The report, Path of Most Resistance, argues the province’s proposed pathway to net-zero electricity emissions by 2050 depends largely on natural gas plants equipped with carbon capture and storage (CCS), hydrogen fuel and future nuclear technologies such as small modular reactors (SMRs).

Those technologies could eventually play a role in reducing emissions, the Calgary-based think tank says, but relying on them as the backbone of the power system represents a series of “risky bets.”

The analysis comes as Alberta negotiates with Ottawa over the future of electricity regulation under a Canada–Alberta memorandum of understanding signed last November.

Under the agreement, the federal government has indicated it could suspend its Clean Electricity Regulations in Alberta if the province can demonstrate that its own policies would achieve equivalent emissions reductions.

Pembina says that outcome should depend on whether Alberta presents a credible and detailed alternative plan.

Heavy reliance on uncertain technologies

The report argues Alberta’s current strategy places a large share of its emissions reductions on technologies that remain expensive, uncertain or years away from widespread deployment.

Carbon capture has been demonstrated at only a handful of power plants globally. Small modular reactors are still under development, with most projects not expected to come online until the 2030s or later.

Hydrogen, which Alberta officials have promoted as a potential fuel for power generation, also faces significant economic and technical hurdles, including high production costs and transportation challenges.

According to Pembina researchers, relying on these technologies to decarbonize Alberta’s grid could delay emissions reductions and increase costs if they fail to scale as expected.

Renewable growth slowed by policy changes

At the same time, the report says provincial policy decisions over the past two years have slowed the development of wind and solar power.

In 2023 the Alberta government imposed a seven-month moratorium on approvals for new renewable energy projects while regulators reviewed land-use rules and grid impacts. The government later introduced new regulations governing renewable development.

Since the moratorium began, nearly 11 gigawatts of wind, solar and energy storage projects have left the Alberta Electric System Operator’s development queue, according to Pembina analysis.

That amount of capacity exceeds Alberta’s average electricity demand.

The province had been a national leader in renewable energy development earlier in the decade, attracting the majority of new wind and solar investment in Canada.

But analysts say regulatory uncertainty and shifting market rules have made developers more cautious about building projects in Alberta.

Government emphasizes reliability

The Alberta government has defended its approach, arguing intermittent power sources such as wind and solar must be balanced with reliable generation to maintain grid stability and keep electricity affordable.

Provincial officials have pointed to natural gas, nuclear and emerging technologies as key components of a reliable, low-emissions electricity system.

However, the Pembina report suggests Alberta could reduce emissions more quickly and at lower risk by accelerating renewable deployment while expanding grid connections with neighbouring provinces.

Greater electricity trade with hydro-rich provinces such as British Columbia and Manitoba could help balance renewable generation by using hydroelectric reservoirs as a form of large-scale energy storage.

Industrial self-generation — including rooftop solar, geothermal and on-site wind generation — could also help reduce demand on the grid while cutting emissions from heavy industry.

Negotiations with Ottawa could shape future

The negotiations between Alberta and the federal government could determine how the province’s electricity sector evolves over the coming decades.

If Alberta can demonstrate a credible pathway to reduce emissions while maintaining reliability and affordability, Ottawa may allow the province to regulate its electricity sector independently through an equivalency agreement.

But if the province’s strategy relies too heavily on technologies that take decades to scale, Pembina warns Alberta could risk missing emissions targets while other jurisdictions move ahead with cleaner power systems.

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By Joseph Winters

Drawing down carbon from the air and stashing it in underground rock formations has been framed as an essential way to slow and reverse global warming. But new research published Wednesday in the journal Nature finds there are far fewer suitable places to do this than previously thought.

After screening out “risky” areas, like those that are vulnerable to earthquakes, a team of researchers from Europe and the U.S. found that the Earth can only safely store about 1,460 gigatons of injected carbon in its sedimentary basins. This is an order of magnitude less than previous estimates, and — if you convert stored carbon to an estimated impact on the climate — only enough to cut global warming by about 0.7 degrees Celsius (1.3 degrees Fahrenheit), not the 6 degrees C (10.8 degrees F) described in other research.

Carbon storage “can no longer be considered an unlimited solution to bring our climate back to a safe level,” one of the study’s co-authors, Joeri Rogelj, said in a statement. “Geological storage space needs to be thought of as a scarce resource that should be managed responsibly to allow a safe climate future for humanity.” Rogelj is director of research at the Grantham Institute on climate change and the environment at Imperial College London.

Carbon storage, for the sake of the paper, refers to the injection of carbon dioxide into underground reservoirs where it theoretically can’t contribute to climate change. There are two broad ways to get this carbon: first, by capturing it at the point of emission — say, the smokestack of a fossil fuel-powered cement factory — and second, by sucking it out of the ambient atmosphere.

According to the United Nations’ Intergovernmental Panel on Climate Change, or IPCC, the world’s foremost authority on the topic, at least some carbon storage will be necessary to achieve international climate targets.

But the amount needed is dependent on a number of factors, including how much countries plan to slash emissions versus “offsetting” them, especially from hard-to-decarbonize sectors, and whether they intend to blow past 1.5 or 2 degrees C (2.7 or 3.5 degrees F) of global warming and then return to a more liveable temperature by removing carbon from the atmosphere. The latter is a contentious idea known as “overshoot,” and it would necessitate more carbon pulled out of the air and stored. Some IPCC scenarios involving substantial overshoot assume up to 2,000 gigatons of carbon storage by the year 2100.

According to the study’s authors, no previous global or regional estimate of the Earth’s technical carbon storage potential has taken into account key risk factors that would make some areas undesirable for storage. Starting from an estimate of all potentially available storage sites, their analysis cuts out areas that are too shallow, too deep, and too prone to earthquakes, as well as environmentally protected areas and areas near where people live. This reduces the total available capacity for carbon storage from 11,780 gigatons to just 1,460 gigatons of CO2, 70 percent of it on land and 30 percent on the seafloor.

The authors used an existing conversion rate from the IPCC to translate that gigaton number to about 0.4 to 0.7 degrees C (0.7 to 1.3 degrees F) of reduced global warming.

They also noted some geographical disparities in the potential for carbon storage: While some historical climate polluters such as the U.S. and Canada have lots of space to safely stash carbon, others in Europe don’t. If those countries intend to make carbon storage a significant piece of their climate mitigation plans, they will likely have to look for locations in countries that have done little to contribute to climate change, potentially in Africa.

Sally Benson, an energy science and engineering professor at Stanford University who was not involved in the new research, said its findings should not be seen as “alarming” or “dramatic.” As described in the paper, IPCC scenarios that give the world a 50 percent chance of limiting global warming to 1.5 degrees Celsius by the end of the century would require sequestering about 9 gigatons of carbon per year (assuming that net-zero emissions are achieved around 2050). That means it could be more than 160 years before the world reaches the safe carbon storage limit calculated in the study.

“What that tells me is that this is kind of good news,” Benson said. “Somebody has taken the most conservative of possible approaches to looking at this capacity and concluded, from my perspective, that there’s a lot of capacity relative to what we need.”

The study authors note that the need for storage could continue after their theoretical limit is reached, especially if countries keep needing to offset residual emissions from agriculture or the burning of fossil fuels in some sectors. Climate tipping points could also release more carbon dioxide into the atmosphere than anticipated, necessitating more carbon removal than expected.

But Benson said these risks are too far in the future and that “we need to use all of the technologies available as quickly as possible.”

Both Benson and another independent expert — Jennifer Wilcox, a professor of chemical engineering and energy policy at the University of Pennsylvania’s Kleinman Center for Energy Policy — said the paper’s central estimate for safe and prudent carbon storage is likely too conservative. Wilcox told Grist it “undercounts what carefully pressure-managed projects can safely deliver.”

But Naomi Oreskes, a professor in the history of science at Harvard University, held the opposite opinion. Oreskes said the paper fails to consider governmental, economic, and scientific challenges to actually deploying carbon storage at scale. “When you take those factors into account,” she said, “the potential for carbon storage, particularly in the crucial next decade, is even less.”

Despite significant hype around the technology, only about 0.05 gigatons of CO2 are currently stored via point-of-emission carbon capture each year. So far, most of these carbon capture projects inject carbon into the ground to aid the extraction of even more oil and gas, in a process known as “enhanced oil recovery.” And only 0.00001 gigatons of CO2 are removed from the ambient air each year. That’s less than the stated annual greenhouse gas emissions of Bowdoin College, a small liberal arts school in Maine.

“This new information is consistent with a broader pattern we have observed, of overstating the promise of ‘solutions’ that sidestep the central issue of reducing fossil fuel use,” Oreskes said.

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In Canada, new carbon dioxide (CO₂) pipeline projects are being announced. In September 2023, Wolf Midstream announced the expansion of its Alberta Carbon Trunk Line (ATCL) to Edmonton, AB. In Saskatchewan, Whitecap Resources stated it started engineering design of a new CO₂ capture and pipeline project. However, both projects are adding capacity to an existing network of large CO₂ pipelines that has been in operation for more than two decades. More projects could be expected in the future, as the development of carbon capture and storage (CCS) capacity is an essential part of the federal and provincial strategies to reduce emissions and transition to a low carbon future.

Carbon dioxide pipelines are an essential part of any carbon capture and storage project. Canada currently has five large CO₂ pipeline systems. The Alberta Carbon Trunk Line⁽¹⁾ (ACTL), and the Quest⁽²⁾ project pipelines are in Alberta, while the Boundary Dam to Weyburn, the Souris Valley⁽³⁾ and the Cardinal Energy Ltd.’s Midale CO₂⁽⁴⁾ pipelines are in south Saskatchewan (Table 1). Total capacity of these pipelines is estimated in 2023 at 7.1 million tonnes of CO₂ per year (Mt CO₂/year).

The Souris Valley pipeline⁽⁵⁾—the oldest and largest—has been in service since 2000, the Midale pipeline since 2005 and the Boundary Dam pipeline since 2014. The Quest and ACTL pipelines became operational in 2015 and 2020, respectively. The Canada Energy Regulator (CER) regulates the Souris Valley pipeline, while Quest and ACTL are regulated by the Alberta Energy Regulator (AER)⁽⁶⁾ and the Boundary Dam and Midale pipelines by the Saskatchewan provincial government.

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by Scott MacDougall,  Jonathan Arnold,  Janetta McKenzie

This is the third article in a series of three on Canada’s climate objectives and the oil and gas sector. The first article can be found here, the second here. 

Companies responsible for 95 per cent of oilsands production in Canada have committed to achieving net-zero upstream emissions by mid-century.

Achieving this ambitious goal requires timely and unprecedented investments. It will also be essential to comply with the federal government’s forthcoming cap on oil and gas emissions and to stay competitive in the global low-carbon transition.

Looking across the options that oilsands producers have to reduce their emissions, carbon capture and storage (CCS) could have the biggest impact. Despite its potential, however, the economic case for CCS is still unclear. Publicly available information is limited and shows a wide range of costs to deploy the technology.

Meanwhile, the largest oilsands operators are requesting an additional $11 billion from governments to help pay for CCS projects.

To shed light on how existing regulations and proposed financial incentives affect the economics of oilsands CCS projects, we developed a cash-flow model (using publicly available information) to examine the viability of retrofitting two hypothetical oilsands facilities with CCS.

(For the purposes of our analysis, we leave aside questions about whether CCS technology can be deployed at scale and assume it can and should be scaled.)

The upshot? Our modeling shows that these projects are economically viable after factoring in Canada’s suite of climate regulations and incentives, including the rising carbon price. In fact, our modeling shows private investment in oilsands CCS projects could yield substantial returns for the companies.

These findings raise big questions about the role of government policy, particularly at a time when the oilsands industry is asking for billions of dollars in additional taxpayer funds.

For starters, our results show why further public subsidies, beyond what have been announced, are not necessary to make these projects economic.

They also highlight the need to design public incentives with mechanisms that prevent excessive profits from supporting projects that would ultimately make it harder and more expensive to reduce emissions.

In addition, the results show why it’s critical to finalize keystone policies to get oilsands CCS projects off the ground and to provide policy certainty. Not all CCS projects will get the same incentives, project costs vary and critical incentives from federal and provincial carbon pricing systems are not easy to bank on in the long term.

Proposed contracts for differences that would help underwrite the carbon-pricing risk, as well as proposed investment tax credits, have been slow to be developed and are not yet final.

As federal and provincial governments continue to weigh the economics and tradeoffs at play, we offer three major takeaways from our results (our in-depth technical supplement is forthcoming on the Pembina Institute website).

1. Deploying CCS on oilsands facilities can improve the industry’s carbon competitiveness but does not eliminate transition risk

Scaling up CCS could significantly cut emissions and improve an oilsands facility’s carbon competitiveness.

A new analysis by the Canada Energy Regulator (CER) shows that as the transition to a global low-carbon economy accelerates, oil demand is expected to decline significantly. In that shrinking market, oil producers with the lowest costs and carbon intensities will be more competitive and will have a lower risk of their facilities becoming stranded.

The chart below shows carbon intensity and production costs for existing Canadian oilsands facilities and how they compare with international crudes.

Some Canadian facilities perform only a little worse than global averages, while some are much worse. Over time, as oil demand declines, cost pressures and the requirements to reduce emissions could increase stranded-asset risk for facilities with higher break-even prices and higher carbon intensities.

The figure above shows the impact of adding one megatonne per year of CCS to an oilsands in-situ and to an integrated mine facility.

At the in-situ facility, CCS could allow it to beat the global average crude oil emissions intensity, cutting emissions by 40 per cent. An oilsands mining facility, on the other hand, would need to invest in several CCS projects to achieve global average emissions intensity.

Importantly, both projects could generate net earnings from installing CCS, equivalent to about $2 per barrel, improving a project’s cost competitiveness.

These improvements would not, however, eliminate the transition risk facing oilsands facilities. Achieving the Paris Agreement goal requires a steep drop in the emissions generated from upstream oil production over time (about 90 per cent from 2023 levels, according to the CER analysis), so benchmarking against current averages will not be good enough.

Moreover, installing CCS might not be worth it at facilities with limited remaining reserves, or very high carbon and cost intensities, because it may not be feasible or justifiable to make them competitive in the medium to longer term.

Even for competitive projects, stranded asset risk is not static. Those with longer economic lifespans and lower risk today will eventually face a high longer-term risk of becoming stranded as global oil demand declines.

2. Governments should follow through with announced policy measures swiftly, so installing CCS on existing oilsands facilities is economically viable before 2030

A key indicator for whether any decarbonization project is economically viable is how its cost compares to Canada’s rising federally set carbon price, which applies to large industrial emitters. If the cost to reduce (or eliminate) emissions from a facility is cheaper than paying a carbon price on these same emissions, businesses have an incentive to build the decarbonization project.

Our modeling shows that both types of CCS projects are economically viable against this measure.

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By Joseph Winters

For years, fossil fuel companies and utilities have touted carbon capture and storage, or CCS, as a way to cut climate pollution from the power sector. Now, federal regulators are asking them to walk the walk.

The U.S. Environmental Protection Agency, or EPA, on Thursday proposed a new rule to nearly eliminate climate pollution from the nation’s coal- and natural gas-fired power plants by 2040. In contrast to previously proposed regulations that required “generation-shifting” — forcing utility companies to replace their fossil fuel-fired power generators with renewables, a strategy that the Supreme Court shot down last summer — the new proposal focuses on what’s achievable using technologies like carbon capture and storage, or CCS.

At least, they focus on what’s theoretically achievable based on optimistic projections from CCS’s proponents. Although the EPA says CCS technology is “adequately demonstrated” and “highly cost-effective,” experts are deeply skeptical that it can deliver on its promised emissions reductions. In the end, some told Grist that fossil fuel power plants could find it more economical to shut down and switch to renewable energy.

“The EPA is calling the bluff on the power industry,” said Charles Harvey, a professor of civil and environmental engineering at the Massachusetts Institute of Technology. “There have been so many arguments that they’ve made in favour of CCS as a mature technology. … Now the EPA is saying ‘OK, you have to do it,’ and I don’t think they really can.”

To be clear, EPA’s proposed standards don’t mandate a specific emissions reduction strategy, since that was deemed beyond the EPA’s authority by the Supreme Court. Instead, the agency put forward overall pollution caps, with different limits depending on the fuel facilities use (e.g., coal or natural gas), how frequently they run, and how long they plan to remain in operation. Starting in 2030, the rule would require almost all fossil fuel power plants to begin driving down their emissions, with the most stringent requirements for coal-fired power plants and the most frequently used natural gas plants.

According to the EPA, its proposed rules would cut 617 million metric tons of CO2 emissions through 2042 — an amount equal to about 40 per cent of the power sector’s emissions in 2022. The agency highlights two technology-based “pathways” that power plants could choose: one based on CCS, which uses chemical reactions to strip carbon out of the emissions that come out of a facility’s smokestacks, and the other involving hydrogen, which can be blended with natural gas to reduce greenhouse gas emissions.

Industry groups have promised much from CCS, saying that it can — or will — be capable of capturing 90 per cent of a power plant’s greenhouse gas emissions, and the EPA’s 680-page proposed rule making seems to take those promises at face value. The document cites a long history of research into the technology, as well as declining costs for its deployment, thanks to unprecedented funding for CCS included in the Biden administration’s 2022 climate spending law.

But despite this long history, CCS doesn’t have a strong track record of actually sequestering carbon — especially for the power sector, where 90 per cent of proposed carbon capture capacity has failed or never gotten off the ground. In the 2010s, the Department of Energy supported five demonstration projects with some $2 billion in funding, but only one ever became operational. That project, attached to a coal-burning power plant near Houston, Texas, called Petra Nova, closed in 2020, leaving just one commercial power plant in the entire world still using carbon capture: the Boundary Dam coal plant in Saskatchewan, Canada.

The EPA highlights Boundary Dam in its proposed rule making but does not note that the facility only captures about half of its CO2 emissions, far short of its targeted 90 per cent.

“It’s not feasible to decarbonize using carbon capture and storage,” said Bruce Robertson, an energy finance analyst for the nonprofit Institute for Energy Economics and Financial Analysis. “A far more effective way is to produce renewable electricity,” the cost of which has fallen precipitously in recent years. One paper published in 2021 found that cost reductions in wind and solar reduced the value of CCS by up to 96 per cent.

Even utilities that were once bullish on CCS have in recent months seemed to reverse course, suggesting that the EPA’s technology-based standards might not be so easy to meet with CCS after all. As reported by Time, some three dozen utility companies submitted a comment to the EPA last summer highlighting the “low likelihood” that CCS would be appropriate for use in the agency’s power plant regulations. They criticized the EPA for pointing to pilot projects as evidence of CCS’s viability. “A proposed or developing project … is not proof of a technology being available,” the utilities wrote.

It’s hard to say what kind of political considerations ultimately shaped the agency’s new proposal. Whether the EPA believes in CCS or is deliberately using it as a “cudgel” against power plant operators — potentially a backdoor approach to encourage a switch to renewable energy without technically mandating it — is unclear. The EPA did not directly respond to Grist’s request for comment on generation-shifting and instead said it had considered “a range of technologies” in developing its proposed carbon pollution standards.

Still, many environmental advocates are not a fan of the EPA’s approach, regardless if there’s a broader strategy behind it. Even if power plants could capture 90 per cent of their carbon pollution, experts say there’s no guarantee that the carbon would then be stored in perpetuity. Only about one-fourth of all the carbon dioxide captured annually — mostly from processing raw gas into liquefied natural gas — is injected into dedicated underground storage reservoirs, and Harvey, the MIT professor, said it’s “an unresolved issue” whether it will stay put long-term. Almost all of the rest of the world’s captured carbon is used for “enhanced oil recovery,” a process where CO2 is pumped into oil fields in order to push more fossil fuels out of the ground. When burned, these fossil fuels release carbon back into the atmosphere, exacerbating global warming.

“This is just perpetuating the use and reliance on fossil fuels,” Abbe Ramanan, a project director for the nonprofit Clean Energy Group, told Grist. Ramping up carbon storage, she added, would require developing a vast, expensive, and potentially dangerous network of CO2 pipelines. And CCS fails to address other pollutants like nitrogen oxides, which could continue to come out of power plants and harm nearby communities.

Jason Rylander, legal director for the nonprofit Center for Biological Diversity’s Climate Law Institute, said the EPA’s proposed regulations are likely to “pass muster” with the Supreme Court, but yearns for a more aggressive approach. “EPA has done what it can with this program, but it has failed to do what it must to address the climate emergency,” he said. Instead of endorsing CCS, he urged the Biden administration to declare carbon dioxide, methane, and other greenhouse gases “criteria pollutants,” which would require the EPA to declare national ambient air quality standards, or NAAQS, for them.

“If this administration wants to get serious about climate,” Rylander said, “it will stop approving new polluting projects and it will do a comprehensive pollution rule under NAAQS.”

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The new plant, expected to be online by 2026, will be built near Occidental’s Permian Basin operations.

NET Power’s technology produces power while inherently capturing nearly all emissions with its patented oxy-fuel combustion and supercritical CO₂ cycle. These plants produce clean, on-demand power at low cost and address critical issues of air quality and land use, virtually eliminating air emissions including nitrogen oxides , sulphur oxides, and carbon dioxide (CO₂).

In the fall of 2021, NET Power proved its technology at its La Porte demonstration site, culminating with synchronization to the Texas electric grid. NET Power announced a partnership with Baker Hughes in February of this year to develop and market a suite of integrated equipment and technologies, including supercritical CO₂ turboexpanders. This utility-scale serial number one project serves as the commercial launch pad for NET Power’s core process technology, and will help boost other projects already in development and providing the pathway for global deployment of this decarbonization platform.

“Having demonstrated the capability of the technology at La Porte, and having partnered with Baker Hughes to commercialize the NET Power system, we are excited to accelerate the deployment of this game changing technology,” said Ron DeGregorio, CEO of NET Power. “This plant allows for the quick ramp up in NET Power’s global deployments, providing a clear and meaningful pathway to near emission-free reliable power.”

NET Power selected the project located at an Occidental hosted site near Odessa, Texas from a slate of early adopter project candidates. The project targets approximately 300 megawatts (MW) of carbon-free power and will transport captured CO₂ to a permanent underground sequestration location through Occidental’s existing Permian CO₂ handling infrastructure and operations.

NET Power says it will engage its strategic shareholders to support the project with resources.  Occidental will provide CO₂ transportation and sequestration and power off-take, while Constellation Energy Generation offers expertise in plant operations and power off-take.  Key integrated process equipment and technologies will be provided by Baker Hughes and 8 Rivers Capital will be on the team for project development support.

Richard Jackson, President, U.S. Onshore Resources and Carbon Management, Operations, Occidental said, “We are excited to support NET Power’s first utility-scale project. This plant will accelerate plans to reduce carbon emissions to help achieve net zero goals. The project allows both companies to develop best practices that use NET Power’s technology to provide near emissions-free power for our Permian operations and future Direct Air Capture sites.”

NET Power says the project builds on years of internal development of a standardized and modularized design concept. Pre-Front End Engineering and Design (Pre-FEED) studies have been completed with full FEED work to commence in the first quarter of 2023.

Chris Barkey, CTO – Industrial & Energy Technology at Baker Hughes, remarks “We are excited to support the development of the NET Power system. Our technology is robust, and the program is progressing well to deliver a world-class 300MW class suite of equipment enabling utility-scale operation in 2026, and a rapid ramp-up in commercial deployments thereafter.”

According to the North Carolina-based company, the project will be financed through a combination of NET Power’s current capitalization program, investments from existing shareholders, and new project financing. Additionally, NET Power is pursuing government support available at the federal, state, and local level, with special focus on grant and loan opportunities arising from the Bipartisan Infrastructure Law.

The long-term opportunity for NET Power projects is further improved with the Inflation Reduction Act and its enhancements to the 45Q carbon capture tax credit available to capturing facilities. To qualify for these credits, electric generation units must be designed to capture at least 75 percent of carbon dioxide emissions, a number which NET Power facilities easily exceed.

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In Canada’s Energy Future 2021 report (EF2021), one of the key findings is that the Evolving Policies Scenario^Footnote1 projects unabated fossil fuel use to fall 62 per cent by 2050 from 2021 levels. Unabated fossil fuel use is fossil fuel combustion without the application of carbon capture and storage (CCS) technology.

The fall in use is driven by a decrease in overall demand for energy in the scenario (-21 per cent from 2021 levels by 2050), as well as an increase in use of low and non-emitting energy sources like renewables and fossil fuels with CCS. While this implies a significant reduction in GHG emissions by 2050, achieving net-zero will likely require more change than included in this scenario.

This snapshot explores unabated fossil fuel use by sector in the Evolving Policies Scenario to highlight the opportunities and challenges of reaching net zero by 2050.

Figure 1 shows unabated fossil fuel use in the Evolving Policies Scenario, broken down by sector. It includes all fossil fuels used for energy purposes, as these make up most Canada’s emissions. It excludes fossil fuels used for feedstocks for industrial production, like petrochemical feedstocks and lubricants, because they are considered low-emitting in this scenario.^Footnote2 Combined, the oil and gas and transportation sectors made up nearly 60 per cent of the fossil fuel use in 2020, while the industrial (excluding oil and gas), residential, commercial, and electricity sectors made up the remaining 40 per cent.

In EF2021 projections, there are two main reasons for sectoral differences in unabated fossil fuel use: 1) the availability and cost of low-carbon technologies and 2) the strength of policies applied to the sector. If the policies are strong enough to make low-carbon technologies more competitive than unbated fossil fuels, the new technologies will begin to make inroads. The policies applied in the Evolving Policies Scenario can be found in Appendix 1 of the EF2021 report.

In the Evolving Policies Scenario, the sectors that reduce their unabated fossil fuel use the most by 2050 from current levels are oil and gas (-79 per cent) and electricity (-72 per cent). The electricity sector has many low-carbon technologies available at relatively low costs, such as wind and solar. In addition, the costs for these technologies are assumed to drop considerably over the projection period in the Evolving Policies Scenario.

The oil and gas sector relies predominantly on energy efficiency and carbon capture and storage (CCS) as options to reduce unabated fossil fuel use in the Evolving Policies Scenario. The reliance on CCS is mainly due to Alberta’s oil sands industry which can capture and store carbon at a relatively low cost compared to the rest of Canada due to its proximity to high-quality storage sites and a growing CO₂ transportation network in the province. Although CCS is a viable technology, there are currently very few large-scale CCS projects globally. Therefore, the level of implementation is a key uncertainty for the projections in EF2021.

Industry other than oil and gas (-36 per cent) and transportation (-47 per cent) reduce their unabated fossil fuel use the least from current levels to 2050. Although passenger transportation electrifies significantly by 2050, unabated fossil fuel use persists in freight transportation and aviation.

Freight, aviation, and industry (excluding oil and gas) all feature fewer and more expensive low-carbon technologies than other sectors of the Canadian economy under the cost and policy assumptions in the Evolving Policies Scenario. Some examples include, electrified and biofuel-based freight transportation, hydrogen-based aviation, and major process shifts in cement and iron and steel making. Because of these assumptions, the industry and transportation sectors do not decarbonize as much as others.

The level of remaining unabated fossil fuel use in the Evolving Policies Scenario highlights that further change is likely needed to reach net-zero by 2050. It also shows where there are opportunities for significant emission reductions, like in electricity generation, and where there may be challenges, like in freight and aviation decarbonization.

Footnotes

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Blue hydrogen is made from natural gas using carbon capture and storage in its production process. Accurately measuring greenhouse gas emissions must take into account upstream carbon emissions from the extraction and transportation of natural gas, and the production and transportation of the hydrogen, as well as the level of carbon captured.

A full life cycle assessment of GHG emissions in blue hydrogen includes emissions generated in construction of natural gas facilities, extraction and transportation of natural gas, production of hydrogen, and the process of carbon capture and storage. Carbon capture rates could vary from 48 per cent captured by facilities operating today, to projected 95 per cent in proposed projects.

“Major policy and investment decisions that could shape the future of hydrogen in Canada must be based on accurate data,” said Karen Tam Wu, BC Regional Director, the Pembina Institute. “This research shows that the climate benefits of blue hydrogen vary depending on the technology used to create it.”

A new technical paper, The carbon intensity of blue hydrogen production, examines relative emissions levels for different production methods, as well as the feasibility of reducing greenhouse gas emissions with carbon capture and storage.

The study compares the relative life cycle emissions for production of blue hydrogen using various current technologies. As Canada’s federal and provincial governments move forward with strategies for hydrogen as a key element in achieving net-zero by 2050, Canadian consumers, producers and investors must look at the complete picture.

In its report, Pembina says carbon intensity could vary from 67kg CO2e/GJ for blue hydrogen currently produced today to ~15.6 kg CO2e if using clean electricity (e.g. hydro) and reducing methane emissions by 40 per cent.  It is technically feasible for a new hydrogen production plant to eliminate 90 per cent of plant emissions, if electricity to run production comes from non-emitting sources.

Production of hydrogen purely as an energy carrier is still a nascent industry. Globally there are four facilities that produce blue hydrogen for use in oil extraction for fertilizer production in operation. Hydrogen’s utility will mainly be in sectors that are hard to decarbonize, and in end uses such as long-haul heavy-duty freight and high-heat industrial processes.

Around the world, there are currently 26 carbon capture and storage (CCS) plants. Three of them are associated with hydrogen production

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IEA sees carbon capture vital to meeting global climate targets

This article was published by the National Energy Board on Jan. 30, 2019.

Canada is a leader in carbon capture and storage (CCS) and carbon capture, utilization, and storage (CCUS) with a number of operating projects and decades of experience in the technology.

CCS separates (or “captures”) CO₂ from industrial exhaust, for example, at coal power plants, before injecting it in deep underground rock formations. CCUS “utilizes” CO₂ for other things, including enhanced oil recovery (EOR), which is a process of injecting CO₂ into declining oil fields to help to recover additional oil from reservoirs.

Western Canadian CCS projects are possible because of a combination of technical expertise, geological suitability for CO₂ storage, and legal, regulatory, and policy frameworks.

The number of operating projects continues to grow. In 2014, the SaskPower Boundary Dam power station became the world’s first power plant with CCS. In 2015, the largest CCS project in Canada, Shell’s Quest CSS project began capturing CO₂ from a bitumen upgrader near Edmonton and injecting it into an underground reservoir for storage.

The newest project, the Alberta Carbon Truck Line (ACTL), is under construction and is scheduled to be on-stream later in 2019. ACTL will take CO₂ from the new Sturgeon refinery and a nearby fertilizer plant, and transport it by pipe 240 kilometres to an EOR project in central Alberta.

The Quest and ACTL projects, at 1.0 and 1.7 million tonnes per year respectively, are injecting the CO₂ equivalent emissions of 600 000 cars annually.

Globally, there are now 18 large scale CCS facilities in operation, and approximately the same number proposed for development. Collectively these facilities would capture less than 100 Mt CO₂ per year, less than 1 per cent of present global emissions.

The International Energy Agency (IEA) and the Intergovernmental Panel on Climate Change (IPCC) foresee a vital role for CCS/CCUS in meeting global climate targets. In the IEA’s “450 Scenario” outlook, CCS in power and industry would capture 5 100 Mt CO₂ per year by 2040. This is a relatively minor amount compared to the CO₂ reductions from renewables and efficiency measures, but still significant in terms of reductions.

The extent of CCS development depends heavily on improving technology and reducing costs. A report for the expansion of CCS on a coal-fired power plant in Saskatchewan estimated a 67 per cent cost reduction (USD $45/t) compared to Boundary Dam.

A number of promising technologies are in the research and development stage. If technology improves and costs fall, the CCS market could also move into areas such as conversion to fuel, including methanol and hydrogen, and direct air capture of CO₂.

These technologies could result in negative emissions, for example removing CO₂ from ambient air. Although, these options are more costly than many readily available technologies for combustion processes.

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