'Forgotten' lake shows South's stubborn drought

By Associated Press


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A decaying highway, plunged deep underwater after Lake Hartwell was dammed in the 1950s, sits exposed once again across what remains of the bay outside Big Water Marina.

It's a depressing reminder of the toll from a stubborn Southern drought that only recently began to abate with replenishing rains this fall. Much of the region has recovered, but a ring stretching from northeast Georgia to the western Carolinas remains stuck in "extreme" drought.

And Hartwell, a massive 56,000-acre lake straddling Georgia-South Carolina state line, is near the epicenter. Even after a spate of recent downpours, its water line is nearly 18 feet below normal levels.

"We never thought we'd see it. We never thought the lake would go this far down," said Jane Davis, who built the marina from the ground up with her husband. "Everyone needs water, but Hartwell has finally given more water than it can take."

Forecasters say there's no telling when it will end.

"When you start looking at an area like that that's been under duress so long, even one or two rain events aren't going to completely wipe away the long-term problems," said Brian Fuchs, a climatologist with the National Drought Mitigation Center.

Hartwell has for decades been a source of water, recreation and electricity for scores of towns and thousands of residents on both sides of its ever-growing banks.

Now moldy boat shells, aging beer cans and even long-lost highways once deep underwater bake in the sun. Jagged islands once topped with buoys to ward off unsuspecting boats now sit uncomfortably 8 feet above water.

Some residents blame the U.S. Army Corps of Engineers, which sends millions of gallons of water from the lake each week downstream to the Savannah River to help supply Savannah, Augusta and other cities.

They also worry that the Corps and another federal agency, the Southeastern Power Administration, focus too much on generating electricity and too little on keeping the lake full.

"You're going to have to put lake levels on the priority list," said Mike Gray, a real estate broker in nearby Anderson, S.C., who has a growing list of unsold homes on the lake's banks.

The Corps, which has reduced water releases from Hartwell by 15 percent this month, said producing electricity is an "incidental" byproduct of sending water downstream.

Corps spokesman Billy Birdwell said the agency was following federal guidelines designed to meet the competing demands.

"This lake is not forgotten," said Birdwell. "We're watching the levels constantly. We're trying to meet the different demands. There are needs upstream, there are needs downstream. And right now, water supply and quality is taking the highest precedence."

Engineers for SEPA, which markets the energy produced by Hartwell and other nearby lakes, say it is also following its federal mandate.

"We're not driving the generation, we're just the front man," said Douglas Spencer, a SEPA hydrologist. "We're just responsible for marketing the generation."

Others say Hartwell's plight has been overlooked while water sources like north Georgia's Lake Lanier have earned more attention because of they are near Atlanta.

"There's a feeling that the lake has been forgotten, in part because it's not near a major metropolitan center and in part because it's divided by two states with varied interests," said Juan Brown, a retired physician who lives in nearby Anderson, S.C.

"It's a negative cloud that's been over us all through these droughts, and this is particularly bad because of the economy," Gray said. "People are depressed, and they are beginning to lose hope that it's going to come back."

Meanwhile, Davis' marina is slowly vanishing. The number of occupied boat slips has dropped about 80 percent, and Davis is warning the rest of her customers to get out while they can. The lake, she fears, will ultimately fall to 35 feet below normal levels.

"A lot of my customers just don't want to come to the lake anymore," she sighs, her voice trembling. "We're going to be a land-based marina very soon. And that's disastrous. Our marina is in crisis."

As she spoke, the skies opened up, and a light but steady rain began to soak the marina. But to Davis, it seemed like a cruel joke: "It's not enough."

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Spain's power demand in April plummets under COVID-19 lockdown

Spain Electricity Demand April 2020 saw a 17.3% year-on-year drop as COVID-19 lockdown curbed activity; renewables and wind power lifted the emission-free share, while combined cycle plants dominated islands, per REE data.

 

Key Points

A 17.3% y/y decline amid COVID-19 lockdown, with 47.9% renewables and wind at 21.3% of the national power mix.

✅ Mainland demand -17%; Balearic -27.6%; Canary -20.3%.

✅ Emission-free share: 49.7% on the peninsula in April.

✅ Combined cycle led islands; coal absent in Balearics.

 

Demand for electricity in Spain dropped by 17.3% year-on-year to an estimated 17,104 GWh in April, aligning with a 15% global daily demand dip during the pandemic, while the country’s economy slowed down under the national state of emergency and lockdown measures imposed to curb the spread of COVID-19.

According to the latest estimates by Spanish grid operator Red Electrica de Espana (REE), the decline in demand was registered across Spain’s entire national territory, similar to a 10% UK drop during lockdown. On the mainland, it decreased by 17% to 16,191 GWh, while on the Balearic and the Canary Islands it plunged by 27.6% and 20.3%, respectively.

Renewables accounted for 47.9% of the total national electricity production in April, echoing Britain’s cleanest electricity trends during lockdown. Wind power production went down 20% year-on-year to 3,730 GWh, representing a 21.3% share in the total power mix.

During April, electricity generation in the peninsula was mostly based on emission-free technologies, reflecting an accelerated power-system transition across Europe, with renewables accounting for 49.7%. Wind farms produced 3,672 GWh, 20.1% less compared to April 2019, while contributing 22% to the power mix, even as global demand later surpassed pre-pandemic levels in subsequent periods.

In the Balearic Islands, electricity demand of 323,296 MWh was for the most part met by combined cycle power plants, even as some European demand held firm in later lockdowns, which accounted for 78.3% of the generation. Renewables and emission-free technologies had a combined share of 6.4%, while coal was again absent from the local power mix, completing now four consecutive months without contributing a single MWh.

In the Canary Islands system, demand for power decreased to 558,619 MWh, even as surging demand elsewhere strained power systems across the world. Renewables and emission-free technologies made up 14.3% of the mix, while combined cycle power plants led with a 45.3% share.

 

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Is The Global Energy Transition On Track?

Global Decarbonization Strategies align renewable energy, electrification, clean air policies, IMO sulfur cap, LNG fuels, and the EU 2050 roadmap to cut carbon intensity and meet Paris Agreement targets via EVs and efficiency.

 

Key Points

Frameworks that cut emissions via renewables, EVs, efficiency, cleaner marine fuels, and EU policy roadmaps.

✅ Renewables scale as wind and solar outcompete new coal and gas.

✅ Electrification of transport grows as EV costs fall and charging expands.

✅ IMO 2020 sulfur cap and LNG shift cut shipping emissions and particulates.

 

Are we doing enough to save the planet? Silly question. The latest prognosis from the United Nations’ Intergovernmental Panel on Climate Change made for gloomy reading. Fundamental to the Paris Agreement is the target of keeping global average temperatures from rising beyond 2°C. The UN argues that radical measures are needed, and investment incentives for clean electricity are seen as critical by many leaders to accelerate progress to meet that target.

Renewable power and electrification of transport are the pillars of decarbonization. It’s well underway in renewables - the collapse in costs make wind and solar generation competitive with new build coal and gas.

Renewables’ share of the global power market will triple by 2040 from its current level of 6% according to our forecasts.

The consumption side is slower, awaiting technological breakthrough and informed by efforts in countries such as New Zealand’s electricity transition to replace fossil fuels with electricity. The lower battery costs needed for electric vehicles (EVs) to compete head on and displace internal combustion engine (ICE)  cars are some years away. These forces only start to have a significant impact on global carbon intensity in the 2030s. Our forecasts fall well short of the 2°C target, as does the IEA’s base case scenario.

Yet we can’t just wait for new technology to come to the rescue. There are encouraging signs that society sees the need to deal with a deteriorating environment. Three areas of focus came out in discussion during Wood Mackenzie’s London Energy Forum - unrelated, different in scope and scale, each pointing the way forward.

First, clean air in cities.  China has shown how to clean up a local environment quickly. The government reacted to poor air quality in Beijing and other major cities by closing older coal power plants and forcing energy intensive industry and the residential sector to shift away from coal. The country’s return on investment will include a substantial future health care dividend.

European cities are introducing restrictions on diesel cars to improve air quality. London’s 2017 “toxicity charge” is a precursor of an Ultra-Low Emission Zone in 2019, and aligns with UK net-zero policy changes that affect transport planning, to be extended across much of the city by 2020. Paris wants to ban diesel cars from the city centre by 2025 and ICE vehicles by 2030. Barcelona, Madrid, Hamburg and Stuttgart are hatching similar plans.

 

College Promise In California: Community-Wide Efforts To Support Student Success

Second, desulphurisation of global shipping. High sulphur fuel oil (HSFO) meets around 3.5 million barrels per day (b/d) of the total marine market of 5 million b/d. A maximum of 3.5% sulphur content is allowed currently. The International Maritime Organisation (IMO) implements a 0.5% limit on all shipping in 2020, dramatically reducing the release of sulphur oxides into the atmosphere.

Some ships will switch to very low sulphur fuel oil, of which only around 1.4 million b/d will be available in 2020. Others will have to choose between investing in scrubbers or buying premium-priced low sulphur marine gas oil.

Longer-term, lower carbon-intensity gas is a winner as liquefied natural gas becomes fuel of choice for many newbuilds. Marine LNG demand climbs from near zero to 50 million tonnes per annum (tpa) by 2040 on our forecasts, behind only China, India and Japan as a demand centre. LNG will displace over 1 million b/d of oil demand in shipping by 2040.

Third, Europe’s radical decarbonisation plans. Already in the vanguard of emissions reductions policy, the European Commission is proposing to reduce carbon emissions for new cars and vans by 30% by 2030 versus 2020. The targets come with incentives for car manufacturers linked to the uptake of EVs.

The 2050 roadmap, presently at the concept stage, envisages a far more demanding regime, with EU electricity plans for 2050 implying a much larger power system. The mooted 80% reduction in emissions compared with 1990 will embrace all sectors. Power and transport are already moving in this direction, but the legacy fuel mix in many other sectors will be disrupted, too.

Near zero-energy buildings and homes might be possible with energy efficiency improvements, renewables and heat pumps. Electrification, recycling and bioenergy could reduce fossil fuel use in energy intensive sectors like steel and aluminium, and Europe’s oil majors going electric illustrates how incumbents are adapting. Some sectors will cite the risk decarbonisation poses to Europe’s global competitiveness. If change is to come, industry will need to build new partnerships with society to meet these targets.

The 2050 roadmap signals the ambition and will be game changing for Europe if it is adopted. It would provide a template for a global roll out that would go a long way toward meeting UN’s concerns.

 

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Covid-19 puts brake on Turkey’s solar sector

Turkey Net Metering Suspension freezes regulator reviews, stalling rooftop solar permits and grid interconnections amid COVID-19, pausing licensing workflows, EPC pipelines, and electricity bill credits that drive commercial and household prosumer adoption.

 

Key Points

A pause on technical reviews freezing net metering applications and slowing rooftop solar deployment in Turkey.

✅ Monthly technical committee meetings suspended indefinitely

✅ Rooftop solar permits and grid interconnections on hold

✅ EPC firms urge remote evaluations for transparency

 

The decision by the Turkish Energy Market Regulatory Authority to halt part of the system of processing net metering applications risks bringing the only vibrant segment of the nation’s solar industry to a grinding halt, a risk amplified as global renewables face Covid-19 disruptions across markets.

The regulator has suspended monthly meetings of the committee which makes technical evaluations of net metering applications, citing concerns about the spread of Covid-19, which has already seen U.S. utility-scale solar face delays this year.

The availability of electricity bill credits for net-metering-approved households which inject surplus power into the grid, similar to how British households can sell power back to energy firms, has seen the rooftop projects the scheme is typically associated with remain the only source of new solar generation capacity in Turkey of late.

However the energy regulator’s decision to suspend technical evaluation committee meetings until further notice has seen the largely online licensing process for new solar systems practically cease; by contrast, Berlin is being urged to remove PV barriers to keep projects moving.

The Turkish solar industry has claimed the move is unnecessary, with solar engineering, procurement and construction services businesses pointing out the committee could meet to evaluate projects remotely. It has been argued such a move would streamline the application process and make it more transparent, regardless of the current public health crisis.

 

Net metering 

Turkey introduced net metering for rooftop installations last May and pv magazine has reported the specifics of the scheme, amid debates like New England's grid upgrade costs over who pays.

National grid operator Teias confirmed recently the country added 109 MW of new solar capacity in the first quarter, most of it net-metered rooftop systems, even as Australian distributors warn excess solar can strain local networks.

Net metering has been particularly attractive to commercial electricity users because the owners of small and medium-sized businesses pay more for power, as solar reshapes electricity prices in Northern Europe, than either households or large scale industrial consumers.

Until the recent technical committee decision by the regulator, the chief obstacle to net metering adoption had been the nation’s economic travails. The Turkish lira has lost 14% of its value since January and around 36% over the last two years. The central bank has been using its foreign reserves to support state lenders and the lira but the national currency slipped near an all-time low on Friday and foreign analysts predict the central bank reserves could run dry in July.

The level of exports shipped last month was down 41% on April last year and imports fell 28% by the same comparison, further depressing the willingness of companies to make capital investments such as rooftop solar.

 

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Electricity retailer Griddy's unusual plea to Texas customers: Leave now before you get a big bill

Texas wholesale electricity price spike disrupts ERCOT markets as Griddy and other retail energy providers face surge pricing; customers confront spot market exposure, fixed-rate plan switching, demand response appeals, and deep-freeze grid constraints across Texas.

 

Key Points

An extreme ERCOT market surge sending real-time rates to caps, exposing Griddy users and driving provider-switch pleas.

✅ Wholesale index plans pass through $9,000/MWh scarcity pricing.

✅ Retailers urge switching; some halt enrollments amid volatility.

✅ Demand response incentives and conservation pleas reduce load.

 

Some retail power companies in Texas are making an unusual plea to their customers amid a winter storm that has sent electricity prices skyrocketing: Please, leave us.

Power supplier, Griddy, told all 29,000 of its customers that they should switch to another provider as spot electricity prices soared to as high as $9,000 a megawatt-hour. Griddy’s customers are fully exposed to the real-time swings in wholesale power markets, so those who don’t leave soon will face extraordinarily high electricity bills.

“We made the unprecedented decision to tell our customers — whom we worked really hard to get — that they are better off in the near term with another provider,” said Michael Fallquist, chief executive officer of Griddy. “We want what’s right by our consumers, so we are encouraging them to leave. We believe that transparency and that honesty will bring them back” once prices return to normal.

Texas is home to the most competitive electricity market in America. Homeowners and businesses shopping for electricity churn power providers there like credit cards. In the face of such cutthroat competition, retail power providers in the region have grown accustomed to offering new customers incredibly low rates, incentives and, at least in Griddy’s case, unusual plans that allow customers to pay wholesale power prices as opposed to fixed ones.

The ruthless nature of the business has power traders speculating over which firms might have been caught short this week in the most dramatic run-up in spot power prices they’ve ever seen, and even talk of a market bailout has surfaced.

Not all companies are asking customers to leave. Others are just pleading for them to cut back to reduce blackout risks during extreme weather.

Pulse Power, based in The Woodlands, Texas, is offering customers a chance to win a Tesla Model 3, or free electricity for up to a year if they reduce their power usage by 10% in the coming days. Austin-based Bulb is offering $2 per kilowatts-hour, up to $200, for any energy customers save.

Griddy, however, is in a different position. Its service is simple — and controversial. Members pay a $9.99 monthly fee and then pay the cost of spot power traded on Texas’s power grid based on the time of day they use it. Earlier this month, that meant customers were saving money — and at times even getting paid — to use electricity at night. But in recent days, the cost of their power has soared from about 5 to 6 cents a kilowatt-hour to $1 or more. That’s when Fallquist knew it was time to urge his customers to leave.

“I can tell you it was probably one of the hardest decisions we’ve ever made,” he said. “Nobody ever wants to see customers go.”

Griddy isn’t the only one out there actively encouraging its customers to leave. People were posting similar pleas on Twitter over the holiday weekend from other Texas utilities and retail power providers offering everything from $100 rebates to waived cancellation fees as incentives to switch.

Customers may not even be able to switch. Rizwan Nabi, president of energy consultancy Riz Energy in Houston, said several power providers in Texas have told him they aren’t accepting new customers due to this week’s volatile prices, while grid improvements are debated statewide.

Hector Torres, an energy trader in Texas, who is a Griddy customer himself, said he tried to switch services over the long weekend but couldn’t find a company willing to take him until Wednesday, when the weather is forecast to turn warmer.

 

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Clean, affordable electricity should be an issue in the Ontario election

Ontario Electricity Supply Gap threatens growth as demand from EVs, heat pumps, industry, and greenhouses surges, pressuring the grid and IESO to add nuclear, renewables, storage, transmission, and imports while meeting net-zero goals.

 

Key Points

The mismatch as Ontario's electricity demand outpaces supply, driven by electrification, EVs, and industrial growth.

✅ Demand growth from EVs, heat pumps, and electrified industry

✅ Capacity loss from Pickering retirement and Darlington refurb

✅ Options: SMRs, renewables, storage, conservation, imports

 

Ontario electricity demand is forecast to soon outstrip supply as it confronts a shortage in the coming years, a problem that needs attention in the upcoming provincial election.

Forecasters say Ontario will need to double its power supply by 2050 as industries ramp up demand for low-emission clean power options and consumers switch to electric vehicles and space heating. But while the Ford government has made a flurry of recent energy announcements, including a hydrogen project at Niagara Falls and an interprovincial agreement on small nuclear reactors, it has not laid out how it intends to bulk up the province’s power supply.

“Ontario is entering a period of widening electricity shortfalls,” says the Ontario Chamber of Commerce. “Having a plan to address those shortfalls is essential to ensure businesses can continue investing and growing in Ontario with confidence.”

The supply and demand mismatch is coming because of brisk economic growth combined with increasing electrification to balance demand and emissions and meet Canada’s goal to reduce CO2 emissions by 40 per cent by 2030 and to net-zero by 2050.

Hamilton’s ArcelorMittal Dofasco and Algoma Steel in Sault Ste. Marie are leaders on this transformation. They plan to replace their blast furnaces and basic oxygen furnaces later this decade with electric arc furnaces (EAFs), reducing annual CO2 emissions by three million tonnes each.


Dofasco, which operates an EAF that is already the single largest electricity user in Ontario, plans to build a second EAF and a gas-fired ironmaking furnace, which can also be powered with zero-carbon hydrogen produced from electricity, once it becomes available.

Other new projects in the agriculture, mining and manufacturing sectors are also expected to be big power users, including the recently announced $5 billion Stellantis-LG electric vehicle battery plant in Windsor. Five new transmission lines will be built to service the plant and the burgeoning greenhouse industry in southwestern Ontario. The greenhouses alone will require enough additional electricity to power a city the size of Ottawa.

On top of these demands, growing numbers of Ontario drivers are expected to switch to electric vehicles and many homeowners and business owners are expected to convert from gas heating to heat pumps and electric heating.

Ontario is recognized as one of the cleanest electricity systems in the world, with over 90 per cent of its capacity from low-emission nuclear, hydro, wind and other renewable generation. Only nine per cent comes from CO2-emitting gas plants. But that’s about to get dirtier according to analysts.

Annual electricity demand is expected to grow from 140 terawatt hours (a terawatt hour is one trillion watts for one hour) currently to about 200 terawatt hours in 2042, according to the Independent Electricity System Operator, the agency that manages Ontario’s grid.

Demand is expected to outstrip currently contracted supply in 2026, reaching a growing supply gap of about 80 terawatt hours by 2042. A big part of this gap is due to the scheduled retirement of the Pickering nuclear station in 2025 and the current refurbishment of the Darlington nuclear station reactors. While the IESO doesn’t expect blackouts or brownouts, it forecasts the province will need to sharply increase expensive power imports and triple the amount of CO2-polluting gas-fired generation.

Without cleaner, lower-cost alternatives, this will mean “a vastly dirtier and more expensive electricity system,” York University researchers Mark Winfield and Collen Kaiser said in a recent commentary.

The party that wins the provincial election will have to make hard decisions on renewable energy, including new wind and solar projects, energy conservation, battery storage, new hydro plants, small nuclear reactors, gas generation and power imports from the U.S. and Quebec. In addition, the federal government is pressing the provinces to meet a new net-zero clean electricity standard by 2035. These decisions will have huge impact on Ontario’s future, with greening the grid costs highlighted in some reports as potentially very high.

With so much at stake, Ontario’s political parties need to tell voters during the upcoming campaign how they would address these enormous challenges.

 

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LNG powered with electricity could be boon for B.C.'s independent power producers

B.C. LNG Electrification embeds clean hydro and wind power into low-emission liquefied natural gas, cutting carbon intensity, enabling coal displacement in Asia, and opening grid-scale demand for independent power producers and ITMO-based climate accounting.

 

Key Points

Powering LNG with clean electricity cuts carbon intensity, displaces coal, and grows demand for B.C.'s clean power.

✅ Electric-drive LNG cuts emissions intensity by up to 80%.

✅ Creates major grid load, boosting B.C. independent power producers.

✅ Enables ITMO crediting when coal displacement is verified.

 

B.C. has abundant clean power – if only there was a way to ship those electrons across the sea to help coal-dependent countries reduce their emissions, and even regionally, Alberta–B.C. grid link benefits could help move surplus power domestically.

Natural gas that is liquefied using clean hydro and wind power and then exported would be, in a sense, a way of embedding B.C.’s low emission electricity in another form of energy, and, alongside the Canada–Germany clean energy pact, part of a broader export strategy.

Given the increased demand that could come from an LNG industry – especially one that moves towards greater electrification and, as the IEA net-zero electricity report notes, broader system demand – poses some potentially big opportunities for B.C.’s clean energy independent power sector, as those attending the Clean Energy Association of BC's annual at the Generate conference heard recently.

At a session on LNG electrification, delegates were told that LNG produced in B.C. with electricity could have some significant environmental benefits.

Given how much power an LNG plant that uses electric drive consumes, an electrified LNG industry could also pose some significant opportunities for independent power producers – a sector that had the wind taken out of its sails with the sanctioning of the Site C dam project.

Only one LNG plant being built in B.C. – Woodfibre LNG – will use electric drive to produce LNG, although the companies behind Kitimat LNG have changed their original design plans, and now plan to use electric drive drive as well.

Even small LNG plants that use electric drive require a lot of power.

“We’re talking about a lot of power, since it’s one of the biggest consumers you can connect to a grid,” said Sven Demmig, head of project development for Siemens.

Most LNG plants still burn natural gas to drive the liquefaction process – a choice that intersects with climate policy and electricity grids in Canada. They typically generate 0.35 tonnes of CO2e per tonne of LNG produced.

Because it will use electric drive, LNG produced by Woodfibre LNG will have an emissions intensity that is 80% less than LNG produced in the Gulf of Mexico, said Woodfibre president David Keane.

In B.C., the benchmark for GHG intensities for LNG plants has been set at 0.16 tonnes of CO2e per tonne of LNG. Above that, LNG producers would need to pay higher carbon taxes than those that are below the benchmark.

The LNG Canada plant has an intensity of 0.15 tonnes og CO2e per tonne of LNG. Woodfibre LNG will have an emissions intensity of just 0.059, thanks to electric drive.

“So we will be significantly less than any operating facility in the world,” Keane said.

Keane said Sinopec has recently estimated that it expects China’s demand for natural gas to grow by 82% by 2030.

“So China will, in fact, get its gas supply,” Keane said. “The question is: where will that supply come from?

“For every tonne of LNG that’s being produced today in the United States -- and tonne of LNG that we’re not producing in Canada -- we’re seeing about 10 million tonnes of carbon leakage every single year.”

The first Canadian company to produce LNG that ended up in China is FortisBC. Small independent operators have been buying LNG from FortisBC’s Tilbury Island plant and shipping to China in ISO containers on container ships.

David Bennett, director of communications for FortisBC, said those shipments are traced to industries in China that are, indeed, using LNG instead of coal power now.

“We know where those shipping containers are going,” he said. “They’re actually going to displace coal in factories in China.”

Verifying what the LNG is used for is important, if Canadian producers want to claim any kind of climate credit. LNG shipped to Japan or South Korea to displace nuclear power, for example, would actually result in a net increase in GHGs. But used to displace coal, the emissions reductions can be significant, since natural gas produces about half the CO2 that coal does.

The problem for LNG producers here is B.C.’s emissions reduction targets as they stand today. Even LNG produced with electricity will produce some GHGs. The fact that LNG that could dramatically reduce GHGs in other countries, if it displaces coal power, does not count in B.C.’s carbon accounting.

Under the Paris Agreement, countries agree to set their own reduction targets, and, for Canada, cleaning up Canada’s electricity remains critical to meeting climate pledges, but don’t typically get to claim any reductions that might result outside their own country.

Canada is exploring the use of Internationally Transferred Mitigation Outcomes (ITMO) under the Under the Paris Agreement to allow Canada to claim some of the GHG reductions that result in other countries, like China, through the export of Canadian LNG.

“For example, if I were producing 4 million tonnes of greenhouse gas emissions in B.C. and I was selling 100% of my LNG to China, and I can verify that they’re replacing coal…they would have a reduction of about 60 or million tonnes of greenhouse gas emissions,” Keane said.

“So if they’re buying 4 million tonnes of emissions from us, under these ITMOs, then they have net reduction of 56 million tonnes, we’d have a net increase of zero.”

But even if China and Canada agreed to such a trading arrangement, the United Nations still hasn’t decided just how the rules around ITMOs will work.

 

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