Planned in an area battling drought, the project’s water needs would also be vast, rivalling the annual use of hundreds of thousands of Alberta households.

Called “Wonder Valley,” the project is still nowhere near getting off the ground. But if it ever gets built as planned, it could pump out 25.7 to 30.5 megatonnes of emissions a year, depending on what turbines and gas are used, and whether or not it includes carbon capture, found Pembina Institute senior analyst Jason Wang, who crunched the numbers for The Mix.

“It would be the equivalent of a return to the era of mostly coal-fired electricity,” said Wang.

The reversal would set the province and Canada back about 20 years, matching the 27 megatonnes of coal emissions Alberta phased out between 2005 and 2023.

The data centre complex, which O’Leary claims will be the “largest on Earth,” would require the equivalent of about 10% of all gas supply in Alberta once fully operational.

It’s still just a concept, but in the Municipal District of Greenview where it’s planned, local officials are confident it will be built. “We’re about to pull off the largest project in Canadian history in this sector, and I think Greenview should be really proud of that,” chief administrative officer Stacey Wabick told council members at a budget review meeting in November.

Wonder Valley was announced with great fanfare last December, a few days after the Alberta government unveiled a new data centre strategy designed to attract $100 billion in investments.

At the time, Innovation Minister Nate Glubish said data centres would play a “significant role” in Premier Danielle Smith’s plan to double oil and gas production by increasing domestic demand for gas.

The land designated for Wonder Valley is south of Grande Prairie, about 460 kilometres northwest of Edmonton. It’s located on the massive Montney Formation, one of North America’s, and perhaps one of the world’s, largest gas reservoirs.

Wang said the first phase of the project, requiring 1,400 megawatts (MW) of power, would generate about 4.7 megatonnes of carbon dioxide per year using shale gas to run a combined-cycle gas turbine, the most efficient type of gas power. That would make it one of the largest industrial facilities in the province, he said.

OpenAI selects Argentina for its first data centre in Latin America

Carbon capture and storage has been promised for Wonder Valley, but not necessarily at start-up. Wang said a carbon pipeline would need to be built between the facility and an injection site. “With carbon-capture efficacy at about 80%, it would still mean the first phase of Wonder Valley would be 1.3 megatonnes per year of greenhouse gas emissions,” Wang said.

Another requirement for data centres is the large amount of water they use for cooling. But water is also needed to run gas power plants. Even though the Grande Prairie area is known for longer, colder winters, Wang estimated that the water needed for the fully completed data centre, including both cooling and for the power plant, would be between 112 and 195 billion litres per year. That is roughly one-third to two-thirds of the total annual water consumption of all the households in Alberta.

Multiple communities in the region are struggling with drought and water supply issues. Greenview itself declared an agricultural disaster due to drought this past summer, and that same day, its council approved adding more land to the purchase agreement being negotiated with O’Leary.

This story is part of the Hidden Wonder Valley investigative series by The Energy Mix. It has been edited to conform with Corporate Knights style.

Jody MacPherson is a freelance journalist based in Calgary. 

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When Texas legislators conceived of the Texas Energy Fund (TEF) in the spring of 2023, its goal of jump-starting the construction of more natural gas power plants to support the state’s strained power grid seemed reasonable.

In the two years since that vote, however, experts say the energy market has turned against the development of gas-fired power plants. Experts and energy companies say the fund’s $7.2 billion (all figures in U.S. dollars) worth of low-interest loans and bonus grants may not be appealing enough to overcome those economic headwinds. “It is a challenging market for natural gas developers right now, and it has been for a good amount of time,” said Walt Baum, CEO of Powering Texans, a trade association representing Calpine, Constellation, NRG and Vistra, the state’s four largest operators of dispatchable power.

Only two new proposals have been approved so far through TEF’s In-ERCOT Generation Loan Program, the one of four programs included in the fund intended to coax energy companies into building new gas power plants. The two loans, both to be paid back over 20 years at a 3% interest rate, would tap just $321 million of the $7.2 billion total.

Together, the plants would have a capacity to generate 578 megawatts of electricity, a drop in the bucket compared to the roughly 62,500 megawatts of additional electricity that regulators forecast the state will need to generate by 2030.

The market in Texas is saying loud and clear that gas is not going to be built any time soon.

– Dennis Wamsted, Institute for Energy Economics and Financial Analysis 

Another 15 loan applications are currently in the pipeline totalling 8,392 megawatts, according to the Public Utility Commission (PUC), which administers TEF.

But of the 25 total loan applications that have advanced to the fund’s due diligence review stage, seven have been pulled from consideration by the companies that filed them, citing supply chain issues or forecasts that the projects would not be as profitable as expected. An eighth application was denied funding last fall because of accusations of fraud.

The most recent company to withdraw an application, Hunt Energy Network, cited the cost effectiveness of constructing a natural gas power plant under the loan program as the reason for its withdrawal, according to a July 25 letter to the PUC.

Economic factors work against natural gas development

The fund was created in the wake of winter storm “Uri,” the February 2021 storm that plunged most of the state into blackouts during freezing weather for days, leaving hundreds of people dead.

Governor Greg Abbott and other Republican leaders were quick to blame trouble with wind- and solar-power generation for the power outages. While renewables did struggle to generate electricity in the frigid temperatures, so did natural gas power generation after power plant equipment and some pipelines that supply gas to the plants froze.

After that disaster, lawmakers argued that the state needed more on-demand power – specifically natural gas power plants – that doesn’t require wind and sun to generate electricity. They started the Texas Energy Fund with an initial $5 billion, and earlier this year added another $5 billion. $2.8 billion was set aside for separate programs to support backup power generation for critical infrastructure and modernization incentives for natural gas plants.

But since 2023, the economic factors working against the development of natural gas plants have only worsened.

Energy demand is rising globally as a result of the construction of new data centres for artificial intelligence, and many regions are turning to natural gas power because of its relative affordability, lower emissions compared to coal, and its ability to operate at all times of the day, unlike wind and solar.

That demand is straining the supply chain for turbines, specialized equipment used in power plants that cost tens of millions of dollars. Wait times on orders for the machinery have doubled just over the past year, and tariffs are now increasing their price further.

A turbine order placed today likely would not arrive before 2029, and only if a company were willing to pay a premium to get it quickly, said Doug Lewin, author of the Texas Energy and Power Newsletter.

At the same time, the Electric Reliability Council of Texas, the state’s power grid operator, is predicting that energy demand in the state will double by 2030. The increase is driven by oil and gas operators in the Permian Basin transitioning operations to run on electricity rather than gas or diesel, as well as Texas’s own AI and data centre boom.

Renewables set to satisfy surging power demand

The state is on course to meet those electricity demands, but largely through advancements in solar technology and battery storage, which are significantly cheaper than natural gas power plants to install.

In Texas’s deregulated energy market, which gives preference to the least-expensive power, this takes away the forecast market share available to companies hoping to profit from a new natural gas power plant, meaning the plants cost more to install and are likely to make less money over time, said Dennis Wamsted, an energy analyst with the non-profit Institute for Energy Economics and Financial Analysis. “Markets speak loud and clear if you listen to what they’re saying,” he said. “The market in Texas is saying loud and clear that gas is not going to be built any time soon.”

Legislators this spring have responded by extending the deadline for spending the $5 billion they approved in 2023. Under the original legislation creating the fund, the PUC had until the end of this year to distribute the money earmarked for power plant construction loans. Senate Bill 2268 by state Senator Charles Schwertner (R-Georgetown) gave the PUC authority to extend that deadline if “market factors necessitate.”

“What we didn’t know two years ago is that various market influences would affect the TEF application process, such that supply chain disruptions . . . would impact the timeline for several otherwise well-qualified projects,” Schwertner said in an April committee hearing about the bill.

PUC says interest remains high for loans

The PUC in a statement said that demand for the natural gas plant loan program has been high, citing the 15 applications that have reached the due diligence review stage. The agency said it is focusing on reaching loan agreements for those 15 applicants before deciding if an extension on the disbursement deadline is necessary.

State Representative Rafael Anchía (D-Dallas) said he believes those who have applied for loans were planning to build a natural gas plant without the state energy fund and are now asking taxpayers to help cover the cost. “If taxpayers are subsidizing a lower interest rate than what they could get in the market, of course [energy companies] will take a free ride,” Anchía said.

Anchía voted against SB 2268, calling the loan program a “big government” approach to influencing the energy market. He did vote for the additional $5 billion in money for the fund, citing the fund’s two other programs supporting backup power generation for critical infrastructure and modernization incentives for natural gas units.

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Members of the Legislature’s Texas Energy Fund Advisory Committee have not met since October but plan to in the coming months as part of a regular review of the effectiveness of the fund’s policies, said Representative Ana Hernandez (D-Houston), a member of the committee.

Representative David Spiller (R-Jacksboro), who is co-chair of the advisory committee, said he believes the fund’s effectiveness is worth studying because the Legislature’s original intention was to bring these gas plants online quickly. “We know that over a period of time we will get to where we need to be,” Spiller said. “My concern is over the next five or six years, bridging that gap. I think sooner rather than later we need to look at that and maybe review what we have in place and tweak it some.”

This article originally appeared in The Texas Tribune, a member-supported, nonpartisan newsroom informing and engaging Texans on state politics and policy. It has been edited to conform with Corporate Knights style. 

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This is no longer the case.

Canadian pension funds have risked billions of dollars in workers’ retirement savings on gas companies that make the climate crisis worse and that face terminal decline as the energy transition accelerates. While gas companies insist they can decarbonize their operations and protect their business model by repurposing their infrastructure to transport and use hydrogen, these flimsy claims don’t stand up to due diligence.

As climate change provokes stronger emission-reduction policies and as cheaper zero-carbon technologies proliferate, gas companies are soon entering an era of shrinking demand and lost customers. This could result in billions of dollars in stranded gas assets and significant losses for Canadian pension funds.

New research published by Shift reveals the extent of these climate-related financial risks. Nine of Canada’s public pension managers are co-owners of 22 private gas distribution, transmission, power generation, processing and storage companies, collectively operating nearly 350,000 kilometres in pipelines globally.

As long-term investors with a fiduciary duty to invest in members’ best interests, pension funds are obligated to manage climate-related risks. Owning thousands of kilometres of gas pipelines has become incompatible with this duty.

– Patrick DeRochie, Senior Manager, Shift Action for Pension Wealth and Planet Health

Demand for low-cost electrification technologies, like heat pumps, renewable energy and battery storage, is skyrocketing. Gas companies face the prospect of lower demand for gas transmission and distribution – leading toward a “gas utility death spiral.” Gas utility customers are increasingly choosing to leave the gas system (for example by swapping their gas furnace for a heat pump). As more customers ditch gas, utilities must spread their fixed infrastructure costs over a shrinking pool of customers, driving up prices for those remaining. That in turn pushes even more gas customers to leave.

There’s no safety for pensions in betting that the energy transition will occur slowly. The longer these pipelines operate – perpetuating the production, transportation and combustion of methane – the worse the climate crisis gets. This, in turn, multiplies risks for pension portfolios across the wider financial system.

Banking on hydrogen puts pension managers in a bind

Gas companies downplay their exposure to this growing transition risk by touting plans to repurpose their infrastructure to transport and use hydrogen. Hydrogen may well play a niche role in the energy transition in hard-to-decarbonize industrial processes. But expert analysis has poured cold water on the potential for hydrogen’s use in existing gas infrastructure, concluding that hydrogen is “expensive to produce, difficult to transport, and a second- or third-best clean energy solution in almost all proposed markets.”

A peer-reviewed 2024 study found that “hydrogen is not an effective decarbonization tool for use in homes and buildings” and that “attempts to repurpose gas systems for use with hydrogen face major safety, technical, political, regulatory and economic hurdles.” A meta-review of 54 studies on hydrogen for home heating concluded that none supported heating with hydrogen at scale.

This should set off alarm bells for Canadian pension managers.

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The Ontario Teachers’ Pension Plan recently bought large stakes in gas distribution and transmission companies in the United Kingdom and Italy. Similarly, the British Columbia Investment Management Corporation co-owns gas pipeline networks in Brazil, Czechia, Germany and the United Kingdom. Both pension managers claimed that their gas investments were about “net-zero transition” and “decarbonization” but have neglected to disclose credible plans for how these high-carbon assets could profitably transition.

The Canadian pension sector’s significant exposure to gas companies puts these investment managers – and the pension plan members they invest on behalf of – in a bind.

As long-term investors with a fiduciary duty to invest in members’ best interests, pension funds are obligated to manage climate-related risks. Owning thousands of kilometres of gas pipelines has become incompatible with this duty.

In the long run, there are no winners when investors bet against the energy transition.

Pension managers should act quickly to ensure the climate integrity of their risky gas investments – helping to protect both financial returns and a healthy planet on which to enjoy them. This means increasing transparency and disclosure of gas company holdings and how they are aligned with pension fund net-zero commitments, halting investments in unjustifiable gas and hydrogen infrastructure, and acknowledging the need for gas companies to transform their business model and plan for the decommissioning of gas infrastructure over time.

It’s time for pension funds to stop pretending that gas is a “transition fuel” or that hydrogen will rescue their soon-to-be-stranded gas assets. If gas companies refuse to align their business with credible decarbonization plans, they don’t belong in pension portfolios.

Patrick DeRochie is the senior manager for Shift Action for Pension Wealth and Planet Health, a charitable project that tracks the fossil fuel investments and climate policies of Canadian pension funds and mobilizes beneficiaries to engage their pension managers on the climate crisis.

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The answer might surprise you, given the way each has talked publicly about fossil fuels: former president Donald Trump embracing them, and President Joe Biden and Vice-President Kamala Harris focusing on reducing fossil fuel use to fight climate change.

Under each of the three most recent presidencies, Republican and Democratic alike, U.S. oil and gas production was higher at the end of the administration’s term than at the beginning.

That production has both pros and cons. Together, oil and gas account for nearly three-quarters of U.S. energy consumption. Producing oil and gas in the U.S. provides energy security, and high production generally keeps prices down. Burning oil and gas, however, releases carbon dioxide into the air, contributing to climate change. And natural gas is mostly methane – another potent greenhouse gas.

Global events can also have large effects on production.

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A backlash to bans on gas infrastructure in new buildings has arrived in Canada.

Last week, Vancouver City Council voted to repeal its prohibition of “natural” gas for heating new buildings in a move climate advocates say will jeopardize the city’s climate goals.

“Council’s decision is [a] big step back for a city renowned for its leadership,” said Betsy Agar, the director of the Pembina Institute’s buildings program. “To stick natural gas back into new home construction would jeopardize Vancouver’s climate goals and do nothing to reduce the costs of operating buildings over the long term.”

The repeal comes as state and municipal gas bans are going through a bit of an evolution in the United States, as they have continued to spread but have also suffered some setbacks in court. More than two dozen Republican-led state governments have barred municipalities from introducing their own prohibitions. And the first city in North America to introduce a ban – Berkeley, California – was forced to repeal its ban after a 2023 Ninth Circuit Court of Appeals ruling rolled it back.

Vancouver’s move came after a change in government. City council originally implemented the ban (which did not extend to gas used for cooking) in 2020. But last week, a group of conservative councillors, who were part of Mayor Ken Sim’s centre-right ABC Vancouver party elected in 2022, tried to turn the issue into an affordability one. The contingent claimed that reversing the prohibition was necessary to keep the cost of new homes down. Sim, who was called into the council meeting on Zoom while he was on vacation to cast a tie-breaking vote, said that “we all love the environment, but we need balance. We also have an affordability crisis.”

Related:

• Despite backlash, bans on gas use in new buildings keep spreading
• Is the LNG industry gaslighting the path to net-zero?
• How the natural gas supply chain is leaking methane

Climate advocates have, however, questioned whether the move will improve affordability, given that electrified buildings can be built cost-effectively.

“The housing crisis in Vancouver is driven by multiple complex factors, and delaying the construction of reliable, climate-safe buildings that are affordable to heat and cool is not a viable solution,” Agar said. “Local governments should collaborate with the provincial government to ensure new homes meet the highest standards for efficiency and electrification. This approach not only reduces emissions but also lowers energy costs for residents.”

Vancouver’s buildings are responsible for approximately 55% of the city’s total greenhouse gas emissions. Considering that, advocates say the repeal of the ban will greatly hinder the city’s pledge to reduce its carbon emissions by 50% by 2030. City staff have warned council that rolling back the bylaw could set the city back “tens of thousands” of tonnes of greenhouse gas emissions.

The new policy will likely come into effect in November and comes at a time when other cities in B.C., such as Victoria, have adopted the top tier of a stringent provincial building code that will limit the greenhouse gas emissions of new buildings and effectively phase out most fossil-fuel use in them.

“By reverting to natural gas, [Vancouver] risks locking itself into a high-carbon infrastructure at a time when urgent climate action is needed,” Agar said.

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If provincial governments and regulators continue treating gas as the default option for heating new homes and commercial buildings, rather than shifting the lion’s share of that heating demand to an electrified system dominated by heat pumps, the transition off carbon will cost more than it needs to, the Institute warns. As households and businesses abandon the system for cheaper, more efficient electricity, the remaining ratepayers will be left with higher costs. And if those costs get so high that regulators decide they’re beyond ratepayers’ ability to pay, the burden will eventually shift to taxpayers.

“The critical thing is that we change our approach to expansion and that we think very seriously about how we’re going to deal with existing systems,” Senior Research Director Jason Dion told a media briefing Wednesday.

“We need to be thinking very carefully about whether [new gas infrastructure] is going to be used and useful over its lifetime,” he added, while dealing with the complexities of managing the existing gas network as demand for its product declines.

The report puts most of the onus on provincial governments, regulators, and utilities to deliver a viable path to net-zero heating in the buildings sector, which saw its emissions rise 8.8% between 2005 and 2022. Along with upstream oil and gas and agriculture, the sector is one of the few in Canada that have not managed to bring their emissions down.

The report pins much of that problem on the way buildings are heated, with more than half of the furnaces and boilers in Canadian homes and commercial buildings running on fossil fuels, mostly gas. While the sector can increase the energy efficiency of new construction and speed up energy retrofits in the existing building stock, decarbonizing and largely electrifying heat will require a focus on the wider energy system.

Without changing the regulations that govern that system, “gas utilities will likely continue to focus on expanding their networks because regulatory models limit their ability to diversify,” the CCI says.

“On a cost-optimal pathway to net zero, electricity will power most space heating in Canada,” the report declares. But “despite some recent progress, Canada’s buildings sector and its electricity and gas systems are not yet on that cost-optimal net zero path.” Getting there “will require a significant increase in the use of electricity for building heat, and a declining use of gas, starting right away,” but inertia in provincial systems means those changes are unlikely under current policies and regulations.

Gas Utilities Are Forced to Expand

A major part of the problem is a business model for gas utilities that compels them to continue expanding their networks, since their revenue comes mainly from the regulated returns they receive on installed infrastructure, not from the gas they pass through to households at cost. When those system expansion decisions are made, “what looks like a promising option for a utility’s bottom line may not always be in the best interest of ratepayers and the energy system overall, nor the most cost-effective path to net zero for the broader economy,” the institute said.

The report calls on provincial governments to legislate 2050 net-zero targets with interim milestones and give regulators, system operators, and utilities the tools to make decisions consistent with a net-zero future. Those tools include independent net-zero assessments that are updated regularly, and more granular energy roadmaps that “present the government’s vision for how the jurisdiction’s technology and energy mix, and the infrastructure it will require, should evolve in line with net-zero. In particular, roadmaps should specify the roles of the gas network and electricity grid through the transition and identify responsibilities for overall energy system coordination.”

Provinces should treat electricity, not gas, as the default option for new buildings and “immediately direct regulators to consider the risks of stranded gas assets when reviewing gas utility submissions, and weigh those risks against alternatives to replacing and extending gas pipelines,” the institute writes. Provincial governments can also shift obligation-to-serve provisions that require gas utilities to expand their networks and mandate that new buildings be fully electric unless a thermal energy network or some other net-zero alternative is available.

The report calls on gas utilities to disclose their network maps to support a managed transition to electricity and advises governments at all levels to “strengthen policies to support building electrification, peak management, and energy efficiency,” all while filtering policy design and program delivery through an equity lens.

‘This Is How We Deliver’

“This is how we deliver on our climate goals in a space that involves regulated utilities,” says Dion. “Because leaving the existing policy architecture as it stands is not a neutral choice.”

Guiding that transition meant producing a report that was “more than just a modelling exercise,” he added.

“We’ve done a lot of careful policy analysis around the current incentives for utilities, how regulators’ mandates interact and intersect with climate goals, and what is the policy space that governments have laid out. And we’ve heard a lot of feedback from regulators, in particular, that [welcomed] our diagnosis of what is amiss in the way we regulate utilities, and how central it is to the energy transition.”

In particular, Dion says the institute has been receiving a thumbs-up from regulators for identifying energy roadmaps “as the missing piece, and a vital part of the way forward.” He says the Canada Electricity Advisory Council reached a similar conclusion in its report earlier this week, which included a detailed annex on best practices for energy roadmaps.

With regulators operating under mandates that predate any consideration of the climate crisis, “what we have heard is a certain amount of appreciation that we are training our sights on this complex target,” Dion says. “It’s not a simple one. It takes time and resources to answer concretely and credibly.”

Transformative Change At Scale

The report frames a challenge as wide as the country’s existing gas and electricity systems. Alongside “building-by-building changes, the clean energy transition will require transformative change at the scale of provincial energy systems,” it states. “Governments, utilities, and regulators are just starting to contend with the impact this transition will have on the vast network of gas pipelines buried beneath large parts of the country, as well as the impact on Canada’s electricity infrastructure.”

That’s why the report looked beyond individual buildings to the whole energy system, “including the cost of building and maintaining electricity and gas infrastructure and how a transition in building heat could affect other sectors,” said CCI Mitigation Research Director Sachi Gibson. The wider focus was needed “because the sector is currently stuck,” she explained.

“Greenhouse gas emissions from buildings are still rising. Change is happening, with better financing and greater uptake of heat pumps, but it’s not happening fast enough.”

Yet buildings are crucial to the energy transition, Gibson said. Every household and business is looking for reliable, affordable energy, and “the decisions we make today about investments in electricity and gas systems will be something we live with and pay for for decades.”

Heat Pumps Rule

The projections and recommendations in the report are directed primarily at the provinces, partly because that’s where jurisdiction over utilities lies, “but also because there’s so much geographic variation,” said Kate Harland, the Climate Institute’s mitigation research lead, with the pace and degree of electrification varying by region and building type.

Between 2020 and 2050, the CCI projects the proportion of Canadian homes heated with electricity rising from 34 to 85%, with the remainder covered by electric systems with gas backup. Heat pumps rise from 7 to 73% of purely electric heating, while inefficient baseboard heating falls from 27 to 12%. Electric heat in commercial and institutional spaces rises from 11 to 48%, with hybrid systems supplying 50%.

The proportion of homes heated with electricity varies from 63 and 70% in Alberta and Saskatchewan to 99% in New Brunswick, 97% in Prince Edward Island, 94% in Quebec, 93% in Manitoba, and 92% in Nova Scotia, with baseboard heating all but eliminated in PEI and Nova Scotia.

Across all regions, “heat pumps and electric resistance heating are the cost-optimal technologies for the system in the vast majority of homes by 2050,” the report states. “Widespread electrification of heat on a cost-optimal pathway occurs in part because heat pumps are so much more energy efficient than gas furnaces. When considering the broader economic impacts of the energy system, the alternative of using hydrogen or biomethane in buildings leaves less of those low-emission fuels available for other uses where they are highly needed, such as in heavy industry.”

Higher Peak Electricity Demand

The report says electricity systems will have to grow 2.6- to 2.9-fold on average to hit a net-zero target by 2050 — not only due to building decarbonization, but because so many other sectors of the economy will be shifting to electricity at the same time, while more intermittent renewables come onto the system.

The modelling behind the report shows peak power demand in buildings holding steady or declining in provinces that already heat primarily with electricity, but rising in regions that use a lot of gas. With demand growing in other sectors, as well, peak demand across the economy increases everywhere.

Within the buildings sector, however, “total energy demand decreases dramatically,” the report projects. “On a cost-optimal pathway to net zero, from 2020 to 2050, the total square footage of buildings increases as the population and economy grows. But due to significant improvements in energy efficiency over time, total energy demand from the buildings sector declines on a cost-optimal path to net zero.”

Still, “mitigating peak demand to keep electricity affordable and reliable will likely emerge as the central challenge facing electric utilities in this transition,” the institute writes. “In the buildings sector, retrofits of existing buildings, the rising energy efficiency of new buildings, and the switch from electric baseboards to much more efficient heat pumps can all contribute to reducing the scale of the necessary electricity system buildout,” with hybrid gas-electric systems meeting peak demand in the cold of winter. Options like heat and energy storage, thermal energy networks, and demand-side management “will also likely play an important role.”

This article was first published by The Energy Mix. Read the original story here. 

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The move was one of the latest victories for the gas industry and its supporters, who observers say have been emboldened by a 2023 Ninth Circuit Court of Appeals ruling that rolled back the country’s first municipal gas ban, in Berkeley. Since the northern California city introduced its ban on gas hookups in new buildings in 2019, 25 states have adopted prohibitions on municipalities approving their own gas bans, according to S&P Global Commodity Insights.

The appeals court decision has had somewhat of a chilling effect in some cities and states, worried they may also face legal challenges. Soon after the decision, Palo Alto, which introduced its own gas ban in 2022, said it would no longer enforce it. Others followed suit, including Berkeley.

Earlier this year, the court refused to hear Berkeley’s appeal of the decision. At the time, the Biden administration said it could “cast a cloud of uncertainty over any health or safety law that may indirectly affect someone’s ability to use a product for which the federal government has issued an energy conservation standard.”

New York State is also facing a lawsuit by gas and construction industry groups for its restrictions on gas infrastructure in most new buildings.

But not everything is going the gas lobby’s way. Gas bans have continued to spread and evolve in other parts of the country. On the east coast, several Maryland counties are introducing changes to building codes to ensure that heating in new buildings is all-electric. And late last year, local lawmakers in Burlington, Vermont, approved new requirements that developers use low-carbon or renewable sources of energy to heat their buildings or pay a one-time carbon fee for their expected life-cycle emissions.

Climate advocates are now regrouping, considering other types of action that they hope will curb the use of natural gas in buildings, which along with the construction sector accounts for 37% of global greenhouse gases, according to the United Nations. One of the main components in most natural gas is methane – a potent, heat-trapping greenhouse gas. “Learning from Berkeley’s ill-fated experience, cities across California and the U.S. west have already introduced different rules focused on energy performance,” Alastair Iles, a professor at the University of California, Berkeley, told The Guardian. “Cities can also set air pollution emission standards to favor electric appliances.”

Local leaders in California, who feel handcuffed by the appeals court decision, are trying to put pressure on Governor Gavin Newsom to implement state-wide electric building standards.

The idea is also spreading internationally. Last month, the European Parliament voted to approve new requirements that all new buildings be zero-emission starting in 2030.

In Canada, some cities in British Columbia, Victoria among them, have adopted a stringent provincial building code that will limit the greenhouse gas emissions of new buildings, effectively phasing out most fossil-fuel use. Come October, a ban will come into effect in Montreal on gas-powered heating systems, stoves and water heaters in most new buildings.

No municipalities in Ontario have implemented similar gas bans, but the province’s energy regulator gave Ottawa climate activists a win last year when it rejected Enbridge’s application to build a new gas pipeline in the city to replace an aging one. The regulator determined that repairing and retrofitting the existing pipeline would be sufficient at a time when the city is trying to wean itself off fossil fuels. Enbridge is looking to reopen its application, claiming it now has evidence to show that the old pipeline needs to be replaced.

When it comes to gas bans in the United States, it can sometimes feel like climate advocates take a step forward only to get shoved back three steps by the gas industry and its supporters. But local and state leaders in some of the most populous states in the country are finding creative ways to get around the roadblocks.

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The announcement came as many countries (Canada included) are looking to build new LNG export terminals and expand natural gas exports all while pledging to reduce emissions from the sector.

Natural gas is often billed as a bridge or transition fuel for economies looking to shift away from polluting coal. But hundreds of studies have found that methane emissions from the oil and gas sector are up to 70% higher than the levels reported. Leaks from the well to the burner tip remain elusive. Here are five ways methane escapes en route.

1. Oil and gas wells

There are nearly one million active oil and gas wells in the U.S. and more than 460,000 in Alberta alone, including 90,000 abandoned wells. Methane is leaked during drilling and hydraulic fracturing, escaping from both active and orphaned oil and gas wells. More escapes from pneumatic pumps and other equipment. It’s also routinely vented and flared in oil fields where producers have no access to gas pipelines.

2. Processing

After natural gas is extracted, it’s processed to remove liquids such as propane and butane. Thanks to faulty seals, methane often leaks from holding tanks and processing equipment. Producers have great incentive to reduce leaks to minimize loss of product; the amount of leakage varies greatly among companies and jurisdictions. The same is true for LNG plants.

3. Transportation

Methane escapes from the pipelines that carry the gas from production fields to processors to distributors and finally consumers. The U.S. EPA estimates losses of close to 1% from transportation and distribution systems. Losses also occur in ocean tankers when LNG evaporates or “boils off” from storage tanks, particularly on older ships.

4. Power plants and factories

Roughly half of natural gas is sold to large power plants and factories in the U.S. (in Canada, a third), where methane escapes from leaky processing equipment. Gas-fired power accounts for 3% of total global methane emissions, according to gas-fuelled turbine maker GE.

5. Residential end use

Buildings account for 25% of natural gas demand, and in homes methane leaks from every natural-gas-fired appliance: furnaces, water heaters, stoves and fireplaces. Natural gas stoves emit up to 1.3% of the gas they use as unburned methane. Even when they are not running, gas stoves in the U.S. put out an amount of methane equivalent to 2.4 million tonnes of carbon dioxide each year, according to one study.

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On one stretch of the Douglas Channel shoreline is the site of LNG Canada, a partnership of international corporations including Shell PLC and PetroChina. The LNG Canada project currently under construction and the TC Energy pipeline that will supply it with gas were jointly billed as the largest private-sector investment in Canadian history – made possible with $5.4 billion in subsidies from British Columbia and $275 million in support from Ottawa.

Further along the shore is the planned home of Cedar LNG, a smaller yet-to-be-green-lit project that is majority owned by the Haisla with a minority stake held by Calgary-based Pembina Pipeline Corp. Privately owned Woodfibre LNG is also under construction at Squamish.

All told, 24 would-be LNG developers have received natural-gas export permits from the federal energy regulator, though many of those will not proceed. Canada is well behind competitors like the United States and Australia in the race to supply a fossil fuel market that has limited growth prospects over the medium term. Advocates of Canadian LNG exports say that sending gas to Asian markets will help them reduce reliance on coal, and thereby decrease global carbon emissions.

It is a much-disputed argument. Several recent studies challenge the industry position. Researchers suggest that the leakage of methane throughout the LNG life cycle can eliminate any greenhouse-gas (GHG) advantage gas has over coal at the point of final combustion. And some question whether growing reliance on LNG could slow the deployment of less carbon-intensive alternatives.

Still, producers want the federal government to include exported LNG as part of its climate change strategy, including policies for preferential financing. Ottawa is currently developing a transition taxonomy – essentially a guideline as to which types of investments are appropriate in the transition to a net-zero economy. In a report last March, the federally appointed Sustainable Finance Action Council (SFAC) said that only projects that are aligned with a net-zero pathway should be included in the taxonomy, without clarifying whether natural gas falls into that group. The government now faces a concerted lobbying effort to green-light expanded LNG capacity. Sources tell Corporate Knights that the minister’s office has delayed commenting on SFAC’s recommendations because of concerns over LNG.

West Coast dreams of LNG-fuelled prosperity rest on a shaky foundation of questionable assumptions.

Methane leakage

Numerous recent studies suggest that a major expansion of LNG exports from Canada would contribute to the growing climate crisis, rather than mitigate it as proponents claim. Both the International Energy Agency (IEA) and the United Nations Environment Programme warned this past fall against expansion of fossil fuel infrastructure that could lock in carbon emissions for decades.

Cornell University ecosystem scientist Robert Howarth recently concluded that LNG exported from the U.S. to Asia or Europe has higher carbon intensity than local coal use due to the leakage of methane – a powerful warming agent – throughout the LNG supply chain, but particularly during shipping. To address the urgency of the climate crisis, the world must “move away from any use of LNG as a fuel as quickly as possible, and immediately stop construction of any new LNG infrastructure,” Howarth wrote in a paper released in November. He’s been an outspoken critic of natural gas for more than a decade, facing years of harassment for his stance. But he’s not alone in his critiques. Researchers at RMI – the Rocky Mountain Institute – published a paper last July in which they concluded that methane leakage rates as low as 0.2% can eliminate any carbon advantage natural gas would have over coal-fired energy. 

Hundreds of studies using an array of measurement techniques have concluded that the industry’s methane emissions are often wildly underestimated. Methane can leak from a number of points in the natural gas cycle, from extraction and processing to transportation and power generation facilities – and there are no reliable government systems in place to comprehensively track the leaks. 

Globally, the IEA has estimated that methane emissions are 70% higher than industry reports. Carleton University’s Energy and Emissions Research Lab recently completed a census of methane emissions from upstream oil and gas production. Led by engineering professor Matthew Johnson, the researchers measured emissions at 3,500 oil and gas facilities and 5,600 wells. As Carleton reported, “Johnson and his team discovered that the actual quantity of methane produced by Canada’s oil and gas sector in the provinces of British Columbia, Saskatchewan and Alberta is consistently far higher than what was previously reported.” Alberta’s facilities, in particular, were found to be underreporting by nearly 50%.

At the COP28 climate summit in early December, the federal government announced new draft regulations that it says would result in a 75% reduction in methane emissions in the oil and gas sector from 2012 levels by 2030 while acknowledging that further work is required to accurately quantify methane emissions. Slashing methane emissions – along with better tracking – would help Canadian gas producers make the environmental case versus coal. However, natural gas still produces CO2 emissions and expanding supply and demand is inconsistent with net-zero plans. 

A paper co-authored by University of Calgary professor Sara Hastings-Simon suggests that newly built natural gas assets would become white elephants if the world succeeds in reducing its demand for fossil fuels as governments have pledged to do. At the same time, growing LNG imports in Asia could slow the adoption of lower-carbon alternatives, including renewable energy, the researchers concluded.

LNG at best represents a short-term opportunity, Hastings-Simon and her colleagues say. By the 2030s, the costly new LNG export terminals will either become stranded assets or lock in emission growth that takes us in the wrong direction on climate change.

In a special report released ahead of the United Nations climate summit in November, the IEA forecast that global demand for natural gas will peak by 2030 and could decline precipitously over the following two decades if countries rise to the challenge of global warming. The Paris-based agency – which advises wealthy countries on energy policy – urged against a major expansion of any fossil fuel infrastructure, noting that the world would need to reduce natural gas demand by 20% by 2030 and 75% by 2050 if we’re to limit warming to 1.5°C. “The ‘Golden Age of Gas,’ a term coined by the IEA in 2011, is nearing an end,” said the IEA report.

“Successful clean energy transitions require much lower demand for oil and gas, which means scaling back oil and gas operations over time – not expanding them,” Fatih Birol, the agency’s executive director, says in the report. Rapid expansion in LNG supply over the past 10 years will be sufficient to supply the market and compete against pipeline gas in Asian markets, the agency says.

Essentially, building LNG infrastructure represents a bet against climate success.

Industry optimism

Still, backers of LNG Canada, Woodfibre and Cedar LNG remain optimistic. TC Energy’s $14.5-billion 670-kilometre Coastal GasLink pipeline that will ship supply from the gas fields of northeastern B.C. to the coast is 98% complete, according to the company. Construction at Woodfibre and the LNG Canada site is well underway; LNG Canada expects the first LNG shipments in 2025. Cedar’s owners – the Haisla and Pembina Pipeline Corp. – are aiming to make a final investment decision in the coming months.

Canadian LNG producers maintain that they have the lowest carbon intensity of any facilities in the world. LNG Canada says its phase-one facility will have a life-cycle GHG footprint 65% lower than the global average for the industry and 28% below the best performers. That figure is based on carbon intensity in the Montney gas field of northeastern B.C., as well as “highly efficient processes” and use of renewable power from B.C. Hydro. Carleton’s Energy and Emissions Research Lab also concluded that stronger regulation and monitoring in B.C. has meant that methane intensities are approximately four times lower on average than neighbouring facilities in Alberta, though there are variations between facilities.

LNG Canada’s partners are considering plans to fully electrify phase two of the project, should they decide to proceed. Though that would require completion of a $3-billion transmission project to bring additional power to Kitimat for commercial and residential use. B.C. reportedly wants Ottawa to cover half the cost of the line.

First Nations’ support

Many First Nations leaders in B.C. support the expansion of the LNG industry, seeing it as a path to economic development. That support remains, despite the much-publicized battles over the Coastal GasLink pipeline that will feed LNG Canada and Cedar. Land defenders led by hereditary chiefs of the Wet’suwet’en First Nation have blocked construction on the pipeline right-of-way, prompting a series of arrests by the RCMP. Still, elected First Nations leaders continue to support LNG expansion and, in some cases, have equity positions in projects.

I think [ownership of LNG development] is one of the solutions to helping our people to get out of poverty.

 

Karen Ogen, First Nations LNG Alliance

Karen Ogen – who served as elected chief of the Wet’suwet’en for six years – leads the First Nations LNG Alliance and travelled this fall to Beijing. In a telephone interview, Ogen says Asian nations have communicated their desire for LNG supply from Canada to replace coal, and alliance members are eager to benefit. “For 150 years, we were not included when major projects went through our territories and have not benefited from them,” Ogen says. “I think [ownership of LNG development] is one of the solutions to helping our people to get out of poverty.”

The First Nations communities are looking for loan guarantees from Ottawa to help finance their equity participation in resource projects, including LNG facilities and fossil fuel pipelines. In her fall economic statement in November, Finance Minister Chrystia Freeland announced that the federal government would develop a loan guarantee program but provided no details. In a release, the First Nations Major Projects Coalition said Ottawa should not exclude fossil fuel projects from the financing plan, but rather allow First Nations governments to pursue the projects they deem appropriate.

That approach could leave Canadian taxpayers on the hook for massive loans to finance risky fossil fuel projects that are designed to last 30 years. “There is no justification for the Government of Canada to be subsidizing any new oil or gas production, including LNG, no matter the project’s owner,” says Julia Levin, associate director of national climate policy at Environmental Defence.

There is no justification for the Government of Canada to be subsidizing any new oil or gas production, including LNG, no matter the project’s owner.

 

–Julia Levin, associate director of national climate policy at Environmental Defence.

Meanwhile, advocates on both sides of the LNG debate are waiting with bated breath to see where the federal government lands on LNG in its transition taxonomy – will it make the cut or not. Behind the scenes, insiders have told Corporate Knights off the record that the finance minister’s office has been holding up the taxonomy’s release until LNG gets the green light.

In an email, SFAC chair Kathy Bardswick says that individual projects will have to be assessed on their own merits. Individual LNG projects could qualify “if there is a credible link to transition,” she says. “But there is no scenario that will pass scrutiny related to ‘new exploration.’”

In a report for the First Nations Climate Initiative, economist Robert Johnston concludes that Canadian LNG could qualify for the transition taxonomy if methane emissions are minimized and the result tracked and verified. But that’s a lot of ifs, which, as of yet, remain unresolved.

 Back at the COP28 climate summit, 50 companies (including LNG Canada partners Shell and Petronas) signed on to an agreement that commits them to “near zero” methane emissions from their oil and gas production operations. Notably, the commitment covers production but not processing at liquefaction plants or transportation in pipelines or ships. 

Given all the uncertainties, it’s unclear whether Canadian-based producers will be able to benefit in the marketplace from any carbon advantage they claim. Will buyers opt for supplies from a producer that can certify its low GHG intensity? Will they be willing to pay a premium? Would they sell credits from reducing any coal use that the additional LNG supply might allow? To date, there has been little evidence of that type of energy trading.

At most, Canada may add another LNG plant or perhaps two. Investment decisions are looming on Cedar LNG and LNG Canada’s phase two. They will depend on a host of political, environmental and market-based factors.

One thing is clear, however: a major expansion of Canadian LNG production runs counter to climate goals and entails a significant risk of big financial losses down the road for the producer, their First Nations partners and, potentially, for Canadian taxpayers.

Shawn McCarthy is an independent writer focused on energy and climate change. He is also a senior counsel at Sussex Strategy Group.

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