Resource Works Margareta Dovgal on B.C. Climate Policies, and Their Implications

From EnergyNow.ca

By Margareta Dovgal

In the midst of a memorable polar cold snap in January, British Columbia faced a stark reality that should serve as a valuable lesson for climate activists and policymakers alike. As Stewart Muir, the founder of our organization, aptly pointed out at the time, “When it’s cold like now, BC gets two thirds of its energy for heating, etc., from natural gas. Promises to ditch the fuel by 2030, 2035, 2050, are political theatre to be taken with a large scoop of road salt.”

The deep freeze eventually thawed, but it left behind a lingering question about the feasibility of ambitious climate policies in a province heavily reliant on natural gas for its energy needs. The provincial government responded with a proposal to ban conventional gas equipment in new residential, commercial, and institutional buildings by 2030. This move would not only prohibit the sale and installation of gas water heaters but also impose restrictions on new gas furnaces and boilers, permitting them only as part of a hybrid dual-fuel system that integrates electric or gas heat pumps with conventional gas combustion appliances.

While the government embarked on consultations with natural gas contractors, First Nations, and other stakeholders, the public sentiment was reflected in a Castanet news service poll in the Okanagan region. The poll asked, “Should BC ban the use of conventional natural gas for home heating as of 2030?” The results were strikingly clear:

No: 12,460 (91%)
Yes: 725 (5.3%)
Unsure: 501 (3.7%)

However, the proposal to shift away from natural gas raised concerns about BC’s electricity infrastructure. During the cold snap, the province had to import 15% of its electricity, and when Alberta faced even colder temperatures, BC had to step in and send power across the border. Contractors like Al Russell of Prince George questioned the province’s ability to meet increased electricity demands, especially with the limitations of existing infrastructure.

Russell pointed out the need for significant upgrades to the electricity grid, including more and larger transmission lines and transformers. The pressing question remained: “Where are we getting this power from and how are we getting it there? When does this expansion start, and how much will it cost?”

These concerns are not unique to BC. A recent report from the Public Policy Forum emphasized that to achieve its goal of net-zero emissions by 2050, Canada must invest heavily in expanding its electricity generation capacity. This ambitious undertaking comes with a potentially significant cost, with the report envisioning a landscape filled with new dams, turbines, nuclear plants, and solar panels.

Even though BC’s BC Hydro once maintained that no additional power generation was needed, the province now anticipates a shift from a surplus to a deficit of power by 2030, even with the Site C power dam set to be operational by 2025. Consequently, BC Hydro plans to seek new clean and renewable energy sources through a competitive process, inviting power providers to contribute to the province’s energy needs.

Premier David Eby has also announced a significant update to Hydro’s 10-year capital plan, earmarking nearly $36 billion for community and regional infrastructure projects by 2034. However, building new transmission lines in the past has proven to be a lengthy process, taking anywhere from eight to ten years. Eby himself acknowledged that such delays were unacceptable.

Chair of the Energy Futures Initiative, Barry Penner, highlighted the findings of the North American Electric Reliability Corporation, which forecasted increased energy risks for BC in 2026 due to rising demand and the retirement of natural-gas-fired generation.

All these developments transpire as BC advances its CleanBC policy and program. Yet, the BC Business Council voiced concerns about the economic implications, stating that the provincial government’s policies could potentially shrink BC’s economy by $28 billion by 2030, setting prosperity back more than a decade.

The cold snap served as a reminder that the impact of these policies goes beyond mere comfort or convenience. In northern climates like BC’s, extreme cold can pose significant hazards to human health, wellness, and survivability. It also underscores the importance of stable and secure infrastructure, especially with the risk of water pipes bursting during freezing temperatures.

As BC strives to replace some natural gas services with electricity, affordability becomes a pressing concern. There are three key aspects to consider:

Capital and Operating Costs: Transitioning to electricity comes with increased costs compared to running natural gas systems.
Heat Pump Installation: Installing heat pumps adds to the financial burden.
Housing and Rent Costs: The ripple effect of increased costs may result in higher housing and rent expenses, exacerbating affordability challenges in the region.

An editorial from The Orca labeled BC’s natural gas plan as ‘all hot air,’ expressing concerns about making new homes more expensive to build and live in, especially during a housing crisis.

The climate policies in BC carry significant implications, not only for the affordability of living in the province but also for its economic growth and stability. These policies have the potential to impact the types of jobs available, their associated wages, and the province’s global competitiveness.

The net outcome of these policies could determine the fate of industries deeply rooted in BC’s history. If these industries can no longer thrive due to regulatory changes, it may have far-reaching consequences for the well-being of the province’s residents.

As BC navigates this complex landscape, there is an opportunity for the provincial government to engage with and consider the concerns of the public. With an election year on the horizon, the public should continue to ask questions, seek clarity, and actively participate in shaping the future of their province.

Margareta Dovgal on these issues, and more, on Vancouver’s Spice Radio: https://ow.ly/hxsB50QvfJ9

Margareta Dovgal is Managing Director of Resource Works. Based in Vancouver, she holds a Master of Public Administration in Energy, Technology and Climate Policy from University College London. Beyond her regular advocacy on natural resources, environment, and economic policy, Margareta also leads our annual Indigenous Partnerships Success Showcase. She can be found on Twitter and LinkedIn.

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Trump opens door to Iranian oil exports

Canadian Energy Centre / 9 hours ago

Alberta oil sands legacy tailings down 40 per cent since 2015

Economy

Trump opens door to Iranian oil exports

Published on July 3, 2025

Todayville

This article supplied by Troy Media.

By Rashid Husain Syed

U.S. President Donald Trump’s chaotic foreign policy is unravelling years of pressure on Iran and fuelling a surge of Iranian oil into global markets. His recent pivot to allow China to buy Iranian crude, despite previously trying to crush those exports, marks a sharp shift from strategic pressure to transactional diplomacy.

This unpredictability isn’t just confusing allies—it’s transforming global oil flows. One day, Trump vetoes an Israeli plan to assassinate Iran’s supreme leader, Ayatollah Khamenei. Days later, he calls for Iran’s unconditional surrender. After announcing a ceasefire between Iran, Israel and the United States, Trump praises both sides then lashes out at them the next day.

The biggest shock came when Trump posted on Truth Social that “China can now continue to purchase Oil from Iran. Hopefully, they will be purchasing plenty from the U.S., also.” The statement reversed the “maximum pressure” campaign he reinstated in February, which aimed to drive Iran’s oil exports to zero. The campaign reimposes sanctions on Tehran, threatening penalties on any country or company buying Iranian crude,
with the goal of crippling Iran’s economy and nuclear ambitions.

This wasn’t foreign policy—it was deal-making. Trump is brokering calm in the Middle East not for strategy, but to boost American oil sales to China. And in the process, he’s giving Iran room to move.

The effects of this shift in U.S. policy are already visible in trade data. Chinese imports of Iranian crude hit record levels in June. Ship-tracking firm Vortexa reported more than 1.8 million barrels per day imported between June 1 and 20. Kpler data, covering June 1 to 27, showed a 1.46 million bpd average, nearly 500,000 more than in May.

Much of the supply came from discounted May loadings destined for China’s independent refineries—the so-called “teapots”—stocking up ahead of peak summer demand. After hostilities broke out between Iran and Israel on June 12, Iran ramped up exports even further, increasing daily crude shipments by 44 per cent within a week.

Iran is under heavy U.S. sanctions, and its oil is typically sold at a discount, especially to China, the world’s largest oil importer. These discounted barrels undercut other exporters, including U.S. allies and global producers like Canada, reducing global prices and shifting power dynamics in the energy market.

All of this happened with full knowledge of the U.S. administration. Analysts now expect Iranian crude to continue flowing freely, as long as Trump sees strategic or economic value in it—though that position could reverse without warning.

Complicating matters is progress toward a U.S.-China trade deal. Commerce Secretary Howard Lutnick told reporters that an agreement reached in May has now been finalized. China later confirmed the understanding. Trump’s oil concession may be part of that broader détente, but it comes at the cost of any consistent pressure on Iran.

Meanwhile, despite Trump’s claims of obliterating Iran’s nuclear program, early reports suggest U.S. strikes merely delayed Tehran’s capabilities by a few months. The public posture of strength contrasts with a quieter reality: Iranian oil is once again flooding global markets.

With OPEC+ also boosting output monthly, there is no shortage of crude on the horizon. In fact, oversupply may once again define the market—and Trump’s erratic diplomacy is helping drive it.

For Canadian producers, especially in Alberta, the return of cheap Iranian oil can mean downward pressure on global prices and stiffer competition in key markets. And with global energy supply increasingly shaped by impulsive political decisions, Canada’s energy sector remains vulnerable to forces far beyond its borders.

This is the new reality: unpredictability at the top is shaping the oil market more than any cartel or conflict. And for now, Iran is winning.

Toronto-based Rashid Husain Syed is a highly regarded analyst specializing in energy and politics, particularly in the Middle East. In addition to his contributions to local and international newspapers, Rashid frequently lends his expertise as a speaker at global conferences. Organizations such as the Department of Energy in Washington and the International Energy Agency in Paris have sought his insights on global energy matters.

Troy Media empowers Canadian community news outlets by providing independent, insightful analysis and commentary. Our mission is to support local media in helping Canadians stay informed and engaged by delivering reliable content that strengthens community connections and deepens understanding across the country.

Canadian Energy Centre

Alberta oil sands legacy tailings down 40 per cent since 2015

Published on July 3, 2025

Todayville

Wapisiw Lookout, reclaimed site of the oil sands industry’s first tailings pond, which started in 1967. The area was restored to a solid surface in 2010 and now functions as a 220-acre watershed. Photo courtesy Suncor Energy

From the Canadian Energy Centre

By CEC Research

Mines demonstrate significant strides through technological innovation

Tailings are a byproduct of mining operations around the world.

In Alberta’s oil sands, tailings are a fluid mixture of water, sand, silt, clay and residual bitumen generated during the extraction process.

Engineered basins or “tailings ponds” store the material and help oil sands mining projects recycle water, reducing the amount withdrawn from the Athabasca River.

In 2023, 79 per cent of the water used for oil sands mining was recycled, according to the latest data from the Alberta Energy Regulator (AER).

Decades of operations, rising production and federal regulations prohibiting the release of process-affected water have contributed to a significant accumulation of oil sands fluid tailings.

The Mining Association of Canada describes that:

“Like many other industrial processes, the oil sands mining process requires water.

However, while many other types of mines in Canada like copper, nickel, gold, iron ore and diamond mines are allowed to release water (effluent) to an aquatic environment provided that it meets stringent regulatory requirements, there are no such regulations for oil sands mines.

Instead, these mines have had to retain most of the water used in their processes, and significant amounts of accumulated precipitation, since the mines began operating.”

Despite this ongoing challenge, oil sands mining operators have made significant strides in reducing fluid tailings through technological innovation.

This is demonstrated by reductions in “legacy fluid tailings” since 2015.

Legacy Fluid Tailings vs. New Fluid Tailings

As part of implementing the Tailings Management Framework introduced in March 2015, the AER released Directive 085: Fluid Tailings Management for Oil Sands Mining Projects in July 2016.

Directive 085 introduced new criteria for the measurement and closure of “legacy fluid tailings” separate from those applied to “new fluid tailings.”

Legacy fluid tailings are defined as those deposited in storage before January 1, 2015, while new fluid tailings are those deposited in storage after January 1, 2015.

The new rules specified that new fluid tailings must be ready to reclaim ten years after the end of a mine’s life, while legacy fluid tailings must be ready to reclaim by the end of a mine’s life.

Total Oil Sands Legacy Fluid Tailings

Alberta’s oil sands mining sector decreased total legacy fluid tailings by approximately 40 per cent between 2015 and 2024, according to the latest company reporting to the AER.

Total legacy fluid tailings in 2024 were approximately 623 million cubic metres, down from about one billion cubic metres in 2015.

The reductions are led by the sector’s longest-running projects: Suncor Energy’s Base Mine (opened in 1967), Syncrude’s Mildred Lake Mine (opened in 1978), and Syncrude’s Aurora North Mine (opened in 2001). All are now operated by Suncor Energy.

The Horizon Mine, operated by Canadian Natural Resources (opened in 2009) also reports a significant reduction in legacy fluid tailings.

The Muskeg River Mine (opened in 2002) and Jackpine Mine (opened in 2010) had modest changes in legacy fluid tailings over the period. Both are now operated by Canadian Natural Resources.

Imperial Oil’s Kearl Mine (opened in 2013) and Suncor Energy’s Fort Hills Mine (opened in 2018) have no reported legacy fluid tailings.

Suncor Energy Base Mine

Between 2015 and 2024, Suncor Energy’s Base Mine reduced legacy fluid tailings by approximately 98 per cent, from 293 million cubic metres to 6 million cubic metres.

Syncrude Mildred Lake Mine

Between 2015 and 2024, Syncrude’s Mildred Lake Mine reduced legacy fluid tailings by approximately 15 per cent, from 457 million cubic metres to 389 million cubic metres.

Syncrude Aurora North Mine

Between 2015 and 2024, Syncrude’s Aurora North Mine reduced legacy fluid tailings by approximately 25 per cent, from 102 million cubic metres to 77 million cubic metres.

Canadian Natural Resources Horizon Mine

Between 2015 and 2024, Canadian Natural Resources’ Horizon Mine reduced legacy fluid tailings by approximately 36 per cent, from 66 million cubic metres to 42 million cubic metres.

Total Oil Sands Fluid Tailings

Reducing legacy fluid tailings has helped slow the overall growth of fluid tailings across the oil sands sector.

Without efforts to reduce legacy fluid tailings, the total oil sands fluid tailings footprint today would be approximately 1.6 billion cubic metres.

The current fluid tailings volume stands at approximately 1.2 billion cubic metres, up from roughly 1.1 billion in 2015.