by Mitchell Beer

The federal and Alberta governments have reached a preliminary agreement that will allow the province to set its own regulations on climate-busting methane emissions and postpone its emission reduction deadline by five years.

The deal’s effectiveness in putting a lid on methane pollution will depend on details that are still under development. But experts say Ottawa already traded away the equivalent of 53 million tonnes of carbon reductions last November, when it first signalled that it would allow Alberta to postpone methane controls from 2030 to 2035.

Methane carries about 84 times the global warming potential of carbon dioxide over the crucial 20-year period when humanity will be scrambling to get climate change under control. The Intergovernmental Panel on Climate Change identifies methane reductions as one of the cheapest paths to the quickest, deepest greenhouse gas emission reductions by 2030.

The agreement in principle, released Wednesday, cements a five-year postponement in Ottawa’s 2030 methane target that first appeared in the November, 2025 memorandum of understanding (MOU) between Canada and Alberta. If the two governments can agree on an “outcome-based equivalency agreement” under the Canadian Environmental Protection Act, Canada will stand down its own methane regulations in deference to Alberta’s.

The two governments have also agreed to identify an independent third party “to conduct methane modelling, analysis of emissions reductions, and to assess methane reduction results”. That provision is being hailed as an important step, a week after analysis by the Calgary-based Pembina Institute concluded that Alberta’s methane emissions are up to 90% higher than the province’s official estimate, which relies on self-reporting by industry.

The agreement is to take effect on January 1, 2027, following a 60-day consultation on the draft plan.

The methane equivalency agreement was one of several commitments in the Canada-Alberta MOU that were meant to be finalized by April 1. Alberta Premier Danielle Smith now says other elements of the deal, including a proposed new oil pipeline to Canada’s West Coast, will be delayed beyond next week’s deadline.

Canadian Climate Institute (CCI) President Rick Smith declared the agreement in principle a “positive step forward”. He called the provision for an independent third party “an important approach to reinforce policy ambition and integrity, and help ensure the regulations cover the true extent of methane pollution levels from Alberta’s oil and gas sector.”

But he cautioned that “the final details of the equivalency agreement, and follow-through on the commitment to independent and transparent verification of outcomes, will be critical to determine the agreement’s success.”

CCI Senior Research Associate Alison Bailie said she had confidence in the agreement’s focus on “looking at the Alberta numbers, not just accepting them,” adding that methane measurement technologies have improved in recent years—with some of the gains achieved by Emissions Reduction Alberta with funding from the province’s Technology Innovation and Emissions Reduction (TIER) system.

“That’s where I see the hope and the benefits of doing this properly,” she told The Energy Mix. “It helps Alberta’s own companies,” creating a business case for methane controls in Canada and enabling them to position themselves for methane abatement projects overseas.

Bailie added that Canada has “tended to see greater emission reductions” when federal and provincial governments actually work together. “That can work really well,” she said. “We’d like to see more.”

Aly Hyder Ali, senior program manager, oil and gas at Environmental Defence Canada, called the five-year delay an “unnecessary concession” that represents a “bad deal for everyone outside the oil patch.” Citing Pembina Institute modelling, he said the carveout would pour 1.9 million extra tonnes of methane into the atmosphere, the equivalent of 53 million tonnes of carbon dioxide over a 100-year period—or far more over a 20-year span.

Amanda Bryant, manager of Pembina’s oil and gas program, agreed in a release that independent, third-party verification is a “vitally important and positive step”, allowing Alberta to “report its methane progress more credibly”. She said the agreement “signals an end to the roadblock that had been preventing progress on this crucial element of climate and energy policy,” enabling industry to “invest and hire with confidence to advance the next stage of methane mitigation work.”

But so far there’s no clarity on whether the “independent party” responsible for monitoring Alberta’s methane controls will rely on theoretical modelling or actual measurement of releases from oil and gas infrastructure, or on whose data the monitor will rely. Real measurement “will be vital, both for an effective response to climate change and to ensure ongoing access to major international natural gas markets that are demanding provably low-emissions-intensity fossil fuel imports, such as the European Union, South Korea, and Japan,” Bryant said.

Last week, a Pembina technical analysis flagged data and regulatory gaps in Alberta’s current approach to methane controls, resulting in actual emissions that have been up to 90% higher than official government figures.

“Alberta should not be afraid modernize its measurement data and methods, including vehicle-based systems, aircraft, and satellites to effectively reduce its methane emissions,” Bryant said at the time.

But Alberta Premier Smith may have a different take on what to expect from the independent third party. During an unrelated media conference Wednesday, she said the goal is to arrive at “a common set of facts” after “some other reports that have been put out there kind of put us at odds,” iPolitics reports.

The agreement in principle states that, “should third party analysis determine that emissions are higher than expected, Alberta commits to take the necessary corrective actions.”

The post Alberta to Set Its Own Methane Regulations, Delay Deadline to 2035, Under Draft Deal with Ottawa appeared first on Thoughtful Journalism About Energy's Future.

On February 9, 2026, Tokyo Electric Power Company Holdings (TEPCO) confirmed the restart of the 1,356-megawatt Unit 6 at Kashiwazaki-Kariwa in Niigata Prefecture, with full commercial operations expected by mid-March. The reactor — offline since the 2011 Fukushima Daiichi accident for safety enhancements and regulatory review — will be the first TEPCO unit to resume service in nearly 14 years and is projected to generate about 9.5 terawatt-hours (TWh) annually once fully ramped up.

Japan now has 15 operating nuclear reactors with a combined capacity of about 33 gigawatts (GW), out of an operable fleet of 32. In 2024, this fleet produced roughly 83 TWh — about 9 per cent of total electricity generation — as nuclear capacity gradually returned after extensive safety reviews and public debate over nuclear energy’s role.

Impact on fossil fuel use and LNG imports

Analysts and government estimates suggest the added nuclear output from Unit 6 could displace about 1.3 million tonnes of LNG — equivalent to roughly 62 billion cubic feet of natural gas imports annually — if generation from nuclear substitutes for gas-fired power. That displacement figure reflects Japan’s ongoing effort to reduce reliance on imported fossil fuels for electricity, a legacy effect of all reactors shutting down following the 2011 tsunami and nuclear accident.

Natural gas previously accounted for about 33 per cent of Japan’s electricity mix in 2024, with LNG imports serving as a critical feedstock for gas-fired plants. Japan remains the second-largest LNG importer globally after China, though annual LNG demand has declined in recent years as nuclear and renewables have grown. Japanese companies imported roughly 9 billion cubic feet per day (Bcf/d) of LNG in 2025, down from about 11 Bcf/d in 2018, according to market data. Australia, Malaysia, Russia and the United States have been among Japan’s top LNG suppliers, with Australian volumes rising in recent years while U.S. shipments declined.

The increase in nuclear output also fits within Japan’s long-term energy strategy, which aims to raise nuclear’s share of electricity generation to around 20 per cent by 2040. Meeting that goal would require up to 30 reactors in operation, meaning some of the 17 currently non-operating reactors would need to clear regulatory and local hurdles before restarting. Three units have initial Nuclear Regulation Authority approval and six more are under review.

Renewables and policy context

Alongside nuclear, Japan’s power mix has seen renewable generation grow steadily. Solar capacity, in particular, expanded rapidly in the past decade, and preliminary statistics indicate that renewables accounted for more than 26 per cent of electricity generation in 2024, with solar alone contributing more than 11 per cent and hydro nearly 8 per cent. Fossil fuels, including coal and natural gas, still made up the majority of generation but have trended downward from levels exceeding 70 per cent earlier in the decade.

Japan’s evolving energy policies — including its 6th Strategic Energy Plan and the broader Green Transformation (GX) agenda — reinforce these shifts. The plans aim to nearly double renewable generation’s share and boost nuclear’s role by 2030 while reducing fossil fuel dependence significantly. Officials see nuclear as an essential part of ensuring energy security and reducing electricity price volatility, particularly in a country that imports roughly 90 per cent of its energy needs.

Historical and public sentiment backdrop

Japan’s reliance on nuclear power draws directly from its pre-2011 energy configuration, when reactors provided around 30 per cent of electricity. Following the Fukushima disaster, all reactors were taken offline for safety upgrades under new regulatory standards, and public opinion tilted sharply away from nuclear generation. That shift significantly increased fossil fuel use and raised energy import costs.

Efforts to restart large reactors like Kashiwazaki-Kariwa have often been met with local debate and scrutiny over safety and disaster preparedness. Approval from regional authorities has been essential for restarts, reflecting lingering public sensitivity to nuclear risks. Still, government policy revisions now emphasize maximizing both renewable and nuclear “carbon-free” power sources, signalling a broader acceptance of nuclear as part of Japan’s decarbonization trajectory.

Market and geopolitical implications

Bloomberg and Reuters reporting over recent years has underscored that Japan’s nuclear comeback is closely tied to broader energy security concerns, including volatile LNG markets and price spikes following global supply disruptions. Analysts have noted that a robust nuclear fleet could insulate Japan from some of these risks, particularly as competition for LNG supplies intensifies in Asia.

NPR highlighted the challenge Japan faces balancing safety, public sentiment and decarbonization goals, noting that nuclear restarts require meticulous regulatory oversight and clear communication to gain social license.

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By Mitchell Beer

Alberta is demanding even faster federal approval of a bitumen pipeline to British Columbia’s west coast, even as a former provincial energy minister admits the project would have “zero” chance of attracting private investors without federal subsidies to “backstop” it.

The new demands came just six weeks after Premier Danielle Smith and Prime Minister Mark Carney signed a controversial memorandum of understanding (MOU) that envisioned an accelerated, two-year approval schedule for at least one new pipeline. Smith issued her latest letter to Carney after Donald Trump’s bombing and kidnapping raid in Venezuela became the latest pretext to demand ever-faster federal action on the pipeline plan despite a glutted global market for oil.

“Alberta intends to submit its application for a pipeline to the Major Projects Office by June—and [Smith] asked that it gets approved by this fall,” CBC reports.

“Within the current geopolitical context, timelines of up to two years are still woefully long and risk putting Canada at a disadvantage,” Smith wrote. “Any delay risks ceding market share, losing investment, and undermining Canada’s competitive position in a rapidly changing global energy landscape.”

When the MOU was signed in late November, impact assessment experts warned that even a two-year approval period would be too short to allow for thorough review of a major, new pipeline, or for engagement with Indigenous and other affected communities. Short-circuiting those steps could help land a project in court, where it would only face further delays.

Smith’s letter also sidestepped major questions about the years it would take to refurbish Venezuela’s decrepit oil production infrastructure, whether U.S. fossil companies are willing to invest, and whether there will significant global demand for new oil—from Venezuela, Canada, or anywhere else—by the time any new project could be completed.

A west coast pipeline would also need federal subsidies, Smith’s former energy minister, ex-pipeline lobbyist Sonya Savage, told a CBC podcast. Without taxpayer support, “I would say it’s not just diminishing, the likelihood of a private sector proponent.… I would almost say it is zero at this point,” she said.

While the MOU explicitly calls for any new pipeline to be built and financed by private companies, Savage said a federal “backstop” to cover cost overruns, like the massive, 584% budget increase that plagued the Trans Mountain pipeline expansion, would not be a new concept for Canada.

“The TransCanada mainline gas line in the 1950s would not have been built without federal government intervention,” she told CBC’s West of Centre podcast. “They set up a Crown corporation, they backstopped it. Enbridge’s Line 9 in the 1970s would not have been built without a federal government backstop.”

In a release Monday, the Calgary-based Pembina Institute called on both governments to “stay true” to the language about “strong regulations that will drive down oil and gas emissions” that accompanied the release of the MOU.

“Alberta using this moment to lobby in public against what it is now calling an ‘overly aggressive’ industrial carbon price raises more questions about the outcome Alberta has in mind—especially given it already agreed in the MOU to strengthen its system,” said Executive Director Chris Severson-Baker. “This is in addition to the regulatory changes Alberta pushed through in December—days after signing the MOU—that weakened its industrial carbon pricing system and effectively moved the goalposts on the negotiation before it had begun.”

Severson-Baker added that, “far from being a reason to further expedite a pipeline proposal and weaken Canadian climate policy, the Venezuela situation should give further pause for thought and reassessment about the best economic bet for Canada going forward.”

“42 days after signing the ‘grand bargain’ MOU with the federal government, Alberta is trying to change the terms of the agreement, leveraging the current situation in Venezuela,” veteran climate analyst Dan Woynillowicz wrote on LinkedIn. “Underpinning the MOU is a commitment to ‘good faith’ collaboration,” but “I don’t see how seeking any and every opportunity to change the terms of the MOU or shift the goalposts can be seen as living up to this.”

On Substack, fossil industry analyst and communicator Bill Whitelaw praised Savage for “speaking her truth” on the taxpayer backstop that private investors would expect before pouring their own money into a new pipeline project. That “loadsa dough” subsidy won’t happen, he said, as long as there’s a chance that Alberta separatists will succeed in pulling the province out of Canada—much less making it Donald Trump’s sought-after 51st state.

“Ottawa will need to pony up big bucks to bolster an already-thin business case,” Whitelaw wrote. “Fellow Canadians would never countenance Ottawa forking over billions to a province that can’t be bothered with Confederation.”

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By Chris Bonasia

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By Lennie Kaplan

Alberta’s climate-change strategy, the emissions reduction and energy development plan (ERED), announced with fanfare by the Smith government in April 2023, seems to be in public limbo after more than two years.

The plan outlined a series of actions, opportunities and commitments to reduce the province’s emissions, including an aspirational target of a carbon-neutral economy by 2050.

But implementation appears to have stalled, which is troubling given renewed talks between Ottawa and Alberta about a “grand bargain” focused on significantly reducing greenhouse gas emissions, encouraging carbon capture and storage deployment, and unlocking pipeline development.

The 2025 mandate letters from Premier Danielle Smith to the ministers of environment and protected areas and energy and minerals make no reference to implementing the plan despite a 2023 mandate letter from the premier that talked about the two ministers co-ordinating to do so.

No significant action on implementation appears to have occurred over the past two years around the following key initiatives, which I support and believe are critical to success:

• reducing the provincial oilsands 100-megatonne (Mt) annual emissions limit to align with carbon capture and storage project targets – an estimated 11-Mt annual reduction in CO2 emissions by 2030 – of the Pathways Alliance, an organization representing six of the largest oilsands producers;
• working collaboratively with partners – including environmental NGOs, industry, Indigenous organizations, municipalities, labour groups and others – to design effective policy and programs to support implementation of the ERED;
• establishing policies and programs that are evidence-based, including understanding the environmental, social and economic impact of policy choices;
• publishing reports documenting the progress and outcome of the actions taken as part of the plan.

In a 2018 audit, the Office of the Alberta Auditor General pointed out that critical elements of a robust system to manage provincial climate-change plans included maintaining overall and sectoral implementation plans, as well as rigorous and effective monitoring of the progress of climate-change programs, including complete information on costs.

The lack of action on the ERED creates uncertainty about how Alberta can reach its goal of carbon neutrality by 2050 or any interim emissions-reduction targets for 2030, 2035, 2040 or 2045.

To come to that conclusion, we use the Canada Energy Dashboard, updated with detailed data to January 2025, based on the current suite of federal and provincial climate-change policies (but not the proposed federal oil and gas emissions cap, the federal clean-electricity regulations and the federal 75-per-cent oil-and-gas methane-reduction requirement) to examine Alberta’s emission projections. We further use refence cost assumptions for technologies such as carbon capture and storage, solar, wind and batteries, and hydrogen.

Based on this reasonable scenario, Alberta will miss its 2050 target of carbon neutrality by 222.4 megatonnes.

Canada needs to accelerate its transition to renewable energy

Many Albertans still fine with an oil-and-gas future

These Alberta emission levels do not include the implications of the latest Alberta government goal to increase oil production from nearly four million barrels per day in 2024 to six million barrels per day by 2030 and to eight million barrels per day by 2035.

Clearly, further actions will be critical, including vigorous implementation of the ERED, coupled with aggressive adoption of carbon capture and storage, and the early advent of direct air capture. So why the implementation delay?

One of the key components of a successful ERED is the need to conduct comprehensive emissions forecasting and analysis to develop credible sectoral and overall action plans.

The Alberta Environment and Protected Areas ministry recognized this recently when it issued an RFP to enhance the government’s internal capability to perform sophisticated analysis and forecasting of the social, economic and environmental impact of provincial climate-related policies and federal climate-related policies.

The goal is to have access to best practices and methods in the field of empirical economic-energy-environment modelling, including the ability to study the economic impact of policy scenarios, as well as how policy, energy prices and technological change impact energy use. This work is scheduled to begin in January.

Enhancing emissions forecasting and analysis capabilities within government is critical in preparing an overall ERED action plan as well as action plans for key industry sectors; establishing sectoral and interim emissions targets for 2030, 2035, 2040 and 2045; and promoting vigorous monitoring and reporting systems.

These are all best practices of a robust legislated climate-change accountability framework, which is vital because maintaining national and international credibility is important to Albertans.

The Alberta government talks about sovereignty within a united Canada. To put meaning to these words, Alberta needs a strong ERED if it expects to conclude a successful “grand bargain” with Ottawa on significantly reducing emissions, encouraging carbon capture and storage deployment, and unlocking pipeline development.

The post Opinion: What is going on with Alberta’s climate-change strategy? appeared first on Thoughtful Journalism About Energy's Future.

By Chris Bonasia

The post Fossils’ response to methane leaks improves too slowly, 90 per cent still ignored: UN appeared first on Thoughtful Journalism About Energy's Future.

By Jody MacPherson

The post Alberta orphaned wells strategy faces pushback from residents, municipalities, experts appeared first on Thoughtful Journalism About Energy's Future.

The post Declines in output from existing oil and gas fields have gathered speed, with implications for markets and energy security appeared first on Thoughtful Journalism About Energy's Future.

By Mitchell Beer

The post IEA to project continuing oil and gas growth as U.S. arm-twisting intensifies appeared first on Thoughtful Journalism About Energy's Future.

By Alexander Bressers, Senior Oil Market Analyst

Oil prices are one of few tailwinds at the moment for global oil consumption in the face of a challenging macroeconomic backdrop and the increasing uptake of electric vehicles. Crude oil is currently trading near multi-year lows – about $15 per barrel below this year’s high.

On the face of it, one might expect prices at these levels to spur demand in developing countries, where oil‑intensive sectors such as mining, agriculture and heavy industry can drive a significant share of output. Moreover, since energy is a basic necessity, it frequently accounts for a comparatively high share of household expenditures in less affluent nations. It would follow, then, that consumption would be particularly sensitive to oil price changes.

Yet oil demand in developing nations has been less sensitive to recent price movements than consumption in advanced economies, our analysis shows.

Using data from GlobalPetrolPrices, which tracks what drivers around the world pay at the pump, we calculated by country the correlation between retail prices in local currency and wholesale prices on global gasoline markets. These generally follow crude oil prices closely, typically trading at a differential termed the “crack spread” that reflects an oil refinery’s profit margin from converting crude oil into gasoline.

This analysis showed that from January 2022 to May 2025, the average demand‑weighted correlation between global gasoline prices and prices at the pump was 77 per cent among member countries of the Organisation for Economic Cooperation and Development (OECD). This was about twice as strong as in other economies, where it was 39 per cent. The equivalent correlations for diesel were similar: 77 per cent and 38 per cent, respectively.

Understanding the looser relationship between retail prices and demand in emerging economies

This weak linkage between wholesale and retail prices stems from the prevalence of government price controls and state subsidies for oil in many emerging and developing economies. This is particularly apparent in major oil and gas producers in the Middle East. In Saudi Arabia, Kuwait and Qatar, gasoline prices at the pump have remained essentially unchanged for years. In large swathes of Asia, including India and Malaysia, these prices have also barely moved – or only faintly reflected developments in oil and currency markets, as is the case in China.

State intervention in oil market dynamics is no less common in advanced economies. However, these governments typically deploy fuel taxes rather than subsidies or price freezes (although this distinction is not absolute: for example, Japan’s extensive scheme of fuel subsidies renders it an outlier). As a result of these taxes, retail prices for gasoline and diesel tend to be much higher. Crucially, however, the taxes do not block the link with international oil markets – though the type of tax used determines the extent. Excise duties, which are quantity based, result in less of a link than value-added taxes, which are calculated based on price. Countries with low excise taxes, like the United States, therefore retain a clear transmission of market signals and a strong demand correlation to prices.

The impact of oil price and currency movements on short-term forecasts for oil demand

This structural disparity is an important factor in the different trajectory we see for oil demand in advanced economies compared with trends in developing countries this year. The IEA currently forecasts that global oil consumption in 2025 will rise by less than 700 000 barrels per day compared with 2024 – about 350 000 barrels per day less than our estimate at the start of the year. This downgrade since the beginning of 2025 is almost entirely attributable to lower-than-expected demand in emerging and developing economies.

Conversely, demand in advanced economies has proved resilient in the face of macroeconomic headwinds, supported by a relatively cold winter that boosted oil use for heating. Importantly, falling pump prices have also acted as a key support.

The impact of the drop in retail prices in some developed markets has been magnified by currency movements – most notably in Europe. Global oil prices and the US dollar have historically tended to move in opposite directions, with a weaker dollar typically coinciding with firmer oil prices. However, this trend has broken down in 2025, with a softer dollar accompanied by lower oil prices. (The US Dollar Index and benchmark Brent crude prices are each down about 10 per cent year to date.) Since global oil markets are priced in dollars, a weaker dollar reduces the cost of oil in local currencies for importing countries, incentivising demand.

The greenback’s decline has been most pronounced against the euro, which has risen 13 per cent against the dollar. The MSCI Emerging Market Currency Index has only appreciated by 6 per cent, with investor sentiment towards developing economies weighed down by turmoil over tariffs.

Partially as a result of this euro strength, we see oil demand in Europe growing by 20 000 barrels per day in 2025. That’s a notable change from the contraction of 80 000 barrels per day that we had forecast at the start of this year. This upward revision stands in marked contrast to downgrades in the consumption forecasts for most regions of the world in 2025.

 

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