Total Energy Services Inc. (TOT) Earnings Call Transcript & Summary

Thank you for standing by. This is the conference operator. Welcome to the Total Energy's Third Quarter Results Conference Call. [Operator Instructions] The conference is being recorded. [Operator Instructions] I would now like to turn the conference over to Daniel Halyk, President and CEO of Total Energy Services. Please go ahead.

Thank you. Good morning, and welcome to Total Energy Services Third Quarter 2021 Conference Call. Present with me is Yuliya Gorbach, Total's VP Finance and CFO. We will review with you Total's financial and operating highlights for the 3 months ended September 30, '21, and then provide an outlook for our business and open up the phone lines for questions. Yuliya, please proceed.

Thank you, Dan. During the course of this conference call, information may be provided containing forward-looking information concerning Total's projected operating results, anticipated capital expenditure trends and projected drilling activity in the oil and gas industry. Actual events or results may differ materially from those reflected in Total's forward-looking statements due to a number of risks, uncertainties and other factors affecting total businesses and oil and gas industry in general. These risks, uncertainties and other factors are described under the heading Risk Factors and elsewhere in Total's most recently filed annual information form and other documents filed with Canadian provincial securities authorities that are available to the public at www.sedar.com. Our discussions during this conference call are qualified with reference to the notes to the financial highlights contained in the news release issued yesterday. Unless otherwise indicated, all financial information in this conference call is presented in Canadian dollars. Total Energy's financial results for the 3 months ended September 30, 2021, reflect improving industry conditions in North America, particularly in Canada and lower activity levels in Australia as compared to the third quarter of 2020. Higher North American activity and the reactivation of 2 drilling rigs in Australia contributed to a significant year-over-year improvement in Total's third quarter financial results and a return to profitability with third quarter net income of $4.3 million as compared to a net loss of $4.6 million in 2020. Third quarter consolidated EBITDA increased 51% from $17.9 million in Q3 of 2020 to $27 million in the third quarter of 2021. Excluding COVID-19 relief funds, third quarter EBITDA increased 115% on a year-over-year basis. Total geographical diversification continue to be a stabilizing factor for our financial performance. Geographically, as the year-over-year industry activity levels in Australia declined, activity levels in North America continued to recover from the historic lows experienced during the second quarter of 2020. This is evident by North America contributing 82% of consolidated revenue in the third quarter of 2021 as compared to 68% in the third quarter of 2020. Within North America, the recovery in Canada was more pronounced compared to United States with the relative contribution from Canada to consolidated third quarter revenue increasing 15 percentage points compared to Q3 of 2020. Third quarter revenue contribution from the United States decreased by 2 percentage points on a year-over-year basis. And Australia's contribution declined by 14 percentage points as compared to 2020. By business segment, Contract Drilling Services was the largest contributor to consolidated revenue, generating 36% of 2021 third quarter consolidated revenues followed by compression in process services at 32%; Well Servicing at 21%; Rentals and Transportation Services contributing 10%. This compares to Q3 of 2020 when CPS contributed 42% of consolidated revenue; Well Servicing 30%; Contract Drilling Services 21%; and the RTS segment 8%. While third quarter 2021 consolidated revenue increased by 54% as compared to Q3 2020, EBITDA increased by 100% after adjusting to exclude COVID-19 relief funds and unrealized foreign exchange gains and translation of intercompany working capital balances, resulting in an adjusted EBIT -- quarterly EBITDA margin of 19% as compared to 14% in the third quarter of 2020. The $4.5 million of COVID-19 relief funds recorded during the third quarter of 2021 reduced cost of services by $4 million and SG&A by $0.5 million. This compares to $7.4 million of COVID-19 relief funds in Q3 of 2020, which reduced cost of services by $6.4 million and SG&A by $1 million. Consolidated third quarter gross margin, excluding COVID-19 funds was 4 percentage points higher as compared to 2020. This was primarily due to modest price increase in North America necessary to offset rising labor and material costs. Excluding COVID-19 relief funds, gross margin percentage of revenue improved to 25% for the third quarter of 2021 as compared to 21% in Q3 of 2020. Selling, general and administration expenses for the third quarter of 2021 increased by $1.6 million or 27% compared to Q3 of 2020. As employee compensation was reinstated to pre-COVID levels and the contribution of COVID-19 fund decreased by $0.5 million or 50% compared to the prior year comparable quarter. The improvement in North America drilling activities and the reactivation of 2 Australian drilling rigs contributed to an over threefold increase in Total operating drilling days in Total CDS segment. This resulted in 213% increase in consolidated drilling utilization during the third quarter of 2021 as compared to prior year. Despite a 14% decrease in revenue per operating day as a result of lower North American day rates and changes in the geographic revenue mix, high activity resulted in a 68% year-over-year increase in third quarter CDS segment revenue. Third quarter CDS segment EBITDA increased 263% compared to 2020 as a result of cost management and changes in the mix of equipment operating in North America. An increase in Canadian drilling activity resulted in 254% increase in third quarter operating days in Canada compared to 2020. Recovering industry conditions and market share gains contributed to 380% year-over-year increase in third quarter United States operating days, which in turn drove a 406% year-over-year increase in third quarter U.S. drilling revenue. Third quarter operating days in Australia increased 34% compared to 2020 as 2 drilling rigs returned to service following the completion of recertifications and upgrades. One Australian rig was removed from operation during the third quarter for recertifications and upgrades and is expected to return to service in the first quarter of 2022. The improving industry conditions and the commencement of several major projects in Canada that were previously delayed contributed to 86% increase in third quarter equipment utilization within RTS segment as compared to 2020. Third quarter RTS revenue increased 107% on a year-over-year basis, which in turn drove an 82% increase in segment EBITDA. EBITDA increased at slightly lower pace than revenue due to the mix of equipment operating cost inflation not being fully offset by price increases and lower year-over-year COVID-19 assistance has been received. Third quarter revenue in total CPS segment increased 18% compared to 2020. And this segment saw our fourth consecutive quarterly increase to its fabrication sales backlog, which was 158% higher on a year-over-year basis. Higher natural gas prices also provided support for CPS segments parts and service business and utilization of the compression rental fleet continued to improve for the third consecutive quarter, increasing 18% from December 31, 2020. The operating income for the third quarter of 2021 increased 12% on a year-over-year basis, primarily as a result of ongoing cost management and increased overhead absorption with a higher production activity. Third quarter revenue increased 10% in our Well Servicing segment compared to 2020. While service hours increased 15% during the third quarter, revenue per service hour decreased 4% due primarily to the geographical revenue mix and lower pricing in Australia. Continued strength of oil prices and increased well abandonment activity in Canada contributed to a substantial increase in North American activity that was partially offset by lower utilization in Australia. This segment's EBITDA margin decreased 7 percentage points in the third quarter of 2021 as compared to the same quarter last year due primarily to cost inflation in North America that was not fully recovered through price increases. Total Energy's financial and liquidity positions remain very strong. At September 30, 2021, the weighted average interest rate on outstanding bank debt was 2.8% as compared to 2.85% at September 30, 2020. This lower interest rate, combined with lower outstanding debt balances contributed to a 20% year-over-year decrease in third quarter finance costs. Total's net debt position at September 30, 2021, is the lowest since we completed the acquisition of Savanna in June of 2017 as we remain focused on continued repayment of debt. Total Energy exited the third quarter of 2021 with over $145.6 million of liquidity, consisting of $25.6 million of cash and $120 million of available credit under the company's revolving credit facilities. Total Energy's bank covenants consist of maximum senior debt to trailing 12 months bank EBITDA of 3x and a minimum bank-defined EBITDA to interest expense of 3x. At September 30, 2021, company's senior bank debt to bank EBITDA ratio was 1.6 and the bank interest coverage ratio was 14.45x.

Thank you, Yuliya. Improving North American industry conditions underpinned a significant year-over-year improvement in Total Energy's third quarter financial performance. While industry activity levels remain below pre-COVID levels in all geographic regions where Total operates, continued efforts to manage operating and overhead costs in response to challenging industry conditions were effective in restoring corporate profitability. Total's diversified business model has proven resilient, once again, and has allowed us to generate significant free cash flow even during the most difficult of times. For the first 9 months of 2021, after funding capital expenditures, capital lease and interest obligations and working capital requirements, Total Energy generated $44.2 million of free cash flow or $1.01 per share outstanding at September 30, '21. This free cash flow was directed towards continued debt repayment and share buybacks. Notwithstanding continued strength in commodity prices, many oil and gas producers have been hesitant to substantially increase capital budgets. At current commodity prices, Total Energy expects that oil and natural gas drilling and completion activity will continue to moderately increase, led by private producers not under the same pressure to curtail their capital investment programs. Demand for equipment and services provided by our CPS segment continues to strengthen as investment in global energy infrastructure recovers from the pandemic collapse. Total Energy's track record of fiscal discipline and maintaining a sound financial position allows us to respond to opportunities that are arising in a recovering energy services market. In response to increasing demand for drilling rigs and compression rental equipment, our Board of Directors has approved $6.5 million increase to our 2021 capital budget, which now stands at $33.2 million. We intend to fund the remainder of our 2021 capital budget with cash on hand. Enhancing shareholder returns, including through debt repayment and share repurchases remains a corporate priority. As we look forward to better times for our business, I would like to take this opportunity to thank all of our employees for their perseverance and dedication over the past 18 months. Together, we worked to get through a severe industry downturn and a global health pandemic and came out a stronger and more innovative organization. I would now like to open up the phone lines for any questions.

[Operator Instructions] Our first question comes from Cole Pereira of Stifel.

Maybe to start. So obviously, good rebound in earnings. The balance sheet is in pretty good shape. And so you're getting more active with the buyback, but how are you thinking about other capital allocation priorities, namely M&A and resuming the dividend?

The same way we've always thought about allocation of capital, we'll deploy capital to the highest risk-adjusted opportunities.

I guess, maybe phrased in a different way. Do you see just the returns from debt and share buybacks just being much higher than M&A and dividend at this point?

Certainly, our share buyback is an extremely compelling investment in this market. There's 0 integration risk and you've got a fairly good idea of what your earnings capacity is go-forward, so that certainly ranks high. Debt repayment, again, we continue to be methodical in bringing down the total debt. On a net debt basis, so net of working capital, we're now at the point where it's certainly going to invite other thoughts and discussions, but those will be at a Board level. On the M&A front, we see a lot of different opportunities, but we rank those against share buybacks, and it's difficult to make a lot of those work.

Okay. Perfect. That's helpful. So contract drilling looked pretty strong overall, but the U.S. business, in particular, had a lot of market share capture. Can you just talk about some of the drivers behind that and what you see as the near-term outlook for that business?

Well, first of all, our U.S. drilling group has done a wonderful job in capturing market share through providing quality equipment in a safe and efficient manner. I think what we're seeing in the U.S., and I expect we'll see it up in Canada is a move towards lighter, more efficient rigs as opposed to bringing the biggest rig possible to the well site. And I think there's a number of drivers for that, but not the least of which is operational and move efficiencies. And so we're -- we have 3 triples in the U.S., and those are all working, but definitely, our quality fleet of doubles and singles is enjoying some strong utilization.

Okay. Great. That's helpful. And so one of your compression peers cautioned on margins over the next few quarters due to pricing pressure and supply chain issues. I mean, do you see some of those same margin risks for Total's Compression business?

Well, certainly, we're in an inflationary environment. We're seeing that in all divisions. One of the benefits that our CPS segment had coming into this rebound is a significant inventory of major components. And so both from a cost inflation and a procurement risk physical supply risk perspective, we feel quite comfortable in where we stand in the marketplace.

Our next question comes from Tim Monachello of ATB Capital Markets.

Cole sort of answer -- or asked a couple of my questions. But I guess just when you look across your platform as diversified as it is and with a view to -- probably a pretty tight market in Canada in Q1 and maybe a tightening market in the U.S. through the next few quarters, which business lines do you see the most optimism in? And where do you think there might be challenges in terms of capacity of the industry to meet demand?

I'm optimistic on all 4 divisions for various reasons. And I think we're certainly going to see, particularly, in Canada in Q1, what the true capacity of our industry is, both from an equipment and personnel perspective. And I'm not sure -- time will tell, but I'm not sure the market fully appreciates the limited supply capability on the service side. And as we ramp up in Q1, we'll find out together what that means. But the capacity that exists today is not even close to what it was 5 years ago. And I would say that's across the board.

Okay. That's helpful for sure...

And I just don't see an environment where you're going to see capital come in and trying to increase that capacity.

What are you seeing from a labor standpoint, any challenges there?

Labor is tight. Again, I think more on the field services front, but we always find a way to get the job done. So I'm pleased with our various divisions and their efforts to procure labor. And at the end of the day, we tried to carry as many through a tough time as we could, have to make some tough calls, but feel quite comfortable with how we position ourselves coming into this recovery and the fact that we're able to invest capital to ensure that our employees and our customers have the best equipment that's fit for duty and ready to go to work, and that's part of it, providing your employees with the proper equipment and good safe operations. So we'll find a way, but I think it's definitely going to be a little more -- well, certainly more challenging than a year ago.

Okay. In particular, on the rentals business side, I think there's a comment in the MD&A that just said that price increases haven't kept up with cost inflation. In the tightening market, do you see pricing starting to overcome cost inflation in the coming quarters?

Well, we're certainly hoping so. The directive to all of our divisions is to -- we're not going to hopefully see margins contract in an $80 oil environment.

Yes, I would hope not.

No, we're in a bit of an adjustment period here weaning ourselves -- the industry weaning itself off of COVID assistance. Again, you still have a pretty modest rig -- North American rig count and an Australian rig count, for that matter. And we're finding equilibrium. But my sense, generally speaking to producers, they understand that the service sector pricing is not sustainable. And most reasonable customers are willing to work with you to come up with something that's fair that works for both sides.

With oil prices in the mid-80s, we're starting to see activity outside the Permian accelerate. Is that helping to tighten some of those business lines like U.S. rentals?

Certainly, yes. The rig count drives all 4 divisions. Ultimately, it's a good leading indicator. So a recovery across the board in all basins in the U.S. is positive for all of our divisions.

Okay. And then last one for me. I was just wondering if you could talk to the progression in some of the, I guess, energy transition or nontraditional end market business lines and opportunities that you're seeing?

So we're at the front of that. The reality is it's not a big component today, but we're in line and if and when those opportunities become significant, we'll get our fair share. We take a pragmatic approach to those opportunities. At the end of the day, it's really not complex, a lot of the engineering and design are off-the-shelf technologies. The reality is capital has to flow in a significant way into those opportunities. And when it does, we'll be ready to get our fair share.

Is the U.S. rental fleet as you build that out in terms of compression, are you looking at electric at all? That...

Very much so. We've been doing electric for 20 years.

Okay. [indiscernible]. Appreciate the details.

Electric's been doing magic -- we've been doing electric drive compression for 20-plus years.

Okay. Yes, I just wanted to -- there's some details from the few of the U.S. competitors around it. So I was just curious what your stance was, and that's helpful.

Yes. No, we're -- at the end of the day, a lot of it depends on your sources and availability of electricity. A good example is one of our heavy AC doubles its drilling actually fairly close to the city of Calgary, and we tried to put it on high-line power, but there was insufficient power in the grid to power the rig. So that goes to the reality of trying to transition too quickly. The grid is simply not capable of providing enough electricity to power a double drilling rig. So we generate the electricity through diesel power generators. But if we could, we could plug it into high line.

Our next question comes from Josef Schachter of Schachter Energy.

Congratulations on the nicely improved quarter. Three questions for me. The first one is on the service business. Are you seeing a pickup in the abandonment programs where people that are taking advantage of the program that expires in '22? Or is the focus more on getting volumes up, so they're looking at more recompletions. And maybe any idea you have of -- do you think in 2022, will that be busier while the funds are still available?

So Josef, we've seen a pretty significant increase in abandonment work over the past year. The reality is the government of programs were announced probably close to 2 years ago. And for the first 9 months, nothing happened. And just as oil prices were recovering, funds started flowing. So I would say what you're seeing is a competition now between abandonment and production work, such that we probably skewed more towards the production side than the abandonment, but there's good strong demand. And frankly, we have more work than service rigs -- crude service rigs right now. So that's a challenge.

Okay. Does that help away in margins and pricing going forward?

It better...

Is it better?

Yes, it better help.

Yes. But [indiscernible] competitors -- are competitors not as tight as you and, therefore, there the pricing is still a problem?

I think it depends on the area and the specific competitive landscape. But at the end of the day, when you have more demand than supply over the medium term, that will drive pricing.

Second question for me is debt is -- net debt's now at $64 million, down from $100 million in December. Is there a target in your mind to get that down to 0 before you start looking at alternatives? Do you have a number in mind for net debt?

So we looked at our debt kind of there's 2 components. One's our mortgage debt, which to us would be -- to myself personally, would be kind of permanent debt. And then there's the line, the revolving credit facilities, which, on a gross basis, was $135 million and on a net basis, was about $110 million or so. So we're quite comfortable keeping the mortgage debt as permanent debt. We rolled a $50 million mortgage. We picked up a $17 million mortgage when we bought Savannah. To us, that's kind of permanent. It will keep ruling. We're focused on the revolving side. As that comes down, we'll likely contract our facility. We don't pay for things we don't need. And certainly, as we -- when you have no debt left to pay, you look at other options. But I won't steal the Board's thunder. Certainly, I'm personally a fan of a dividend. I know our Board is. And at some point when it's the right time, I would expect that we will revisit that.

Okay. Super. Last one for me. This is kind of a crazy one. The COP26, we heard that they're going to be cutting off funding and countries have signed up for international energy investments, with your Australian operations, does that affect the financial capability of your clients? And is that something that you guys are concerned about in terms of working in the international environment?

Well, I think last I checked, Asian LNG prices were north of $30 an Mcf. So the financial capacity of our customers there, which are all major LNG participants is from why it can tell fairly solid. We'll see how this plays out. The reality is we're going into winter in the Northern Hemisphere, and you're seeing some energy crisis playing out. At the end of the day, food, clothing and shelter fundamentals and shelter includes a warm shelter. I'm reasonably bullish on natural gas. I think in the medium to long term, it has a very bright future, particularly as we realize the limitations of the current accelerated attempt to displace it. And physics and economics ultimately prevail. And I'm quite comfortable playing in the natural gas space, which is primarily the market for us in Australia. And at the end of the day, I think there's no doubt that capital will be restrained, but that just further reinforces my views on supply and demand, both within the production side and the service side, which is part of the reason why we're quite focused on paying down debt. And like we have been for 25 years, we've not really ever been dependent on equity markets to fund our business. It's been cash full.

Good. That does it for me. And again, congratulations on a nicely improved quarter.

Our next question comes from John Gibson of BMO Capital Markets.

Again, congrats on the strong quarter. I just have 2. The first one kind of leads on what Cole was asking, maybe asked in a different way. So just wondering if you could speak to margins that are currently churning through your system, which I'm guessing were kind of signed early in the pandemic versus maybe new orders signed today and how they may differ? And maybe just keeping the fact that you have a fairly large inventory out of the equation.

So one thing that hit our margins in the CPS segment in Q3 was we took an $800,000 provision. So if you back that out, basically, our margins were fairly flat year-over-year despite reduced COVID funds. And so what we're seeing and certainly your observation on order -- timing of the order versus completion is correct. We are moving into an inflationary environment. And certainly, I know all divisions, including CPS, are cognizant of that. And as you're pricing new bids, you're certainly factoring that in. So I would say, generally, I have a high degree of confidence in our CPS management to price appropriately. And obviously, it's a competitive marketplace. But at the end of the day, it's a commodity. And low cost gets the best margins. So as much as you focus on price, we also focus very much on manufacturing efficiencies, overhead efficiencies and the like. I think one of the other things that hopefully will play out to our advantage here in all of our divisions is this is part of our kind of restructuring during the last 2 years, we really made an effort to displace leased facilities with owned, and we're almost -- done that for the most part as leases came off. And for example, in our CPS segment, we had the opportunity to vacate lease premises and relocate into owned as we were converting, say, RTS branches into CPS branches likewise or putting 2 groups in 1 building. So we're being fairly innovative in and trying to keep our costs under control and both through cost management and price strategy continue to maintain and ultimately grow margins. I don't know if that answers your question, John.

No, it does. I appreciate the answer. The second one for me, and you've obviously benefited from various COVID-relief programs, as is everybody. I'm just wondering if you could maybe put some specific globals around what you expect to receive in 2022?

At this point, 0.

Okay. Great. Again, congrats on the quarter.

Our next question comes from John Bereznicki of Canaccord Genuity.

I just want to focus on CPS for a second. Obviously, the backlog growth pretty meaningful in Q3. Broad brush, can you give us a sense of kind of where that came from, either geographically or product wise?

Hesitant to do that for competitive reasons, but we sell to the world, John.

Okay. Okay. Fair enough. I won't push on that one any further. But looking at the numbers, it still looks like U.S. has, obviously, skewed more rentals Canadian market to sales. Any signs that, that's changing given capital allocation with your customers? Or is that kind of a trend you're factoring on here as you move forward?

Sorry, I didn't quite get your U.S. rentals skewed...

Just within CPS, looking through the numbers. It looks like rentals are a bigger component in the U.S. versus sales in Canada.

Yes. I think generally, part of it is just a much, much, much larger market. Certainly, there's, I think, culturally and economically different reasons to rent versus own. But we're seeing good demand for the rental, steady redeployment. We had, it was Q4 last year, a bankruptcy of a U.S. customer that resulted in a fairly significant return of equipment. We're steadily putting that back to work. And our expectation is going into Q1, we should see a reasonable pickup in compression both sides of the border as in particular, Canada where customers are wanting to put on winter drilled wells on to production before breakup. So seasonally, Q1 is usually a fairly good time for rental demand, so.

Okay. That's helpful. And then just...

[indiscernible] question, but...

Yes, that's helpful. Sorry, go on.

I was just going to say it's throwing darts at a dart board though. For us, we don't -- demand for rentals could be very unique, and it sort of comes when it comes. And Again, we're not into the -- I think some of our competitors are in the boom market. Ours are dry rentals.

Right, right. No, I appreciate it. That's helpful. Just looking at Australia, it looks like you were able to put the 2 upgrade rigs to work in the third quarter, sequential uptick in activity. Things looked a little flatter on the Well Servicing side. Just wondering if that trend has continued through the fourth quarter, kind of what you're seeing in that market right now?

I think, generally, Australia lagged North America by a year, 9 months to a year. So we saw the rig count come off. We had some company-specific issues as you just noted, taking 2 out of the 5 rigs out of service. We're currently operating 4 out of 5. And the fifth is out of service for upgrade and reset and it will be back at service in Q1. Certainly, on the Well Servicing side, similar to the overall rig count in Australia, we saw a bit of a pullback in part, though, due to weather. They've had quite a wet spring going into summer. But overall, I think just like North America, producers are cautious, but the flip side is they're enjoying a fairly significant increase in commodity prices there. So we'll see how it plays out. But we feel reasonably comfortable with our market position, both in drilling and Well Servicing there.

[Operator Instructions] Our next question comes from [ Akshay Phil ], a Private Investor.

I had a question on the Rentals and Transportation Services. We noticed that the revenue went up substantially compared to the same time last month -- last year. However, I noticed among all the segments, this one has the lowest utilization even though that it's doubled compared to the same time last year. What in your opinion is a good utilization rate? And is there any plans to rightsize the assets further to get to that number?

Good question. I think historically, full utilization in that division would be 60% to 65%. Just the nature of the assets you constantly have the assets moving back and forth, jobs being cleaned, repaired, so 60% to 65% utilization would be peak utilization. So it's not the same as a drilling rig that sits on a well just constant. A lot of this stuff is used to contain solids, liquids has to be cleaned, repaired. So you're never going to see the utilization in our other -- in that line of equipment, as you will, in other divisions. So certainly, last year, with the collapse in the North American rig count, you had extremely low utilizations. Historically, we needed 20% to 25% utilization to generate pretax income through our restructuring and, basically, we shrank our footprint in Canada fairly substantially. We've lowered that utilization threshold to achieve profitability significantly such that Q3, we came quite close to pretax profitability again at a pretty low utilization. And that's just simply the leverage we have to activity. You have a high fixed cost structure in that business relative to your other ones. And once you kind of get over your fixed costs, you get pretty significant drop down to the bottom line. So we ran, just looking at the number here for 11% -- pardon me, 10% -- 13% overall North American utilization, and we're pretty close to pretax profitability, whereas that number historically have to be kind of 20%, 25%. So we're excited to see what happens as we hopefully get busier there.

Okay. Also, I think you briefly touched based on this, but can you talk a little bit about opportunities at OPSCO and how you see that business line going in the future?

So OPSCO has been around a long time since the 60s. They've been involved in conventional oil and gas as well as some fairly interesting emerging opportunities. OPSCO was originally involved in the construction of the original carbon trunk line in Alberta, the first CO2 capture, a major project in Alberta, quite a few years ago. So I think our prospects there are both your conventional oil and gas infrastructure but also emerging opportunities, whether it's carbon capture, hydrogen, biogas or what have you. At the end of the day, gas is gas. The chemistry is a little different for each type of gas, but we build things to handle gas of whatever nature. So OPSCO and Bidell certainly give us good exposure to any significant infrastructure investment globally in some of these alternative energy opportunities.

This concludes the question-and-answer session. I would like to turn the conference back over to Mr. Halyk for any closing remarks.

Thank you all for participating in our conference call and look forward to speaking with you after we release our year-end results. Have a good day.

This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.