Cypress Environmental Partners, L.P.
Q4 2016 Earnings Call Transcript

Published: 15 Mar 2017

[Operator:]

Welcome to the Cypress Energy Partners’ Fourth Quarter Earnings Release Conference Call. At this time, all participants are in a listen-only mode. I would now like to turn the call over to Richard Carson. Sir, you may begin.

[Richard Carson:]

Thank you. Hello, and welcome to the Cypress Energy Partners’ fourth quarter investor conference call. I am Richard Carson, the General Counsel. With us today are Pete Boylan, our Chairman and CEO; and Les Austin, our CFO. We’ve released our fourth quarter 2016 financial results and posted the associated press release on our Web site, cypressenergy.com. In the press release, you will find an important disclaimer regarding forward-looking statements. This disclaimer is integral to our remarks and you should review it. Also included in the press release are various non-GAAP measures that we have reconciled to Generally Accepted Accounting Principles. Those reconciliations appear at the back of the press release. So, with that, I will turn the call over to Pete.

[Pete Boylan:]

Good morning. Thank you for joining us today and your interest in our company. As outlined in our press release, we announced our fourth quarter 2016 results. The fourth quarter continued a general trend of sequential improvement in many of our key metrics and profitability from our trough and EBITDA in the first quarter of 2016. I’m pleased that we continued to diversify our business despite a difficult two-year industry downturn adding over 40 new customers in 2016. We are continuing to see the benefits of our cost reductions implemented earlier in 2016 and I would like to thank our employees for their dedication hard work and sacrifices. Our customers have been increasing spending, but not as quickly as we would hope and Q1 is always our softer quarter of the year. Our sponsor, Cypress Energy Holdings and its affiliates, who control our general partner remained aligned with our common unit holders with an approximate 64% ownership in CELP, because of this alignment CEH as again provided financial support to CELP with temporary relief of the administration fee owed to CEH pursuant to the Omnibus agreement, which would have charged $1 million to CELP this quarter absent the relief consistent with what we stated during our third quarter conference call. As with the Omnibus agreement relief provided in prior quarters, CEH did not require any consideration from CELP for this additional support. Although CELP is operating performance again sequentially improved in the fourth quarter despite a very tough winter in the Bakken the season low activity, we traditionally see in the first quarter of each year coupled with two unanticipated adverse events in Q1 will likely lead CEH to provide some level of financial support to CELP in the first quarter also for no consideration. During the quarter, we aggressively pursued several acquisition opportunities, advancing to the final rounds while maintaining our discipline approach to due diligence, risk and valuation. Unfortunately for a variety of different reasons we concluded that the risk and return profiles of these opportunities were not appropriate for CELP. CEH remains willing to deploy capital to assess CELP in acquiring attractive assets that maybe larger then what CELP can currently independently acquire with plans to offer those assets to CELP as dropdown opportunities. We are disappointed that we were not able to complete any attractive acquisitions. However, we are very fortunate that we can remain patience and thoughtful because we can organically grow our existing lines of business with minimal investment as we continue to win new customers and existing clients slowly increase their spending coming out of the downturn. We have remained hopeful and cautiously optimistic that we would either find an attractive acquisition with an appropriate risk and reward profile or that are based business would recover more quickly. Unfortunately, we have experienced some financial setbacks in this quarter, on January 15, during an intense thunderstorm we experienced a lightning strike leading to a fire at our Orla Texas Permian Basin SWD facility. Although we have property insurance coverage to rebuild the facility, we experienced a material decline in our volumes and revenue from this valuable location. We quickly reopen with temporary surface facilities while we completed the cleanup and remediation and commenced plans to rebuild the facility, but we are restricted on the volumes we can process in the interim. The start of the year has also been slower than anticipated and in early March we learned that a lower margin but important Canadian inspection customer selected new vendors on several existing contracts that were expiring. The Bakken region where the majority of our SWDs are located continues to materially lag other basins during this recovery with lower levels of activity and lower net commodity prices. It also experienced a few tough months of winter weather that negatively impacted North Dakota production by approximately 90,000 barrels a day according to the North Dakota petroleum council. The Bakken region now has 38 rigs working down from over 200 at the peak, but up from a lower 22 in Q2 of 2016. Nine of those rigs are within a 10 mile radius of our facilities. The Bakken has approximately 850 DUCs remaining with approximately 300 of those within a 15 mile radius of our facilities. Lastly, Brown Integrity our hydro testing business also continues to have low utilization operating below plan in both fourth quarter and year-to-date. We continue to invest in our businesses and have recently hired some new business development talent at both Brown and TIR to focus on organic growth opportunities. In light of these developments and softening commodity prices, our board now believes its prudent and responsible to make difficult decision to reduce our quarterly distribution for the first time since our initial public offering in January 2014. Absent an acquisition in the near future, we currently anticipate reducing the current distribution by approximately 50%. The exact amount, record date and payment date of the distribution will be determined by the board after a review of the first quarter results. If this anticipated distribution level is maintained throughout the fiscal year 2017 compared to the previous distribution level of 0.40643 per quarter or $1.63 annualized, it will provide approximately $9.7 million of internally generated capital on an annualized basis to provide increase liquidity, reduced leverage, invest in selected growth projects in the future and strengthen the company’s balance sheet. This action should provide a sound catalyst to reducing our currently elevated cost of capital by de-levering and improving increased distribution coverage to our unit holders. We went public at a 7.75% yield in January ‘14 and traded down to as low as a 6% yield. We believe our appropriate yields should be in the single digits, given the quality of our underlying business and assets. We are confident these actions support the long-term interest of our unitholders, employees and stakeholders. We see encouraging signs with some new customers and we are focused on organic growth and improved SWD asset utilization in an effort to improve cash flow that will in turn contribute to the improvement of all of our financial ratios. We continue to believe the fundamental demand for increased inspection as well as water disposal remains strong over the long term, but the recovery has been slower than previously anticipated. At this time, I would like to introduce Les Austin, our CFO, so that he can walk you through the highlights on the financials.

[Les Austin:]

Thanks, Pete. I would like to take a moment to highlight some of our financial information. Adjusted EBITDA, which we define as net income or loss plus interest expense, depreciation and amortization expenses, income tax expenses, impairments, offering costs, non-cash allocated expenses and equity-based compensation was $6.9 million, $6.7 million of which is attributable to our common and subordinated unit holders, and $0.2 million of which is attributable to our non-controlling interest holders that own 49% of our hydrostatic testing subsidiary. Distributable cash flow for the fourth quarter was $5.1 million and on February 13, we paid our 10th quarterly distribution of $4.8 million or $0.406413 per unit, which represents a 4.88% increase over our minimum quarterly distribution and is consistent with the prior nine quarterly distributions. Our common unit coverage ratio was 2.09 times, since approximately 50% of our units remained in subordination through our February 13 payment, at which time we exited subordination and 1.05 times on all units. I am providing this additional information to further help our investors understand our performance. On a GAAP basis, net income in the fourth quarter was $1.8 million. That net income was comprised of $2.4 million, attributable to our common and subordinated unit holders, $0.4 million attributable to our non-controlling interest holders and a net loss of $0.9 million attributable to our general partner. In addition to the financial highlights on net income, adjusted EBITDA and distributable cash flow, I would also note the following. We continue to have over 85% of our revenues generated from investment grade customers, and have continued to win new business with additional investment grade customers that should be seen in future periods. We are currently bidding on some new major contracts and have picked up some nice new work despite the loss of a portion of our inspection work for a good Canadian customer to a competitor. More than 90% of our inspection clients continue to be investment grade. Our leverage ratio as calculated under our credit facility was 3.41 times versus our covenant of 4.0 times and our interest covenant ratio was 3.78 times versus our covenant of 3.0 times with a cash position standing at $26.7 million at the end of quarter in part as a result of financial support from our sponsor. Although January experienced its consistently seasonal low headcounts as our clients start ramping up work following the holidays through February and into March. We have seen our average domestic inspector headcounts increased from the averages experienced in the fourth quarter of 2016. We are currently evaluating our strategic options in our Canadian operation which generated 8.4% of our 2016 revenues. Given the loss of a material portion of the significant customer contract on pricing. We also continue to renew several sizable existing contracts and our bidding on some new major contracts, but continue to see some of our customer's projects slipping past the original start dates typically as a result of permitting delays. During the fourth quarter, approximately 96% of total water volumes came from produce water, and pipe water represented approximately 47% of total water volumes. When commodity prices improved and drilling activity increases, we expect to have significant operating leverage with our cost structure and minimum maintenance CapEx expenditures required as volumes increase. We have estimated that 514 drilled and uncompleted wells or DUCs within a 15 mile radius of our facilities comprised of 302 in North Dakota and 212 in the Permian. As prices improved, we expect to benefit from the completion of these DUCs. SWD facilities are only utilized at approximately 25% of their capacity. When activity picks up in the Bakken we should see some meaningful benefits given the majority of our facilities are located in this region. Several customers recently announced that they were going to increase spending in both the Bakken and the Permian as an example of improving levels of investments. Our integrity services business or Brown Integrity, Q4, 2016 results sequentially declined with average utilization of 53% during the seasonally low holiday period. We have recently invested significantly in business development talent and we continue to bid on the substantial amount of work. Through March, our backlog in this segment is increasing. However, the business unit lost money in Q4 and year-to-date in Q1 historically the bulk of their revenue and activity is in Q3, Q2 and Q4. We averaged 1,093 inspectors and 20 field personnel per week for the fourth quarter of 2016. We have over 1,100 inspectors currently working. We disposed of 3.4 million barrels of salt water during the fourth quarter of 2016, average revenue per barrel was $0.68 for the fourth quarter of 2016. Despite the impact of lower drilling activity, oil prices and disposal rates, the water environmental business still generated fourth quarter gross margins of 70.8% and strong adjusted EBITDA with nominal maintenance capital expenditures which is attractive relative to many service businesses serving the energy industry. The winter was particularly tough in the Bakken as noted in Pete’s comments. Maintenance capital expenditures for the three months ended December 31st 2016 were $101,000 reflecting the attractive business model of limited maintenance capital expenditures required to operate our businesses. This remains a key differentiator for CELP versus virtually all other MLPs. In fact in 2016, our total maintenance capital expenditures were only 307,000. And with that, I will turn the call back over to Pete.

[Pete Boylan:]

Thanks, Les. Many of our customers are more optimistic about 2017 with stronger commodity prices compared to last year. That should benefit our business. The Bakken remains slower than we would hope and Les mentioned the low utilization we continue to have with Brown Integrity our hydrotesting subsidiary. We continue to aggressively look for attractive acquisition opportunities that will allow us to supplement our organic growth and are currently conducting due diligence on a half dozen potential targets. We are also awaiting bid results on a few major inspection opportunities and continue to believe that our business will benefit materially from the proposed new PHMSA and California rules despite the loss of some of our business in Canada. We are looking at reducing our Canadian cost structure by moving various activities to our headquarters in the U.S. The inventory of DUCs around our facilities are slowly being completed benefitting the long-term produced water anticipated to be received from some of these well. Today, our facilities like most competitors remain materially underutilized and the tough winter weather in the Bakken didn’t help us either. We’re now transitioning from the winter blazers to the meltdown that inevitably leads to various road closures that negatively impact volumes and activity. The Bakken is and always will be a challenging environment to operate in compared to other more mild climates. We have a strong sponsor that as a material economic interest in CELP owning 64% of the units that is interested in growing the value of the LP interest, and assisting in financing acquisition opportunities that are larger than what the MLP could handle independently at this time. We also remain focused on making a thoughtful decision regarding our distribution policy to ensure that we have a suitable metrics and a viable currency to grow our partnership over the long-term. We truly appreciate your valuable time, investment and continued support and we remain focused on execution organic growth and sequential improvement in our current operations. Our Board of Directors, management team and employees remain committed to building a great company with a focus on long-term unitholder value through a disciplined approach to growth. Operator, we may begin taking some questions.

[Operator:]

Thank you. Ladies and gentlemen at this time, we will conduct a question-and-answer session. [Operator Instructions]. And our first question comes from John Whyte of Raymond James. Please state your question.

[John Whyte:]

I was just hoping that I could dig a little bit more into the facility within the Permian. So, it sounds like the current capacity is a little bit lower than what the former capacity was. Can you go into a little bit more on that? And how long you think the timeframe is before you could rebuild the surface of equipment to bring the capacity back up to where it was previously?

[Pete Boylan:]

Sure. Thanks for the question. So, the surface facilities burnt to the ground, we have a substantial amount of produced water in the storage tanks, had about 7,500 barrels of storage. The oil tanks remarkably did not burn and we were able to salvage the residual oil. The location of the facility is and probably one of the best areas in the United States right now in the Orla area, the Permian Basin. And so we’re currently looking at design options on building a larger facility that can handle more surge volumes given the dramatic amount of drilling activity in the area. So, the size of the facility that we end up building is something we’re evaluating right now. We were able to get the facility reopened within I think 10 days, with temporary storage facilities. Obviously, none of the down hall assets were damaged in the fire. And it's our hope that we would be able to have the final facility once we conclude the exact size, rebuild and open sometime in the next three to four months would be my best guess.

[John Whyte:]

Okay. Thank you. That’s extremely helpful. And then I was just hoping to get a little bit better sense of regulatory environments and how some of the changes that are occurring within particularly with an new administration. Just how do see all that playing out and especially how well it impacts your business?

[Pete Boylan:]

Well, I think its without debate if the new administration is being very positive for the energy industry and our customers in particular, and that should benefit Cypress overtime. As most of you know he has green lighted a number of projects that were held up in various stages of approval in permitting that we’ll deal with some de-bottlenecking issues in the Northeast and I think the general approach to regulation is very beneficial to the energy industry. We haven't seen yet what changes if any will be made in the DOT and PHMSA, but to date we’ve seen nothing but positive dynamic associated with their policies and how they impact our customers.

[John Whyte:]

Okay. All right. Thank you. I'll turn it back now. Thanks.

[Operator:]

Okay. Thank you. And our next question comes from Ethan Bellamy. Please state your question.

[Ethan Bellamy:]

So, to start, could you walk through where you think the current market rate per barrel is disposal by basins where you're active?

[Pete Boylan:]

So, the markets vary substantially between basins and even within a basin depending upon the local supply and demand fundamentals. And as you certainly appreciate the Bakken and the Permian is huge place, where we currently have facilities with many counties and each and every one of those neighborhoods has kind of a different competitive dynamics. So with that caveat let me kind of give you some ranges. So, in the Bakken at its peak people might have received as much as $2 a barrel for flow back and over a $1 a barrel for produce water. I think when we went public in January 2014, flow back was $1.75 a barrel up there and produce water was about $0.75 a barrel. Today, depending upon the neighborhood because the Bakken is materially overbuild relative to the current levels of produce water and drilling activity. You can see flow back as low as $0.50 and you can see produced water as low as $0.40. I’d say on balance we’re seeing higher prices for flow back and higher prices for produced water at our facilities, but again each and every facility is kind of a little different competitive dynamic where you're competing for the available water in that market. Generally, speaking you're looking at maximum radius of 30 miles and more typically 10 miles to 15 miles, a lot depends on the roads and weight restrictions and other matters. Down in the Permian basin, you’ve never had differential pricing on flow back and produce water and so when you look at our averages you’ve got to keep that in mind. I think at its peak we got as much as $0.65 to $0.75 a barrel. I think today, the market ranges anywhere from $0.40 to $0.55 and probably averaging closer to $0.45 to $0.50 again depending upon the neighborhood and the competitive landscape. The market is also overbuild in the Permian although the activity levels continue to pick up pretty substantially as you’ve seen the tremendous increase in rig count from trough that occurred in the second quarter of last year. Other basins that we don’t operate in vary all over the map, some places like the Eagle Ford people got down to $0.10, $0.15, where you couldn’t even cover your cost of operating and one of the reasons why we have not invested in net basin today.

[Ethan Bellamy:]

That’s very helpful color. How far off where your rigs in Canada where you lost the customer relative to the competition and are they pricing at noneconomic levels or just to keep people employed. What is the pricing dynamic there when that vendor loss?

[Pete Boylan:]

Yeah. Thanks. I don’t know yet, I'm in fact flying up there next week to have a meeting with the clients regarding that. So we do not have Intel at this time as to how close we were. We still remain hopeful that the decision that was made ultimately the vendor won’t be able to perform at the level of service the client expects, but I just don’t know at this point in time.

[Ethan Bellamy:]

Okay, see. It sounds like you’ve been coming up shy on a couple of these acquisitions. Would you describe the market as irrational or just overly aggressive because of all the capital or are you guys just too conservative? Is there a common thread between the deals that you’re missing?

[Pete Boylan:]

Well, that’s a great question and something I discuss with my board on a regular basis. I do believe there is a staggering amount of capital out there competing for opportunities and some of the transactions we’ve seen get consummated, they just don’t make economic sense at the prices some folks have been willing to pay, and we don’t see how they’re ever going to earn a suitable return on their capital, unless they’ve just got a widely different view on the markets and commodity prices and how things could unfold. Several of them we've been pretty close to, but because of our alignment with the common unit holders, we look very seriously at not just the price, the accretiveness of the opportunity, the return on the capital, but we also look very closely at the risk -- and the risk and include environmental risk, and regulatory risk, and customer loss, and all the things that everybody is familiar with. We’re highly confident that we will find an attractive opportunity and unfortunately, you have to get up to bat and spend time, diligenceing a lot of opportunities. So we’ve got a very robust process and as I mentioned, we’re looking at least half a dozen opportunities right now. I just unfortunately can’t predict which one of them will be something we can bring to closure on terms that we consider to be reasonable and prudent.

[Ethan Bellamy:]

Got it. Going back to disposal, what was the -- I think you mentioned -- I think you said 25% in your prepared remarks. Is that including or excluding the facility that got burned down? And could you talk about the utilization rate in the fourth quarter, the exit rate for the end of the year and maybe your utilization now on an apples-to-apples basis? I’m interested in the trend line of utilization.

[Pete Boylan:]

Yeah, so I’ll take a crack at that and then Les I'll let you takeover. But the 25% utilization was in Q4, and the lightning strike and fire did not occur till January 15. And as it relates to utilization, I believe we bottomed sometime in May, June of last year and the water business had been sequentially improving each month. Obviously, with the Orla fire, there is going to be a difference in same-store comp sales or I really like to call it. Les, you want to add to that?

[Les Austin:]

Yeah. So, the 25% utilization is the aggregate utilization for the entire quarter and that’s on a run-rate basis versus the 50 million barrels of total disposal capacity we have in all of our facilities. And I think as we’ve said in our prepared remarks as well, we saw the volume softening so, the run-rate volumes in January would probably have been down from that utilization percentage to answer your question.

[Pete Boylan:]

And I’d also add the 50 million, Ethan, is wheel capacity based upon the well bores, the pressure is what the formation will take, where the nameplate capacity that a lot of people quote would be much higher than 50 million based on what the permit allows just because of permit allow something doesn’t mean facility could really handle that much water.

[Ethan Bellamy:]

Got it. Thanks. Les, when will we get the 10-K please?

[Les Austin:]

It should be out later this afternoon.

[Ethan Bellamy:]

Excellent. Thanks, gentlemen.

[Operator:]

And our next question comes from Michael Hoffman.

[Michael Hoffman:]

Hi. Well, Brian and I have both got questions, so we’re going to both jump in and out of here. Thanks for taking them Les and Peter. And I apologize I missed part of your opening remarks, so if you answer some of this I apologize in advance for being redundant. If you think about the utilization curve find upon Ethan, 25% in 4Q dips in 1Q and you should be recovered with the rebuild into 2Q, or are we a dip and down 1Q and 2Q and then it'll recover. All things being equal, no improvement in business fundamentals, just the same sort of -- trying to understand the trend.

[Pete Boylan:]

Yes. On a consolidated basis which includes to the Bakken, yes I think Q2 will be soft because we won't have the Orla facility in the Permian rebuild and open taking the same levels of water. Once we're reopen, we'll have to win some of that volume back that when and found a home elsewhere while we had to rebuild the facilities. And then the Bakken as you know is just a lot softer, there is far fewer rigs running up there and even with the rigs running you’ve got a lot of the E&P producers that have their own SWD networks and their water both flowed back and produced isn't available for third party disposals. So, you really have to look at the specific of a given location and who are the producers around there and are they sending their water to the third parties for disposal or are they handling it all internally.

[Michael Hoffman:]

Okay. And then how do you think Dapple plays into the work down of all the DUCs in North Dakota?

[Pete Boylan:]

I think it’s a net positive and you’ve already seen some contraction and the discount that the Bakken producers have to take to move their oil. And I think that discounts once it flowing will further reduced benefiting the economics for all the producers out there.

[Michael Hoffman:]

And when you think of it as wells that you identified being within a certain mileage of your sites, are you getting any messaging from the customer say we’re going to work through the DUCs first before we start incremental drilling and then we’ll pick the drilling activity up?

[Pete Boylan:]

I think that’s generally the trend, but it again varies with each customer. If somebody has to drill to hold some acreage on a lease, they might prioritize that ahead of the DUC. If the DUCs got substantially inferior economics to some better core zone, they might alter it. But when you’re talking $0.50 instead of a $1.00 [ph] generally the DUCs are going to go first.

[Michael Hoffman:]

Okay. And then what’s the analysis that needs to be done to decide whether you’re staying in Canada or not, and the pipeline inspection side and if you didn’t win would you make that decision?

[Pete Boylan:]

Sure. So as I mentioned to Eathan’s question I’m going to be up there this coming week visiting the customer and making some decisions on that. We have probably six or seven customers we do work for up there and many of them we believe can be serviced out of our headquarters in Tulsa without requiring the cost and physical presence out there and we’ll be visiting the customers about their comfort level with us in staffing and managing those accounts out of Tulsa versus Calgary and that will really dictate whether we continue to have a physical presence up there. I’d really like to pick up some SG&A benefits of having some of those activities take place in Tulsa.

[Michael Hoffman:]

Okay, and then when do we see evidence of the investment in business development in the Brown business, the TIR business?

[Pete Boylan:]

Yeah, those are very good questions, unfortunately it doesn’t happen overnight. We have two people that started at Brown and in the last three weeks both of them are industry veterans with substantial rolodex relationships. So it's not like somebody that has to start from zero. So we’re cautiously optimistic that we’re going to see some immediate results out of that, but it's too early to tell you exactly what those will be. We are bidding on a lot of work at Brown, so the bad news is the results of Brown, the good news is, there is a lot of work to be had and we have fixed versus variable cost model as you well understand where if we can win enough bids to at least cover our overhead and we can start generating some real cash flow again.

[Michael Hoffman:]

Okay, and that brings me to the next question, which again if you touched in the opening remarks, I apologize. So you’ve shared with us the review of the distribution of off first quarter results review. One, pure mechanics, are you going to report the quarter and then make a decision about changing that or review it before your quarter one and two. What needs to happen not to cut the distribution?

[Pete Boylan:]

Yeah, so we will have our regular schedule, board meeting in early May following the completion of Q1 and at that time ones we see how the quarter finishes, I think the Board will make a final decision, but as we noted in our press release in our comments we are inclined to a 50% reduction. What would alter that would be some acquisition that we were able to consummate between now and then that would allow us to not address the development basis.

[Michael Hoffman:]

Okay. Brian, do you have anything you need to follow-up on?

[Unidentified Analyst:]

No, I think I'm good.

[Michael Hoffman:]

Thanks, guys.

[Operator:]

And our next question comes from Michael Gyure. Please state your question.

[Michael Gyure:]

Yeah. Can you talk a little bit on the spending side of things realizing the fire and kind of the rebuild efforts that are going on there? Kind of how you're thinking about the cost and are you going to consider those costs kind of maintenance versus capital and then maybe which you're looking at is maybe organic growth capital for 2017?

[Pete Boylan:]

Hi. So, we have good insurance coverage on that facility, and as I mentioned we are currently evaluating whether to use this unfortunate incident as an opportunity to build a larger facility that can handle more surge volumes because this location is a very good location and we have had a number of situations where we have to turn away business because we can't pump the water down fast enough, we didn’t have enough storage. So, I'm actually looking at the possibility of increasing my storage at this facility by as much as 50%. So, the insurance proceeds will cover rebuilding what we had. We’re also looking at some incremental new lines of business opportunities, fresh water sale, brine sales, a truck washout facility and potentially a solids processing facility. So, I've got an engineering firm working with my team on designing. We actually own this location fee simple with no royalty which is very unusual in the Permian, gives us a nice advantage and we’ve got about 19 acres. So, we are designing the possibility of having all those things I mentioned plus potentially some land field sales that could take oil field waste. So, what we rebuild that would be replacing what was there in the past, we believe we’ll have insurance coverage for, if we expand the facility to have the ability to take on new lines of business or greater volumes and something like that would be growth CapEx.

[Michael Gyure:]

Okay. And then maybe on the Canadian inspection side of things. Have you ever quantified or can you quantify the number of inspectors or maybe the percentage of inspectors that are up in Canada?

[Pete Boylan:]

Les, we provide any disclosure on that?

[Les Austin:]

We don’t. Mike, we don’t disclose that number, but we have said in our prepared remarks that the Canadian operations represented about 8.4% of our consolidated revenues.

[Michael Gyure:]

Okay. Thanks very much guys.

[Pete Boylan:]

Thank you.

[Operator:]

Okay. And there appear to be no further questions. I’d like to turn the floor back to Peter.

[Pete Boylan:]

Okay. Well, thank you everybody for your time and we look forward to visiting with you next quarter. Thank you.