Sturgeon Refinery Start-Up – What Happens Next?
The $9.7 billion Sturgeon Refinery, owned by North West Redwater Partnership (NWRP), is now in the final stages of start-up. The Refinery has already been producing about 25,000 bpd of high quality diesel and 15,000 bpd of diluent from synthetic crude oil feedstocks for several months as work to complete the final heavy oil processing units continued. Synthetic crude oil, sourced from Alberta’s oil sands upgraders is a low-sulphur, bottomless feedstock, and the Refinery was able to process a limited volume into diesel in its Hydro-cracker while construction on other process units was completed. With the recent completion of the LC Finer and Gasifier units of the Refinery, diluted bitumen will become its feedstock as it will have the full capability to process this heavy, high sulphur crude into high quality, low sulphur diesel and diluent.
What Does This Mean?
Several important changes are set to take place as full start-up is achieved:
- The Refinery will ramp-up to full production and will process about 80,000 bpd of diluted bitumen (50,000 bpd of bitumen) feedstock. This comes at a critical time for Alberta, since bitumen production is overwhelming existing export pipeline capacity, resulting in very large price discounts. For example, Western Canadian Select (WCS), the price marker for diluted bitumen, should trade at a discount of about US$12/barrel to West Texas Intermediate (WTI) in a balanced market. Recently this discount has been greater than US$30/barrel as growing bitumen supply is forced to find sub-optimal markets. Processing 80,000 bpd of diluted bitumen into diesel, which will be delivered to consumers by rail or truck, and diluent which will be sold in local markets, will help ease pressure on the export pipeline system. This should help to reduce the wide bitumen price differential which is reducing producer revenues by $10 to $15 billion per year, and therefore reducing combined federal and provincial government revenues from corporate income taxes and bitumen royalties by $4 to $6 billion per year.
- After 30 consecutive days processing diluted bitumen at 50% or more of its design capacity, the Refinery will declare “Commercial Operations Date” or COD has been achieved. At this point the Processing Agreements with the Alberta Petroleum Marketing Commission (APMC) as 75% toll payer and Canadian Natural Resources (CNRL) as 25% toll payer, require each of them to supply their share of diluted bitumen feedstock to the Refinery and to pay defined processing tolls to have it processed for a 30 year term.
- APMC will begin to purchase 55,000 bpd of diluted bitumen (containing about 37,500 bpd of bitumen) for delivery to the Refinery. APMC will be purchasing about 20 million barrels of diluted bitumen each year at cost of $1 billion or more, depending on market conditions. It will pay an average toll to the Refinery of about $850 million per year to have this feedstock processed, and will get its 75% share of the revenue from sales of the refined products and diluent produced. In times of wide bitumen differentials and strong diesel prices the revenue that APMC earns should cover the feedstock costs and toll payments and leave an operating profit. The arrangement with the Refinery effectively acts as a hedge for a portion of Alberta’s exposure to bitumen prices that comes from the bitumen royalty system. Narrow bitumen price differentials mean higher bitumen prices and higher oil sands royalties, but could result in losses for APMC at the Refinery. The profits or losses from this business activity will directly impact Alberta’s deficit position each year for decades to come. Until export pipeline issues are resolved bitumen price differentials are likely to be wide.
- The work of the tens of thousands of engineers, project managers and skilled trades workers who designed and built the Refinery with an outstanding safety record will be complete. Over the course of construction the on-site workforce peaked at over 8,000 and over 36,000 individuals were oriented to work on site. At peak, over 130 busses transported workers to the site each day from the Edmonton region, and over the course of construction this amounted to over 4 million individual car trips that were avoided. Completing construction of the Refinery greatly reduces demand for skilled trades people in Alberta, particularly when added to the recent completion of both the Horizon and Fort Hills projects.
What Have We Learned?
- Development of the Sturgeon Refinery was effectively one of the largest Public-Private Partnerships (PPPs) in Canadian history, and one of the largest business ventures Alberta has ever been involved in, comparable in scope to the development of Syncrude in the mid-1970’s. This structure married Alberta’s financial strength, through its Processing Agreement, with NWRP’s project development, execution and operations capabilities.
- The contractual structure put in place for the project enabled NWRP to raise over $8 billion of investment grade debt financing (80% of the total capital required for the project) at favourable interest rates, despite the 2014 oil price crash and the chilling effect it had on energy related financings; the project greatly exceeding the original $5.7 billion budget; and COD being months later than planned.
- Building a new bitumen refinery is a very large and complex undertaking. The Refinery took over a decade to develop and had to overcome many challenges to reach COD. Some ask: why doesn’t Alberta refine all of its bitumen production rather than exporting it? With Alberta’s bitumen exports exceeding 1.5 million barrels per day and growing, the development of this 50,000 bpd bitumen Refinery is an instructive reference point for what can be achieved and the risks that are involved. Assessing the overall success of the Sturgeon Refinery will take years, and will depend on its operating performance and bitumen and refined product prices.
- It makes sense for Alberta to use the levers it has available to protect its economic interests. The oil sands are one of the largest oil resources in the world and have the potential to deliver lasting benefits for decades to come. However, since Alberta can’t control what happens outside its borders, particularly with respect to the development of export pipelines, it remains vulnerable to severe price discounting from having its resources sold into distressed markets, greatly reducing revenues and increasing deficits. Risk sharing approaches between industry and government can help to deliver home-grown solutions to mitigate this risk – and they may continue to be a necessary strategy given ongoing pipeline and market access challenges.
Richard Masson is an Executive Fellow at The School of Public Policy, University of Calgary. He is currently Chief Commercial Officer of Fractal Systems, working to commercialize its partial upgrading technology. He was previously CEO of the Alberta Petroleum Marketing Commission and developed oil sands projects with both Nexen and Shell.