Enbridge teams up with Alberta First Nations on carbon capture project

Capital Power’s Genesee Generating Station, located west of Edmonton. (Supplied)

Kerry McAthey
CTV News Edmonton
Feb. 4, 2022 

Enbridge has partnered with four Treaty Six Nations and the Lac Ste. Anne Métis Community to expand a proposed carbon capture and transportation project west of Edmonton.

In a Thursday announcement, Enbridge said the Open Access Wabamun Carbon Hub is being developed to both transport and store carbon, in support of recently announced carbon capture projects by Capital Power, Lehigh Cement, and others.

The Alexander First Nation, Alexis Nakota Sioux Nation, Enoch Cree Nation, and Paul First Nation recently formed the First Nation Capital Investment Partnership (FNCIP) to pursue ownership in major infrastructure projects. The partnership with Enbridge on the Hub is the FNCIP’s first such project.

“This path creates an opportunity to generate wealth, but more importantly it allows sustainable economic sovereignty for our communities,” said Chief George Arcand Jr. of Alexander First Nation in a release. “We’re looking forward to working with industry leaders who share our values of environmental stewardship and to collaborate with Enbridge on world-scale carbon transportation and storage infrastructure investments.”

The hub would transport carbon emissions like those from the Lehigh Cement plant in Edmonton by pipeline, to be stored by Enbridge. According to Enbridge, that project alone could capture up to 780,000 tonnes of carbon dioxide annually.

Combined, the emissions from Capital Power and Lehigh’s projects could avoid nearly four million tonnes of atmospheric carbon dioxide emissions.

Enbridge has applied to develop the open access hub through the province’s Request for Full Project Proposals process.

Enbridge and its partners haven't publicly said what the project will cost, except that it expects to invest "hundreds of millions of dollars."

The company said pending regulatory approvals, it could be up and running by 2025.

Alberta's investment in carbon capture technology not worth bang for buck, environmental group argues

Alex Antoneshyn
CTVNewsEdmonton.ca Digital Producer
Updated Jan. 21, 2022 


A new report accuses the oil-and-gas industry of greenwashing the impact of carbon capture and storage – also known as CCS – technology, pointing to an oil-processing complex in Alberta that emits more carbon than it buries in the ground.

The report by Global Witness argues CCS is a poor substitute for phasing out fossil fuels and an expensive undertaking that the governments of Alberta and Canada partly funded.

"We think this really isn't sustainable, it's not climate friendly, and it shows that governments across the world, not just in Canada, mustn't support fossil hydrogen," report author Dominic Eagleton told CTV News Edmonton. "They should boost more genuinely sustainable alternatives to fossil hydrogen, such as renewables."


Global Witness, a non-government organization based in the U.K., says its goal is to create a "more sustainable, just and equal planet."

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Eagleton, a senior campaigner with the group, compared the amount of emissions produced at Shell's Scotford Complex in Fort Saskatchewan, northeast of Edmonton, with the amount of carbon dioxide its CCS system – called Quest – removes. He says the site was chosen because of the data publicly available on it.

Global Witness found that between 2014 and 2019, Quest stored five million tonnes of carbon dioxide, or CO2. During the same period, it says the Scotford Complex produced in total 7.5 million tonnes of greenhouse gases, including methane. The data was pulled from reports submitted by Shell to the Alberta government, as well as data crunched by the Pembina Institute.

Eagleton calls the 2.5-million tonne difference a "wake-up call for the world."

Shell believes Quest hints at what is possible in the future.

'A DEMONSTRATION PROJECT'

Shell operates Quest on behalf of its partners mining oil sands in northern Alberta and refutes Global Witness' assertion it overpromised Quest's potential.

In addition to the CCS system, Scotford Complex consists of an upgrader that turns bitumen from those oil sands into lighter crude products, a refinery that makes fuels and other products from synthetic crude oil, and a chemical plant.

In order to upgrade bitumen, Shell makes hydrogen, producing carbon dioxide in the process.

Quest's job is to capture and liquefy CO2 before trapping it two kilometres below ground.

Quest has stored about six million tonnes of carbon in its six-and-a-half years – faster and cheaper than expected, according to the company. However, the system was never meant to capture more than one third of the Scotford upgrader's emissions, Shell maintains.

When Quest was built, it was touted as the world's first commercial-scale CCS facility at an oil sands operation. And, as one of the first facilities of its kind, Quest isn't able to capture and store as much carbon as is now possible – around 90 per cent, the industry estimates.

"We were there working with the government to really demonstrate Quest as a proof point that CCS does work. Not only in the capture in a brownfield site, but also the storage complex," Shell's national CCS lead Tim Wiwchar told CTV News Edmonton.

"We called it a demonstration project."

Shell is currently planning a CCS project at Scotford that would have a storage capacity of 300 million tonnes of carbon dioxide, or the above-90 per cent capture levels industry says current technology now allows.

The company is expected to decide to move forward or not with Polaris in late 2023.

'A FRACTION OF THOSE EMISSIONS'

Quest cost $1.35 billion, $845 million of which came from the provincial and federal governments. Some of the provincial dollars, contingent Quest's performance, continue to flow in.

And more dollars will flow to similar projects in the future.

Alberta wants to increase its CCS capacity and has incentivized proposals as part of a plan to capitalize on what is expected to become a $2.5-trillion global hydrogen market by 2030. Hydrogen's potential is premised on its nature to burn cleanly. When it is made alongside a carbon capture system, like at Shell Scotford Complex, it's known as blue hydrogen – and considered dirtier only than green hydrogen made with renewable energy.
Alberta prioritizes oil sands' carbon storage hub, energy minister says
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Alberta funding $131M in new emission reduction projects

But Eagleton says it is misleading for the fossil fuel industry to present hydrogen production and carbon capture as favourably as it does when CCS can't transform the oil-and-gas sector into a zero-emitting industry.

The senior campaigner at Global Witness found Quest only captured 48 per cent of carbon emissions produced by the Scotford complex – which he called "a fossil hydrogen plant," which Shell disputed – and 39 per cent of all greenhouse gas emissions.

"Trying to apply carbon capture systems to the rest of the world's fossil hydrogen plants could be a disaster for the climate because it might only capture a fraction of those emissions," Eagleton told CTV News Edmonton.

He also believes investing more in carbon-capture infrastructure is a bet in technology that hasn't yet proven itself, when compared to things like wind and solar power.

"It's these options that will take us to a safer climate and not more investment in fossil-fuel infrastructure, which is what fossil hydrogen will entail," Eagleton added.

"Given…that CCS is required in other industries that go beyond fossil fuels -- fertilizer, cement, chemicals, those are all going to be required into the future -- that again, this is a proof point using an oil and gas facility that CCS does work," Wiwchar responded.

"[Quest] has captured over six million tonnes of CO2. That's six million tonnes that would have been emitted from the upgrader…had we not built Quest."

Alberta's energy minister did not respond to CTV News Edmonton's request for comment.

With files from CTV News Edmonton's Touria Izri


Quest carbon capture and storage facility in Fort Saskatchewan Alta., on Nov. 6, 2015. (Jason Franson / THE CANADIAN PRESS)

Enbridge and Lehigh Cement agree to advance a CO2 storage solution in Alberta

January 26, 20226:50 AM CNW

CALGARY, AB – Enbridge Inc. (Enbridge) (TSX: ENB) (NYSE: ENB) and Lehigh Cement, a division of Lehigh Hanson Materials Limited (Lehigh), are pleased to announce a memorandum of understanding to collaborate on a carbon solution for Lehigh’s cement manufacturing facility in Edmonton, Alberta.

Lehigh is developing North America’s first full-scale carbon capture, utilization and storage (CCUS) solution for the cement industry at its Edmonton plant, with the goal of capturing approximately 780,000 tonnes of carbon dioxide (CO2) annually. Captured emissions would be transported via pipeline and permanently sequestered by Enbridge. Subject to the award of carbon sequestration rights and regulatory approvals, the project could be in service as early as 2025.

With the support of Lehigh and Capital Power Corporation (Capital Power) with their local facilities, Enbridge will be applying to develop an open-access carbon hub in the Wabamun area, west of Edmonton, Alberta, through the Government of Alberta’s Request for Full Project Proposals process.

Combined, the emissions from Capital Power and Lehigh’s planned carbon capture projects represent an opportunity to avoid nearly 4 million tonnes of atmospheric CO2 emissions. Once built, the Open Access Wabamun Carbon Hub will be among the largest integrated CCUS projects in the world.

“At Lehigh Hanson, we believe that carbon capture and storage technology will play a key role in transforming the cement industry and building a more sustainable future,” said Joerg Nixdorf, President of Lehigh Hanson’s Canada Region. “We are excited about taking the next steps in our ambitious journey to achieving carbon neutrality across the cement and concrete value chain.

“Having a carbon hub solution in place by 2025 is essential for the successful implementation of the CCUS project at our Edmonton cement plant,” Nixdorf added.

“Lehigh Cement’s pioneering CCUS project is an exciting addition to our proposed Open Access Wabamun Carbon Hub, which is poised to support the decarbonization of multiple industries, including power generation, oil and gas, and now cement,” said Colin Gruending, Enbridge Executive Vice President and President, Liquids Pipelines. “This collaboration demonstrates our focus on local, cost-effective, customer-focused carbon transportation and storage solutions that drive scale and competitiveness while minimizing infrastructure footprint to protect land, water and the environment.”

“We applaud Lehigh and Enbridge in advancing plans for definitive climate action in Canada with this full chain CCUS initiative and we are proud to be a part of the carbon capture development at Lehigh’s Edmonton cement plant,” said Mark Demchuk, National Director, Strategy & Stakeholder Relations at the International CCS Knowledge Centre. “Collaborative CCUS solutions like this are a vital enabler of large-scale emissions reductions, across multiple industries, including cement production.”

“The Cement Association of Canada (CAC) welcomes the announcement of an MOU between Lehigh Hanson and Enbridge for Lehigh’s Carbon Capture Utilization and Storage project in Edmonton, Alberta. This is another positive step forward in the development of Lehigh Hanson’s CCUS project, supporting an end-to-end solution for carbon capture and permanent storage,” said Michael McSweeney, CAC President/CEO. “These types of partnerships on critical technologies like CCUS are how we will win the fight against climate change and demonstrate to Canadians and the world how our hard to abate industry will reach its net-zero ambition. We are so pleased to see this CCUS project moving forward.”

Visualizing Carbon Storage in Earth’s Ecosystems

on January 25, 2022
By Sponsored Content
Article/Editing:

Dorothy Neufeld
Graphics/Design:

Miranda Smith
The following content is sponsored by the Carbon Streaming Corporation.

RIGHT CLICK TO OPEN LARGER IN NEW TAB

Visualizing Carbon Storage in Earth’s Ecosystems

Each year, the world’s forests absorb roughly 15.6 billion tonnes of carbon dioxide (CO2).

To put it in perspective, that’s around three times the annual CO2 emissions of the U.S. or about 40% of global CO2 emissions. For this reason, forests serve as a vital tool in regulating the global temperature and achieving net-zero emissions by 2050.

In this graphic sponsored by Carbon Streaming Corporation, we look at the Earth’s natural carbon sinks, and break down their carbon storage.
Carbon Storage by Ecosystem

Forests contain several carbon sinks, from living biomass such as roots and leaves to soil. In fact, soil contains nearly twice as much carbon than the atmosphere, plant, and animal life combined.
Soil: 2,500 gigatonnes (Gt)
Atmosphere: 800 Gt
Plant & animal life: 560 Gt

The soil type, vegetation, and climate all affect how carbon is stored. For example, colder and wetter climates promote the most effective carbon storage in soil.
Global Carbon Storage* (Tonnes of carbon per hectare)VegetationSoilWetlands 43 643
Boreal forests 64 344
Temperate grasslands 7 236
Tundra 6 127
Tropical forests 120 123
Tropical savannas 29 117
Temperate forests 57 96
Croplands 2 80
Deserts and semideserts 2 42

*Average stored carbon in tonnes per hectare at a ground depth of one meter
Source: IPCC

Wetlands are substantial reservoirs of carbon. Despite occupying only 5-8% of the Earth’s land surface, they hold between 20 to 30% of all estimated organic soil carbon.
Risks to Natural Carbon Sinks

Around 8.1 billion tonnes of CO2 leaks back into the atmosphere each year.

Over the last 20 years, the world has lost about 10% of its tree cover, or 411 million hectares (Mha). The main causes behind this are forestry (119 Mha), commodity-driven deforestation (103 Mha), and wildfires (89 Mha). What’s more, research suggests that Amazon rainforests emit more carbon than they absorb due to record levels of fires, many of which are deliberately set to clear for commodity production.

With the increasing frequency of wildfires and deforestation, the world’s forests are at risk of releasing carbon. Protecting and preserving these biomes is critical to the Earth’s carbon balance and mitigating climate change.
Carbon Credits Provide a Solution

Given the risk of losing critical carbon sinks, carbon credits play an important role in preserving these ecosystems.

Carbon credits can help finance projects that reduce or remove GHG emissions from the atmosphere. From improved forest management to reforestation, there are a number of different types of carbon projects across wetlands, grasslands, and various forests:
Reforestation and Afforestation
Avoided Deforestation
Natural forest management
Wetland restoration

For instance, a carbon credit project may preserve endangered tropical lowland peat swamp forests spanning thousands of hectares, such as the Rimba Raya Biodiversity Reserve Project in Indonesia, one of the projects that Carbon Streaming has a carbon credit stream.

Through this project, forests are prevented from being converted into palm oil plantations to reduce and avoid 130 million tonnes of GHG emissions during the 30 years of the project.

Another example would be the Cerrado Biome Project in Brazil, another carbon offset project where Carbon Streaming has a stream agreement. This project is protecting and preserving native forests and grasslands from being converted to commercial agriculture.

Importantly, these projects would not be economically viable without the sale of carbon credits. 

Protecting Stored Carbon

To prevent further loss of stored carbon, government policies, NGO-led initiatives, and the financing of carbon offset projects are gaining momentum. Taken together, they offer the critical intervention needed to preserve the earth’s carbon vaults.

ALBERTA

TransAlta completes conversion from coal to natural gas power in Canada

December 30, 2021

The Canadian Press

CALGARY – A major Canadian electricity producer is successfully off coal power in this country, nine years ahead of a government deadline.

Calgary-based Trans-Alta Corp. announced Wednesday it has finished its planned transition from coal to natural gas in its Canadian power generation.

The company said the recently completed conversion of the Keephills Unit 3 power plant west of Edmonton was the last of three coal-to-gas conversions at its Alberta thermal power generation facilities.29dk2902l

In a news release, TransAlta president and chief executive John Kousinioris said the company has achieved a significant milestone well ahead of the federal mandate that will require the full phaseout of coal-fired electricity generation in Canada by 2030.

“We are pleased to have completed this important step, nine years ahead of the government target,” Kousinioris said. “Our coal transition is among the most meaningful carbon emissions reduction achievements in Canadian history.”

Since 2019, TransAlta says it has invested $295 million into its coal-to-gas program, which also included the conversion of Sundance Unit 6 and Keephills Unit 2 near Wabuman, Alta., and Sheerness Units 1 and 2 near Hanna, Alta., plus the construction of new high-volume gas delivery infrastructure.

Converting to natural gas from coal maintains the company’s current generation capacity while at the same time reducing carbon dioxide emissions by almost 50 per cent, the company said.

As of Friday, TransAlta will also close its Highvale thermal coal mine, which is the largest in Canada and has been in operation on the south shore of Wabamun Lake west of Edmonton, since 1970.

TransAlta’s move away from coal is a major milestone in Alberta, which has been working to reduce its reliance on coal for power generation.

In 2014, 55 per cent of Alberta’s electricity was produced from coal. The province, under then-premier Rachel Notley, announced in 2015 — three years ahead of the federal government’s own coal mandate — that it would eliminate emissions from coal-powered generation by 2030.

In addition to TransAlta, other Alberta-based companies have also made major utility conversion commitments. Edmonton-based Capital Power Corp. has said it will spend nearly $1 billion to switch two coal-fired power units west of Edmonton to natural gas, and will stop using coal entirely by 2023.

TransAlta said that overall, it has retired 3,794 megawatts of coal-fired generation since 2018. The company still operates the Centralia coal-fired power plant in Washington State, which is set to shut down at the end of 2025.

TransAlta said that it is on track to reduce its annual greenhouse gas emissions by 60 per cent, or 19.7 million tonnes, by 2030 over 2015 levels and achieve net-zero emissions by 2050.

 Calgary·Opinion

Alberta steps closer to ending coal power, faster than many expected. But then comes the hard part

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Blake Shaffer on how to get to zero emissions from power

sector while keeping lights on (and costs down)

Blake Shaffer · For CBC Opinion · January 1,2022

TransAlta has finished converting the last of its three coal power generating plants to natural gas, a transition at the Keephills plant west of Edmonton. The Calgary-based company says the switch cuts almost in half the emissions intensity of the power at the Keephills unit. (Sam Martin/CBC)

This opinion piece is by Dr. Blake Shaffer, an assistant professor of economics and public policy at the University of Calgary. He was formerly the head trader for western power and gas at TransAlta. 

---

Another year, another step closer to the end of coal power in Alberta.

As we turn our calendars to 2022, only three coal-fired power plants will remain in Alberta. With TransAlta's Keephills 1 coal power plant shuttering Dec. 31, and Keephills 3 and Sundance 4 switching from burning coal to natural gas, the Genesee 1, 2, and 3 facilities at Warburg are now the last of what was, only a few years ago, Alberta's most-used source of electricity.

The end of coal power in Alberta is happening faster than many expected, and well ahead of regulations set first by Ottawa in 2012 and updated in Alberta in 2015. Only a decade after Alberta commissioned its last coal plant, the regulatory phase-out scheduled for 2030 is a moot point, with the remaining Genesee plants set to convert to natural gas by the end of 2023. Coal, once responsible for over 80 per cent of Alberta's electric generation, and roughly half only five years ago, will be gone. 

This chart shows coal power's share of Alberta's annual electricity demand, as it shrinks over the years from a high of 81 per cent in 2001 to 20 per cent in 2021 and an expected zero per cent by 2023. (Blake Shaffer)

This will be the biggest greenhouse gas reduction in Alberta's history. A true climate success story. But we're not done yet. Converting to natural gas was the easy part. The road ahead to meet the federal government's goal of eliminating all emissions from the power sector by 2035 will be the hard part.

Our recent cold snap, with temperatures plunging to –30, and lower, across the province offers a glimpse of the challenge ahead. While renewables now account for one quarter of Alberta's generating capacity (that alone is a pretty amazing stat), they produced less than five per cent of the energy during the cold days at the end of 2021. A dearth of wind coinciding with the coldest conditions, something unfortunately all too common for Alberta wind in winter, meant the lion's share of Alberta's power came from natural gas.

This line graph shows how wind power generation in Alberta dropped during a cold snap in late December. A dearth of wind coinciding with the coldest conditions, something all too common for Alberta wind in winter, meant the lion's share of the province's power came from natural gas. (Blake Shaffer)

This isn't intended as a knock on renewables. It's simply a reminder that they are what they are, and that is raw, or intermittent, energy. And that's OK so long as that's what we expect and what we're paying for. When wind and solar were expensive, as in Ontario a decade ago, people had a reason to question their merit. But now that they're cheap — and they really are cheap — it can be worth accepting their intermittency. (As I like to tell my electricity students, even I will drink cheap red wine sometimes, so long as it's cheap!)

The key is knowing what to expect, being honest about what they provide (and paying accordingly), and finding ways to integrate these abundant and cheap resources into our power mix using other flexible, or "firm," resources. Renewables can and likely will produce the bulk of Alberta's electric energy in the future, but other resources will be needed to couple with them to ensure reliable capacity, or "on-demand" availability.

Firming up Alberta's power supply

With that in mind, how can Alberta get to zero while keeping the lights on (and costs down)? 

First, we need to better engage demand. While not for everyone, encouraging those with some flexibility (hello, EV chargers!) to shift when they pull from the grid can limit the strain on the system. More supply variability from renewables, and cheaper automated ways to flexibly control demand, make this an increasingly valuable and feasible low-cost option. Regulators and electricity providers need to innovate to encourage this type of behaviour.

Second, while unabated natural gas has a limited role in a zero emission future, natural gas plants equipped with carbon capture offer a way to take advantage of Alberta's plentiful natural gas reserves. Capital Power is planning to go down this route with their Genesee facility. Another option is to convert these plants to clean-burning hydrogen. As hydrogen production gets cheaper, this starts to become an attractive option. "Green" hydrogen, produced through electrolysis, also offers a way to store hydrogen by soaking up periods of excess wind and solar power.

While unabated natural gas has a limited role in a zero emission future, natural gas plants equipped with carbon capture offer a way to take advantage of Alberta's plentiful natural gas reserves, Blake Shaffer writes. Capital Power is planning to go down this route with their Genesee Generation Station, located 70 kilometres southwest of Edmonton. (Supplied by Capital Power)

Third, nuclear reactors, of the small modular variety, are a potential game-changer. Though they have to clear some pretty steep technical and economic hurdles to be viable, it's worth remembering that wind and solar were also once deemed infeasibly expensive 10 years ago, until they weren't. 2035, however, is a tight deadline for nuclear to get its technical, economic, and regulatory ducks in a row. Geothermal is another firm supply option, one similarly plagued with cost questions, but also one that can leverage the oil and gas skill set in this province.

Fourth, storage offers a way to take advantage of Alberta's abundance of cheap wind and solar, shifting the energy from periods of plenty to when it's needed. Batteries can offer short duration storage, while pumped hydro and even compressed air can offer longer duration opportunities. As renewables get cheaper, storage becomes increasingly attractive. And believe me, Alberta will be building a lot more renewables in the years to come.

Fifth, bigger transmission connections between Alberta and B.C. ought to be part of the mix. Comparative advantages exist on both sides of the border (B.C. has the peaking capacity; Alberta has the cheap variable energy). Rather than one-way flow like pipelines, transmission lines mean exporting when the wind is fierce, and importing hydro power when it's not. This exchange won't come free, but it's cheaper than many of the alternatives.

So what's needed to make these resources a reality?

For starters, those saying "it can't be done" need to be reminded that many also said phasing out coal by 2030, let alone 2023, wouldn't be possible, that coal-to-gas conversions were hard, and that wind would never be procured for less than $80 per megawatt-hour, let alone the mid-$30s observed recently.

Nonetheless, some clarity on where we are headed is needed. Uncertainty is anathema for investors. If Alberta is truly headed for zero emission power by 2035, planning and investment needs to start now. To the extent governments can de-risk policy uncertainty by providing clear and durable guidance on future carbon prices and emissions regulations, this will better enable the new resources that are needed to be built.

Also, and perhaps a topic for a deep dive on another day, Alberta's market design may have to evolve to ensure reliability as we transition. We went down this road five years ago, with Alberta's system operator recommending, and the NDP accepting, the introduction of a capacity market — essentially paying for steel in ground, i.e., the ability to produce, not just energy generated. This was rescinded in 2019 under the UCP, but the need for some form of instrument to ensure sufficient resources in the longer run never went away.

To date, Alberta's short run energy market has attracted sufficient long run investment. Will that be the case as we transition? And, importantly, what will prices do along the way? Texas, whose power market is the closest thing in North America to Alberta's, is grappling with this same question in the aftermath of brutal power outages last February. They, too, are currently considering enhancing their market with some form of reliability mechanism. Alberta ought to take note and take this issue on proactively.

What are we the consumers to do?

Finally, what does this mean for you and I? 

Those that follow me on Twitter won't be surprised to hear me say: get on a fixed rate plan. While the market will be volatile, there's no reason those bumps need to flow through to consumers' pocketbooks. There remain five-year fixed rate plans today that are well below where the market is currently indicating prices will be over that period. And if things change, most of these plans give you the flexibility to exit. I've done it, and I'd encourage others to consider it as well.

Installing solar panels is one way consumers can insulate themselves against rising power prices, Blake Shaffer writes. Here, solar panels can be seen on the roofs at the Prairie Sky Cohousing Co-operative in northeast Calgary, which has got all its energy from solar since 2020. (Submitted by Lise Rajewicz)

Another option to consider to protect yourself against rising prices is to add solar panels. It won't take you off the grid — you'll still be paying those pesky fixed charges, and for power when you're using more than you generate — but the amount you produce will reduce your exposure to energy prices, even allowing you to receive a credit when you're surplus. What was once a luxury for the ultra-green or techno-curious is now in the realm of economically reasonable with panel costs falling and the federal government handing out $5,000 retrofit cheques. And with the cities of Calgary and Edmonton now offering low-cost financing by spreading the cost over many years on your property tax bill, it's more accessible to more people.

The bottom line is that Alberta's power system is changing. And though the emissions reductions are a good thing, with change will come some turbulence. Getting to zero by 2035 will be no easy feat with many bumps in the road. It's time to ensure our markets, policies, and plans are ready to get us there.

ABOUT THE AUTHOR

Blake Shaffer

Blake Shaffer is an assistant professor of economics and public policy at the University of Calgary. Prior to academia, he had a 15-year career in energy trading.

Canada's Capital Power and Enbridge to partner on carbon capture project


FILE PHOTO: The Enbridge Tower on Jasper Avenue in Edmonton

Mon, November 29, 2021, 7:14 AM·1 min read

(Reuters) - Capital Power Corp and Enbridge Inc agreed to partner on a carbon capture and storage (CCS) project, the companies said on Monday, that would aim to capture up to three million tonnes of carbon dioxide emissions annually.

The proposed project would serve Capital Power's Genesee Generating Station near Warburg, Alberta, which currently provides over 1,200 megawatts of baseload electricity generation to Albertans.

Alberta, home to Canada's oil sands, is aiming to become a hub for carbon storage and hydrogen production as the world moves away from fossil fuel consumption and tries to cut climate-warming carbon emissions.

Enbridge would be the transportation and storage service provider, while Capital Power would be the carbon dioxide provider on the project, which could be in service as early as 2026.

The captured carbon dioxide emissions from the re-powered units would be transported and stored through Enbridge's open access carbon hub that could also serve several other local industrial companies.

Enbridge is applying to develop an open access carbon hub in the Wabamun area through the government of Alberta's request for full project proposals process, which is expected to start as early as December 2021.

Companies including TC Energy, Suncor Energy, Royal Dutch Shell also plan to build new CCS storage facilities.

(Reporting by Arunima Kumar in Bengaluru; Editing by Shailesh Kuber)

Small villages in Alberta quietly disappearing as revenues dry up, costs rise

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In the last decade, 15 communities have dissolved in the province

Liam Harrap · CBC News · Posted: Oct 16, 2021

The Village of Warner, Alta., is located approximately 65 kilometres south of the Lethbridge, Alta. Next year, the community will face a vote by resident on whether to dissolve and become a hamlet. (Joel Dryden/CBC)

After 92 years, the Village of Hythe in northern Alberta is no more. 

The community of approximately 800 people became a hamlet this summer after 95 per cent of local residents voted in support of the change.

"No one thought this was the best thing that ever happened to us, but it was the best of two bad choices," said Brian Peterson, former mayor of Hythe, west of Grande Prairie. 

If Hythe remained incorporated, property taxes would have increased by 150 per cent to pay mounting infrastructure bills, Peterson told CBC Edmonton's Radio Active. 

Due to closing commercial businesses in rural Alberta communities, there is less revenue to pay for public services like plowing snow, water and sewage, said Peterson. 

• After nearly 110 years, Granum is no longer a town

Small rural communities are also hubs for the broader surrounding areas with doctor offices, hockey arenas and churches — all of which pay no tax to the municipality. 

"It becomes unsustainable," said Peterson. 

Even if Hythe remained a village and increased taxes, few could have afforded to pay, he said. 

"There was no other way out." 

6:56Hythe Alberta

The village voted to dissolve itself and become a hamlet. Brian Petersen is the former mayor of the community. 6:56

The death of local governments

This problem is not solely Hythe's. 

Since 2012, 15 communities have dissolved in Alberta, resulting in them no longer having a mayor or council. Instead they become governed by the local county. 

In Hythe's case that's the County of Grande Prairie, which manages 11 other hamlets.

"We've lost self-direction," Peterson said. 

In the last 29 years, Jasper is the only newly created municipality in Alberta.  

Municipality	Year incorporated	Year dissolved
Village of New Norway	1910	2012
Village of Tilley	1940	2013
Village of Minburn	1919	2015
Village of Galahad	1918	2016
Village of Strome	1910	2016
Village of Willingdon	1928	2017
Village of Botha	1911	2017
Town of Grande Cache	1966	2019
Village of Ferintosh	1919	2020
Town of Granum	1904	2020
Village of Cereal	1914	2020
Village of Dewberry	1957	2020
Village of Gadsby	1909	2020
Village of Wabamun	1980	2021
Village of Hythe	1929	2021

Municipal Affairs press secretary Greg Smith said in an email to CBC that the vast majority of municipalities have financial resilience and the province does not expect a surge in applications for communities to dissolve in the coming years. 

But Peterson has a different point of view on the issue. 

"I think there's a lot of other towns and villages that are in financial trouble and don't realize it," he said. 

Rising costs

To preserve village governments, the province needs to develop new tax structures and share revenues more equally, Peterson said. 

• Grande Cache residents vote to dissolve their town

The province has significantly cut grants to help with upgrading infrastructure, said Jon Hood, chief administration officer for the Village of Warner, south of Lethbridge. 

Warner has lost grant funding by approximately 40 per cent in the last five years, he said.

Meanwhile, costs to provide services are increasing.  

Soon the community will have to pay to have an RCMP presence, a service that was previously free. 

"It's becoming extremely difficult to survive," said Hood. 

Residents of Warner will vote next year on whether to follow the same path as Hythe. 

The Town of Grande Cache was incorporated in 1966 for the development of a coal mine and was dissolved in 2019 due to a shrinking population. (CBC)

Tonya Ratushniak, former mayor of the Village of New Norway, which dissolved in 2012, said the rising cost of insurance is also hurting rural communities. 

"We used to have a lot more ham and turkey bingos and suppers," she said. 

Now, to cover liability in case someone falls, trips or chokes, it's not easy to throw events together quickly or cheaply, she said. 

"Because of this there aren't as many events in a small town as there used to be," said Ratushniak. 

While Hythe's decision to dissolve was necessary to save the community, said Peterson, it's not something he's proud of as the village's last mayor. 

"I'm certainly not going to put it on my resume," he said quietly. 

"But sometimes when you're in a leadership role, you have to make tough decisions." 

Liam Harrap  is a journalist at CBC Edmonton. He is also a big fan of fruit and meat pies. Send story tips (and recipes) to him at liam.harrap@cbc.ca.