Most Canadian oil sands crude production comes from very expensive mining or underground steam heating operations designed to produce consistently for decades that are costly to shutter in a downturn. Right now the crude netbacks (market price less transport costs) for these projects are more or less under water depending on transport routes. Yet production continues and new projects are still coming online. Today we estimate the netbacks (market price less transport cost) that Canadian producers are realizing.
In Episode 1 of this series we reviewed the woes of hard-pressed Canadian producers in the face of ever lower crude prices. U.S. shale producers are struggling to keep the debt collectors from their doors and cutting capital budgets left and right to survive with prices for benchmark West Texas Intermediate (WTI) trading below $30/Bbl. Yet $30/Bbl probably sounds like lottery money to their counterparts in the Western Canadian oil sands. Crude prices there for benchmark Western Canadian Select (WCS) are currently (11 February 2016) trading at a $12/Bbl discount to WTI in Hardisty, Alberta – reflecting the higher transport cost to get Canadian crude to U.S. refineries and quality differentials for heavier oil sands grades. That means Canadian producers get $15/Bbl at best ($14.20/Bbl on February 11, 2016) for their crude in Alberta. And some of that $15/Bbl has already been spent to buy the lighter and more expensive hydrocarbon diluent that is required to blend heavy oil sands bitumen at the lease so that it can flow in pipelines. Since most of the demand for heavy oil sands crude comes from U.S. refiners – in the Midwest or increasingly on the Gulf Coast – producers have to eat high transportation costs to get their crude to market. We also discussed how oil sands extraction plants that use steam assisted gravity drainage (SAGD – used by the majority of recent projects) are difficult to shut down when economics are this bad – because the start up process is very lengthy and expensive and the process of stopping production can damage the resource reservoir. In the circumstances cash struck producers are selling midstream assets and hunkering down even as – in some cases – they are experiencing a net cash outflow on every barrel produced. In today’s episode we take a look at the economics for a typical oil sands producer to understand just how bad things are in the Canadian oil patch these days.
Our analysis starts with a worst case scenario – shipping a Canadian heavy “dilbit” crude blended with 28% diluent via truck from the lease to Hardisty, Alberta and from there by rail to Houston or similar Texas Gulf Coast destination. We assume the crude being shipped is of similar quality to WCS – meaning that its destination value is the market price for WCS in Houston. Since WCS is a pipeline blend in Hardisty it is unlikely to move by rail. Oil sands heavy crude grades moving by rail are likely to be heavier than WCS and attract a discount to WCS at the Gulf Coast. To keep things simple we have not applied that discount and assume a WCS price at the Gulf Coast. What we are trying to determine is how much (in $US) the producer is left with after all the transport costs and any diluent premium are taken care of – back to the lease. The various cost elements and a summary of the calculation are shown in Table #1. We assume that the rail journey from Hardisty to Houston will be on a unit train (dedicated to shipping crude) with 600 Bbl of crude in each rail tank car. The rail freight cost from Hardisty to Houston is estimated at $12.00/Bbl. The rail tank car lease would add another $0.50/Bbl at $600/month (2 round trip turns/month = $300/trip divided by 600 Bbl = $0.50/Bbl). There would also be rail load and unload terminal fees of $1.50/Bbl at each end of the trip. The total rail freight cost is therefore $15.50/Bbl. On February 8, 2016 the destination value for the dilbit crude is the WCS Houston price - $20/Bbl. By subtracting the rail freight from the WCS Houston price we get $4.50/Bbl netback at the Hardisty rail terminal. But there are additional producer costs that have to be taken into account to get back to the lease.