Closing the position. I have reconsidered the commodity risks implicit in owning E&G, the recent drop in WCS pricing, and poor outlook for WCS this year, make a private sale of the remaining assets less likely. Without a sale the thesis falls apart.
However it may re-rate when earnings are reported in April, so if you are comfortable waiting until then.
I owned 1000 shares b4 your write up. They are in an IRA I inherited from my dad. No idea how he got into this one.
I bought some additional shares on the morning of Nov 19 and again Nov 20 outside the IRA after your excellent missive. (I did some research to confirm the dates you (correctly) provided. Just being prudent.
I have yet to see the dividend and of course the stock has dropped as I expected it would. I’ve had a couple other situations where large ‘special’ dividends have taken 2-3 weeks to finally show up. But I’m curious as to whether anyone has received the dividend or notice that it’s coming. Thanks.
Nice write-up; I like the tax-benefit analysis. Just one question on the “~1.5x cash flow” framing: since Lycos materially paused drilling recently and has indicated capital activity is expected to resume in 2026, I’m not sure the current run-rate AFFO (or netbacks) translates to true FCF after sustaining capex if the company is operated rather than sold. How are you treating capex in the no-sale case?
I built out a DCF model using a pro-forma FCF number of 4M for Q4,
I used guidance of 1,700 bbd production for q4, used similar proportional line items that quarter as Q3, i.e. minimum capex (non exploration) was 8% of revenue. And modeled out annual decline rates of 30,25,20,15,10,10,10.
In a no-new-wells run-off, fixed cash costs don’t fall with revenue. If cash G&A + facility/fees are ~C$5M/yr, the $/boe overhead balloons as production declines. A model that scales G&A down proportionally will make the tail look too good.
Same for ARO/clean-up: in run-off mode, you eventually write a cheque. If you don’t include either a terminal abandonment hit or a realistic ARO spend schedule, PV is overstated.
Also, it is worth stress-testing the 2-3 year payback narrative. A ~20% oil move is plausible. Under a run-off PV10 with fixed overhead + explicit abandonment (and using CFO ex-WC), I get a wide range: around C$0.2/sh at ~WTI 65 / diff 20, but it can flip to ~zero/negative at ~WTI 55 / diff 20 once abandonment is included. That suggests the stub (~C$0.60) isn’t necessarily protected by liquidation value in mid/weak pricing.
I do think a hold-flat/operate case can justify upside (alongside the asset sale scenario), but the operating thesis maker/breaker is maintenance capex (is it C$8M, C$12M, C$15M?) and the implied decline/type curves. Do you perhaps have any disclosure or assumptions on the 2026 program (wells, costs, expected adds)?
I’ve gone back through the model and updated it to incorporate each of the issues you raised. First, on fixed costs in a run-off: you’re absolutely right that G&A and facility overhead didn’t scale with production. I didn’t orginally include it as it was so marginal. I’ve adjusted the model so that corporate G&A remains fixed at roughly C$1.1M per year (based on the Q3 financials and excluding one-time transaction costs), instead of declining proportionally as in the earlier version, but this didnt change the valuation much, but does compress the long-tail PV. Second, on ARO: I’ve now modeled abandonment explicitly, using either a lump-sum terminal-year charge of roughly C$9.4M (consistent with retained ARO post-sale) or an annual spend of ~C$0.9M, based on the Q2 MD&A decommissioning accrual scaled to the remaining wellbase. This directly addresses the concern that run-off NAVs can be overstated if abandonment is ignored.
I’ve also added full commodity-price sensitivities, as you suggested. The updated run-off PV10 is included above and uses realized sale price (in CAD) using a $20 diff (as historicall accurate).
On sustaining capex, I agree this is the key swing factor. Using the Mannville multilateral capital efficiency range ($12–20k/flowing) and a blended decline curve averaging ~26%, I estimate ~442 bbl/d of base declines, which implies maintenance capex of around C$8.8M/yr in the base case, with a reasonable envelope of roughly C$6–15M depending on rock quality and pad sequencing. I’ve included explicit sensitivity runs for this as well.
Finally, regarding 2026, Lycos has not issued any public guidance on drilling, capex, or expected adds post-sale, so the sustaining-case assumptions necessarily rely on historic capital efficiency and the multilateral type curves included in their investor presentation (which I recommend you check out). Taken together, these updates bring the model much closer to the real economics you’re describing, and I think the revised analysis now captures both the structural downside in a pure run-off as well as the upside optionality in a hold-flat or asset sale scenario.
I still get to a value of $44M for the stub at 65 realized prices, add in NOLs of $9M, and I get a fair value of $53M. And add in the upside value of an immediate sale. Still looks good to me.
Again everything I am seeing here is that the Alberta assets are higher quality than the SK assets.
Can you share your model so I can double check that I am not being overly optimistic?
Appreciate the updates, big improvement. Two lingering mechanical points, though:
(1) The C$8.8M “maintenance capex” is likely understated. Using 26% decline × 1,700 bbl/d gives an end-of-year production drop (~442 bbl/d). But to keep average production flat through the year, you usually need more than that because new wells come on mid-year (partial-year contribution), and they decline quickly right away. So the effective “flowing adds” you must replace tends to be >442 bbl/d, which pushes maintenance closer to something like C$10–15M unless the wells are unusually stable and the program timing is perfect.
(2) The C$1.1M/yr fixed G&A looks too low vs the filings. Lycos’ MD&A shows net G&A running around ~C$1.2M per quarter in Q2 2025 (and ~C$2.6M for the first six months), and FY2023 net G&A was ~C$4.2M. More importantly, the MD&A notes that capitalized overhead recoveries drop when capex drops — meaning in a run-off / low-capex scenario, more overhead tends to show up as expensed G&A, not less. So using a low-capex quarter to justify very low “fixed G&A” can bias the tail PV upward. I’d sanity-check with a C$3–6M/yr cash G&A range post-sale
Good point. I stressed tested in the above DCF at 10.8M a year in Capex. I could also test higher.
Sorry, I wasnt clear on that tab. The pro forma IS is quarterly. My DCF model in the final tab “DCF - maintain production” assumes continued G&A of 4.4M. Again, I think this is reasonable due to transaction costs of recent transactions and some streamlined costs (land admin, etc.).
This modelled G&A is cash expense of overhead not inclusive of capitalized G&A associated with the drilling program. All my drilling costs including capitalized G&A is grouped under my Capex number.
Nice writeup - I think ex-dates are same as payment dates for large distributions, which is what it seems like today? This is how it has been in the US at least.
Closing the position. I have reconsidered the commodity risks implicit in owning E&G, the recent drop in WCS pricing, and poor outlook for WCS this year, make a private sale of the remaining assets less likely. Without a sale the thesis falls apart.
However it may re-rate when earnings are reported in April, so if you are comfortable waiting until then.
bought 60c, sold 70c, 16% return.
Why necessary to own before the dividend? Why not buy now for the rerate?
Either way. Honestly probably better to own after. Charles Schwabb was confused and dividends were delayed too long on their end. Lesson learned
Still largest position?
I have not received the dividends either. I hold them via IBKR. Wonder if anyone has received the dividends yet?
Nothing yet at Fidelity. I would expect these to hit Dec 4, it can take some time to process the due bills, added time for the OTC issuance.
I owned 1000 shares b4 your write up. They are in an IRA I inherited from my dad. No idea how he got into this one.
I bought some additional shares on the morning of Nov 19 and again Nov 20 outside the IRA after your excellent missive. (I did some research to confirm the dates you (correctly) provided. Just being prudent.
I have yet to see the dividend and of course the stock has dropped as I expected it would. I’ve had a couple other situations where large ‘special’ dividends have taken 2-3 weeks to finally show up. But I’m curious as to whether anyone has received the dividend or notice that it’s coming. Thanks.
Odd that distributions have taken you 2-3 weeks.
Due bill period ended dec 1, it takes 3-4 days for the payments to hit.
Of course talk to your broker if you have any concerns.
Nice write-up; I like the tax-benefit analysis. Just one question on the “~1.5x cash flow” framing: since Lycos materially paused drilling recently and has indicated capital activity is expected to resume in 2026, I’m not sure the current run-rate AFFO (or netbacks) translates to true FCF after sustaining capex if the company is operated rather than sold. How are you treating capex in the no-sale case?
I built out a DCF model using a pro-forma FCF number of 4M for Q4,
I used guidance of 1,700 bbd production for q4, used similar proportional line items that quarter as Q3, i.e. minimum capex (non exploration) was 8% of revenue. And modeled out annual decline rates of 30,25,20,15,10,10,10.
Basically the model is a no-capex run off model.
And it gets a NPV value of $48M.
Please let me know if I am off on anything there.
https://docs.google.com/spreadsheets/d/1d1sowZoKnZTQFWKJSriI3EJfz6mQN9gqNuJx8ElnJXM/edit?usp=sharing
Quick pushback on the run-off DCF.
In a no-new-wells run-off, fixed cash costs don’t fall with revenue. If cash G&A + facility/fees are ~C$5M/yr, the $/boe overhead balloons as production declines. A model that scales G&A down proportionally will make the tail look too good.
Same for ARO/clean-up: in run-off mode, you eventually write a cheque. If you don’t include either a terminal abandonment hit or a realistic ARO spend schedule, PV is overstated.
Also, it is worth stress-testing the 2-3 year payback narrative. A ~20% oil move is plausible. Under a run-off PV10 with fixed overhead + explicit abandonment (and using CFO ex-WC), I get a wide range: around C$0.2/sh at ~WTI 65 / diff 20, but it can flip to ~zero/negative at ~WTI 55 / diff 20 once abandonment is included. That suggests the stub (~C$0.60) isn’t necessarily protected by liquidation value in mid/weak pricing.
I do think a hold-flat/operate case can justify upside (alongside the asset sale scenario), but the operating thesis maker/breaker is maintenance capex (is it C$8M, C$12M, C$15M?) and the implied decline/type curves. Do you perhaps have any disclosure or assumptions on the 2026 program (wells, costs, expected adds)?
did i alleviate your concerns or am i still totally off base here?
I really appreciate the feedback.
I’ve gone back through the model and updated it to incorporate each of the issues you raised. First, on fixed costs in a run-off: you’re absolutely right that G&A and facility overhead didn’t scale with production. I didn’t orginally include it as it was so marginal. I’ve adjusted the model so that corporate G&A remains fixed at roughly C$1.1M per year (based on the Q3 financials and excluding one-time transaction costs), instead of declining proportionally as in the earlier version, but this didnt change the valuation much, but does compress the long-tail PV. Second, on ARO: I’ve now modeled abandonment explicitly, using either a lump-sum terminal-year charge of roughly C$9.4M (consistent with retained ARO post-sale) or an annual spend of ~C$0.9M, based on the Q2 MD&A decommissioning accrual scaled to the remaining wellbase. This directly addresses the concern that run-off NAVs can be overstated if abandonment is ignored.
I’ve also added full commodity-price sensitivities, as you suggested. The updated run-off PV10 is included above and uses realized sale price (in CAD) using a $20 diff (as historicall accurate).
On sustaining capex, I agree this is the key swing factor. Using the Mannville multilateral capital efficiency range ($12–20k/flowing) and a blended decline curve averaging ~26%, I estimate ~442 bbl/d of base declines, which implies maintenance capex of around C$8.8M/yr in the base case, with a reasonable envelope of roughly C$6–15M depending on rock quality and pad sequencing. I’ve included explicit sensitivity runs for this as well.
Finally, regarding 2026, Lycos has not issued any public guidance on drilling, capex, or expected adds post-sale, so the sustaining-case assumptions necessarily rely on historic capital efficiency and the multilateral type curves included in their investor presentation (which I recommend you check out). Taken together, these updates bring the model much closer to the real economics you’re describing, and I think the revised analysis now captures both the structural downside in a pure run-off as well as the upside optionality in a hold-flat or asset sale scenario.
I still get to a value of $44M for the stub at 65 realized prices, add in NOLs of $9M, and I get a fair value of $53M. And add in the upside value of an immediate sale. Still looks good to me.
Again everything I am seeing here is that the Alberta assets are higher quality than the SK assets.
Can you share your model so I can double check that I am not being overly optimistic?
Appreciate the updates, big improvement. Two lingering mechanical points, though:
(1) The C$8.8M “maintenance capex” is likely understated. Using 26% decline × 1,700 bbl/d gives an end-of-year production drop (~442 bbl/d). But to keep average production flat through the year, you usually need more than that because new wells come on mid-year (partial-year contribution), and they decline quickly right away. So the effective “flowing adds” you must replace tends to be >442 bbl/d, which pushes maintenance closer to something like C$10–15M unless the wells are unusually stable and the program timing is perfect.
(2) The C$1.1M/yr fixed G&A looks too low vs the filings. Lycos’ MD&A shows net G&A running around ~C$1.2M per quarter in Q2 2025 (and ~C$2.6M for the first six months), and FY2023 net G&A was ~C$4.2M. More importantly, the MD&A notes that capitalized overhead recoveries drop when capex drops — meaning in a run-off / low-capex scenario, more overhead tends to show up as expensed G&A, not less. So using a low-capex quarter to justify very low “fixed G&A” can bias the tail PV upward. I’d sanity-check with a C$3–6M/yr cash G&A range post-sale
https://docs.google.com/spreadsheets/d/1aWaqh-G6aR-YhoZrOsWGJ5ayQ3sgjy78_K9VjNxal8k/edit?usp=sharing
Good point. I stressed tested in the above DCF at 10.8M a year in Capex. I could also test higher.
Sorry, I wasnt clear on that tab. The pro forma IS is quarterly. My DCF model in the final tab “DCF - maintain production” assumes continued G&A of 4.4M. Again, I think this is reasonable due to transaction costs of recent transactions and some streamlined costs (land admin, etc.).
This modelled G&A is cash expense of overhead not inclusive of capitalized G&A associated with the drilling program. All my drilling costs including capitalized G&A is grouped under my Capex number.
I added that capex data table above. You are right, if we assume 12.8 M capex and 65 realized oil, include NOLs we get to a fair value.
However you are getting that fair price and significant free upside if they sell the remaining assets now that they are subscale.
Since this is a ROC, we can be sure US investors face no additional withholding tax correct?
I am no tax lawyer but from my research yes. A ROC should only reduce your taxable basis as a us taxpayer.
Nice writeup - I think ex-dates are same as payment dates for large distributions, which is what it seems like today? This is how it has been in the US at least.
I’m sorry I should have spent more time on that, and I may have used “ex-date” wrong. That is probably correctly stated as Dec 1.
Here are the key dates:
Record Date: Nov 20, 2025
Payment Date: Nov 28, 2025
Due Bill Period: Nov 20 – Nov 28 (inclusive period, most brokers can handle buys during this period)
Ex-Dividend (ex-distribution) date: Dec 1, 2025