Challenges Facing the Canadian Oil Sands Megaprojects
Even prior to the price collapse in 2014, the Canadian oil sands faced a number of challenges, including market access, environmental opposition, and capital cost escalation. Individually, these issues would likely be manageable, but collectively they pose a risk to the longer-term trajectory of growth. The low-price environment has trumped these for the time being, but what will be the lasting impact and how will producers respond? How might this affect the labor force?
Costs are falling in the current low oil price environment, but even when prices recover, there is an opportunity for the oil sands to avoid the cost pressure of the recent past. Producers in this environment are focused on cost structures and on operational excellence; subsequently, costs are falling. In 2015, we saw an overall operating cost reduction of approximately 20%. An average in-situ facility went from approximately USD 13/bbl to USD 10/bbl, and a mining operation went from USD 42/bbl to USD 32/bbl from 2014 to end of 2015 (inclusive of the reduction in the Canadian dollar).
Capital expenditure was reduced approximately 6% in 2015, which likely would have been larger if it were not for currency depreciation which increased the cost of key inputs such as steel and pipe. Additional reductions are possible as industry looks to increase standardization of replacement parts, processes, and the design of future projects and expansions. Many producers are looking at redefining what level of maintenance is necessary for operations.
Conceivably, not all the reductions are going to be retained. Some reductions are the result of a slow market, allowing access to more efficient equipment, labor, and services. As prices rise and growth returns, some of those reductions will consequently reverse. Yet, costs are poised to reset with potential for lower cost and more efficient growth in the future. The challenge that faces the Canadian oil sands is that costs are falling globally, and in spite of best efforts by producers, the relative competitive position of oil sands in the world could still shift.
What does the future of oil sands look like for growth and human resources?
As we look to the future of the Canadian oil sands, we see a picture that is likely to be different from that of the past. Over the past 15 years, oil sands production grew steadily—from approximately 600,000 bbl in 2000 to more than 2.3 million bbl in 2015. Over that period, the oil sands also experienced cost escalation, with IHS estimating that costs escalated more than 70% from 2000 to 2014. To put that in perspective, that means that a USD-2-billion project in 2000 cost USD 3.4 billion in 2014.
Investments that were made to grow oil sands production also expanded associated infrastructure and capacity in Alberta. The service sector and labor market grew alongside production, and at the start of the price collapse was much larger and more capable than it was in the past. Alberta, even today, is much more capable of supporting growth than it has been at any time in the past.
The future of oil sands is expected to be dominated by brownfield projects. Smaller in scale, cheaper to build, and quicker to bring to production, these projects coupled with Alberta’s capacity may be setting up the oil sands for a period of production growth with more moderate cost escalation. In addition, it is possible some producers may shift away from the distinctive phased nature of expansions toward a process of continuous capacity creep, or continuous debottlenecking. These factors may contribute to help keep cost pressures in check in the future.
There is a risk that this price environment could negatively impact the established labor and service sector capacity in Alberta. Lower prices are lowering activity and forcing companies to make difficult decisions, including rationalizing their equipment and labor. As this occurs, the ability of Alberta to support projects could diminish. It is difficult to say to what degree capacity will be impacted, or how quickly it could be ramped up in the future.
Corporate knowledge and senior leadership may also be impacted in this downturn. The oil industry in Alberta is notorious for senior leaders retiring more than once due to the cyclic nature of commodity price. If indeed these senior leaders retire for the last time, considerable corporate knowledge and experience will be lost by the industry. The questions are “How much knowledge will remain, and how quickly could capacity be ramped back up?”
Is this a repeat of 1986? If not, what is different?
This is not 1986 when a generation of workers was lost to different industries. The oil industry in Canada is significantly different from the one 3 decades past. In those days almost the entire industry was made up of conventional assets. When prices fall, these assets are more easily trimmed back (e.g., by simply laying down rigs). Oil sands projects are large, established facilities that require ongoing labor and capital investment to maintain production. These oil sands facilities are a much larger piece of today’s industry, which is helping to blunt the full extent of the low price impact on workers, the service sector, and the economy.
Oil sands projects are built to last a minimum of 30 years. When that investment is made, it is made with the expectation that price volatility will occur over the life of the project. Looking back 30 years, there have been numerous events that spurred volatility in the market, including the first and second Gulf wars, the fall of the Berlin wall, 9/11, hurricanes Katrina and Rita, and the great recession. The low prices over the past year will stress test oil producers globally, yet oil sands production will continue. Most oil sands production is backed by what we consider large oil sands companies or global majors. These types of companies typically have deep pockets and a large, diverse portfolio of assets such as downstream refining or perhaps even non-oil assets that can help offset low prices. That being said, it is one thing to anticipate a protracted, low price environment; it is entirely another thing to live through it.
Following the Suncor acquisition of Canadian Oil Sands in January 2016, should we expect increased mergers & acquisitions (M&A) activities in the near future?
In general, there are two ways for an oil producer to grow production. One is to find a resource and develop it, and the other is M&A. In a low commodity price environment, the cost to go out and acquire existing production may become preferential over the cost to develop new production. As oil prices remain low, M&A will likely occur, but the scale of most oil sands operators makes it difficult to foresee large-scale M&A in the sector.
Joint ventures are certainly a very successful way to lower the upfront costs and risk, but are hard to predict. In general, we see most of the future growth coming from expansion of existing facilities or brownfield developments. This would likely be a perpetuation of the existing relationships between partners that are already in place.
In addition to commodity price woes, the oil sands megaprojects have seen a change in both the provincial and federal governments in 2015. There has been increased focus on greenhouse gas (GHG) impact, implications on the royalty framework, and market access for these landlocked assets. How are these additional hurdles approached by an already challenged industry?
GHG policy in general represents an incremental cost to the industry. If this cost is not shouldered equally by various types of production, domestically and internationally, it could disadvantage one source of supply over another. However, if the world is moving toward less carbon, GHG policy can serve to incentivize innovation and technologies that help reduce emissions and thus make companies more efficient and competitive in the lower carbon future.
Alberta has rolled out new climate policies and conducted a review of the existing royalty framework for the province. The government released the royalty report in January after a detailed review by expert panel members. Included in the report are recommendations to revisit directives concerning how much of an oil sands resource must be recovered by an operator. Changes to these rules may provide producers greater flexibility to high-grade their oil sands resources, helping them lower costs by extracting only the most economic and consequently lowest-GHG-intensity oil in place.
Pipelines exiting Western Canada are running at capacity, and market access remains an elusive objective for oil sands producers. Rail and pipeline shipments are both safe forms of transport. However, pipelines are viewed by many as advantaged over rail in cost and reliability—seldom being affected by weather or congestion. From a refinery standpoint, a pipeline is also preferred when only a few days of feedstock may be stored on-site at any given time. Several pipeline options continue to advance and only time will reveal the fate of these remaining options, two heading west to the Asia Pacific region [Kinder Morgan Trans Mountain Pipeline Expansion and Enbridge Northern Gateway] and one eastward [TransCanada Energy East].
Kevin Birn is part of the IHS North American Crude Oil Markets’ team and leads the IHS Energy Oil Sands Dialogue. His expertise includes Canadian oil sands development, oil sands cost and competitiveness, crude oil markets, crude-by-rail, crude oil life cycle analysis, and Canadian energy and climate policy. Birn has authored several reports on or associated with development of the Canadian oil sands for major news outlets such as The Wall Street Journal. He holds an undergraduate degree in business and a graduate degree in economics from the University of Alberta. Birn’s oil sands research is publically available from IHS at
http://www.ihs.com/oilsandsdialogue.