|Shares Out. (in M):||46||P/E||14.7||11.6|
|Market Cap (in $M):||451||P/FCF||5.3||4.9|
|Net Debt (in $M):||278||EBIT||57||66|
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Total Energy Services Inc. (“Total,” “TOT,” or the “Company”) is a Canadian oilfield services company offering contract drilling, equipment rental, compression and process services, and well servicing.
For anyone still reading, TOT stock at its current price offers extremely attractive risk/reward with a potential for significant long-term compounding and a 2.4% dividend yield. The Company currently trades at less than 8x my base case operating profit and less than 4x my high case operating profit. While this isn’t a complex situation, I believe the opportunity exists because the Company’s headline performance numbers don’t tell the actual story while the abysmal state of Canadian oil and gas and TOT’s illiquidity provide two good reasons for investors not to spend time digging in further.
(i) 80% of Total’s $35 million of trailing-twelve-month operating profits are from outside Canada
(ii) Performance varies widely by regional sub-segment. Total will add $18 million of operating profits by simply “cleaning up” the loss-earning sub-segments resulting from the difficult Canadian environment and the distressed acquisition of Savanna Energy that Total made in 2017.
(iii) Total’s Compression and Process Services business is growing quickly and has a large addressable market. I estimate that this segment will grow operating profit by ~$10 million each year.
(iv) Total has an excellent, return-on-capital-minded management team that has compounded shareholder capital over the last twenty-one years and should continue to create significant value
(v) The Company has had good results cold stacking its equipment and reactivating with minimal cost. If Canada solves its energy distribution infrastructure issues, I model an additional $59 million of operating profit. This is not included in my base case estimate.
II. Company Overview
There are three key elements to an investment in Total: (i) a collection of eight cyclical oilfield services businesses comprising contract drilling, oilfield rentals, and well servicing across Canada, the U.S., and Australia; (ii) a gas compression and process equipment division that has cyclical exposure but also has a massive secular growth opportunity ahead of it; and (iii) a management team with an owner mindset that is skilled in allocating capital and focused on building up the balance sheet in strong industry environments in order to refuse unprofitable business and make transformational distressed acquisitions when the industry is weak.
Total’s Management, Strategy, and Incentives
I’ll start by discussing Total’s management and strategy because it provides the correct lens through which to evaluate the prospective performance of the consolidated Company and each of its businesses. The following table shows summary performance data from the last twenty years.
Given that the Company has managed three commodity-ish businesses in the cyclical and volatile oilfield services sector, I find Total Energy’s track record impressive. The Company has delivered a 20-year average ROE of 14% and unlevered return on capital of 12% while increasing book value per share 13x and providing a 28% IRR to those who purchased stock at the end of 1998.
Much more important, however, has been Total’s ability to reduce downside volatility. Two of its segments generated positive operating income every single year until 2016 (a historically bad year in Canadian oil and gas) and the Compression division has never had a negative operating income year. Similarly, consolidated operating profit has been positive every year other than 2016 and net income, after turning positive in 2000, was positive every year until 2016. Note that these are as-reported, unadjusted numbers (no addbacks). This is a company that refuses to lose money.
Total’s reduced downside volatility is an outgrowth of the company’s discipline and full-cycle outlook. On the capital allocation side, this means (i) steering capital to its highest and best use across divisions and only to opportunities that exceed its cost of capital and (ii) building up the balance sheet in strong markets in order to not only survive industry downturns, but use them to increase its earnings power through opportunistic acquisitions (note that in the chart above, in the years when revenue declines significantly and costs have clearly been reduced, average assets tend not to decline significantly, implying that Total does not sacrifice future earnings power in order to cut costs). Total’s two largest acquisitions took place in 2009 (DC Energy), a year when its revenue declined 30%, and 2017 (Savanna Energy) following two consecutive years of revenue declining 30%. Importantly, the Company doesn’t pay up for assets. Total’s $1.1 billion balance sheet, assembled over the course of over two dozen acquisitions, includes only $4 million of goodwill.
On the operational side, this means (i) only engaging in business that can deliver required returns (i.e. idling equipment rather than taking work that doesn’t cover cash costs plus depreciation plus a return exceeding the cost of capital), (ii) compensating many of its managers for bottom line performance (rather than revenue or other operational metrics), (iii) weighting compensation toward bonuses rather than salary in order to reduce costs during downturns without laying off high quality employees, and (iv) continually striving for cost efficiency.
Although management, led by CEO Dan Halyk, is clearly highly skilled both in operational efficiency and capital allocation, it is worth discussing incentives, which also play into the Company’s success. Half of senior executive bonuses are dependent on Total outperforming its cost of capital, with zero bonus awarded if the cost of capital is not earned, and the full bonus earned if return on capital exceeds cost of capital by 6% or more. 15% of bonus is based on growth in capital assets (i.e. management must compound capital by increasing the capital base and then earning an acceptable return on such capital. It’s not enough to just earn a return on a static amount of capital), 10% is earned based on continually improving safety performance and the final 25% is based on individual performance. I find this to be a highly respectable and shareholder-friendly compensation scheme for a company of any size, not to mention a company of Total’s size.
This is a management team that I’m very happy to coinvest with. And coinvest is the right term. Dan Halyk holds 1.37mm shares worth $13.5mm CAD or 15.5x his average compensation over the last three years. In the summer of 2014 Total’s stock price peaked at over $21 / share and the value of Halyk’s holdings exceeded $25 million. Since then as the stock has traded down to its current level of $9.80 (despite PP&E doubling), Halyk has personally spent over $1.7 million on 46 separate open market purchases at prices ranging from $9.00 to $15.00, including 22 purchases totaling nearly $800k in 2018 alone.
I expect Total’s management to continue to create an entity worth more than the sum of its parts by running the assets efficiently, making distressed acquisitions during downturns, and allocating capital capably among its business segments and dividend / repurchase opportunities.
Contract Drilling, Rentals, and Well Servicing
I’ll discuss Total’s Contract Drilling (“CDS”), Rental and Transportation (“RTS”) and Well Servicing (“WS”) businesses together as they are capacity utilization businesses that don’t have the sort of secular growth opportunity that the Compression and Process Services (“CPS” or “Bidell”) segment does. The following chart gives a big-picture overview.
As mentioned above, the mild profits in the CDS segment and mild losses in the RTS segment belie more significant losses (U.S. CDS and Canada RTS) that are offset by profitable regions. Total’s management is not in business to lose money and can be counted on to either make these businesses profitable or shut them down.
Contract Drilling Business
Total’s Contract Drilling Segment (“CDS”) is the result of the Company’s second opportunistic transformational acquisition, which occurred in 2017 when Total purchased Savanna Energy for 4.8x midcycle EBITDA (or ~$460mm for ~$1.8 billion gross asset value of operating assets, land, and buildings), and merged its fleet of 18 Canadian drill rigs into Savanna’s fleet of 68 Canadian rigs, 28 U.S. rigs, and 5 Australia rigs. Total is now the second largest drilling company in Canada behind Precision/Trinidad.
Contract drilling is fairly commoditized with the main differentiator being fleet composition as certain drilling projects require a specific rig type. Sales relationships, quality and reliability of service, and condition of assets are also factors and Total believes that its efficiency and reliability make it highly competitive on these axes. Total’s CDS fleet composition is shown below:
As one might expect from this management team, the CDS fleet is not full of bleeding edge super-spec rigs as Total does not optimize for utilization, day rates, revenue, or even profit dollars, but rather return on capital (where equipment purchase price is a factor). Total historically aligned its drilling operations toward the sub-3000 meter market in Western Canada, which it believed was underserved. Savanna’s original sin in the drilling market was over-investing in doubles which often couldn’t drill the long horizontals that many customers are looking for. However as one might also expect, Total focuses on finding pockets of opportunity for its rigs (e.g. with their lower day rates, shallower-spec rigs can be a cost-effective way to drill top holes before bringing in a heavier duty rig to drill a horizontal) and maximizing the value of its equipment. The Company stated on its Q218 call that it drilled a 6,700 meter well using a mechanical double with no top drive in a “materially shorter period” than the well was AFE’d for. There may be some sort of “gotcha” here (possibly narrower borehole) as it is unlikely this rig had a hook load that could support that much pipe weight, but the point is that these are capable and creative operators. To that point, they’ve also partnered with Pason Systems to collaborate on automation and optimization technologies.
To the extent Total cannot put its rigs to work at an appropriate return on capital, the Company is happy to idle them and give up low-return market share. The Company stated in early 2017 that it was able to restart its oldest and lightest double, which had been idle for well over a year, with nominal startup costs and zero downtime for repairs.
Canada Drilling Business
It is no secret that Canada’s current energy transportation bottlenecks are stifling prices for Canadian oil and therefore drilling activity (and more recently the government has instituted production limits). Total’s utilization for its Canadian drilling business was 21% in Q318 and the business is barely profitable. Although there are several potential pipeline solutions, I have no reason to underwrite any improvements here and Total’s Canadian fleet is too large achieve high utilization on “pockets of opportunity”. My base case contemplates Total continuing to refuse unprofitable business and idling as much equipment as necessary in order to avoid losses and preserve upside for if/when these infrastructure issues are solved. Although I believe Total wants to retain at least some exposure to a potential recovery in Canada, management has stated its willingness to move equipment anywhere in the world that it can work for an acceptable return.
U.S. Drilling Business
If Total’s Canada drilling fleet is a large fish in a weak pond, the U.S. fleet is a tiny fish in a stronger pond. With ~1,030 rigs working, the U.S. employs over 4.5x the entire working Canadian fleet, with 470 of these rigs in the Permian alone. If this picture sounds rosy, keep in mind that there are over 1,600 idle rigs in the U.S. keeping overall utilization below 40% with the super-spec rigs winning a disproportionate share of the business. However, Total’s Q318 utilization of 34% for its U.S. drilling business implies that its small fleet of 26 U.S. rigs (~1% of the total U.S. rig fleet of ~2,670 and ~2.5% of the ~1,030 rigs actually working) is able to work with the table scraps provided by (i) drilling top holes, (ii) traditional vertical projects, and (iii) horizontal projects that don’t require a super-spec rig. More importantly than utilization however is profitability. And it’s awful. On a TTM basis the U.S. drilling business lost $11 million of operating profit. These losses are a function of a distressed Savanna entering into low-priced drilling contracts prior to the merger in order to generate cash. Total’s management has said definitively that “We’re not going to work for nothing. That’s going to stop” and reiterated that they’re happy to give up unprofitable market share. The Company is working to reposition these rigs into profitable business or idle them. This is an ongoing project that I believe will be successful, leading to a flat operating profit in my base case, and whose progress can be seen in the Q318 results where U.S. drilling revenue declined by 24% ($5.4 million) year-over-year but operating loss shrank by $2.8 million to $1.5 million.
Australia Drilling Business
Total’s five rigs (vs. a market of ~45 rigs) engaged in coal seam gas drilling in Australia and operating at 80% utilization in Q318 are a meaningful profit driver. These are typically shallower wells that don’t require super-spec. The market here is strong due to excess gas demand. Margin compression from labor market tightness is a bigger concern than utilization. In general, Australia’s onshore coal seam gas operations feed its Queensland LNG export operations, which were funded by Asian buyers in exchange for providing contracted sales of gas. Thus there is a tension to find enough gas to fill the LNG plants and send to Asia while still providing gas to the domestic market at a reasonable price. As a result the drilling remains constant. A rig manager I spoke with said that in the last 8 years he hasn’t had to miss a single shift. Total and Easternwell are leading players in this market. My base case assumes a continuation of recent utilization, pricing, and margins.
Rentals and Transportation Business
The Rentals business is conducted from locations in western Canada (with exposure to every major resource play in Western Canada) as well as North Dakota and Wyoming. Total’s rental fleet consists of approximately 11,000 pieces of major rental equipment (fluid containment pools, pressure vessels, shale tanks, loaders, light towers, generators, etc.) of which ~95% is in Canada and 112 heavy trucks along with small rental equipment pieces and access matting. Total’s RTS business was historically levered mostly to natural gas drilling in Northwestern Alberta but now pursues both oil and gas business in Canada and the U.S.
This is again a largely commoditized business other than sales relationships, quality and reliability of service, and condition of assets, and again Total believes that it is competitive. As in drilling, Total gives up low-return market share in order to generate attractive full-cycle returns.
The U.S. rental business is very small and marginally profitable. I expect this to continue and there may be some opportunity to move additional equipment into the U.S. but such improvement doesn’t merit inclusion in the base case.
As RTS utilization has dropped into the 20s in Canada, the segment has started causing meaningful losses due to the relatively fixed costs associated with keeping branch facilities open. Management stated on the Q318 earnings call that it intended to close 20% of its RTS branches in order to align the segment’s cost structure with the current market environment and that it expected these closures to be completed by the end of the year. My base case (also my high case) assumes that Total manages this division to a neutral operating profit.
I’ll finish by noting quickly that today’s RTS segment is the result of Total’s first transformational opportunistic acquisition in December 2009 when it agreed to acquire a distressed DC Energy for its net asset value of $44.5 million (zero goodwill paid). This acquisition was the largest in the Company’s history and increased the size of Total’s rental fleet by 80%. The acquisition was possible in part because Total cut its dividend by 70% in 2007 “in anticipation of difficult industry conditions and compelling investment opportunities,” resulting in a balance sheet that strengthened over the course of 2008 and finished the year with a Debt / EBITDA ratio of approximately 1.0. This transaction, along with other prudent additions to rental assets, resulted in a 34% incremental return on capital ($38mm increase in operating profit for a $113mm increase in division assets) between 2006, the peak prior to the DC Energy deal, and 2011, the subsequent peak.
Well Servicing Business
Total acquired the well servicing segment as part of the Savanna acquisition. This segment comprises 57 rigs in Canada (representing approximately 6% of the ~950 service rigs that exist in Canada), 14 in the U.S. (based out of North Dakota), and 12 in Australia. The segment provides well completion, workover, maintenance, and abandonment services. Although workover, maintenance, and abandonment services are generally performed on existing rather than just-drilled wells, this business is still basically driven by drilling activity, though perhaps with a slight lag and a slight insulation relative to the contract drilling segment (when legacy Savanna’s contract drilling utilization in Canada dropped from 47% in 2014 to 17% in 2016, its Canadian servicing utilization only dropped from 42% to 27%).
Similar to the CDS segment, Australia has significantly higher utilization than North America and drives the vast majority of profits. My projections for this segment contemplate the same environments on which my contract drilling projections are based and reflect a continuation of existing market conditions (i.e. finding pockets of opportunity, refusing unprofitable business, and preserving exposure to industry upturns). Total did not have a well servicing business prior to the Savanna acquisition so we do not have a great picture of what performance for this business looks like under Total’s management team (I’d expect higher profitability and higher return on capital than it experienced under Legacy Savanna).
Bidell Compression and Process Services
Bidell, the Company’s compression and process services division, assembles, sells, and rents a variety of compression packages to its customers and sells various process equipment (process services are performed under the Spectrum brand). Bidell operates out of facilities in Calgary, Alberta and Weirton, WV and offers reciprocating and rotary screw compression packages ranging from 20 to 8,000 horsepower. While the Company has stated that the majority of Bidell’s revenue has historically been generated by sales of compression units, the division also has a rental fleet representing 45,500 horsepower of compression as of Q318. Total is extremely tight-lipped about breaking out anything relating to Bidell but it appears that a quarter to a third of its revenue is from compression rentals (this is a high margin business into which Total has been investing significant capital).
Gas compression can be used in a diverse range of applications (gas lift compression, wellhead compression, gas reinjection, transportation, processing), however it appears the bulk of the compression packages that Bidell sells and rents are used for gathering and transportation (i.e. getting natural gas from a number of different wells to, and into, a pipeline). The division’s core activity of spec’ing out and assembling compression packages (basically welding an engine, compressor, and other processing equipment to a skid) is, as it sounds, fairly commoditized. Bidell competes with Exterran, Enerflex, Propak, and a number of other competitors including rental-focused companies such as Archrock, CSI Compressco and USA Compression Partners.
I discuss Bidell separately from the other businesses because it’s growing very quickly (40%-100% yoy for each of the last seven quarters) and thus doesn’t reflect the same sort of capacity utilization / efficiency management story. In fact this is a somewhat difficult time to make a long-term forecast of compression revenues as Bidell’s competitors are growing quite quickly as well (and the recent conference calls that I’ve looked at state the market continues to appear strong through 2019). Although it is possible that we are seeing a significant catch-up of deferred spending from the last couple of years, the backdrop of increasing natural gas production remains a tailwind. I estimate the U.S. compression market at approximately ~$3 billion USD, which would imply that Bidell, at under $400 million CAD of TTM revenue (including process services revenue) has significant headroom to continue growing and taking share. This market size figure doesn’t contemplate additional geographies or growth into more highly engineered solutions such as large fixed process services plants such those that Exterran offers.
Admittedly Bidell has greatly benefitted from the facility that it built in Weirton, WV in 2017, giving it a location (and therefore cost) advantage for Northeast customers relative to Texas-based competitors. At some point this facility will reach capacity, but the Company believes that it has a lot of room to run. A second potential differentiator for Bidell is its patented trailer-mounted compression package called the Nomad. Historically trailer-mounted compression packages would vibrate themselves to pieces. Total doesn’t say much about how they made it work, but you can get a look at the patent, which basically just describes an articulating trailer. A trailer-mounted compression package is highly desirable because (i) it can just roll onto any flat piece of ground and start working immediately rather than requiring a multi-week site prep effort for a skid-mounted package, (ii) it greatly simplifies the process of swapping compression rigs for aging wells with declining pressure levels and (iii) a highly mobile unit like the Nomad allows customers to keep a single spare compression rig onhand that can travel to any nearby sites rather than needing a separate backup rig for every site.
The table below shows summary historical and projected financial data for Bidell.
Broadly, I project a lower growth rate for Bidell than its recent history because I have trouble putting a 40+% growth number into my model. I admittedly don’t have a great view into expense leverage, but I expect margins to at least be as high as they’ve been in years past when revenue was much lower. Finally, although I believe in the overall “growth in gas production plus growth in market share” story, this business may have significant temporary downturns in revenue in the event of an industry downturn, so success may not be a straight line.
Outside of the risks enumerated below, I have to state the obvious risk of a total collapse in the global oil and gas industry (i.e. Brent at $10-$20 forever). Although I think that’s unlikely, it’s worth stating that in such a scenario Total’s equity would be significantly or completely impaired.
Earnings in my base case are driven predominantly by Australia and Bidell. This requires (i) continued strong coal seam gas drilling activity in Australia (and maintenance by Savanna of its market share) (ii) reasonable margins for coal seam gas drilling Australia (i.e. labor costs remain manageable) and (iii) continued production of natural gas in the markets that Bidell serves (mostly North America and Australia). Thus the key risks to my base case are:
1: Precipitous decline in global natural gas demand, especially in Asia, to whom Australia sends significant exports, or a drop specifically in demand for Australian coal seam gas. There appears to be broad agreement across forecasts from government agencies, company outlooks, and industry participants I’ve spoken with that natural gas will continue to grow in consumption and importance globally (even as renewables grow in importance), and that Asian importers will continue to leverage the low-priced long-term contracts they’ve signed with Australian gas producers. That said, things can change rapidly in this industry and surprises should be no surprise. The bottom falling out is always a risk with a company like this. Total has shown that it is able to “turtle up” and even thrive when the industry gets difficult, but a loss of profits in Australia may cause a meaningful impairment.
2: Labor inflation significantly pressures margins in Australian business. Availability of labor has been an issue for a while in Australia, which is a factor in the high day rates that Savanna earns in the region. The operators I’ve spoken with have stated that staffing is an issue they spend time on, but not one that they feel poses a major risk to their business.
3: Harmful regulatory or environmental activity in Australia
4: Drop in gas production in North America. This (risk to the compression business) could be driven by a drop in either oil or gas prices. I don’t have a specific figure for how much of North America’s natural gas production comes from gas-specific wells vs. byproduct from oil wells but the compression operators I’ve spoken with have told me that oil price is what they watch to get a feel for demand. I’m not as concerned with Bidell losing share as from what I can tell most compression providers currently have backlogs of about a year, and my base case contemplates a much lower growth rate than what Bidell has been experiencing.
5: Loss of significant management team members. Total’s management team from Daniel Halyk on down several levels is disciplined, thoughtful, and effective. A meaningful portion of the comfort I have investing in Total is driven my belief in management’s ability to manage difficult situations and find attractive opportunities.
6: Industry paradigm shift. I don’t have anything in particular in mind here, but given the massive U.S. shale production that came basically out of nowhere, there is always the possibility of some new resource or recovery technique rendering current drilling and production processes obsolete.
7: I’ve missed some aspect of Bidell’s business that severely limits its total eventual size or profitability
8: Management somehow doesn’t cut costs as I expect in its unprofitable regions
9: Total’s debt load from the Savanna acquisition and currently depressed earnings mean that near-term EV multiples imply significant equity impairment. Thus improved operations and continued cash generation are required for the valuation to “make sense.”
The key catalyst for my base case is just continued rationalization, cost control, and finding pockets of opportunity as the Company reports earnings each quarter. Total has shown improvement in its loss-making regions and I expect that to continue. Although management has stated that the integration of Savanna is complete, there is clearly still work to do in allowing unprofitable contracts to expire, selling off undesired equipment (historically for a gain), and optimizing real estate.
The remainder of the potential catalysts that I lay out below are all things that could go right and contribute towards a high case but are too uncertain to be underwritten.
New pipeline capacity reduces the discount in Canadian oil prices relative to Brent, driving increased industry activity: In the recent peak year of 2014, Western Canadian Select oil traded at a ~$25 discount to Brent. More recently, this discount has been greater than $50 / barrel at times. This significant discount is the result of inadequate transportation infrastructure (i.e. the pipelines are full and Alberta’s oil is stuck in Alberta). This is a well-known issue and there are a couple of potential avenues for solving it, but they are moving slowly due to political and environmental issues.
Trans Mountain Expansion: The original Trans Mountain Pipeline was built in 1953 and has capacity to transport 300k bpd from the Edmonton, Alberta area to Burnaby, BC (tidewater access). The expansion would nearly triple the system’s total capacity by adding 590k bpd. This project is supported by the Alberta government, energy companies, and the Government of Canada, and has been opposed by the BC government, environmentalist groups, and BC First Nations groups. In May of 2018 the Government of Canada purchased the project from Kinder Morgan with the intent of driving it through, but was stymied in August by a Federal Court of Appeal ruling that found environmental studies and consultations with First Nations to be lacking. The National Energy Board submitted a reconsideration of the project this month and the Government of Canada has 90 days to issue a final approval.
Enbridge Line 3 Replacement: The Enbridge Line 3 pipeline runs from Hardisty, Alberta to Superior, WI. It was put into service in 1968 and currently has a capacity of 390k bpd. The pipeline’s original capacity of 760k bpd was reduced as Enbridge reduced pressure due to the pipeline’s age. The Line 3 replacement project upgrades the pipeline from 34-inch to 36-inch diameter and restores the original capacity of 760k bpd (increase of 370k bpd). Construction is currently in progress on the Canadian side and permitting seems to be moving forward on the U.S. side despite opposition from a number of groups including Minnesota Governor Tim Walz. At the end of October, Minnesota regulators formally approved the proposed new route for the replacement pipeline, but this approval is still subject to petitions to reconsider and/or an appeal. Although this project has a number of opponents, it does not appear to be as controversial as Keystone XL or Trans Mountain. Enbridge expects it to come online in the second half of 2019.
Keystone XL Pipeline: This well-understood project would add 830k bpd of pipeline capacity from Alberta to Nebraska. It was denied a permit by the Obama administration and then reopened and fast-tracked under the Trump administration. In November a U.S. District Court judge vacated Trump’s 2017 executive order, halted construction, and ordered the State Department to supplement the Environmental Impact Statement. More recently a federal judge has ordered TransCanada to halt any “pre-construction work.” Progress remains halted indefinitely as lawsuits continue.
Additional pipeline capacity in the Permian drives increased activity: Oil in Midland, TX has traded at a discount to WTI and Brent due to pipeline constraints. I don’t have a great source for prices in Midland, but WTI (priced in Cushing, OK) trades at a $10/bbl discount to Brent today, and the Midland discount to WTI ranges from roughly $5 to $15 / bbl (recently toward the lower end after the startup of the 350k bpd All American Pipeline). There are a number of additional projects to bring more pipeline capacity online between Midland, Cushing, and Houston (tide water access) with completion dates ranging from mid-2019 through 2020. The lifting of these pipeline constraints should result in additional drilling activity in the Permian as these discounts narrow and Midland prices increase $15-$25 / bbl. To the extent production increases along with pipeline capacity, the discount may remain, but it’s the activity increase (not the discount narrowing) that would benefit Total’s U.S. operations.
Development of LNG export facilities in Canada drive increased Canada gas activity: The LNG Canada project at Kitimat received an affirmative final investment decision at the beginning of October and appears to have the support of the BC provincial government and the Government of Canada, as well as arrangements to be fed gas through the upcoming Coastal Gaslink pipeline, which will connect Kitimat with TransCanada’s NGTL system stretching into Alberta. First LNG is expected before 2025. The initial construction calls for two trains totaling 14 million tonnes of LNG annually, with the potential to expand to four trains. Four trains would represent 3.7 bcf / day, vs. Canada’s total production in 2017 of ~16 bcf / day, or incremental natural gas demand of 23%.
Development of LNG export facilities in the U.S. drives further U.S. gas activity: This will not be a significant near-term contributor to Total but may become so over time. Based on the LNG export projects that have been approved by FERC and are under construction, export capacity is set to triple to ~12 bcf / day in the medium term. Behind these, there is another ~28 bcf / day of projects that are either pending approval or in pre-filing with FERC.
I consider an investment in Total as being “paid to wait” for continued rationalizing and optimization of the asset base (and a potential rerating of the stock once this is reflected in the top-level financials) with exposure to some potential positive macro events that may or may not happen. You hold exposure to a potential global oil and gas catastrophe (and certain potential regional catastrophes) during this time, but you have your capital stewarded by an extremely competent management team and receive a modest dividend.
I’ve referenced my base case a number of times already. Essentially the environment continues as it is, Total eliminates losses in U.S. drilling and Canada rentals, and Bidell grows at high single digits. The following table provides additional detail on these projections.
During this time, Total generates a large amount of cash, some of which is returned as a $0.24/yr dividend. An investor purchasing now earns a 20% IRR over four years as the stock approximately doubles (using a 10x EV / Operating Profit multiple). I forecast that Total continues to spend expansion capex only on Bidell and otherwise sticks to maintenance and upgrades necessary to remain competitive. The table below lays out a simplified cash flow model using these assumptions.
As well-managed and efficient as this Company is, as stated above, if Brent goes to $20 tomorrow and stays there, there’s not going to be much value for the equity. I could calculate a huge haircut to book value and call it a downside case, but I’m not sure who’s buying most of the asset base for anything above scrap value in that environment. It’s a very unlikely scenario but there’s no absolute floor here.
From there I’m left with “pick an undesirable scenario and call it a downside case.” If I run the same model as the base case but cut Australia profits in half and also cut Bidell growth in half (so it’s now going from 60% growth to 3%), and use 7x EV / Operating Profit, I get a stock price of $7.41 (down 24% from current) in 2022, having received $0.96 in dividends for an IRR of -4%. To be clear this scenario benefits from four years of cash generation (the same analysis after two years results in a stock price of $3) but I don’t think that’s a bad bet, especially given that depending on which year you look at, today’s valuation implies a “low case” equity cash flow yield of 15% to 19% and an unlevered free cash flow yield of 10% to 12%.
My high case assumes the Trans Mountain Expansion Project and the Enbridge Line 3 replacement project add 960k bpd of takeaway capacity (about 23% of Canada’s total production of ~4.2mm bpd). In that environment I assume WCS trades at $70 ($15 discount to an $85 Brent and no bottleneck between Cushing and Houston exports). Canada drilling activity rises to 80% of the 2014 peak, resulting in a 50% utilization with today’s smaller fleet. I also assume that day rates split the difference between TTM and 2014, resulting in an increase of about 12% from the TTM figure. This results in a Canada drilling operation that generates $290 of revenue at a 19% operating margin for $56 million of incremental operating profit. Canada well servicing generates an additional ~$4 million in operating profit with higher utilization, U.S. drilling sees higher gross margins for $6.6 million of incremental operating profit, and Bidell grows at a CAGR of 11.7% instead of 7%.
Together, these additions result in a high case operating profit of $186 million. If this improvement all takes place in 2022 and the 2019-2021 cash flows are equal to the base case (and EV / operating profit remains at 10x) the resulting stock price is $39.85 (a 4.1x multiple) with a four-year IRR of 43.6%.
(i) Stemming of losses in U.S. Drilling and Canada Rental segments
(ii) Continued growth and profitability from compression business
(iii) Potential Canadian pipelines
(iv) Potential North American LNG export growth
(see writeup for full discussion of catalysts)
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