Engineering & Mining Journal

AUG 2017

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Page 27 of 99

OIL SANDS 26 E&MJ • AUGUST 2017 ty for their reinstatement once prices rise above break-even again. And that in turn raises some inter- esting questions about what production costs in the oil sands industry really are, and what the impact of the low oil price is likely to be on future investment plans. At the end of 2015, IHS Energy pub- lished a report that looked at this and other issues relating to oil sands develop- ment costs. In Oil Sands Cost and Com- petitiveness, the company estimated the break-even economics for new projects, both mines and in situ, noting that "the full-cycle cost — the total cost to find, develop, and ultimately produce oil is of- ten expressed as the price per barrel of oil required for an investment in new oil production to break even (with a 10% in- ternal rate of return)." According to IHS, "on average in 2015 a new oil sands mine required a West Texas Intermediate (WTI) price be- tween US$85 and $95/bbl to cover all the costs associated with a project with capacity to produce 100,000 bbl/d of di- luted bitumen. An in-situ SAGD project requires between US$55 and $65/bbl to produce 30,000 bbl/d of diluted bitu- men," the company went on, adding that "SAGD expansions require prices about US$5/bbl less." The company qualified these esti- mates by pointing out that "although prices in 2015 were below the break-even threshold for new projects (explaining why many have been deferred), an existing fa- cility should have, on average, received sufficient revenue to cover its day-to-day operating costs." That was in late 2015, so what has happened to the price of WTI since then? In reality, not much to keep oil sands op- erators happy, albeit that the price at the beginning of July (US$44.40/bbl) was somewhat better than the nadir of below US$29 recorded in January 2016. In the interim, the price had indeed flirted with US$50 and above, but even that would have meant slim margins for several of the established producers. Increasing productivity and cutting costs have been the order of the day all round since the oil price collapse in 2014 and 2015. And some companies have not only been successful, but have been quick to advertise that success. For example, Canadian Natural re- ported record low annual average op- erating costs of C$25.20/bbl in 2016, after adjusting for planned downtime at its Horizon mine, representing a 12% fall year-on-year. In addition, the compa- ny did even better in the last quarter of the year, reflecting the ramp-up of new capacity through its Phase 2B expansion, reporting quarterly production costs at C$22.53/bbl. As a result, it has revised its 2017 cost estimate down to C$24- $27/bbl, including planned downtime for maintenance, turnaround and tie-in activ- ities relating to its Phase 3 expansion. Meanwhile, Suncor managed to cut its cash production costs during the year to C$26.50/bbl, 5% down year-on-year and the lowest the company had achieved since 2007. It was helped in this respect by its acquisition of a greater share of output from Syncrude, which, it reported, achieved average utilization rates of 97% and cash operating costs of a little more than C$30/bbl during the year. This, Sun- cor added, was "a notable improvement on the 71% utilization rate and C$42/bbl achieved in 2015. In fact, the third and fourth quarters represented the best six months of production that the Syncrude facility has ever achieved," the company stated in its annual report. Mine Capacity Rising... The next mine to be commissioned in the area to the north of Fort McMurray, Fort Hills, is scheduled to produce its first oil late this year. At the end of 2016, minori- ty partner in the project, Teck Resources, reported that construction was then more than 76% complete, with the project's mining and infrastructure sectors turned over to operations. All major plant equip- ment and materials were on site, and all major vessels and process modules had been installed at that stage. However, Teck also noted that the im- pact of the huge wildfire last year together with productivity challenges have caused an increase in the capital cost estimate for the secondary extraction facility, with the revised total capex forecast about 10% higher than the project sanction estimate, excluding foreign exchange impacts. In this respect, changes in the Canadian dollar exchange rate have added around C$300 million to the project cost, which is now estimated at between C$16.5 and C$17 billion. Since the project operator, Suncor, has announced an 8% increase in the nameplate capacity to 194,000 bbl/d, the capex cost per flowing barrel of bitu- men will remain at C$84,000. Operating costs of around C$23.40/bbl are expected over the life of the project. Fort Hills will use traditional open-pit truck and shovel mining, with value-add- ed carbon-rejecting solvent-extraction technology that will allow the operation to produce a higher quality and lower green- house gas (GHG)-intensity bitumen prod- uct that can be sold directly to the mar- Steam generators at the Christina Lake in-situ operation, now wholly owned by Cenovus Energy after ConocoPhillips sold its stake earlier this year. Cutting the amount of steam needed to liberate and fluidize the bitumen underground is a key target for cost and emissions-reduction efforts in the oil sands industry.

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