Tar Sands/Oil Sands
Some of the big international fossils that recently pulled out of hugely expensive, long-term capital commitments to Alberta’s tar sands/oil sands are instead investing heavily in U.S. shale-oil deposits, whose development and production costs are a fraction of those in Canada.
“ExxonMobil Corporation, Royal Dutch Shell Plc, and Chevron Corporation are jumping into American shale with gusto,” Bloomberg reports. The three global giants are “planning to spend a combined $10 billion this year, up from next to nothing only a few years ago.”
The majors’ move into shale represents a change both for them and for the smaller, wildcat-type operations that have dominated shale oil plays in the Dakotas and Texas until now, the news agency observes. “If the big boys are successful, they’ll scramble the U.S. energy business, boost American oil production, keep prices low, and steal influence from big producers such as Saudi Arabia.” Other countries like Canada “would have to contend with lower oil prices.”
The attraction of low cost-of-entry shale has already shifted the investment outlook for Canada’s tar sands/oil sands, among the world’s costliest fossil resources to produce. While Chevron continues (for now) to have an active presence in northern Alberta, both Exxon and Shell have been stepping back.
In February, Exxon wrote off 3.6 billion barrels of its Alberta reserves, conceding that they could no longer be developed profitably. Then earlier this month, Shell announced it would sell off almost all its tar sands/oil sands holdings for US$7.25 billion.
Shell now “plans to spend about US$2.5 billion a year, or about one-tenth of its total spending,” developing U.S. shale properties, Bloomberg reports. “Exxon said it plans to spend one-third of its drilling budget this year on shale, with a goal to lift output to nearly 800,000 barrels a day by 2025.” For comparison, Suncor, the largest tar sands/oil sands operator, produces about 550,000 barrels per day of synthetic crude.
The additional investment is likely to push U.S. domestic oil production above 10 million barrels per day by the end of 2018, Bloomberg predicted, “a level surpassed only twice, in October and November 1970.”
The fossil industry’s worst recession in decades will make a difference of less than 1.7% when Finance Minister Bill Morneau tables his anticipated $300-billion federal budget in the House of Commons today.
It’s not that the impact of the downturn in world oil prices since 2014 has been negligible. “Over the last few years, the decline has cost the Canadian economy $112 billion, which works out to $6,200 for every working person,” CBC News reports.
But that figure is a nominal mathematical average. Most of the real loss has been sustained in oil-producing regions—and most especially Alberta, which faces a $10-billion budget deficit as it waits for oil-based revenues to pick up. Meanwhile other sectors, notably manufacturing, have benefitted as the Canadian dollar fell along with oil activity, with auto manufacturing resuming its place as the country’s leading exporter.
The slump has had an undeniable impact on the federal government’s finances, CBC concedes. Ottawa has given nearly a billion dollars in extraordinary direct aid to Alberta, and seen outlays for social services and employment insurance payouts increase. Its own substantial fuel costs have dropped, however.
As a net result, CBC calculates that world crude prices of around US$50 a barrel cost the federal government about C$5 billion a year in revenue compared to prices at US$80 a barrel—out of a roughly $300-billion budget. That is, 1.666…%.
Alberta will run a C$10.3-billion deficit in 2017-18 and depend on steadily increasing oil prices to eventually balance the books, under the provincial budget released last Thursday by Finance Minister Joe Ceci.
“To no one’s surprise, Alberta did not slay the deficit dragon in its most recent budget. Or even introduce new weaponry for deficit slaying, or offer any new solutions to the problem,” CBC reports. “Instead, the red ink has spread and the hope seems to be that black gold will one day wash it away. Alberta is leaning on its old standby—oil.”
Media, economists, and opposition critics all described the release as a “fingers-crossed” budget that “promises a hospital, new schools, and more money for seniors and social services,” Canadian Press notes, but relies on a commodity price that any jurisdiction can try to predict, but no jurisdiction can control.
“There are no plans to balance outside of oil prices,” University of Calgary economist Ron Kneebone told CBC. “The only way out of it is to hope that oil prices come back to the 80, 90-dollar level, which no one seems to be expecting any time soon.”
UC economist Trevor Tombe added that if oil prices stabilize in their current range of about US$50 per barrel, Alberta can expect an indefinite run of $10-billion annual deficits. Ceci is projecting a balanced budget as of 2023/24, CBC reports, “as the economy recovers and economic diversification takes hold. As well, the province is optimistic about what new pipeline capacity will mean for corporate and government revenue.”
But that depends on oil prices hitting $68 per barrel by 2020. On Friday, Todd Hirsch, chief economist at the provincially-owned ATB Financial, said he foresaw oil stabilizing at $55 per barrel, not a high enough price to restore the Alberta energy sector’s previous trajectory.
“It kind of shifts it now to a lower gear, and it takes on a different role for the economy,” he told the Conference Board of Canada’s Western Outlook 2017 conference. “$50 to $55 stabilizes the industry, the petroleum sector becomes a stable backbone of the economy, but not the growth engine.”
At (virtual) press time, benchmark West Texas Intermediate crude stood at US$48.78 per barrel.
The province is also projecting that conventional oil and gas production will shrink in the years ahead, while tar sands/oil sands output grows 32%, from just under 2.5 million barrels per day this fiscal year to 3.3 million in 2019-20. That’s in spite of projections last month that the province will blow through its vaunted cap on tar sands/oil sands emissions by 2026.
“We are laying the foundation for a return to economic growth,” Ceci said. “Are we out of the woods? No. We will continue to bring the deficit down, to balance thoughtfully and prudently, and we will do so without sacrificing the supports and services families need.”
The province “is investing heavily in tax credits and other financial incentives to diversify the economy and get off what it calls the ‘oil and gas roller coaster,’” CP notes. “A new carbon tax, launched in January, is expected to bring in $5.4 billion over the next three years, to be reinvested in green projects from energy-efficient light bulbs for homeowners to new rapid transit lines.”
CBC tracks 28% of the carbon levy revenue going back to households in rebates, 24% to green infrastructure, 19% to grants to renewable energy and cleantech companies, and 11% to energy efficiency.
In spite of Donald Trump’s January 24 executive order inviting TransCanada Corporation to reapply for permission to build the Keystone XL pipeline, there are three good reasons to think the pipeline may never be built, DeSmog Canada reported last week.
“U.S. approval, while a great leap forward for TransCanada, doesn’t guarantee the Keystone XL pipeline will ever be built,” DeSmog reports, citing economics, landowners, and environment and climate concerns as the three barriers still standing in the project’s path.
Under the heading of economics, DeSmog cites Enbridge CEO Al Monaco’s recent statement that Canada will only need two more pipelines, including the recently-approved Line 3 pipeline expansion, to meet foreseeable demand through the middle of next decade. Other analysts agree, pointing to the huge financial gambles associated with long-term pipeline contracts and the recent decisions by several international fossil companies to abandon their tar sands/oil sands projects.
“There will be no more greenfield projects if the price of oil stays at what it is,” said unconventional fuels specialist David Hughes, formerly with the Geological Survey of Canada.
“The economic case is not there for the three pipelines,” agreed North American climate mitigation lead Amin Asadollahi of the International Institute for Sustainable Development. “Should the massive expansion happen, I don’t think the financial benefits for the sector…would be there.”
First Peoples and non-Indigenous landowners are also gearing up to fight Keystone 2.0 in the courts, just as they did in the first round, DeSmog reports.
“In 2015, over 100 Nebraska landowners sued TransCanada over the proposed use of eminent domain; the company eventually withdrew from the case and its plans for eminent domain, but it appears such conflicts will reignite with the federal approval,” DeSmog notes. “Landowners have already started to meet to plot out how to resist the pipeline.”
Hughes and Greenpeace Canada energy and climate campaigner Keith Stewart also point to the prospect that another 830,000 barrels per day of tar sands/oil sands production to feed Keystone would drive Alberta above its legislated, 100-megatonne emissions cap—which could ultimately lead to court challenges.
“We’re actually looking at a variety of ways to put pressure—including possible legal challenges—on companies that are basing their business model on the failure of the Paris agreement,” Stewart said. “If you’re telling your investors, ‘We’ll make money because the world will not act on climate change’, are you actually engaging politically to try to produce that outcome? Are you lobbying against climate policy?”
Tar sands/oil sands production in northern Alberta hit a record high of 2.79 million barrels per day in November 2016, according to data released this week by the Alberta Energy Regulator.
“The November high was driven by growth in both mining and in situ production,” JWN Energy reports. “Production is expected to reach 3.0 million barrels per day by 2020 as major projects that were under way before the [energy price] downturn are completed.”
JWN cites production increases at sites owned by ConocoPhillips Canada, Cenovus Energy, Devon Canada, and Husky Energy.
Royal Dutch Shell announced yesterday that it will sell off almost all its holdings in the Alberta tar sands/oil sands for US$7.25 billion, becoming the third major fossil in recent weeks and the fourth in three months to scale back their bitumen operations.
“All of the company’s oil sands interests apart from a 10% stake in the Athabasca mining project will be sold to Canadian Natural Resources Ltd.,” Bloomberg reports. The company will continue operating one heavy oil upgrading plant, as well as the Quest carbon capture and storage project.
The deal is a part of a wider effort by Shell to offload US$30 billion in investments after its blockbuster purchase of BG Group Plc in 2015.
“The sale marks another step toward [CEO Ben] Van Beurden’s goal of preparing Shell for a world of lower oil prices and tighter restrictions on carbon emissions,” the news agency states. Alberta’s tar sands/oil sands “lured investors in the past decade as the surge in crude prices above $100 made the difficult extraction process economic. They’ve since fallen out of favour amid a two-year price slump.”
A separate Bloomberg report, carried by the Financial Post, indicates Canadian Natural Resources Ltd. will pay C$12.7 billion to buy tar sands/assets properties from Shell and Marathon Oil Corporation. CNRL President Steve Laut declared that “this transformational acquisition strengthens our robustness and sustainability,” adding that “by any measure, these are world-class assets.” But Bloomberg notes the deal was unveiled on a day when the benchmark price of West Texas Intermediate crude fell back below US$50 per barrel.
“As some producers shift capital away from Northern Alberta toward lower-cost, quicker-return resources such as U.S. shale, Canadian companies without the same global reach are staying put and filling the void.”
Greenpeace Canada Senior Energy Strategist Keith Stewart said Shell “is reading the writing on the wall, and Canadian politicians would be wise to take note: There isn’t much of a future for bitumen in a low-carbon world. Fortunately, Canada can be a green energy leader, and the sooner we get on with it, the less disruption we’ll see to our economy and communities.”
Greenpeace spokesperson Ben Ayliffe added that “this news shouldn’t really surprise anyone—not only is producing oil from the tar sands highly polluting, it’s also extremely expensive, and Shell’s Canadian projects were always going to be on the wrong end of the cost curve.
“Despite being warned that the tar sands made no sense as far back as 2010, Shell continued to throw good money at bad investments, only to finally admit they’re not viable after all.”
The federal Conservative Party’s deputy natural resources critic, Shannon Stubbs, said Shell’s pullout “speaks to the cost factors that are being exacerbated by bad public policy and bad regulations at both provincial and federal levels of government, which is driving away investment.” But Shell Canada President Michael Crothers stated that the “pipeline situation didn’t play into our thinking at all. We believe that we will have adequate pipeline capacity. This was a decision based on, as I said earlier, on our strategy around simplifying the portfolio, focusing in on parts of the business where we thought we could reach globally competitive scale.”
On a conference call from Houston, where he was attending the CERAWeek conference, Natural Resources Minister Jim Carr “sought to boost investor confidence in the oilsands,” iPolitics reports. “Shell said…their reasons were motivated by internal business concerns and not by public policy in Canada, not by competitiveness, not by regulation,” Carr told reporters. “We know that our oilsands are the third-largest oil resource in the world. The deal is evidence of the oilsands’ ongoing value to investors, and we’re very pleased that Canadian Natural Resources has stepped in.
The latest in a series of studies by an eminently qualified environmental geochemist has given weight to arguments minimizing the impact that tar sands/oil sands operations have on the Athabasca River, prompting pushback from established stars in the field.
The discrepancy in results and the ensuing controversy may trace back to the time of year when the water quality measurements were gathered.
Bill Shotyk, former director of the Institute of Environmental Geochemistry at Heidelberg University and now the Bocock Chair in Agriculture and Environment at the University of Alberta, says his sampling of Athabasca River water at 13 sites above and below major tar sands/oil sands facilities “found little difference between lead and arsenic levels in either direction from the mines,” the Canadian Press reports via CBC News.
Shotyk’s research was funded in part by “an industry group focused on environmental research,” CP adds, but the scientist insisted that “our work has not been affected by the source of funds. The folks funding our work simply want the facts. They want to see quality science, and that’s our goal, too.”
The water was analyzed “with equipment capable of measuring water contaminants to parts per quadrillion,” the report notes. Asked whether concerns about contaminants in the river from tar sands/oil sands operations may be overstated in light of his findings, Shotyk answered unequivocally: “Absolutely. No question.”
Shotyk’s researchers found that levels of lead an arsenic were the same upstream and down from tar sands/oil sands mines. “Levels of lead dissolved in the water,” CP reports, “were vanishingly small—comparable to those found in Arctic ice that is thousands of years old.” Some heavy metals associated with bitumen—vanadium, nickel, molybdenum and rhenium—were also present at “tiny” levels.
Other equally eminent scientists, however, were quick to challenge Shotyk’s findings.
Limnologist David Schindler, a widely-admired elder statesman in the field, called into question his U of A faculty colleague’s choice of autumn, when river levels are low and little runoff occurs from nearby landscapes, to conduct his sampling.
Schindler, whose own research has exposed rising levels of many water and airborne contaminants downstream and downwind from tar sands/oil sands operations, told CP that was precisely why he had sampled during the peak runoff season in summer. “That is almost certainly why we were able to detect higher arsenic near and downstream of the oilsands, and they [Shotyk’s team] were not.”
The controversial new research also looked only for heavy metals and arsenic fully dissolved in the water column, not for the total concentrations of those materials, including metallic particles and sediments. In an earlier paper, the news agency reports, Shotyk argued that “unless a metal is in solution, organisms simply don’t absorb it. The same holds true for arsenic concentrations. A third [Shotyk paper] comes to a similar conclusion for snowmelt—that any heavy metals entering the Athabasca do so as particles, often bonded to clay minerals.”
Aquatic biologist Jules Blais of the University of Ottawa challenged that assertion. Blais’ lab “has exposed aquatic animals to sediments containing oilsands materials,” CP reports. Those exposed to non-dissolved sediments, the researcher said, “have higher metal accumulations than those that are screened away from the sediments. We know that the sediments are a source of exposure.”
The level of pollution in the river has been a sensitive issue for the industry and for Canada’s government, which has repeatedly shut down efforts to have the North American Commission on Environmental Cooperation investigate the subject, as it is empowered to do under a side deal to the North American Free Trade Agreement.
Royal Dutch Shell has become the latest tar sands/oil sands operator to call a halt to new project development in Canada’s tar sands/oil sands.
In an interview published this week, Bloomberg reports, CEO Ben Van Beurden said his company “is unlikely to take on new oil sands projects as it maintains a grip on costs after crude’s crash forced competitors to write down Canadian reserves.” Both Conoco Phillips and ExxonMobil recently “de-booked” significant reserves in Alberta’s tar sands/oil sands region, indicating they no longer consider them economical to develop.
Citing Van Beurden, the outlet reported that “while Shell’s existing oil sands operations generate strong cash flows, the expense of developing new projects discourages additional investments.”
Investor jitters over Canada’s high-cost synthetic crude are worsened by political uncertainty south of the border, the Globe and Mail reports: “The spectre of a border adjustment tax championed by U.S. Republicans remains a top concern for its potential to render Canadian crude exports less competitive than shale production in the United States. Pipeline constraints in key exploration zones and big reserve writedowns by major oil sands producers have only added to pessimism dogging the sector.”
“It certainly doesn’t get anyone who’s not in the space thinking they should be looking at it,” Rob Bedin of Calgary’s RS Energy Group told the paper.
Oil prices are inching back up from their 2014 trough, but are still far from the US$80-per-barrel range at which many bitumen extraction operations begin to be comfortably profitable, JWNEnergy observes. But big incumbents are staying put and digging in. Suncor Energy, Canadian Natural Resources, Cenovus Energy, Imperial Oil, and MEG Energy have all “sent strong signals they are all-in” on the tar sands/oil sands, the industry news source reports, “by either bulking up their holdings or announcing shorter-cycle expansion plans.”
JWN sees “large-scale projects sanctioned prior to the downturn” being completed this year, but no ground broken for big new developments. Instead, it says, the industry is focused on “reducing costs, deploying new technologies and streamlining operations.”
Those objectives all favour size, comments Jackie Forrest, vice-president of energy research at ARC Financial in Calgary: “If you’re going to be the low-cost supplier, scale matters. I think you will see more consolidation in order to get economies that come from greater scale.”
That suggests a period of corporate “growth” by cannibalism in the tar sands/oil sands, as the biggest players double down on a competition for market share by picking up remaining smaller operators, a variety of reports suggest.
“I think the large players will remain the large players,” agrees Greg Pardy, who co-leads energy research for RBC Capital Markets. “If anything, the larger companies become bigger at the margin. But I don’t think over the next two or three years that you’re going to see massive changes coming.”
ConocoPhillips has become the second fossil major in a week to downgrade its estimate of its tar sands/oil sands reserves, taking more than a billion barrels out of its inventory because of low global oil prices.
“The U.S. oil major said developed and undeveloped reserves of bitumen—the heavy viscous oil found in northern Alberta’s remote oil sands—totalled 1.2 billion barrels at the end of 2016, down from 2.4 billion barrels at the end of 2015,” Reuters reports, in a story picked up by the Financial Post. In its quarterly filing with the U.S. Securities and Exchange Commission, the company actually “debooked” a total of 1.75 billion barrels.
Then again, the move may be temporary. Executive Vice President Al Hirshberg told investors the company would reinstate the reserves if current global oil prices hold. Calgary-based GMP FirstEnergy analyst Martin King “said the debooking likely had more to do with SEC rules requiring companies to evaluate economic reserves at year-end,” the news agency notes, although “the fact that the oil sands make up 70% of the reduction underlines how much of Canada’s resources are uneconomic in a weaker oil environment.”
RS Energy Group Chief Economist Judith Dwarkin commented that the tar sands/oil sands “are at the upper end of the cost curve,” so Conoco’s action “may or may not speak to future similar events from other producers.” (h/t to Josh Axelrod for pointing us to this story)
Canada’s oil and gas industry is on its way into a jobless recovery, with fossils responding to marginally higher global prices by looking to restart their operations with lower labour costs, according to a survey by Ernst & Young and the Haskayne School of Business.
The study “reflects a widespread expectation in the oilpatch that the oil price recovery is likely to be a jobless one, where companies—spooked by continued commodity price volatility—continue to focus on cutting costs,” the Financial Post reports. Despite oil prices “recovering” more than US$50 per barrel, companies that have already slashed their work forces by up to 50% may still be considering further reductions.
“We’re seeing changes around, is there a better way of doing this? Is there a better way of organizing how we get work done?” said Lance Mortlock, EY’s Canadian oil and gas strategy services leader. With options like robotics and process automation on the table, he added, fossil executives are looking at “different ways that you can do work—better, faster, cheaper—with fewer people involved.”
Of the 72 companies in the survey, 80% had gone through staff cuts, and 9%—mostly in oilfield services and upstream exploration—laid off more than 50% of their work force. The fossil price crash cost Alberta 30,000 direct jobs.
The Financial Post report is consistent with the trend in Texas, where the New York Times says the fossil industry “is embracing technology and finding new ways to pare back the labour force.” With oil prices beginning to recover, West Texas oil fields have been gearing up their operations. But “while there is a general sense of relief in the oilpatch that a recovery is gaining momentum, discussions at company meetings and family kitchen tables are rife with aching worries, especially among those who are middle-aged with no more than a high school education.”
The Times profiles Eustasio Velazquez, a blue-collar worker who spent 10 years laying cables for seismic companies conducting seismic tests for the fossil industry. He was replaced by what the New York newspaper describes as “cheaper, more reliable automated tools” in 2015, and now, “I don’t see a future,” he said. “Pretty soon every rig will have one worker and a robot.”
In a post by Climate Progress founding editor Joe Romm, one fossil executive put it even more starkly. “To me, it’s not just about automating the rig,” said Ahmed Hashmi, head of upstream technology at BP, in a recent Bloomberg interview. “It’s about automating everything upstream of the rig.” Romm cites Bloomberg’s conclusion that “automation means wells need only five workers, down from 20.”
The U.S. lost 163,000 jobs on the fossil price crash, including 98,000 in Texas, the Times notes. “Oil and gas workers have traditionally had some of the highest-paying blue-collar jobs—just the type that President Trump has vowed to preserve and bring back.” But the character of the available jobs is shifting.
“As in other industries, automation is creating a new demand for high-tech workers—sometimes hundreds of miles away in a control centre—but their numbers don’t offset the ranks of field hands no longer required to sling chains and lift iron.”
And as it turns out, that’s fine with many of the workers involved. Although several thousand have returned, “experts say that between a third and a half of the workers who lost their jobs are not returning,” writes reporter Clifford Krauss. “Many have migrated to construction or even jobs in renewable energy, like wind power.”