Consolidation Continues; Output Rises
With last year’s wildfires overcome, Canada’s oil sands industry is continuing its growth trend, while foreign producers have second thoughts and product transport infrastructure remains on the critical path
By Simon Walker, European Editor
The principal beneficiary of that consolidation bout was unquestionably Suncor, which increased its holding in the Syncrude joint venture — and by default its attributable bitumen production — through its acquisition of Canadian Oil Sands Ltd. and Murphy Oil’s stake in the joint venture.
Thus far this year, Canadian Natural Resources has been the main acquirer, taking advantage of Shell’s decision to reduce its oil sands interests to a bare minimum, a policy shared with another foreign-based oil major, ConocoPhillips, which has also cut back on its participation. Add to that Total’s sale in 2015 of a stake in the Fort Hills mining project to Suncor, and the message is becoming clear: players from outside Canada are increasingly viewing the oil sands as being non-core to their businesses. Looked at another way, the research firm Wood Mackenzie has calculated that more than 70% of oil sands production is now held by Canada’s four largest producers: Suncor, Canadian Natural, Imperial Oil and Cenovus Energy.
All the same, the ownership realignments do not seem to have slowed the growth in oil sands output. According to data from the Canadian Association of Petroleum Producers (CAPP), production of bitumen and upgraded crude oil in 2016 rose slightly to reach a total of 2.4 million barrels per day (bbl/d), of which 1.028 million bbl/d were won from mining operations and 1.372 million bbl/d using in-situ recovery techniques. Raw bitumen production totals were 1.147 million bbl/d and 1.391 million bbl/d, respectively, giving an overall total of 2.538 million bbl/d. Once diluents had been added, the oil sands industry fed a little more than 3 million bbl/d of products to Canada’s pipeline and transport network.
In March, Shell announced it was selling all of its Peace River in-situ and undeveloped oil sands interests in Canada, and reducing its share in the Athabasca Oil Sands Project (AOSP) from 60% to 10%. The cost to Canadian Natural was around US$8.5 billion (C$11.1 billion), comprising US$5.4 billion in cash plus US$3.1 billion in Canadian Natural shares.
The AOSP — previously held 60% by Shell, and 20% each by Chevron and Marathon — includes the Muskeg River and Jackpine mines and extraction operations and the Scotford upgrader and Quest CCS project. Its production capacity at both the mines and the upgrader is 255,000 bbl/d.
Comments made at the time by Shell’s CEO, Ben van Beurden, threw some light on the company’s strategy. “This announcement is a significant step in reshaping Shell’s portfolio in line with our long-term strategy,” he said. “We are strengthening Shell’s world-class investment case by focusing on free cash flow and higher returns on capital, and prioritizing businesses where we have global scale and a competitive advantage.”
In other words, Shell did not see the potential for making much money out of its oil sand operations any time soon.
Shortly after Shell’s move, Cenovus Energy announced it was to acquire ConocoPhillips’ 50% interest in the FCCL Partnership, the companies’ jointly owned oil sands venture that was operated by Cenovus. The price paid totaled C$17.7 billion, made up of C$14.1 billion in cash plus Cenovus shares, with the deal including most of ConocoPhillips’ Deep Basin conventional oil and gas assets in Alberta and British Columbia.
Two of the oil sands properties involved, Foster Creek and Christina Lake, are already in production, with capacities of 180,000 bbl/d and 210,000 bbl/d respectively, while the Narrow Lake property remains at the engineering stage of development.
“With the completion of this transformational deal, we now have full control of our best-in-class oil sands projects and an exciting new growth platform in the Deep Basin that provides us with significant short-cycle development opportunities to complement our long-term oil sands growth portfolio,” said Brian Ferguson, Cenovus president and CEO. “As a result of this transaction, we’ve now doubled our production and reserves base.”
In February, the company wrote down the value of its oil and gas reserves by 19%, including 3.5 billion bbl at Kearl and a further 200 million bbl at its Cold Lake in-situ recovery operation. However, as was subsequently pointed out in the media, the removal of these reserves from the “proven” category was more to do with the way that the U.S. Securities and Exchange Commission (SEC) requires companies to categorize reserves than anything else.
In essence, the SEC rules state that companies must value their reserves based on the average commodity price for the preceding calendar year. By contrast, comparable Canadian NI 51-101 criteria permit companies to use seven- to 10-year price forecasts when valuing their reserves — the equivalent, as one commentator in the Calgary Herald put it, of “the U.S. method being akin to driving down the highway while looking in the rear-view mirror while Canada’s approach is fixed on the future.”
Hence, given the low oil price during 2016, ExxonMobil had no option but to remove virtually all of its oil sands reserves from “proven,” with the opportunity for their reinstatement once prices rise above break-even again.
And that in turn raises some interesting 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 published a report that looked at this and other issues relating to oil sands development costs. In Oil Sands Cost and Competitiveness, 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 often expressed as the price per barrel of oil required for an investment in new oil production to break even (with a 10% internal rate of return).”
According to IHS, “on average in 2015 a new oil sands mine required a West Texas Intermediate (WTI) price between US$85 and $95/bbl to cover all the costs associated with a project with capacity to produce 100,000 bbl/d of diluted bitumen. An in-situ SAGD project requires between US$55 and $65/bbl to produce 30,000 bbl/d of diluted bitumen,” the company went on, adding that “SAGD expansions require prices about US$5/bbl less.”
The company qualified these estimates 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 facility 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 operators 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 reported record low annual average operating 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 company 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 activities relating to its Phase 3 expansion.
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, minority 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 equipment and materials were on site, and all major vessels and process modules had been installed at that stage.
However, Teck also noted that the impact 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 bitumen 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-added carbon-rejecting solvent-extraction technology that will allow the operation to produce a higher quality and lower greenhouse gas (GHG)-intensity bitumen product that can be sold directly to the market, Suncor stated in its annual report. The first of three secondary-extraction units should be on stream by the end of 2017, with the other two scheduled to be commissioned in the first half of next year. Ramping up to 90% of the expected capacity will continue during 2018, with Suncor evaluating ways of reducing the ramp-up period.
Meanwhile, Canadian Natural achieved record average annual production during 2016 of about 123,000 bbl/d of synthetic crude oil as the ramp-up of its Phase 2B expansion was completed on time and budget late in the year. However, the average masked a significant upturn in daily capacity as the expansion came on stream, with the company reporting output of more than 178,000 bbl/d during the fourth quarter — a figure that rose to 195,000 bbl/d in January.
Nearly 90% complete at the end of 2016, Horizon’s Phase 3 expansion will add a further 80,000 bbl/d of synthetic crude oil capacity, and is scheduled for commissioning in the fourth quarter of 2017.
ExxonMobil and Imperial Oil also benefited from expanding capacity at Kearl, where average output rose from 72,000 bbl/d in 2014 and 152,000 bbl/d in 2015 to 169,000 bbl/d last year.
In March, ExxonMobil announced a joint venture with the Korean steelmaker, Posco, to mass-produce and supply high-manganese steel slurry pipes for transporting oil sand raw materials. The two companies have been working together on the project for the past five years, including field trials at Kearl on a 1.2-km-long pipeline.
With abrasion from the sand-bitumenwater slurry a major issue, the high-manganese pipe has demonstrated wear resistance five times greater than those made of conventional steel. According to Posco, it expects benefits to include lower maintenance costs and less downtime for pipeline section replacement.
...and on Hold
Meanwhile, Total’s Joslyn North, Suncor’s Voyageur South, Shell’s Pierre River and Teck’s Frontier projects are all either on the back-burner or slowly wending their way through regulatory reviews, although Teck announced in January it has signed an agreement with the Fort McKay Métis community over participation in any future project.
Designed to replace depleted capacity at Suncor’s existing surface mines, Voyageur South is unlikely to come on stream much before the late 2020s, the company has stated, much the same timeframe that Teck has for spending an estimated US$20 billion on developing Frontier. However, oil prices will need to rise to between US$70 and US$80/bbl before large oil sands mines like Frontier can be economically viable, said Mark Oberstoetter, Canadian oil and gas analyst at Wood Mackenzie, quoted by the energy intelligence firm JWN earlier this year.
“In our current outlook, we don’t have any new-build mines,” Oberstoetter said. “We could see some bottlenecking-type expansions from the existing ones, but we think investors and capital markets will focus more on U.S. tight oil, deepwater sources, in-situ steam-assisted gravity drainage (SAGD) and SAGD expansions before tackling a large mine.
“When we run the numbers and costs and the economics, it doesn’t make sense to go ahead and spend $20 billion. The break-even prices are going to be higher than we have in our forecast,” Oberstoetter added.
The Pipeline Conundrum
As noted in previous E&MJ reviews of the oil sands industry, transport systems for both synthetic crude oil and diluted bitumen (“dilbit”) from northern Alberta to refineries in the USA and in other parts of Canada have the potential to place constraints on output, especially as production capacity continues to grow. President Donald Trump’s reversal of the previous U.S. administration’s refusal to permit completion of the controversial Keystone XL pipeline through the Midwest removed one potential bottleneck there, although the state administration in Nebraska still has to grant permits for the proposed pipeline route there.
Another report from IHS Markit, published in April and entitled Piplines, Prices and Promises, looks at how pipeline access, or the lack of adequate pipeline capacity, has the potential to impact Western Canada’s oil industry, including the oil sands. “Transportation constraints have, in the past, contributed to price volatility and a loss of economic value for western Canadian producers,” the report stated, before going on to explain the effects of the long lead times needed for high-volume pipeline construction. “The average pipeline review process, from application to early 2017, has spanned more than five years, with no major additions constructed in recent years,” the report pointed out. “The processes have spanned more than eight years for the Keystone XL pipeline; more than six years for Northern Gateway; more than four years for the Alberta Clipper Expansion; more than three years for the Trans Mountain Expansion; and two years for Energy East, which is still in the early days. This does not include the time prior to application for business development and for front-end engineering and design.”
However, there is also a note of caution: “Although there is a new sense of pipeline optimism, none of the proposed projects is a done deal,” they warned. “Pipeline projects remain controversial and will likely face ongoing challenges from opposition and litigation.”
The alternative to pipelines, transporting crude oil by rail, reached a peak in 2014, the report noted, since when volumes have reduced. In some cases, operators have managed to move more Canadian crude through existing pipelines, an opportunity helped by a fall in conventional crude output while oil sands crude production continues to increase. In addition, operators have been able to increase throughput by using drag-reducing agents that can increase the flow of crude through a pipeline, for example.
Nonetheless, the report noted, “Western Canadian volumes continue to build, and the pipeline system is expected to become increasingly constrained. Toward the end of 2016, U.S. crude oil imports from Canada exceeded 3.5 million bbl/d — the highest on record.
“Despite the optimism, there is no guarantee that these projects and other expansions will advance as proposed,” the report concluded. “Only time will tell whether the pipelines continue to meet delay or if the necessity of new infrastructure for western Canadian oil producers is realized.”
Funding for Greenhouse Gas Emissions-reduction Projects
In July, Emissions Reduction Alberta (ERA) announced the availability of C$50 million in funding for technologies to help the oil sands industry to meet its greenhouse gas emissions limit by 2030. Applications for funding through the organization’s Oil Sands Innovation Challenge have a deadline of early September for submission.
“ERA knows that improving both environmental and cost competitiveness is key to the continued success of Alberta’s energy sector,” said ERA’s CEO Steve MacDonald. “We have worked with our industry partners to identify the gaps that technology can close, and developed this funding opportunity to help accelerate the demonstration, scale-up and deployment of the most promising solutions.”
“Oil sands innovation was crucial in the past and remains key to Alberta’s economic future,” said Shannon Phillips, minister of environment and parks and the minister responsible for the Climate Change Office. “Improvements in technology and efficiency will lead to made-in-Alberta solutions and set Alberta up for a healthy, prosperous future.”
“Albertans were the ones who determined how to get the oil out of the sand and made-in-Alberta innovation is going to get the carbon out of the barrel,” said Margaret McCuaig-Boyd, Alberta minister of energy. “This is a timely investment that will pay huge dividends in strengthening our province’s position as a leader in responsible energy development.”
According to ERA, the focus of the Oil Sands Innovation Challenge is on breakthrough technologies for surface mining as well as in-situ operations that are now ready to go to a field pilot, demonstration or first-of-its-kind deployment. The intent is to reduce both greenhouse gases and costs by investing in opportunities — including alternative steam generation methods, advanced reservoir production technologies and novel surface mining processes.
ERA, which receives grant funding from the Alberta government, will leverage its C$50 million in funding. Industry and other partners will be required to at least match this commitment, creating the opportunity for more than C$100 million in combined new investment.