions, I guess. In terms of the U.S., could you just clarify or maybe reconcile the 3 rigs a month in the U.S. versus your current path for the '15, which I think is more like 2 rigs a month? Is there flex in the third or just maybe -- it's probably just something I'm missing?

Brad, this is Carey. I think the 2 rigs that we have for the third quarter, those were kind of June, July deliveries and so the vast majority of those rigs will be delivered in the first 6 months of the year. So it averages out to about 2.5 rigs a month.

As you roll in our Q4 deliveries this year, I think taken from Q4 through the end of Q2, that gets pretty close to 3 rigs per month. Whether it's 2.8 or 3, I'll round it up to 3.

Yes, that's okay. Fair enough. I was missing something about some other rigs or if it was parts or something, but no problem. On Canada, your comments about LNG, your optimism around the FID projects and the like are -- were good to hear. I guess, I'm curious for a sense of a couple of things. First is -- how much activity is currently would you describe as LNG-based? And I guess the second part of that question is, is there some risk to that activity in the near term if the FIDs wind up coming only next year, if things do get dragged out from a tax arrangement standpoint, for example?

So Brad, you may know that the Government of BC has proposed a new tax structure, but they still have to pass the legislation through their legislature. So that has to happen. The indications appear to be that they understand the risks with delaying that approval. So I'm not going to handicap whether they do or don't, but they appear to understand the risks and I mean they've heard from every angle, about the sensitivity of timing and getting this to move quickly, not slowly. So off the bat, I think they understand the risks and they are prepared to move quickly. I'm not going to bet on whether or not they get it done on time. I have listened carefully to our customers and what they're saying and our customers believe that either late this year or sort of first quarter, maybe early second quarter next year, is the latest they want to see this approved by. I think we'll all be disappointed if it doesn't get approved this fall. But nonetheless, none of our customers seem to be holding a gun to the head of the politicians. So that said, I think a little bit of patience is in mind here for everybody. These are very good projects, particularly with the low cost of lifting this gas out of the ground and this proposed structure is, I think, better than most expected. So again, all the indicators point in the right direction for us. Hopefully, the dominoes continue to line up for us in a nice, straight path. But your question was could we see a reduction in drilling in the near term? I don't think so, Most of what's going on right now is delineation work and kind of reservoir-proving work, which is necessary before -- long before optimization and development drilling starts. So I think the activity we're seeing now in Northwestern Alberta, a little bit in Northeastern BC continues unless something untoward happens to these projects.

The next question is from John Daniel with the Simmons & Co. John M. Daniel - Simmons & Company International, Research Division: Question for you, Rob. As I recall, last quarter, there were some comments made, which seemed to suggest that the cost improvements witnessed in Q2 for the U.S. operations were sustainable and that cash margins would likely improve in the second half of this year, but -- and this quarter, that reversed. So was wondering if you could share with us what the workers' comp rebate was on a per-day basis? And should we assume that the costs incurred in Q3 are onetime in nature?

Yes, John. So the short answer is no, I can't share with you what it was on a per-day basis, but it's a portion of the $1,300 per day increase from Q2 to Q3. The other and more significant pieces are training expenses. As we're getting ready to deploy new build rigs, we have crews that are coming on ahead of the rigs for training. And then we had some rig reactivations in the quarter where we were taking some rigs off of fence lines and putting them back to work and there were some meaningful expenses for reactivating those rigs. So if we kind of got to a steady state where we weren't reactivating rigs and weren't bringing on new build rigs, I expect that the per-day operating expenses would drop back down. But not -- we wouldn't get all $1,300 back because we wouldn't see that rebate again. John M. Daniel - Simmons & Company International, Research Division: Okay. If you looked at this quarter, rig count is up slightly. You've got the benefit of repricing on some rigs, and better mix. I mean, I would assume -- are we wrong to assume that cash margins grow in Q4?

Yes, I would think that there's -- it's going to be kind of flat to slightly up is my best estimate. John M. Daniel - Simmons & Company International, Research Division: Okay, okay. Next one, and Kevin, this may be too early for this one, but at this point, have you had any customers approach you and ask with you to work with them on moderating any of the terms of any of the contracts either price or term? And do you expect this to happen in Q4?

We've had one customer come to us. They asked if we could find some relief between time period for a rig. That's quite common where we have rigs that are either not needed right now or not required for short times. There's a window that we have to remarket the rig for a period of time. That customer remains on the hook and on the obligation for that rig. But I would say that's almost normal course business for any given quarter.

The next question is from Scott Treadwell with TD Securities.

Most of the stuff has been answered, but I do have some housekeeping. So on the contract coverage that's moved up, could you characterize the increase as being kind of fully driven by the new builds? Or have the older rigs -- I know you talked about them recycling, but has that been kind of part of the growth? Or has it been mostly driven by new builds?

It's both, Scott. I would say that it's, call it, 2/3 driven by new builds and 1/3 by recontracting existing rigs, something in that neighborhood. But it's a combination.

Okay. And you wouldn't -- I'm assuming you wouldn't be able to characterize or couldn't really characterize if Precision or the clients initiating those conversations on the existing rigs? It sounds like it's more normal course.

Yes, I'd say it's normal course.

Okay. So turning to the U.S. on the new builds, I know I asked this question last quarter, but maybe an update. With that many rigs going into the basin, do you still expect that new build to be fully additive to the rig count the way you see things today? Obviously, commodities being what they are, you don't know for sure. But any change to that outlook from 3 months ago?

I'll go. Rob might have something to add on it. I heard him about to say something. It's certainly way too early in the cycle for us to pull the plug on 2015. So we're thinking right now that business holds very strong in 2015. One or 2 rigs could slide aside, but most of these rigs running right now, I think, over 90% are Tier 1 rigs and they're doing a great job for their customers, delivering wells on or ahead of the curve. Safety is great. So I think we're doing all the things we need to do to make sure that, that fleet stays heavy utilized. Could 1 or 2 or 3 or 4 rigs come off if commodity prices stay down? We could see a little bit of attrition, but certainly wouldn't guide you to anything dramatic at this point. Rob, do you have any comments?

My only comment, Scott, would be that if there is pressure, which, of course, there may well be in an $80 oil world, it is the lower end of the rig fleet, the Tier 2 rigs that will be most impacted. And today, that's much less an issue for us than it was 3 years ago because it's a relatively small portion of our fleet now that falls in that category. So we're going to have 100% rigs added, that's probably not the case, but I don't think you should expect a big impact.

Okay, perfect. So next one, based on the activity as you see it today, I know you've done a bunch of maintenance and upgrades. What would 2015 maintenance CapEx look like on sort of flat activity accounting for the new builds in the pipeline right now?

Scott, we haven't finished our budgeting process yet. But a reasonable kind of rule of thumb is $1,000 or $1,200 per day of maintenance capital for ops, so whatever your assumption is on operating days, about $1,000 to $1,200 a day.

Okay, perfect. That's a great formula. So the last 2 I have, one sort of technical. You mentioned the side-by-side drill-off on the pad in the Duvernay. When you switched or when the customer switched to the Schlumberger tool, is that like-for-like? So it's an MWD kit against an MWD kit? Or is there a rotary steerable and a sort of another level of technology?

Scott, both of these are pretty -- let's just leave it kind of broad and say, high-spec downhole tool strings and the customer is a long ways down the curve to hitting their targets for drilling efficiency. And we're kind of leading that charge right now. So I feel pretty good about it, but these are not just straight MWD low-spec jobs.

Okay, perfect. And my last question, on the balance sheet. A good amount of cash there. Obviously, you've got the luxury of being able to fund increased rig builds if it plays out. Kind of at what point do you have a sort of drop dead date where you might look to pay out the 2019 notes where that becomes maybe a more attractive allocation of capital? Is it sort of the summertime? Or is it sort of a fluid -- you're monitoring it every day and if it looks like it's the best way to go, you'll do it?

Yes, I'd say it's more of the latter, Scott. We have the ability to call those notes starting in March of 2015 and depending on what our outlook is for capital plan, uses of cash, we'll consider it. But it becomes a more real consideration in the second quarter of next year.

The next question is from Klayton Kovac with Tudor, Pickering, Holt. Klayton Kovac - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: So my first question's regarding the Schlumberger-Precision alliance. How are the 27 wells split between Canada and the U.S.? Was it skewed one way or the other?

There's no meaningful skew that has any value in discussing. We're not disclosing that information quite specifically. But just fair to say, it's spread out among 7 different basins and a variety of different customers. So I feel pretty good about the early uptake by our customers. And we still have a ways to go yet before this is a fully accepted, proven model. But both Schlumberger and ourselves are, right now, doing all the right things to make this work well for our customers. Klayton Kovac - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, thanks. And then as a follow-up, in your earnings release, you cited competitive pricing in Canada for some rig segments, which partially offset an increase in revenue rates this quarter. Which rig segments did you experience this in?

It's primarily the smaller rigs.

The next question is from Dana Benner with AltaCorp.

I wanted to start with a question that's been asked of me several times today, so I'd rather put it you for the definitive answer -- I certainly have my thoughts -- and that is with respect to the dividend, moving it up at this time, heading into what could be a $75, $80 oil environment, we'll see how it shakes out. And while that is happening, also deferring a portion of your '14 and is it a deferral, is it a cancellation ultimately of those infrastructure and upgrade projects, et cetera. So thought I'd give you the opportunity to address that.

Yes. Dana, those 2 things are not connected. The decision to increase the dividend is one that we review annually. And really people should take that as a reflection of our confidence in this business and in the ability to generate cash even in a downturn kind of environment, which generally leads to much lower capital spending. And given the quality of our rig fleet and our contract position, we feel very comfortable that, that's not going to strain the balance sheet of the business to increase the dividend modestly. The delay in CapEx is, like I say, it's not a part of the same decision and it really just reflects timing on when we think the money is going to get spent. So just our estimate of when the projects we're going to get done, changed.

Okay, excellent. I guess, secondly, thinking about the new build market, it swung so heavily toward the U.S. and almost seems to come to a standstill in Canada and I'd be curious to get your color on why that would be. Obviously, timing of LNG-related decisions is going to be a part of that, but one would think that there may -- for the same reason that we've seen an upgrade cycle emphasized in the U.S, one would think there'd be a need for that in Canada. So would love to hear your thoughts on that.

So first of all, Dana, I think right now today, sort of October, November, even late September time frame, our customers are really knee deep in their 2015 budgets. And some of those we won't hear about until mid-January. So it's going to be a process over the next few months, not weeks, for Canada. No question that our customers in Canada, some were out drilling cash flows; some were hedged; some were utilizing the capital markets, both equity and debt. So there's a lot of moving pieces right now. Does the fleet need to be kind of regenerated a bit? It depends on where you think it's going. So I think the short answer is it's a little hard to read that. Certainly, if we're developing and continue to develop Duvernay, LNG, the need for deeper pad-style rigs, 1,500-horsepower, some big 1,200-horsepower rigs that have large racking capacity, that's evident. So we see potential 2015, 2016 to be building more 1,200- and 1,500-horsepower high-racking capacity pad-type rigs for horizontal drilling up in Duvernay and potentially for LNG exports. There's been a pretty good market in Canada for the heavy tele-double and that market's still around today, something we're a little bit underweight on. But I'm not compelled to put speculative capital out today for tele-doubles in a market where there's a lot of uncertainty going forward. So I think I'll leave my comments there, Dana. Is that helpful?

Absolutely. And just thirdly and finally, moving to the rig announcement in Georgia today. I understand that you're going to be serving that rig sort of regionally as it where, but to-date you've really tried to have a focus on certain regions and I wonder if this marks maybe the beginning of what could be a cluster of rigs elsewhere? Or were the terms on this sufficiently good that it outweighed the desire to try to keep more of a concentration in certain areas?

Carey -- or Dana, there's a couple of pieces there that played into that opportunity for us. But the first piece is there's a bit of a shortage right now on 2,000-horsepower rigs that are ready to go to work on a moment's notice. And if you have a rig like that that's available to be deployed immediately, there's a very strong pricing scenario that plays out nicely, whether it's one rig in Georgia or another rig in, say, Kurdistan. So I think we're really happy right now to get that contract. We think that rig could stay there for a long time or it might migrate back into Kurdistan at some point in time; we've got some optionality there. I would say, though, that generally what we're looking to do is build out meaningful footprint. So having 2 rigs in Kurdistan is nice, but getting up to 5 or 6 or 10 would be nicer. And I think as the risks in Kurdistan become better understood, I think that business will get back on its feet and start moving forward and probably sooner rather than later. So I'd say a majority of our focus remains on Kurdistan, Kuwait, Saudi. But if we can be opportunistic with some of the assets we have and pick off adjacents like Georgia, I'm okay with that.

The next question is from Jim Wicklund with Crédit Suisse. James Knowlton Wicklund - Crédit Suisse AG, Research Division: I think about the deepwater market and while 6 generation rigs, Tier 1 rigs, to them didn't get -- aren't going to be stacked, we've already started to see the stacking of the lower-end rigs, to your mention. But we've also seen a fairly dramatic hit to the day rates of the Tier 1 rigs and we have somewhat of the same confluence -- we were accelerating construction into a weakening demand market. Appreciating your comments about it's too early to know, and you can be flexible, why couldn't, not just for you guys, but overall, I mean, we've got 1 analyst out today talking about a 200 rig -- horizontal rig reduction in the U.S. in '15. Would you just dramatically gain market share? And would it be at the expense of day rates? And what would be your strategy or what you think may be the reality of some of these things -- these parallels coming true?

Well, so Jim, I would tell you off the top, I'm a believer that when the tide goes down, the tide goes down for everyone. So if we're in a declining... James Knowlton Wicklund - Crédit Suisse AG, Research Division: Rational.

; I beg your pardon? James Knowlton Wicklund - Crédit Suisse AG, Research Division: Rational. Okay, good.

Yes, so in a declining market and particularly a sharply declining market, there will be pressure on day rates, I understand that. But we very carefully model out customer demand. We're looking carefully at where the rigs are and what type of rigs are drilling right now. And I think our model right now would suggest that the Tier 1 market, high-spec Tier 1 rigs, is probably a little less than half of total activity in the U.S. or right in that range. And we think customer demand versus supply of those rigs stays tilted towards the drillers to some extent. So I think there could be -- could there be 200 horizontal rigs come off? Absolutely. There's an awful lot of Tier 2 rigs right now drilling horizontal wells in the domestic U.S. It's unlikely that you see a pure high-spec Tier 1 rig drilling -- take for example, drilling 11-day Eagle Ford wells or drilling 20-day Permian wells. Unlikely you see one of those rigs coming off. We feel really good about our positioning right now and how well our rigs are performing. James Knowlton Wicklund - Crédit Suisse AG, Research Division: So would it be fair to say that while, come what may, with lower commodity prices on a relative basis, you could easily be the best looking girl in the room?

Well, I think there's us and a couple others out there that are doing a really good job right now and really distinguishing themselves and the performance of their rigs. There are people and their technology. So we might not be the only one out there that looks pretty good. But I would say that, I think, the most important thing, we've got several customers. We've got 5 or 6 rigs running across several different basins. And the performance of those rigs, whether they're in the Marcellus, the Niobrara or the Permian Basin, is identical. And that's really important to our customers right now that they can get that, I'll call it, industrialized quality wherever they go with us. We're doing that. We're not the only driller doing that, a couple other large drillers who are doing that. But I think it's a lot tougher when you move down below the top 3 or 4 drilling contractors to get that multi-basin consistency. And again, I'll say that when the tide comes down, it comes down for all of us, I understand that. But do think that the best look better in this kind of a market. And then some of that technical performance differentiation really becomes apparent in a declining market.

One that I thought was really interesting that we looked at last quarter was if you took the largest 4 drillers in the U.S. and looked at the number of rigs that they added over the trailing 12 months, it was like was 105 rigs that they've added. If you took everybody else combined, it was a decline of 15 rigs. So it really kind of paints the picture of where the market's headed.

The next question is from Jon Morrison with CIBC World Markets.

Was the Georgia opportunity with an existing customer or new customer?

It's a drilling team that we knew well and have known for a long time well, but they're operating under a new concession, I believe, in Georgia or a recent concession in Georgia.

So does it contemplate expansion in that market? Or profitability off of that one rig in country is relatively in line with your other international operations that makes sense?

Jon, I just categorize this as a one-off opportunistic opportunity with a rig that we had ready to go to work and it's going to deliver great returns for us. And it'll be in the area. High degree of certainty it gets recontracted either in Georgia or somewhere nearby. And it's -- while it's not a core in our strategy to be in 1 market with 1 rig, it is close enough to our existing footprint that we'll support it with a minimal amount of infrastructure and overhead support. It's a good one-off deal for us, but it's just a one-off deal.

Rob, what's the expected 2015 CapEx expected to be without maintenance spending? So what's the rollover to deliver those 16 rigs that you have coming?

Well, yes, you can think about the -- first off, we haven't done our capital budgeting yet for 2015. At least, we haven't announced it. But for the 16 rigs that are coming, some of that spend has happened in 2014. Although the majority will be in '15 and so you kind of think it as $20 million per rig and then it'll be a shade lower than that because we've spent some of the money in 2014.

In the context of the current commodity price environment, does your view towards long-term contracts change, i.e., a lower day rate? Or are you willing to take a lower day rate for improved visibility relative to your expectations over the last few years?

Jon, we usually always try to maximize the term of our contracts and we also try to maximize the day rates and margins. I would say that EBITDA margin always receives the highest priority in Precision. So if you're looking for one or the other, we're always driving for maximum EBITDA margin. A little less worried about utilization, and for that matter, a little less worried about contract coverage as the market's going down.

In the release, you talked about cost reductions and focus on efficiency gains in the C&P division. Is that something new that took place in the quarter or that's just a continuation of what you guys have been focused on over the last, call it, 12 or 18 months?

Yes, that's really been since kind of early 2014 where we've -- have come to the realization as an organization that the C&P business is likely to be slow for a little while. And so we've just taken some more direct steps to reduce costs in that business here over the last, call it, 3 quarters.

But Jon, the short answer is our guys are working really hard right now to make sure they don't spend or waste any money anywhere.

Just to follow on Scott's question about the senior note purchase buyback opportunity. If the market is, call it, sideways for some time and there isn't a lot of growth opportunity in front of you for the next 12 to 18 months that aren't already in your capital program, is that the most likely use of proceeds of the $500 million-plus cash on the balance sheet? Or would you look at share buybacks? Or how do you think about allocating capital?

Yes, I mean, we'll consider all of the normal options for uses of excess capital. But certainly, in that discussion will be those -- the $200 million of Canadian notes that comes -- that we can call starting in March.

Last one just for me. Can you give an update on Mexico and the realistic chances of adding any incremental rigs in the next 12 to 18 months in that market?

Jon, it really depends on what happens with PEMEX. They're at the end of the year right now and so they haven't announced their 2015 budget yet. We're kind of waiting for that to move through. But I think the work we're doing right now under the IPM umbrella is going very well and that could increase if PEMEX increases their IPM spending. There's no question they are desperate to bring in foreign direct investment, we know that. If it ends up being large-cap P&B [ph] companies onshore, the likelihood we move rigs down there goes up quickly.

It's fair to say that nothing would signal a slowdown at this point in your eyes?

I think that, that country is on a track to bring in foreign direct investment. And if it's the right kind of investment, we'll be there with it.

The next question is from Kevin Lo with FirstEnergy.

Just want to follow up on Jon's question in Mexico. What is the utilization today? Are all the rigs fully utilized after that $8 million, I guess, onetime gain?

We have 4 rigs running right now in Mexico. And 4, right?

Yes, well, there's 2 rigs that are in short-term standby but -- to get full EBITDA rate and 2 rigs that are operating. And the other 2 are expected to go back to work here shortly.

Okay. So for Q4 then, should we expect that all the rigs will be working or at least getting paid 100%?

Yes.

Great. Second thing is what is your -- what is the percentage of rigs right now in your Tier 2 or Tier 3 category that's working? I mean, you have like, let's say, 220 rigs that are Tier 1, a little bit more maybe. What's that percentage?

We've commented publicly a bunch of times that Tier 2 utilization is in the kind of 25% to 35% range and I think that, that's probably true today. That's pretty close. Whereas for the Tier 1 rigs, we're 90% or better.

Okay, great. And the last thing for me is of the long-lead items you're building into '14 and '15, how many of those parts are committed to long-term contracts?

Of long lead-time components, which we always keep a float going, none of those are committed as yet, but they're sort of shadowing some of the discussions we're having with customers over the longer haul, Kevin. And of course, our view has always been that if we see a slowdown in business, we terminate the program and we utilize those components in our maintenance CapEx. So very quickly, that offsets some of our maintenance needs. And remember, those are things like BOPs and engines and drill pipe and top drives, all things that, when it's busy, the lead times tend to stretch out and when things quiet down, lead times narrow. But having 3 or 4 excess top drives or 6 or 8 or 10 engines excess in our fleet in a downturn is never a bad thing because those end up offsetting some of our maintenance expenses -- our maintenance capital over time. And so I think it's always prudent have that ability to ramp up our delivery periods through long-lead time programs.

That's great. In terms of last -- sorry, not last thing. In terms of renewals, the rates that you're renewing that the rigs are at today, the ones that are coming off contract, are they at current market? Or are they at where they were renewed before? Can you give us a sense of where those ones are being renewed at?

So Kevin, we usually don't give a lot of clarity on renewals. This is not something we want to get into the cycle we're reporting on. But I can tell you that, I think, we had 15 renewals during the quarter and the average renewal rate would have been higher -- at a higher day rate and higher margin than the prior renewal contract. And think about those like they are 6-month to 1-year renewals. I don’t have the average amount of the renewal, but 6-month to 1-year terms, and the vast majority would have been 6-month to 1-year contracts rolling over. That's a good indicator of the tightness on Tier 1 rigs, which is something we've been speaking about throughout most of this call.

[Operator Instructions] The next question is from Jeff Fetterly with Peters & Company. Jeff Fetterly - Peters & Co. Limited, Research Division: Just a couple of random questions. On the CapEx program reduction, the decrease in upgrade CapEx relative to your last update in July, is that a function of the timing of upgrades on rigs? Or is there a change in that market?

No, it's a timing issue, Jeff. Jeff Fetterly - Peters & Co. Limited, Research Division: So should we expect you guys to be upgrading at a similar pace in 2015 as you've done this year?

Yes, I mean, the last few years, we've had pretty substantial upgrade programs, somewhere between $150 million and $200 million of upgrades. And we'll have more upgrades in 2015, but the pace is going to slow at some point because the low-hanging fruit gets picked. And so when we kind of look at the list of candidates, there still are a good number of rigs to update, but it's going to slow as we get through 2015 and into '16.

I guess, the key factor for us, Jeff, is always receiving contracts to cover the cost of that upgrade and give us a pretty decent return. If we continue to see uptake by customers on upgrades, that program stays in place. If we see that soften for any reason, we could slow that program down to 0 if need be. Jeff Fetterly - Peters & Co. Limited, Research Division: Have those -- has demand for that type of spend changed at all relative to where it was in the summer?

The short answer is yes because we're in budget season for 2015, and our customers are trying to figure out commodity prices. So the short answer is yes, it has. But I'd say that all new capital spending by our customers is under review right now with no conclusions as yet. Jeff Fetterly - Peters & Co. Limited, Research Division: Okay. And back to a follow-up in one of the previous questions. So you guys are scheduled to deploy 6 rigs in Q1, 7 in Q2. You talked about 3 rigs per month. But if we go back to the July conference call, you talked about minimum 3, potentially moving to 4 rigs per month in 2015. How much has the market changed since you guys provided those comments a few months ago?

So Jeff, great question, and I think a little more explanation is warranted from us. When we said 3, 4, I mean, we were even possibly talking about 5 at one point. When we said those numbers, what we were suggesting was 3 for the U.S. on average, 1 for Canada -- or 2 for Canada. So what's changed is we just haven't seen any demand pop up yet for Canada that might drive those numbers to a different place. And of course, nobody is prepared to commit to a contract for delivery really past the end of Q2 yet and that would be typical anyways. So we're not seeing much materializing later in the year. So for us right now, today, looking forward, the likelihood that we deliver more than 3 rigs per month in any given month in Q1 or Q2 is getting very close to 0 because you'd have to be signing rigs back in September, October to have deliveries for March and April. So I think modeling us out through the pace that we've shown on our charts, which is about an average over the next 3 or 4 -- 3 quarters-ish of 3 rigs per month is the right way to model us. And the increase, potential to increase really wouldn't come in till Q3 at this point. Jeff Fetterly - Peters & Co. Limited, Research Division: Just to clarify...

If demand -- if commodity prices turn around, demand really picks up between Canada and the U.S., we could ramp up beginning sometime in Q3 2015, but probably no sooner. Jeff Fetterly - Peters & Co. Limited, Research Division: Just to clarify your comments earlier. You are -- you basically have no available spots for the first half of the year in terms of...

Currently, we have no more available slots for the first half of the year as we've managed our build program. Jeff Fetterly - Peters & Co. Limited, Research Division: Okay. And last thing, just from a vulnerability standpoint. So when you look at activity today and assuming that the high grading process is beginning in terms of active rigs in North America, is it correct to assume that of the active rigs that Precision has running today, the number of Tier 2 rigs would be in that 20 to 30?

Yes, that's the right range. Jeff Fetterly - Peters & Co. Limited, Research Division: And how would that 20 to 30 be split between the Canadian and the U.S. side?

Yes, it's pretty even. I don't know off the top of the head, but I would guess it's pretty even, maybe weighted a little bit towards Canada.

Jeff, it's Carey. One easy way to think about this, if you think about 90% utilization with about 210 Tier 1 rigs in North America, you get to about 180 rigs running that are Tier 1 rigs and the remainder would be the Tier 2 rigs. Jeff Fetterly - Peters & Co. Limited, Research Division: And then, for 2015, would those 20 to 30 Tier 2 rigs that are active, would those be the most likely ones to be upgraded? Or would it be the idle rigs that you would look at first?

Some of the operating rigs and some of the idle rigs. It's a bit of a blend depending on where the rig is and what the spec for the customer looks like. I -- cut it in half and say half operating, half idle.

The next question is from Carrie Tait with The Globe and Mail.

You showed a lot of enthusiasm for LNG in BC. I'm wondering if you think there may be enough potential activity there to replace any slowdown that could come in oil development with low prices there?

Carrie, they are almost 2 separate markets with almost 2 different types of rig specs required so -- and it's going to be slow evolving for LNG. I mean, if one project gets FID-ed this December, if that were to happen, and they went out to bid on more rigs, those rigs wouldn't be delivered till later 2015, sort of second half 2015. So there could be a lag period where if Canadian oil drilling slows down, if that Viking-Cardium work slows down, it might be awhile before the LNG work starts to pick up and offset that.

The next question is a follow-up question from John Daniel with Simmons & Co. John M. Daniel - Simmons & Company International, Research Division: Kevin, quick one for me. In the international markets where you operate, broadly speaking, what are the typical drilling times? And are you seeing any of the efficiency improvements that we're seeing in North America?

So most of what we're doing internationally are straight deep vertical wells with the exception of some of the work in Saudi, which has been directional, pointed at -- actually offshore targets from onshore drilling. But nothing that's horizontal in nature like we'd think about North America unconventional horizontal drilling. So I can tell you that it's still all reservoir drilling. Most of the emphasis is on hitting the target rather than maximizing efficiency for the work we're doing. Deep, high pressure, high temperature. The areas where they're really focused on efficiency are mechanical uptime, safety, the things we're actually quite good at in our normal day-to-day operations.

It's not speed of drilling. A lot of these wells are 180-day or 270-day wells. These are big, long wells.

The next question is from Andrew Bradford with Raymond James.

I'll be very quick here. Are any of the upgrades that you're planning either in the original 20 or now in the 17, are they to be effected on what are already Tier 1 rigs?

Probably a couple of the walking systems that we had in our upgrade numbers. Those convert the Tier 1 rigs into fully pad rigs. But those are small enhancements to the rig and not material to the overall dollar change, Andrew.

Okay. Is there anything about the architecture of rigs that you -- if you go all the way back to when you started constructing rigs within fairly big programs, say, 6, 8 years ago, is there anything about the architecture of those earlier rigs that limit their upgradability today?

As we upgraded our rigs all the way along, Andrew, really from 2007 forward, we've converted these rigs into more of a, call it, a Canadian footprint, where you've got all the utility buildings kind of compact in the back and you've got kind of a unitized drilling module. So in fact, our Tier 1 fleet right now has been upgraded Tier 2 rigs to become Tier 1 rigs. Those rigs have been made easier to accommodate pad drilling. So in fact, our Tier 1 fleet, if it's not a pad-configured rig right now, it can be made pad configured for a very minor upgrade.

So that applies to all of the Tier 1 rigs?

Well, some of our Tier 1 rigs are Super Singles you well know are high-revenue making, high-return rigs for us. Those rigs actually can be skidded on a pad in a couple of hours. So it's unlikely that it'd ever become a pad walking rig when you can skid them in 2 hours well-to-well. So if you subtract the number of Tier -- of Super Singles from our fleet and look at the balance of the fleet, that number of rigs would either be already pad configured or easily pad configurable.

There are no further questions registered at this time. I would now like to turn the meeting over to Mr. Ford.

That concludes our third quarter 2014 conference call. Thank you for your participation today.

Thank you. The conference has now ended. Please disconnect your lines at this time, and we thank you for your participation.