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Thank you for standing by. This is the conference operator. Welcome to the Total Energy Services Third Quarter Results Conference Call. [Operator Instructions] And the conference is being recorded. [Operator Instructions] I would now like to turn the conference over to Daniel Halyk, President and CEO. Please go ahead, sir.
Thank you, and good morning. Welcome to Total Energy Services Third Quarter 2020 Conference Call. Present with me is Yuliya Gorbach, Total's VP of Finance and CFO. We will review with you Total's financial and operating highlights for the 3 and 9 months ended September 30, 2020, 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's businesses and the oil and gas service 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 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, 2020, reflect continued difficult industry conditions in North America and the moderation of activity levels in Australia. Efforts over the past several quarters to rightsize our capacity, particularly within our Rentals and Transportation Services segment, combined with the most seasonal -- modest seasonal uptick in Canadian activity levels contributed to improved financial results as compared to the second quarter of 2020. Total Energy's geographical and business diversification has been of a significant benefit during these challenging times. Geographically, revenue generated in Australia during the third quarter of 2020, represented 32% of consolidated revenue, a 12-percentage-point increase relative to Q3 2019. North America represented 68% of consolidated 2020 third quarter revenue as compared to 76% for Q3 2019. By business segment, Compression and Process Services remains the largest contributor to Total's consolidated revenues, generating 42% of 2020 third quarter consolidated revenues, followed by the Well Servicing at 30%, Contract Drilling Services at 21%; and Rentals and Transportation Services contributing 8%. This compares to Q3 2019 when CPS contributed 42% of consolidated revenue. Contract Drilling, 28%, Well Servicing 21%; and RTS segment, 9%. Immediate and decisive actions undertaken at the onset of COVID-19 outbreak to ensure the safe and continued operation of our businesses and protect our financial strength and liquidity have enhanced Total Energy's ability to generate significant free cash flow despite extremely difficult industry conditions. While third quarter revenue declined 55% on a year-over-year basis, consolidated EBITDA only declined by 28% before adjusting for $0.6 million unrealized foreign exchange loss on intercompany working capital balances and a $0.3 million increase to our provision for bad debt. The receipt of $7.4 million of funds and the various COVID-19 relief programs during the third quarter reduced cost of services by $6.4 million and SG&A by $1 million. Consolidated gross margin percentage for the third quarter of 2020 was 30% as compared to 22% during the same quarter of 2019. Excluding funds received from various COVID-19 relief program, gross margin percentage was 20% as compared to 22% in the third quarter of 2019. This decrease was due to lower activity levels and competitive pricing, particularly in North America, as well as year-over-year change in our segmental revenue mix. Selling, general and administration expenses for the third quarter of 2020 decreased by $6.9 million or 55% as compared to Q3 of 2019. Excluding COVID-19 relief funds, third quarter SG&A declined by 47% on a year-over-year basis. Within our CDS segment, third quarter spud to release drilling days decreased by 67% on a year-over-year basis, while revenues decreased by 66% and segment EBITDA declined by 59%. Despite a substantial year-over-year drop in the segment's revenue and EBITDA, the CDS segment's EBITDA margin increased by 22% or 340 basis points. The smaller proportionate decrease in revenue compared to a decrease of spud to release operating days and increase in EBITDA margin was primarily due to increased relative revenue contribution from Australia, combined with North American cost control measured -- measures and receipt of COVID-19 relief funds. During the third quarter of 2020, 2 drilling rigs in Australia were removed from service in order to complete necessary certifications and upgrades that are currently expected to be completed by the second quarter of 2021. Despite a continued decrease in the active U.S. land rig count over the course of third quarter of 2020, utilization in our U.S. drilling operations increased by 267% or 8 percentage points from 3% in Q2 2020 to 11% in Q3 2020. Canadian activity in Drilling segment experienced a more seasonal increase for the second -- from the second quarter. For the first 9 months of 2020, the CDS segment's EBITDA margin increased 50% as a result of completion of various North American equipment rationalization projects during 2019. Increased relative contribution from Australia, ongoing cost control measures in all jurisdictions and the receipt of COVID-19 relief funds. Effective April 1, 2020, the CDS segment revised its depreciation estimate for drilling equipment to reflect changing economic and industry conditions. As a result, additional incremental depreciation expense of $4.2 million was recorded during the third quarter. This prospective change in depreciation estimate has no impact on EBITDA or cash flow. The RTS segment experienced a 50% decrease in rental utilization and 23% reduction in revenue per utilized fees as compared to the third quarter of 2019. The decrease in revenue per utilized fees was primarily a result of mix of equipment operating as well as competitive pricing. While this resulted in a 62% year-over-year decline in revenue, third quarter segment EBITDA increased by 34% and the EBITDA margin increased by 250% as compared to 2019. Excluding COVID -- the receipt of COVID-19 relief funds, the RTS segment saw its third quarter EBITDA decline at half the rate at which revenue declined relative to 2019, and the quarterly operating loss in this segment decreased by 70% on a year-over-year basis as a result of significant rationalization actions taken over the past 2 years. While our Compression and Process Services segment continued to experience reduced demand for new product orders, its fabrication sales backlog remained relatively stable. At September 30, 2020, this segment has $37 million sales backlog compared to $43.8 million backlog at June 30, 2020, and $39.8 million at September 30, 2019. Higher North American natural gas prices in the third quarter of 2020 provided support for the CPS' parts and service and retrofit business lines. Despite a 55% year-over-year decline in CPS' third quarter revenue, the segment's EBITDA for the quarter declined only by 33%. The lower rate of EBITDA decline was primarily due to a lower proportion of revenues being derived from lower-margin fabrication sales, effective cost management and the receipt of CEWS.Third quarter service sales and revenue in our Well Servicing segment were 38% and 36% lower, respectively, while segment EBITDA decreased by 12% as compared to the same period of 2019. Despite lower activity levels in all jurisdictions, the third quarter EBITDA margin in this segment increased by 9 percentage points to 33% as compared to 24% EBITDA margin in Q3 of 2019. This was the result of cost management efforts and the receipt of COVID-19 relief funds. While our Canadian Well Servicing segment began to receive some federal government-funded Well Abandonment Work towards the end of the third quarter, such activity was not significant. During the third quarter of 2020, Total Energy generated $19.8 million of cash flow and $14.4 million of cash from operating activities as compared to $24 million of cash flow and $21.8 million of cash used in operating activities in the third quarter of 2019. Contributing to the increase in cash generated from operating activities was the monetization of $4.2 million of inventory during the third quarter of 2020 as well as lower working capital requirements compared to 2019. Total Energy's financial position continued to strengthen during the third quarter of 2020 and our liquidity position remains strong. At September 30, 2020, the weighted average interest rate on outstanding bank debt was 2.85% as compared to 3.92% at September 30, 2019. This lower interest rate combined with lower outstanding debt balances contributed to $1 million or 34% year-over-year decrease in quarterly interest costs. On November 10, 2020, at our request, Total Energy's primary revolving credit facility was reduced by $40 million to $250 million and the maturity date extended to November 10, 2023. Subsequent to September 30, 2020, an additional $5 million of debt was repaid, such that the current amount drawn on this facility is $175 million. The remaining $75 million of undrawn facility is currently fully available as is an additional $5 million on an undrawn rolling credit facility maintained by a subsidiary of Total. Total Energy's bank covenants consist of a maximum senior debt-to-trailing 12 months bring debt-to-EBITDA of 3x and a minimum bank defined EBITDA to interest expense of 3x. At September 30, the company's senior bank debt to bank-defined EBITDA ratio was 1.96x and the bank interest coverage ratio was 9.82x.
Thank you, Yuliya. We are generally pleased with our performance during the third quarter as all of our businesses continue to navigate through a very challenging business environment where North American industry activity levels remained at historic lows and Australian activity began to moderate. The impact of the COVID-19 virus on our operations was effectively contained and our ongoing efforts to rightsize our business and manage costs gave rise to significant efficiencies as evidenced by Total's ability to continue to generate substantial free cash flow despite a significant year-over-year decrease in revenue. Total Energy's financial position continues to strengthen. After funding $800,000 of net capital expenditures and incurring $2.1 million of interest expense during the third quarter, Total generated $16.9 million of free cash flow before changes in noncash working capital items. Excluding $7.4 million of COVID-19 relief payments received in the quarter, we were still able to generate $9.5 million of free cash flow during the quarter despite operating at extremely low levels in North America. For the 9 months ended September 30, 2020, with the monetization of $11.4 million of work capital and after deducting net capital expenditures, interest expense and dividend payments, Total Energy has generated $46.5 million of free cash flow. We directed $40.5 million of this cash flow towards the repayment of bank debt and lease liabilities, and our cash position has increased by 25% since the beginning of the year to the end of September. We continue to steadily pay down debt and our $111.7 million of net debt at September 30 is the lowest amount since we completed the acquisition of Savanna Energy Services in June of 2017. While industry conditions remain difficult and visibility is poor, there are some encouraging signs. North American natural gas prices have improved over the past year and global oil markets appear to be slowly rebalancing. The competitive landscape in the North American energy service industry also continues to slowly, but steadily improve as older equipment is decommissioned and financially weaker players are forced to liquidate or consolidate. Within our Contract Drilling Services segment, we currently have 10 rigs operating in Canada, 5 in the United States and 2 in Australia. While the outlook is uncertain, we currently expect our Canadian rig count to continue to increase as we go into the seasonally more active winter drilling season, although the absolute rig count will remain weak by historical measures. As Yuliya mentioned earlier, 2 of our 5 Australian drilling rigs were removed from service in Q3 for a recertification and upgrade. One of these rigs has been contracted and is expected to commence operations by the second quarter of 2021 when the recertifications and upgrades are completed. Higher North American natural gas prices have driven steady quoting activity within our CPS segment, while customers continue to remain cautious in ordering new equipment. Based on Q4 activity to date, we are cautiously optimistic that new product sales will increase in the near to medium-term should gas prices remain stable, which in turn would accelerate the monetization of our significant investment in inventory. While previously announced funding of Well Abandonment Work in Canada has been slow to materialize, we are encouraged to see such activity beginning to pick up and expect such activity will increase as we enter 2021. This has and will provide opportunities for our well servicing and RTS segments. Despite some emerging green shoots, we remain in a challenging and uncertain business environment. As such, our focus remains on the safe and efficient operation of our business and the repayment of debt. We will also look to be opportunistic, including in the use of our recently renewed normal course issuer bid. I would now like to open up the phone lines for any questions.
[Operator Instructions] The first question is from John Bereznicki of Canaccord.
Just starting with Australia. Just wondering if you're view in Q3 is sort of a temporary pause or maybe start of it a longer-term downtrend. And then maybe second part to that is, maybe talk a bit about what you're seeing on well servicing versus drilling in that market.
I think all jurisdictions around the world that we operate in and don't operating in are feeling the impact of COVID. And I think you're seeing in Australia what we've seen elsewhere, which is cautious capital spending. The difference in Australia, there's a fairly sizable demand for natural gas to feed LNG, and that's not going to disappear as well. Domestic gas prices relative to North America remain stronger. And so it's just, overall, I would say, a more balanced and healthy environment. That said, the industry is being cautious. I would describe our current activity levels as relatively good compared to overall industry levels. It's tough to know exactly what's going on. You don't have the same transparency in terms of industry utilization. But some of our intelligence suggests that we've generally weathered the storm a bit better than the industry average. But we're hunkered down like everyone else and working with our customers to continue to do a good job as efficiently as possible. What I'll say is we expect to continue to have a good market presence there. And I mentioned we've contracted one of the rigs that is up for recertification upgrade. And I'm not going to get into a lot of detail there other than to say it's a longer-term contract, and it's with a new customer. So that's a positive. So all in all, Australia remains a good market for us, a market that we intend to increase, not decrease, our presence in over the medium to long term.
Great color. I appreciate that, Dan. And then maybe just looking at CPS. Obviously, with North American natural gas showing some green shoots, as you call it. I know you don't provide backlog granularity. But have you seen a bit of a shift in that backlog more towards North America versus the international market?
I'll say generally that we're encouraged by core activity post September 30. And again, we've never given forecasts at the best of times. But if we see stability in gas markets in North America, we expect that, that will translate into better sales here going forward.
Okay. Fair enough. And on the inventory front, obviously, it looks like it's trending down slowly here. Still safe to presume the balance of, I think, $102 million, primarily compression fabrication components?
Yes, correct. The vast majority.
Got it. And then -- okay. And then just one housekeeping question, and I'll get back in the queue here. But just with the various COVID benefits you received in Q3. Give us any color what that might look like in the fourth quarter based on what you know today.
Hard to tell. It's based on hours worked in various jurisdictions. So I'm pretty hesitant to give any numbers on that. I think if one looks at rig counts, that will give you a bit of a barometer of the overall industry activity level, and you can extrapolate as you see fit.
Okay. Sounds good.
Yes, I'm hesitant. We book all our COVID payments on receipt. We don't accrue anything there. So we don't book anything unless until the cash is in the bank.
Too many [ rules ].
Because we don't -- we can't forecast either.
[Operator Instructions] The next question is from Patrick Tang from ATB Capital Markets.
I was just wondering if the demand that you're seeing in North American drilling, like from where you stand, could you see upside to the rigs that you have working today with the 10 in Canada and 5 in the U.S.? Or are we expecting more of a flat environment through to the year-end? Is there any talk of accelerating Q1 '21 programs in Q4 at all?
As I mentioned, Patrick, we expect our Canadian rig count will increase from where we stand today at 10% going into Q1, and that's your normal seasonal uptick. That said, given the macro environment, we expect absolute drilling levels in Canada to remain significantly below kind of historical norms. We're encouraged with our U.S. activity. Today, we have 5 rigs going, all in Texas. That's not a bad market share. For a smaller firm. We're currently marketing 11 rigs in the U.S., all in West Texas. And all of our rigs today that are working are singles and doubles, which is we find interesting.
Pretty encouraging on that. So I'm not sure if you can comment on this, but I mean if you're evaluate [indiscernible] are you being mom-and-pops more willing to sell their businesses in recent times? Or is there still a large valuation gap that prevents you from going down that route at this time?
There's lots of opportunities to buy businesses, equipments, both on a distressed and going concern basis. Bluntly, the largest challenge we have right now is we're staring at our own valuation, and that's the benchmark, and it's pretty tough to beat that right now.
Okay. As a follow-up to that, are you guys participating in the Paycheck Protection Program? And if you are, when do you expect that you'll be able to resume share repurchases without putting your loan forgiveness in peril?
So we have participated 2 quarters ago, Yuliya?
In April.
In April. We are going to apply as soon as we're able to, to seek forgiveness. We were pretty conservative in the use of that program. And so certainly, we don't want to jeopardize anything. But at the end of the day, we're going to -- at some point, you can be penny-wise and pound-foolish. And so depending on the situation, that may or may not be a factor in terms of our use of the normal course issuer bid. And I'm not going to comment on timing or any targets or anything like that in terms of when we might start buying or anything. But we like to buy when everyone else is selling. I'll just leave it at that. The same [indiscernible] our investments as well.
This concludes the question and answer session. I'd like to turn the conference back over to Daniel Halyk. Pardon me, there is 1 more question now from Josef Schachter from Schachter Energy Research.
Congratulations on a good quarter in a difficult environment. With all the consolidation that we're seeing in the industry, are you seeing -- are you working with the larger companies or the acquirers or the companies that have been acquired? And how do you see your mix of business moving with that whole consolidation trend that's starting to happen in the E&P sector?
It's a good question. We certainly work for all of the major companies in North America and certainly, Australia. Australia is a very consolidated market to begin with. Within the Canadian marketplace, we've got a good mix on our drilling rigs. This is public information. We're currently working for everyone from Imperial oil to private companies and public, I'd call it, midsized producers. So good mix there. Within our Compression and Process Services group, we work for pretty much all the majors, major pipeline infrastructure companies, all of that. We see in our Rental and Transportation business, increasing contribution from larger players. I think it's a function of both the consolidation within the industry, but also the consolidation on the supply side. There's just, frankly, less competition that's able to deliver to the standards that are -- these larger companies demand and one of the measurements that you may be familiar with is your TRIF. And our TRIF within -- our consolidated TRIF and TRIF within each of our businesses, including our RTS segment, which is a very difficult business to manage, given the nature of the operations. We have a TRIF south of 2 in our RTS segment, which is a huge factor for gaining work with large, large players. And so I'm encouraged with the trends I'm seeing there. I think you're going to continue to see consolidation on the supply chain. And you're going to continue to see it on the producer side and producers don't want to hire problems and they're going to gravitate towards financially secure, well-run businesses that don't cause some problems and get the job done efficiently and safely. So I'm quite confident in how all of our business divisions will perform in that environment.
Super. Second one for me is, if the vaccine does come in Q2, Q3. And in the second half of 2021, we have $50, $60 WTI. Do you have manpower so that you can ramp up if -- as the customers want more equipment? Or is there -- is manpower going to be a problem to ramp up? And so it will be -- pricing will come through, which will be nice to the bottom line, but use of equipment may not happen because of the lack of qualified employees.
I think the industry as a whole is going to face a manpower challenge, particularly in Canada, given the -- this is year 6, arguably of the downturn. I think company-specific, it's going to depend on your ability to mobilize equipment. I look, for example, at the contract drilling industry in Canada, the top 3 players, which includes us, represent 60 -- 2/3 of the activity. You have a number of smaller players that haven't operated for going on a year. The other factor that's going to drive ability to mobilize is the condition of your equipment base. And again, we've tried to take a balanced approach to deployment of assets. The flip side is we haven't been cannibalizing our fleet. And when we have a market fleet, it's a marketed fleet that can go to work tomorrow with minimal capital investment. And we've seen it over the past 1.5 years or so where we pulled rigs literally that have sat for 5 years and put them to work with nominal capital. But if you're cannibalizing your fleet, pulling pumps or top drives or engines off to keep another rig going, you're looking at millions of dollars per rig to get those rigs going again. And if you're a financially stretched company, that's going to be a huge barrier. So I think the strong financial companies that are in the game today will take a disproportionate amount of the work going forward as we come out of this.
Last one for me. You're seeing companies talk more about wanting dual fuel or electricity, electric-powered equipment and going out forward for their E, as in ESG, goals. How much of your fleet is dual-powered at this point? And how much does it cost to change of equipment over so that you can meet that requirement if customers are willing to contract with you at decent rates?
Any one of our rigs can operate on bi-fuel. We've operated, and we currently have a number that are operating. It's an off-the-shelf package that you stick on. And I'm not going to get into capital costs because we like to keep that stuff a little tight, but we've done that, and we'll continue to do that on all of our rigs. We do have the largest fleet of AC telescopic doubles in Canada and those are a fairly highly desirable rig right now. We also supply a lot of electric power generation in our Rental and Transportation group, which, again, to the extent things are electrified, that's extra work for those units. But we do -- we can run any of our drilling rigs off natural gas.
Congratulations on the good quarter in these tough times.
This concludes the question-and-answer session. I'd like to turn the conference back over to Daniel Halyk for any closing comments.
Thanks all for participating in our conference call. I hope you stay safe and well and look forward to speaking with you at our year-end conference call next year. Thank you, and have a good weekend.
This concludes today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.