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Good morning, ladies and gentlemen, and welcome to the STEP Energy Services Third Quarter 2018 Conference Call. This conference call is being recorded today and will be webcast on STEP's website but may not be recorded or rebroadcasted without the expressed consent of STEP Energy Services. All amounts discussed today are in Canadian dollars, unless otherwise stated. The complete financial statement and management's discussion and analysis for the period ending September 30, 2018, were announced this morning and are available on STEP's website at www.stepenergyservices.com and on the SEDAR website. During the call, management may make projections or other forward-looking statements regarding future events or future financial performance. Actual performance, events or results may differ materially. Additional information or factors that could affect STEP's operation or financial results are included in STEP's most recent annual information form, which may be accessed through the company's website, the SEDAR website, or by contacting STEP Energy Services. Management also calls your attention to the forward-looking information and non-GAAP measures sections of the press release issued earlier today. I would now like to turn the meeting over to Mr. Regan Davis, STEP's President and Chief Executive Officer. Please go ahead, Mr. Davis.
Good morning. Thank you, and -- to everyone for joining the call. Welcome to STEP's Third Quarter Conference Call. With me this morning, I have Rob Sprinkhuysen, our CFO; Mike Kelley -- Michael Kelly, our Executive Vice President; Stephen Glanville, our Chief Operating Officer; and Ivan Cheng, our Manager in Investor Relations and Corporate Development. I apologize, the lights just went out in our meeting room here, so. I'll be providing a brief update today on our third quarter results, some insight to our North American operations and discussing our thoughts around what we see going forward and afterwards. Afterwards, we'll open the call up to questions. I want to begin by stating that we're very pleased once again to report record results despite some challenging conditions this quarter. We've had weather delays impacted our Canadian operations, and we're experiencing reduced industry activity levels due to client capital budget exhaustion, widening differentials and lack of egress capacity. That said, we've taken strategic steps to mitigate some of these realities and believe that our dedicated focus on safety, execution and our quality relationships with our clients position us well looking into the future. As noted in the press release, the integration of the Tucker business is continuing -- continuing very well. We've recently moved a member of our senior leadership team to the U.S. to work with our teams down there, to lead our plans to provide an efficient integrated service model to our U.S. client base. I'm very pleased to share we have maintained very high employee retention from the Tucker professionals, and we have provided an uninterrupted service to their clients. I'm also very proud to note that all Tucker's key clients have continued to partner with us through this integration. Our U.S. operations continue to position us with a strategic advantage as it provides us with flexibility when deploying our capital asset base and gives us options for continued growth. At this point, I'll pass the call over to Rob to speak to our financial results.
Thank you, Regan. During the third quarter, STEP generated record third quarter consolidated revenue of $240 million, representing an increase of 37% relative to the third quarter of last year. The improvements we saw are primarily due to the addition of Tucker and having more equipment deployed. This resulted in third quarter consolidated adjusted EBITDA of $42.5 million or 18% margin. The Canadian operations contributed adjusted EBITDA of $35.2 million or 24%, while the U.S. segment contributed $7.3 million or 8% margin. I'll start with some comments on the Canadian segment. Overall, the company realized strong levels of activity as we benefited from rescheduled work programs that were pushed from the second quarter into the third quarter of this year. This resulted in periods of high utilization and record revenue generation in Canada. As Regan mentioned, September was challenging as rain and snow caused operational delays that extended into the first few weeks of the fourth quarter. When coupled with the completion of capital -- client capital budgets and widened differentials, we're seeing many clients opting to postpone completion programs later into the fourth quarter and some deferring into the first quarter of 2019. STEP has also witnessed aggressive pricing in the marketplace as competitors are attempting to fill short-term gaps in their operation schedule. As a provider of pressure pumping services over the past number of years, these actions aren't surprising, which is why we've taken steps to secure longer term work with clients that are more resilient to commodity price swings and have larger capital programs. Overall, we're pleased with the performance of our Canadian segment and believe our results speak to our ability to generate industry-leading returns. In the United States, our deep capacity coiled tubing platform continues to generate strong performance, and we are pleased to announce that we've deployed our ninth spread to the field, which is equipped with a 14-foot wide reel trailer, the first of its kind at STEP. We also plan to take delivery of 2 additional deep capacity coil spreads before year-end, bringing us to 11 active spreads to start 2019. Echoing Regan's initial comments, the integration of Tucker has been going as planned, and we've had success in maintaining our core client relationships. In the third quarter, our U.S. pressure pumping business experienced inconsistent activity levels, due primarily to our concentrated client base and short-term adjustments made to their completion schedule. This was very much a transitory issue, and we're happy to note that these clients have resumed operations in the back half of the quarter. In addition, a very competitive price environment emerged in the third quarter as extra crews were moved into Oklahoma due to Permian takeaway issues. This lowered pricing and margins across the service sector as companies struggled to maintain utilization on manned equipment. In response to this short-term environment of lower demand and uneconomic spot pricing, STEP opted to reduce our U.S. fracturing operating capacity from 4 to 3 fleets in the third quarter. We fully intend to reactivate the fourth spread when we have line of sight to prolonged stronger economic activity. Lastly, I'd like to provide some comments on our capital program. As we noted in our second quarter 2018 press release, we opted for flexibility in deploying our Canadian fracturing asset base as we did not see the need to add incremental spreads into an oversupplied market. We planned to take delivery of our 2 fit-for-purpose Viking spreads by year-end, which will then display smaller capacity spreads, enabling some horsepower to support operations with higher intensity and horsepower requirements. As such, the company has reduced the 2018 capital program by $20 million and are now expecting to spend $140 million inclusive of 2017 carryforward capital. I'll reiterate that the company is actively and prudently managing its debt levels, and will focus on debt reduction through 2019. I'll pass the line back to Regan to speak to our outlook and provide some closing comments.
Thanks, Rob. I'll now speak briefly to our broader market dynamics to build on some of what Rob has mentioned. In Canada, looking into the fourth quarter 2018, activity has benefited -- our activity has benefited from work deferrals carried over from the third quarter. However, we are seeing budget exhaustion, capital discipline from our clients, largely influenced by wider differentials. We have an oversupply of fracking equipment in the marketplace that is manifesting in competitive pricing conditions and chop utilization. We are also expecting the traditional holiday slowdown period to be more pronounced as we're seeing clients less likely to prespend their 2019 capital. All of these reasons are why we've endeavored to align ourselves with clients that have large capital programs, diversified market egress arrangements and existing processing and infrastructure facilities that we believe will insulate them from some of the impacts of short-term commodity volatility. As mentioned in our business update on October 25, we believe we'd position STEP to be successful in this market by investing in our asset base, which includes enhancing our fracturing asset base with efficient continuous duty assets, bi-fuel equipment, state-of-the-art technology platforms and fine-tuning our high performance operating model. I'll note that we've also been proactively investing in ever-expanding coiled tubing fleet that represents sort of an ongoing evolution of technology in that space. These investments, along with our engaged team of professionals, have assisted us in positioning STEP to execute at a very high-level and enabled us to demonstrate our unique -- capabilities and strong field execution. As previously stated, we've been able to secure firm commitments for more than half of our manned fracturing fleet going into 2019, with many larger strategic clients. We expect this will provide some delivered benefits including effectively hedging a portion of our revenue stream to offset the fixed cost element of our business, while at the same time giving us flexibility in the spot market with our free capacity. Overall, we're of the belief that maintaining consistent utilization will result in year-over-year margin improvement, especially when we have the leverage of our quality and safety focused field execution, technology focused asset base, engaged professionals and low cost structure. We have a proud track record of industry-leading returns and margin performance, and we believe the strategy we have deployed for 2019 will continue to position us to maintain that record. In the U.S., we're taking cautious approach to the business in light of on-growing egress issues, which are impacting pricing and utilization across the southern U.S. market. We expect current market dynamics for fracturing services to continue to be challenging until these egress issues in the major resource patients have been alleviated. Our clients' discussions concern -- our client discussions confirm that although short-term pricing pressures are real, fracturing capacity will likely tighten over the next 6 to 9 months with most industry watchers predicting significant improvement by the second half of 2019. On the same token, we expect demand for coiled tubing services in the U.S. to temper somewhat during this period as completion activities are being curtailed. The company's strategy to increase our business scale and capabilities in the U.S., particularly given the headwinds to growth in the Canadian market, has positioned us to benefit from higher activity levels in the U.S. when these issues are alleviated. This concludes my comments, and I'll now turn the conference over to the operator, who will open the line for questions.
[Operator Instructions] Our first question comes from Ian Gillies with GMP.
Starting in Canada, there's obviously been quite a bit of noise about the pricing environment. I was wondering if you could maybe try to highlight some of the differences, maybe you think you have in your cost structure relative to some your peers, which I would suggest, already starting to show up in Q3?
Yes, so I mean, I'd like to -- I just like to take a moment to address the discussion around -- that's been pervasive in the market around our pricing strategies. I think it's important to highlight that there is currently 6 frac operators, main frac operators is in the basin, and then there's 2 private frac operators in the basin. 2 of our public peers represent over half the Canadian marketplace, STEP and 3 -- our 3 other larger competitors represent the other half of the marketplace. And I think I find it -- I actually find it very flattering that STEP has been in the minds and discussions of many of our peers. Given we represent about 15% of the market, I would suggest them -- we're clearly making an impact in the business and standing out. So as we think about our results, and specific to your question, Ian, what gives us a cost advantage, I'll point to -- I think when we designed our frac business, we set it up with a different cost structure. We were able to create something unique when we started that allowed us to kind of swim against the current of conventional wisdom. That's given us a more efficient cost structure. We have had an active capital program in the last 2 years, dedicated to improving our asset base, buying brand new technology, equipping our professionals with the very best assets. We have -- it's no secret we have a very passionate focus on a high performance culture. We got a team of professionals that are just outstanding, go to work every day to deliver the best possible experience for our clients. I guess I would look to all of those things along with our, sort of, strategy around the clients we align with as factors in why we're able to generate stronger returns, specifically through the third quarter, than our peers did.
Okay. That's helpful. I mean, I suppose like as you move in through 2019 with half of your frac equipment tied up, will you look to go forth and trying contract some more equipment? Or are you positive on what may happen in 2019, so you'd like to see how the spot market evolves from here?
Yes, we're certainly not positive about the outlook for 2019. It's pretty apparent, I think, with these current pricing differentials that our clients are still trying to get their heads around how their capital programs will look for 2019. We're really pleased to have the agreements in place that we have for a large part of our asset base. What we don't talk to is, we have a number of other clients that have meaningful programs. As we look into 2019, Q1 looks like it's going to be very busy for us. And as we look through the balance of the year, we have a suite of clients that have activity planned, and we'll certainly look to manage our utilization around their requirements. And as I said earlier, at this point, there is a lack of clarity just about how 2019 will unfold. The thing we certainly are very pleased with is to have roughly half of our asset base committed to arrangements that see visibility to activity all the way through the year, including second quarter.
Okay, that's helpful. And switching gears to the U.S., I mean, when we look at the margins this quarter, and we go back to maybe Q1 prior to Tucker being in the fold, I mean, I guess -- have coil margins degraded materially from Q1? Or can we assume most of the degradation in margin performance is just due to the higher cost structure associated with having frac equipment now?
Yes, directionally, we have seen some softening in the coil business through Q3. But it was a material -- As we've communicated, we've experienced some pretty tough utilization, we've experienced some pretty significant pricing pressure from peers in the Oklahoma market. So our frac business, the Tucker business, it's had a pretty tough quarter and so definitely, that's an opportunity that we're working on. We look forward to those results improving in the coming quarters. But yes, the bulk of the disappointment in the U.S., certainly at this point would be tied to our fracturing business.
Okay. Last one from me with respect to U.S. frac. I mean, are you considering pivoting at all yet to moving any of the equipment into other basins at this point, given it's inactive and you do have some basis elsewhere?
Yes, for sure, Ian. I mean one of the things we thought we'd benefit from in buying Tucker was our existing coiled tubing client base. We do have operations, operating bases in South Texas, in the Eagle Ford and, of course, the Permian and also in the Haynesville. So we had great opportunity through that infrastructure and those client relations to add to our client base in the U.S. And that has been an active agenda for us since we started working with the Tucker team. And while -- at current, we have not secured work that is going to drag us out of the Oklahoma market, but we're certainly active looking for those opportunities. As we think about where we'd like to be, the right -- if the right opportunity surfaces in the Permian, we'd like to have a -- start seeding an operation there, and certainly through our client relationships, we can see opportunities in the Eagle Ford.
Our following question comes from Greg Colman with National Bank Financial.
I wanted to start in the U.S., talking a little bit about Tucker, maybe asking some of the stuff Ian was focusing on in a little bit of a different way. If you look at the EBITDA in the quarter, not the margin necessarily but just the absolute values, it was actually flat to Q1, which is pre-Tucker. Does that imply that Tucker was just a 0 contribution in the quarter? Or was there a little bit there?
There was a little bit there. But as I said earlier to Ian, it really wasn't a material contribution.
Got it. And the contribution, or rather the close to 0 cultivation from Tucker, is that delta between where it was in Q2 and Q3, just for clarity, almost entirely due to the customer schedule changes?
Well yes, there are certainly more to that discussion than just that answer. But what I can say is, we did see lower utilization, we did see some significant pricing pressure in a couple of our accounts. We did see additional cost carried into the quarter having a fourth crew, which, of course, we parked partway through the quarter. It was a number of factors that contributed to it, but as we've talked about before, Tucker had 3 main clients that had very lumpy activity through the -- sorry, through the third quarter. One of them, of course, was digesting in the early days of beginning to digest some major transactions, so that impacted their activity levels. So I mean, it's a variety of factors that have contributed to how that business has performed so far in Q3.
That make sense. I appreciate that color, and I guess directing myself, directing my questions to your commentaries saying that the customers were back to work at the end of Q3, is that back to work to sort of the, I'll call it, pre-slowdown levels? Or is it more of a ramp-up?
Well, I think one of the things that we're hearing kind of through the chatter mill, was some question around whether or not we'd been able to maintain Tucker's client base. And certainly, what we're incredibly pleased to clarify is that all the 3 main clients that Tucker's build their business with are still active with us today. They began operations again in September, and in through the start of Q4. I don't think -- we're certainly not comfortable sitting here saying that they're going to have activity levels consistent with what we might have seen a year ago. However, they all have active programs. Important to note that -- perhaps building on your earlier question, Greg, as we did find ourselves with new capacity or extra capacity in that market, we were essentially participating in the spot market there. But we're really pleased to be able to say that we have broadened that client base somewhat in the Oklahoma area, so we do have a larger active client base than we've had before that we expect to hopefully build on as we go forward.
Okay, that make sense. Switching gears a little bit. Just thinking about free cash flow. If we exclude the carryover CapEx from 2017, I think I see you 2018 spending just at around $100 million, I think. Are we right in considering the maintenance CapEx component of that, and therefore, the maintenance CapEx in 2019, to be sort of in the $55 million to $60 million range? Or am I off?
Greg, it's Rob. The maintenance capital that we would anticipate for 2019 is going to be in the $40 million to $50 million range with our current outlook of deployed equipment.
$40 million to $50 million, got it. And should we be thinking about any growth capital in and above that?
Greg, it's Regan here. At this point, we are actually really pleased with the asset base we have. We have -- some of it is not active, some of it's not highly utilized, so our outlook as we look into 2019 is no growth capital. And the opportunity to put our asset base to work under higher utilization and hopefully improving pricing as the year goes on.
Got it. And I guess maybe asking very similar question but in a slightly different way. Can you talk to me about management's attitude towards staying within their free cash flow in 2019? And kind of jumping to looking ahead here, presuming you are seeing with the cash flow, how do you look at the waterfall of deploying the excess free cash in the year?
Yes, so again, I think we have no plans for sort of growth capital. As we look into 2019, we do believe we are going to generate a material wedge of free cash flow. And as we think about it today, that cash flow would be deployed to retiring some of revolvers -- our debt facility.
Simple as that...
For the majority of it. The majority of our debt or our free cash flow, we would expect would be directed towards retiring debt.
Our following question comes from Jon Morrison with CIBC Capital Markets.
Regan, can you provide any more comments around the current pricing dynamic within the Canadian fracturing market right now heading into the winter? And I guess the real question is, have you seen a major rate of change in pricing behavior in the past couple weeks? I know, and I know that you'll know, there's an immense amount of noise in the market right now and there is conflicting data points out there, so anything you can help -- anything you can give us to help calibrate whether pricing largely looks to be holding at the current levels or if there's some rate of change would be helpful.
Boy. If we go back to the first half of 2018, what I can tell you is, our success ratio on quoting on opportunities was very low. That told us that we need to adjust our pricing strategy as we look through the back half of the year if we were going to continue to secure work. And so we have adjusted our pricing in some situations, certainly, to take advantage of opportunities. I can tell you that as we look forward, we understand where we want to price work, and we're going to continue to monitor the market to see how successful we are in securing that work. But I'm not sure I have the insight, Jon, just to be able to tell you if -- how the market is behaving right now or changing. It's no doubt in Canada, specifically, we've got, I think, an increasingly cautious outlook as we look through 2019. I think that's going to cause our group of peers to think carefully about their deployed -- deployed horsepower and all of our cost structures. And we're going to manage our business, I think, as a sector to continue to be profitable or generate positive cash flow. I expect that discipline will be in the marketplace.
Given the line of sight that you have in Oklahoma right now, how are you thinking about forward staffing planning for that fourth crew? To Rob's comment in the preamble, you're running 3 today, do you expect that to largely hold for the front half of the year? Or is there enough potential work that you need to be at least thinking about staffing that fourth crew at this point?
I would say the bias today as we think about the first half of '19 in the U.S. frac business would be to leave that third -- or that fourth frac spread part. I think it is so dramatically different, the outlook in the markets, Canada versus the U.S., no secrets there, but client discussions, as we look into 2019, look like through the first half activity levels will build. And through the second half, the outlook's very strong there. So it's very possible, as we think about the second half of 2019, that, that fourth spread will be active. And it's very possible that we could deploy some underutilized assets in Canada down to the States.
And at this point, are you actually thinking about actively moving or planning to move those assets into the U.S. at this point? Or is it really just more of a, see how the market will evolve and the inflection point that comes in spending profiles as we move towards the back half of the year? I guess, are you willing to make the bet to do it early? Or are you willing to let the market evolve and then judge at that point?
Yes, I -- we've got to let the market tell us that opportunity resides there, but certainly, as we spoke to earlier, we've got a lot of unique client relationships through our coil business. We're positioned in 2 great markets that we're currently not fracking in. So I think our bias as we think about the back half in '19 is we will have some Canadian capacity in the States. I think it's a thought, and it's something that we believe we should plan for, but we're not actively pursuing a strategy today to move equipment, so.
Okay. And you talked about in the past having a fairly concentrated customer base in Oklahoma. And obviously, given some of the gaps in programs, you're more active in the spot market. As you think about your 2019 customer base, do you think it's going to be meaningfully different than when you acquired the platform? Or it's really still concentrated to 3 or 4 with, perhaps, just a little bit more smaller work programs for other guys out there?
I think it's entirely possible as we explore opportunities in the States to see the client base evolve there. I think it's -- we just can't escape this reality, we're a small fracker in the U.S. And you're very biased to a concentrated client list with the asset base we have. So as we go forward, we would certainly expect to see a large part of the fracking revenue concentrated to a small number of clients. It's certainly possible that, that could be in different geographic regions, though.
Just a point of clarification, are you actually seeing incremental fracturing crews continuing to move into Oklahoma from the Permian at this point? Or is it really just the hangover effect on the pricing and activity side from some of those crews migrating into that market, a few months ago, when we first started to see kind of a tampering in the completion work in the Permian?
Yes, I think -- today I wouldn't say that there's any frac crews migrating into the Oklahoma market. I think the market, it's pretty clear that the market is well supplied. One of the large U.S. players has got a massive, sort of, investment or asset base operating in the Oklahoma market. So yes, I don't think additional equipment is moving into the Oklahoma market today.
Okay, last one just for me. You talked about the U.S. coil likely plateauing from here, which make sense, just given that you are seeing a plateauing in completion activity in the Permian. Is that really what's driving all of that backdrop that you're talking about? Or are you seeing new equipment arriving in the Permian that's also challenging the competitive dynamic?
Yes, there has absolutely been additional equipment coming to the market into the U.S. It's no secret that the club business has been identified as an area of better margins and pricing, so we have seen competition coming into the market, not unlike ourselves adding new units. And I think, so that capacity is coming to the market. I think the market fundamentally is still growing at the expense of stick pipe, but when you combine that with sort of the slowdown in completions, the growing duck inventory, it is sort of resulting in a market that is modestly oversupplied today.
Our next question comes from Aaron MacNeil with TD Securities.
On the 2019 strategy, is it really just as simple as, like, relative margin performance? Or should we be looking at other metrics? I guess, so overall I'm trying to get a sense of what metrics are important to you guys in how we -- you think we should be evaluating the success of the initiative going forward.
Yes, so I think where you're going, Aaron, is a margin percentage -- what we care about is sort of absolute margin, what we care about -- I think we can start with acknowledging we have a relatively low cost asset base given the strategy we deployed to acquire those assets through the downturn. So we have the ability to generate strong return on capital employed metrics because of that asset base. As we look forward, we think the right way to think about the, sort of, health of the business is in absolute EBITDA relative to your asset base. So we're focused on generating absolute EBITDA. Undoubtedly, that's correlates to EBITDA percentage, but it's the EBITDA that generates -- ultimately, flows through to cash flow, which allows you to continue to invest in your asset base and ideally position you to grow the business, so that's how we think about it.
Understood. So I guess in trying to do that, if I look back at your Canadian coil margins like before STEP acquired the fracturing asset, EBITDA margins look like they're in the 25% range. So if we're trying to split out what Fracturing contributes versus what coil contributes in Canada, do you think using that 25% EBITDA margin percentage on your coil revenue is an acceptable assumption for coil performance?
Aaron, it's Mike Kelly calling -- or speaking. We don't actually discuss the margins on specific service lines in our press release, and that's not something that we're going to go into here. I think the -- some of the commentary that you're driving to is more related to our strategy for next year. If you look at our coil performance, we still believe that based on our assets, configuration and the position we hold in Canada, we have a strong position in the coil market. They're limited competitors who can match some of the service and equipment capabilities we have, which I think tends to insulate you a little bit from some of the downward pressures that we're seeing. Looking into '19, I think as Regan kind of reiterated a couple of times, we have a fairly cautious outlook as to what those -- what that -- what the year will involve in terms of activity. And that really goes a long ways to speaking to our desire to align ourselves with customers to give us better visibility. So I think if we look forward, and with the work that we have committed, we are looking to generate some activity improvements, year-over-year, particularly in Q2, where we see that we'll have a better book of business certainly than what we had last year.
Understood. And then maybe thinking about it a different way, with the 2019 strategy, I think there is an implied shift to kind of higher completions intensity work. So I guess I was wondering, are you guys reevaluating your expense versus capitalized policies for fluid ends? And I know...
That policy is going to be driven by -- the accounting rules are pretty clear. If you have an economic useful life and extends -- that extends beyond a year, you capitalize. So we monitor that extended -- that economic useful life, we monitor life of our fluid ends or power ends. Right now, it's beyond a year. We don't see that changing materially, but if it does, we'll adjust our accounting practices accordingly.
Got it, yes, makes sense. And then of the $40 million to $50 million of maintenance cap that you guys referenced earlier, how much of that do you think would be related to fluid ends?
I think if you look at the nature of the programs we'll be undertaking, that will represent a big cost to the business. It's something we built into our strategy and how we price our work. Our expectation is that there will be a certain amount of dollars that have to be allocated to those equipments based on the type of work that we've taken on.
And obviously, Q4 will have its challenges with budget exhaustion and holiday-related slowdowns. And I know you've already set some fairly strong expectations for Q2, but do you think that Q1 will be a pretty clean quarter that we can kind of evaluate the success of your customer alignment strategy at that point?
Q1 is always difficult to predict simply because weather is such a big impact there. If our customers are successful in executing the programs, they will -- they've -- they expect to, weather cooperates and I think we'll have a good basis for looking at that, but we'll have to see how the weather cooperates.
Okay, and then switching to the U.S., just on a clarifying point, like when you say pricing pressure, is that in the spot market? Or is that for the kind of 3 committed crews that you have in those recommenced work at the end of Q3? Or both?
Certainly, it's both. I mean we've seen the core clients be presented with pricing from our peers down there that have caused us to have to react, which, said very directly, means we've had to reduce pricing with some of our core clients. And then of course, if you're looking for -- if you're looking for additional utilization in the spot market, you're pricing at sort of where the competition is and so that's definitely seeing pricing erosion as well.
Okay. And then with some improvement in utilization in Q4, is it fair to assume that margin performance might improve from Q3 levels? Or do you think kind of holiday-related slowdowns might impact that going forward?
What we're seeing right now, and our expectation is, you're going to see degradation Q4 versus Q3. I think the factors that you articulated, which is just budget exhaustion and holiday schedule contribute. And we're seeing some pretty aggressive pricing on the spot market as ourselves and our peers attempt to fill in gaps in our schedule.
[Operator Instructions] Our next question comes from Josef Schachter with Schachter Energy.
We all know how tough things are going to be for the next couple of quarters but looking into the second half of '19, in the U.S. first, you've got Encana entering with the Newfield purchase and looking at cube design. Also there is going to be egress resolved in the Permian, and also you look at the Anadarko productivity reports from the EIA, you've got over 1,045 wells now DUCs in the Anadarko basin. Can you talk about the egress issues out of that area, if there's pipelines coming on and then also how do you see Encana Newfield with a much more aggressive approach coming impacting the business in the Oklahoma area?
Okay, Joseph, so when you had talked about new pipelines, are you referring specifically to the kind of Mid-Con or Oklahoma market or?...
I'm wondering about the Oklahoma market if there is an issue. We know that the Permian gets resolved in Q2, Q3.
Well, I think the whole southern sort of refinery pipeline processing complex is congested now with the growing production that we've seen throughout Texas and Oklahoma. And while I'm not in a position, like I'm not aware of specific pipeline projects in Oklahoma, I can tell you that the infrastructure dollars being spent to address this bulging production through the southern U.S. states is underway. It's awe-inspiring, frankly, from what I can see how they're actively pursuing solutions to these congestion problems and to the extent that, that has caused some complications in pipeline capacity and processing capacity in Oklahoma, I think that in the broader picture, it's all going to begin to become resolved as we move through 2019. Specific to Encana, I think, yes, I'm very curious about their plans for the Newfield assets. That certainly could result in increased activity level in the Oklahoma market in general, so that will be very positive and constructive, we think.
Okay, if more people go cube design, does that really impact the business a lot? Would that cause shortages of equipment in the local market if that becomes more of the norm in late 2019?
Well, I think the -- one of the things to observe with cube design is that there is a massive capital investment drilling wells and preparing them for completion. So one of the things it can create is a very lumpy completions activity. While these large cube-type pads are being developed, there's no fracking or very limited fracking going on. I think that one of the things that cube development offers is the ability to improve frac efficiencies overall, because you can do zipper fracs, simultaneous operations that can really markedly improve fracs per day, stages per day. So I think you can see lumpiness because of these cube developments and then I think you can see frac efficiencies improve because of them.
Okay. Second question for Canada. We're seeing stronger eco- prices finally getting closer to $3 now. Do you need that to be into Q3 before -- and sustainably there because of the storage being very low before you start seeing a meaningful pick-up in Canadian activity?
Yes. How I think about it is, we need the sort of the back end of the gas curb to move up to the point where producers, our clients can start locking in some hedges. So the longer we see stronger gas prices ideally through this winter period, the more likely it will be for our clients to be able to lock in pricing at higher levels, which should translate into larger capital budgets with improved cash flow.
Thank you. I'm showing no further questions at this time. I would now like to turn the call back to Regan Davis for closing remarks.
Thanks, everyone, for dialing in. We hope this has been insightful and helpful. Certainly, if there is additional follow-up questions outside of the call, reach out to us.
Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program, and you may all disconnect. Everyone, have a great day.