This morning, Suncor held an investor conference call to discuss the decision announced late last night that it would proceed with the development of the Fort Hills mine – a joint venture with Total and Teck. Everything associate with this project is huge – it’s expected to produce 180,000 barrels per day and to cost 15 billion dollars up-front to build. This morning, CFO Bart Demosky laid out Suncor’s financial analysis for the project, and stipulated that their internal analysis found an internal rate of return of 13% – respectable for an oil sands mine.
Here are the basic assumptions Suncor stipulated behind that figure (costs are per bitumen barrel):
- Oil prices of $100/bbl (Brent) and $95/bbl (WTI)
- Bitumen prices at 60% of WTI
- Operating expenditures of $20-24/bbl, in today’s dollars
- Sustaining capital expenditures of $3/bbl
- Up-front capital costs of $84,000 per flowing bitumen barrel, or $15.1 billion including cost escalation and contingency
- Invested 650 million total to-date, not included in IRR calculations
- Canadian dollars at 96 cents US
- Royalties of $11.50/bbl
I took these numbers, dropped them into my oil sands model, with the following assumptions:
- Oil prices of $100/bbl (Brent) and $95/bbl (WTI), AECO-C gas at $3.50/GJ, all increasing at the rate of inflation.
- Canadian dollar at 96 cents US
- Bitumen prices at 60% of WTI, which implies a $25/bbl differential between WTI and Western Canada Select, a 30% blending ratio, and a $6/bbl premium for diluent over WTI (differentials increasing with inflation) .
- Operating expenditures of $20/bbl, increasing with inflation.
- Sustaining capital expenditures of $3/bbl, increasing with inflation.
- Up-front cash capital costs of $84,000 per flowing bitumen barrel, or $15.1 billion, spread over 5 years
- I omitted the 650 million total to-date in capital expenditures, so it’s properly not included in forward-looking IRR calculations, but I added it back in for royalty and tax purposes so that the expenditure is properly counted against project income
- Debt used to finance 50% of up front capital expenditures at a rate of 7%
- Production horizon of 50 years, with cumulative bitumen production of 3.2 billion barrels.
- Build time of 5 years
Using these figures, I can’t replicate Suncor’s IRR – I get 10.2% (after-tax) to their 13%. Here are my results, in 2013 dollars per barrel of bitumen:
|Capital and Debt Costs||$/bbl||8.68|
|GHG compliance costs||$/bbl||0.03|
|Free Cash Flow||$/bbl||12.08|
So, my royalty numbers are higher than Suncor’s, which should indicate that the project as I’ve modelled it has higher net revenue. I’ve taken account of Alberta’s oil sands royalty regime, federal corporate taxes (standard Class 41 CCA), Alberta’s SGER maintained ad infinitum. Despite this, I get a lower after-tax IRR.
I know of a few other people with similar figures. So, people of the internet, what am I missing?
17 responses to “Fort Hills tale of the tape”
Is Suncor’s cost of debt really 7%? I would have guessed that it was lower than that. Not that I am well-informed, but that surprises me.
Good point. You can certainly get to 13% IRR with a lower cost of debt and a higher debt share of capex. Will dig into this more.
I quickly checked Suncor’s existing market debt, all has coupons below 7% (seems most recent issuance lt debt was in 08 at 6.85%).
With a 50 year horizon, the 3 cent/bbl GHG compliance is a real low ball estimate (though not surprised this blog is the purveyor of the proverbial pollyanna low ball).
If you make the reasonable assumption that for reasons of market access/infrastructure permits the industry will at some point over that period need to be at par with or come close to conventional W-T-T GHG you are into at least a couple bucks per bbl depending on the compliance mechanism.
Ah Chris, it’s nice to have you commenting again. As you will see clearly stated, my assumption is that the SGER remains in place. I’ll be writing in the next few days on the exposure of this facility to GHG policies, so stay tuned.
Can you clue us in to Hartz Capital’s disclosure on their carbon liabilities? I’d be interested to know.
Andrew – Sorry I missed the SGER reference. I was blinded by the 3 cent sticker shock. I think its great that you are going to start to talk about climate and carbon again. I was getting worried that this blog had lost its climate dimension. Be sure to do a run with CCS north of 100 bucks — Let’s see what that does to the IRR. And unlike oil sands, Scope I and II emissions in the finance industry aren’t material enough to be considered a liability. Besides, in the north east the carbon content of the upstream electricity is falling due to shale gas (plus some renewables). Lucky us.
I meant with respect to disclosure on investments. What do you demand from companies? What sort of implicit price of carbon or future carbon policies do you build-in to your financials for investment decisions?
Ask CERES that question — that’s what they do
Personally, I just look at the oil sands chart relative to conventional peers. Seems like the market is already pricing some sort of future carbon cost in (a lot more than 3 cents!).
Perhaps the market prices it with CCS @ $100+/tonne since, in Alberta, you like to deride the offset alternative as “hot air”, and efficient cap and trade “as a job killing carbon tax”.
Ah Chris, your segues are so welcome and add so much to the conversation. It’s a shame you can’t even answer a direct question.
If you assume tradeable permits with ample flexibility, the answer is not bullish. History has proven the price forecasting models tend to be wrong: US SO2, EU ETS, CDM, RGGI, REC markets – the works — they all got oversupplied very easily. In my personal view, the discrepancy between forecast and reality is due to the fact that the models tend to be designed by energy economists with an upward price bias and a poor handle on exogenous variables.
In the case of the oil sands, frankly, I don’t know how to price it. Alberta is a peculiar case since they’ve not behaved like rational actors — they’ve rejected low cost compliance options in favour of higher cost ones. So the price could be low double digits or it could be $100++.
On the quantity, I think the smart money assumes the emissions intensity will need to be brought down to conventional W-T-T levels to maintain market access. If the climate science is right, and the impacts will worsen materially by 2063, I can’t see buyers continuing to accept product with an above average emissions footprint over the term of the Foot Hills facility.
The Suncor Fort Hills presentation notes that the 13% IRR includes “integration with Suncor downstream” which could mean that some of the bitumen is being upgraded.
Suncor upgrading capacity in AIF 2012 (released March 2013) was:
U1 – 110,000 SCO, U2 – 240,000 of SCO/diesel output
In 2012, they produced around 310,000 bbl/d of SCO.
This would put utilization around 86%.
If we assume that they lose ~14% of the bitumen from coking losses, this puts input at around 360,000 of bitumen. (FYI no bitumen production figures in the AIF, so I did this to save time). From Mackay and Firebag, they also produced around 48,000 bbl/d. So, they produced around 408,000 bbl/d of bitumen (fyi – I am sure the bitumen data exist and will look)
The EDM refinery can process up to 35,000 bbl/d of dilbit (total refinery capacity around 140,000, but the remainder runs primarily on sour SCO).
If we take the same 14% assumption, this would put AB Suncor bitumen input capacity around 440,000 bbl/d (U1+U2+35,000 @ SU EDM) and production around 408,000 bbl/d (some of which is already being sold as dilbit). If these figures are reasonable (some admitted heroic assumptions here) then there could be some additional room for bitumen from Fort Hills to be processed at one of these places. This, however, does not account for production increases at any of the pre-existing (Mackay, Firebag, Mine) projects nor does it make any assumptions around how much dilbit Suncor would prefer to sell.
Back to the Plumbing,
Thanks for reading, Lily.
Interesting catch. Not sure how that works unless they expect they can see an economic advantage from using their own bitumen in terms of the economics of the Fort Hills plant. Perhaps this is tied to being able to use the bitumen valuation methodology instead of market prices. In theory, if the royalty valuation works, they should be indifferent between selling the bitumen out of Fort Hills and buying market bitumen to run in their refineries vs. running their own bitumen sold non-arms-length.
Andrew — I thought this “offsets and keystone Summit” would be a great one for you to attend.
Just think, you can sit around with Tom Steyer’s folks, hold hands, and sing kumbaya: “Hot air it is, my lord, hot air it is…Alberta’s praying, my lord, but hot air it is… Alberta’s crying, my lord, but hot air it is…”
Thanks Chris. I’ll try to make it.
Could you explain a bit on why “if the royalty valuation works, they should be indifferent between selling the bitumen out of Fort Hills and buying market bitumen to run in their refineries vs. running their own bitumen sold non-arms-length.”, as you said in your previous reply to Lily?
Thank you very much!
The royalty valuation for bitumen is supposed to reflect what the bitumen would be worth in the market, to assess it for royalty purposes when it’s sold to a non-arms-length party (i.e. to themselves). So, if it’s working correctly, the mine should not be paying significantly different royalties if it’s providing bitumen for internal operations as if it’s doing so for market. There may be some tax differences, but royalty-wise it should be the same.
Thanks for your explanation. I see that the bitumen would be worth the same in the market as in selling to a non-arms-length party if royalty valuation works.
The tricky thing, however, is that by including “integration with Suncor downstream” to generate the 13% IRR, Suncor may add the value, created from turning bitumen into SCO/diesel, on the Fort Hills project valuation. Therefore, they got higher IRR than your did. Am I right?