Rates will drop for some customers

Global Coal Power Decline 2019 signals a record fall in coal-fired electricity as China plateaus, India dips, and the EU and US accelerate renewables, curbing carbon emissions and advancing the global energy transition.

Key Points

A record 2019 drop in global coal power as renewables rise and demand slows across China, India, the EU, and the US.

✅ 3% global fall in coal-fired electricity in 2019.

✅ China plateaus; India declines for first time in decades.

✅ EU and US shift to renewables and gas, cutting emissions.

The world’s use of coal-fired electricity is on track for its biggest annual fall on record this year after more than four decades of near-uninterrupted growth that has stoked the global climate crisis.

Data shows that coal-fired electricity is expected to fall by 3% in 2019, or more than the combined coal generation in Germany, Spain and the UK last year and could help stall the world’s rising carbon emissions this year.

The steepest global slump on record is likely to emerge in 2019 as India’s reliance on coal power falls for the first time in at least three decades this year, and China’s coal power demand plateaus, reflecting the broader global energy transition underway.

Both developing nations are using less coal-fired electricity due to slowing economic growth in Asia as well as the rise of cleaner energy alternatives. There is also expected to be unprecedented coal declines across the EU and the US as developed economies turn to clean forms of energy such as low-cost solar power to replace ageing coal plants.

In almost 40 years the world’s annual coal generation has fallen only twice before: in 2009, in the wake of the global financial crisis, and in 2015, following a slowdown in China’s coal plants amid rising levels of deadly air pollution.

The research was undertaken by the Centre for Research on Energy and Clean Air , the Institute for Energy Economics and Financial Analysis and the UK climate thinktank Sandbag.

The researchers found that China’s coal-fired power generation was flatlining, despite an increase in the number of coal plants being built, because they were running at record low rates. China builds the equivalent of one large new coal plant every two weeks, according to the report, but its coal plants run for only 48.6% of the time, compared with a global utilisation rate of 54% on average.

The findings come after a report from Global Energy Monitor found that the number of coal-fired power plants in the world is growing, because China is building new coal plants five times faster than the rest of the world is reducing their coal-fired power capacity.

The report found that in other countries coal-fired power capacity fell by 8GW in the 18 months to June but over the same period China increased its capacity by 42.9GW.

In a paper for the industry journal Carbon Brief, the researchers said: “A 3% reduction in power sector coal use could imply zero growth in global CO2 emissions, if emissions changes in other sectors mirror those during 2018.”

However, the authors of the report have warned that despite the record coal power slump the world’s use of coal remained far too high to meet the climate goals of the Paris agreement, and some countries are still seeing increases, such as Australia’s emissions rise amid increased pollution from electricity and transport.

The US – which is backing out of the Paris agreement – has made the deepest cuts to coal power of any developed country this year by shutting coal plants down in favour of gas power and renewable energy, with utilities such as Duke Energy facing investor pressure to disclose climate plans. By the end of August the US had reduced coal by almost 14% over the year compared with the same months in 2018.

The EU reported a record slump in coal-fired electricity use in the first half of the year of almost a fifth compared with the same months last year. This trend is expected to accelerate over the second half of the year to average a 23% fall over 2019 as a whole. The EU is using less coal power in favour of gas-fired electricity – which can have roughly half the carbon footprint of coal – and renewable energy, helped by policies such as the UK carbon tax that have slashed coal-fired generation.

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Geothermal Power Plant Risks include hydrogen sulfide leaks, toxic gases, lava flow hazards, well blowouts, and earthquake-induced releases at sites like PGV and the Geysers, threatening public health, grid reliability, and environmental safety.

Key Points

Geothermal Power Plant Risks include toxic gases, lava impacts, well failures, and induced quakes that threaten health.

✅ Hydrogen sulfide exposure can cause rapid pulmonary edema.

✅ Lava can breach wells, venting toxic gases into communities.

✅ Induced seismicity may disrupt grids near PGV and the Geysers.

If lava reaches Hawaii’s PGV geothermal power plant, it could release of deadly hydrogen sulfide gas. That’s the latest potential danger from the Kilauea volcanic eruption in Hawaii. Residents now fear that lava flow will trigger a meltdown at the Puna Geothermal Venture (PGV) power plant that would release even more toxic gases into the air.

Nobody knows what will happen if lava engulfs the PGV because magma has never engulfed a geothermal power plant, Reuters reported. A geothermal power plant uses steam and gas heated by lava deep in the earth to run turbines that make electricity.

The PGV power plant produces 25% of the power used on Hawaii’s “Big Island.” The plant is considered a source of clean energy because geothermal plants burn no fossil fuels and produce little pollution under normal circumstances, even as nuclear retirements like Three Mile Island reshape low-carbon options.

The Potential Danger from Geothermal Energy

The fear is that the lava would release chemicals used to make electricity at the plant. The PGV has been shut down and authorities moved an estimated 60,000 gallons of flammable liquids away from the facility. They also shut down wells that extract steam and gas used to run the turbines.

Another potential danger is that lava would open the wells and release clouds of toxic gases from them. The wells are typically sealed to prevent the gas from entering the atmosphere.

The most significant threat is hydrogen sulfide, a highly toxic and flammable gas that is colorless. Hydrogen sulfide normally has a rotten egg smell which people might not detect when the air is full of smoke. That means people can breathe hydrogen sulfide in without realizing they have been exposed.

The greatest danger from hydrogen sulfide is pulmonary edema; the accumulation of fluid in the lungs, which causes a person to stop breathing. People have died of pulmonary edema after just a few minutes of exposure to hydrogen sulfide gas. Many victims become unconscious before the gas kills them. Long-term dangers that survivors of pulmonary edema face include brain damage.

Hydrogen sulfide can also cause burns to the skin that are similar to frostbite. Persons exposed to hydrogen sulfide can also suffer from nausea, headaches, severe eye burns, and delirium. Children are more vulnerable to hydrogen sulfide because it is a heavy gas that stays close to the ground.

Geothermal Danger Extends Far Beyond Hawaii

The danger from geothermal energy extends far beyond Hawaii. The world’s largest collection of geothermal power plants is located at the Geysers in California’s Wine Country, and regulatory timelines such as the postponed closure of three Southern California plants can affect planning.

The Geysers field contains 350 steam production wells and 22 power plants in Sonoma, Lake, and Mendocino counties. Disturbingly, the Geysers are located just north of the heavily-populated San Francisco Bay Area and just west of Sacramento, where preemptive electricity shutdowns have been used during extreme fire weather. Problems at the Geysers might lead to significant blackouts because the field supplies around 20% of the green energy used in California.

Another danger from geothermal power is earthquakes because many geothermal power plants inject wastewater into hot rock deep below to produce steam to run turbines, a factor under review as SaskPower explores geothermal in new settings. A geothermal project in Switzerland created Earthquakes by injecting water into the Earth, Zero Hedge reported. A theoretical threat is that quakes caused by injection would cause the release of deadly gases at a geothermal power plant.

The dangers from geothermal power might be much greater than its advocates admit, potentially increasing reliance on natural-gas-based electricity during supply shortfalls.

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Nova Scotia Integrated Resource Plan evaluates NSPI supply options, UARB oversight, Muskrat Falls imports, coal retirements, wind and biomass expansion, transmission upgrades, storage, and least-cost pathways to decarbonize the grid for ratepayers.

Key Points

A 25-year roadmap assessing supply, imports, costs, and emissions to guide least-cost decarbonization for Nova Scotia.

✅ Compares wind, biomass, gas, imports, and storage costs

✅ Addresses coal retirements, emissions caps, and reliability

✅ Recommends transmission upgrades and Muskrat Falls utilization

Maintaining a viable electricity network requires good long-term planning and, as a recent grid operations report notes, ongoing operational improvements. The existing stock of generating assets can become obsolete through aging, changes in fuel prices or environmental considerations. Future changes in demand must be anticipated.

Periodically, an integrated resource plan is created to predict how all this will add up during the ensuing 25 years. That process is currently underway and is led by Nova Scotia Power Inc. (NSPI) and will be submitted for approval to the Utilities and Review Board (UARB).

Coal-fired plants are still the largest single source of electricity in Nova Scotia. They need to be replaced with more environmentally friendly sources when they reach the end of their useful lives. Other sources include wind, hydroelectricity from rivers, biomass, as seen in increased biomass use by NS Power, natural gas and imports from other jurisdictions.

Imports are used sparingly today but will be an important source when the electricity from Muskrat Falls comes on stream. That project has big capacity. It can produce all the power needed in Newfoundland and Labrador (NL), where Quebec's power ambitions influence regional flows, plus the amount already committed to Nova Scotia, and still have a lot left over.

Some sources of electricity are more valuable than others. The daily amount of power from wind and solar cannot be controlled. Fuel-based sources and hydro can.

Utilities make their profits by providing the capital necessary to build infrastructure. Most of the money is borrowed but a portion, typically 30 per cent, usually comes from NSPI or a sister company. On that they receive a rate of return of nine per cent. Nova Scotia can borrow money today at less than two per cent.

The largest single investment of that type is the $1.577-billion Maritime Link connecting power from Newfoundland to Nova Scotia. It continues through to the New Brunswick border to facilitate exports to the United States. NSPI’s sister company, NSP Maritime Link Inc. (NSPML), is making nine per cent on $473 million of the cost.

There is little unexploited hydro capacity in Nova Scotia and there will not be any new coal-fired plants. Large-scale solar is not competitive in Nova Scotia’s climate. Nova Scotia’s needs would not accommodate the amount of nuclear capacity needed to be cost-effective, even as New Brunswick explores small reactors in its strategy.

So the candidates for future generating resources are wind, natural gas, biomass (though biomass criticism remains) and imports from other jurisdictions. Tidal is a promising opportunity but is still searching for a commercially viable technology. 

NSPI is commendably transparent about its process (irp.nspower.ca). At this stage there is little indication of the conclusions they are reaching but that will presumably appear in due course.

The mountains of detail might obscure the fact that NSPI is not an unbiased arbiter of choices for the future.

It is reported that they want to prematurely close the Trenton 5 coal plant in 2023-25. It is valued at $88.5 million. If it is closed early, ratepayers will still have to pay off the remaining value even though the plant will be idle. NSPI wants to plan a decommissioning of five of its other seven plants. There is a federal emissions constraint but retiring coal plants earlier than needed will cost ratepayers a lot.

Whenever those plants are closed, there will be a need for new sources of power. NSPI is proposing to plan for new investments in new transmission infrastructure to facilitate imports. Other possibilities would be additional wind farms, consistent with the shift to more wind and solar projects, thermal plants that burn natural gas or biomass, or storage for excess wind power that arrives before it can be used. The investment in storage could be anywhere from $20 million to $200 million.

These will add to the asset burden funded by ratepayers, even as industrial customers seek discounts while still paying for shuttered coal infrastructure.

External sources of new power will not provide NSPI the same opportunity: wind power by independent producers might be less expensive because they are willing to settle for less than nine per cent or because they are more efficient. Buying more power from Muskrat Falls will use transmission infrastructure we are already paying for. If a successful tidal technology is found, it will not be owned by NSPI or a sister company, which are no longer trying to perfect the technology.

This is not to suggest that NSPI would misrepresent the alternatives. But they can tilt the discussion in their favour. How tough will they be negotiating for additional Muskrat Falls power when it hurts their profits? Arguing for premature coal retirement on environmental grounds is fair game but whether the cost should be accepted is a political choice. 

NSPI is in a conflict of interest. We need a different process. An independent body should author the integrated resource plan. They should be fully informed about NSPI’s views.

They should communicate directly with Newfoundland and Labrador for Muskrat power, with independent wind producers, and with tidal power companies. The UARB cannot do any of these things.

The resulting plan should undergo the same UARB review that NSPI’s version would. This enhances the likelihood that Nova Scotians will get the least-cost alternative.

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Manitoba Hydro capacity constraints challenge clean energy growth as industrial demand, hydrogen projects, EV batteries, and electrification strain the grid; limited surplus, renewables, storage, and transmission bottlenecks hinder new high-load connections.

Key Points

Limited surplus power blocks new energy-intensive loads until added generation and transmission expand Manitoba's grid.

✅ No firm commitments for new energy-intensive industrial customers

✅ Single large load could consume remaining surplus capacity

✅ New renewables need transmission; gas, nuclear face trade-offs

Manitoba Hydro lacks the capacity to provide electricity to any new "energy intensive" industrial customers, the Crown corporation warns in a confidential briefing note that undercuts the idea this province can lure large businesses with an ample supply of clean, green energy, as the need for new power generation looms for the utility.

On July 28, provincial economic development officials unveiled an "energy roadmap" that said Manitoba Hydro must double or triple its generating capacity, as electrical demand could double over the next two decades in order to meet industrial and consumer demand for electricity produced without burning fossil fuels.

Those officials said 18 potential new customers with high energy needs were looking at setting up operations in Manitoba — and warned the province must be careful to choose businesses that provide the greatest economic benefit as well as the lowest environmental impact.

In a briefing note dated Sept. 13, obtained by CBC News, Manitoba Hydro warns it doesn't have enough excess power to hook up any of these new heavy electricity-using customers to the provincial power grid.

There are actually 57 proposals to use large volumes of electricity, Hydro says in the note, including eight projects already in the detailed study phase and nine where the proponents are working on construction agreements.

"Manitoba Hydro is unable to offer firm commitments to prospective customers that may align with Manitoba's energy roadmap and/or provincial economic development objectives," Hydro warns in the note, explaining it is legally obliged to serve all existing customers who need more electricity.

"As such, Manitoba Hydro cannot reserve electric supply for particular projects."

Hydro says in the note its "near-term surplus electricity supply" is so limited amid a Western Canada drought that "a single energy-intensive connection may consume all remaining electrical capacity."

Adding more electrical generating capacity won't be easy, even with new turbine investments underway, and will not happen in time to meet demands from customers looking to set up shop in the province, Hydro warns.

The Crown corporation goes on to say it's grappling with numerous requests from existing and prospective energy-intensive customers, mainly for producing hydrogen, manufacturing electric vehicle batteries and switching from fossil fuels to electricity, such as to use electricity for heat in buildings.

In a statement, Hydro said it wants to ensure Manitobans know the corporation is not running out of power — just the ability to meet the needs of large new customers, and continues to provide clean energy to neighboring provinces today.

"The size of loads looking to come to Manitoba are significantly larger than we typically see, and until additional supply is available, that limits our ability to connect them," Hydro spokesperson Bruce Owen said in a statement.

Adding wind power or battery storage, for example, would require the construction of more transmission lines, and deals such as SaskPower's purchase depend on that interprovincial infrastructure as well.

Natural gas plants are relatively inexpensive to build but do not align with efforts to reduce carbon emissions. Nuclear power plants require at least a decade of lead time to build, and tend to generate local opposition.

Hydro has also ruled out building another hydroelectric dam on the Nelson River, where the Conawapa project was put on hold in 2014.

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Offshore wind power accelerates low-carbon electrification, leveraging floating turbines, high capacity factors, HVDC transmission, and hydrogen production to decarbonize grids, cut CO2, and deliver competitive, reliable renewable energy near demand centers.

Key Points

Offshore wind power uses offshore turbines to deliver low-carbon electricity with high capacity factors and falling costs.

✅ Sea-based wind farms with 40-50% capacity factors

✅ Floating turbines unlock deep-water, far-shore resources

✅ Enables hydrogen production and strengthens grid reliability

The need for affordable low-carbon technologies is greater than ever

Global energy-related CO2 emissions reached a historic high in 2018, driven by an increase in coal use in the power sector. Despite impressive gains for renewables, fossil fuels still account for nearly two-thirds of electricity generation, the same share as 20 years ago. There are signs of a shift, with increasing pledges to decarbonise economies and tackle air pollution, and with World Bank support helping developing countries scale wind, but action needs to accelerate to meet sustainable energy goals. As electrification of the global energy system continues, the need for clean and affordable low-carbon technologies to produce this electricity is more pressing than ever. This World Energy Outlook special report offers a deep dive on a technology that today has a total capacity of 23 GW (80% of it in Europe) and accounts for only 0.3% of global electricity generation, but has the potential to become a mainstay of the world's power supply. The report provides the most comprehensive analysis to date of the global outlook for offshore wind, its contributions to electricity systems and its role in clean energy transitions.

The offshore wind market has been gaining momentum

The global offshore wind market grew nearly 30% per year between 2010 and 2018, benefitting from rapid technology improvements. Over the next five years, about 150 new offshore wind projects are scheduled to be completed around the world, pointing to an increasing role for offshore wind in power supplies. Europe has fostered the technology's development, led by the UK offshore wind sector alongside Germany and Denmark. The United Kingdom and Germany currently have the largest offshore wind capacity in operation, while Denmark produced 15% of its electricity from offshore wind in 2018. China added more capacity than any other country in 2018.

The untapped potential of offshore wind is vast

The best offshore wind sites could supply more than the total amount of electricity consumed worldwide today. And that would involve tapping only the sites close to shores. The IEA initiated a new geospatial analysis for this report to assess offshore wind technical potential country by country. The analysis was based on the latest global weather data on wind speed and quality while factoring in the newest turbine designs. Offshore wind's technical potential is 36 000 TWh per year for installations in water less than 60 metres deep and within 60 km from shore. Global electricity demand is currently 23 000 TWh. Moving further from shore and into deeper waters, floating turbines could unlock enough potential to meet the world's total electricity demand 11 times over in 2040. Our new geospatial analysis indicates that offshore wind alone could meet several times electricity demand in a number of countries, including in Europe, the United States and Japan. The industry is adapting various floating foundation technologies that have already been proven in the oil and gas sector. The first projects are under development and look to prove the feasibility and cost-effectiveness of floating offshore wind technologies.

Offshore wind's attributes are very promising for power systems

New offshore wind projects have capacity factors of 40-50%, as larger turbines and other technology improvements are helping to make the most of available wind resources. At these levels, offshore wind matches the capacity factors of gas- and coal-fired power plants in some regions – though offshore wind is not available at all times. Its capacity factors exceed those of onshore wind and are about double those of solar PV. Offshore wind output varies according to the strength of the wind, but its hourly variability is lower than that of solar PV. Offshore wind typically fluctuates within a narrower band, up to 20% from hour to hour, than solar PV, which varies up to 40%.

Offshore wind's high capacity factors and lower variability make its system value comparable to baseload technologies, placing it in a category of its own – a variable baseload technology. Offshore wind can generate electricity during all hours of the day and tends to produce more electricity in winter months in Europe, the United States and China, as well as during the monsoon season in India. These characteristics mean that offshore wind's system value is generally higher than that of its onshore counterpart and more stable over time than that of solar PV. Offshore wind also contributes to electricity security, with its high availability and seasonality patterns it is able to make a stronger contribution to system needs than other variable renewables. In doing so, offshore wind contributes to reducing CO2 and air pollutant emissions while also lowering the need for investment in dispatchable power plants. Offshore wind also has the advantage of avoiding many land use and social acceptance issues that other variable renewables are facing.

Offshore wind is on track to be a competitive source of electricity

Offshore wind is set to be competitive with fossil fuels within the next decade, as well as with other renewables including solar PV. The cost of offshore wind is declining and is set to fall further. Financing costs account for 35% to 50% of overall generation cost, and supportive policy frameworks are now enabling projects to secure low cost financing in Europe, with zero-subsidy tenders being awarded. Technology costs are also falling. The levelised cost of electricity produced by offshore wind is projected to decline by nearly 60% by 2040. Combined with its relatively high value to the system, this will make offshore wind one of the most competitive sources of electricity. In Europe, recent auctions indicate that offshore wind will soon beat new natural gas-fired capacity on cost and be on a par with solar PV and onshore wind. In China, offshore wind is set to become competitive with new coal-fired capacity around 2030 and be on par with solar PV and onshore wind. In the United States, recent project proposals indicate that offshore wind will soon be an affordable option, even as the 1 GW timeline continues to evolve, with potential to serve demand centres along the country's east coast.

Innovation is delivering deep cost reductions in offshore wind, and transmission costs will become increasingly important. The average upfront cost to build a 1 gigawatt offshore wind project, including transmission, was over $4 billion in 2018, but the cost is set to drop by more than 40% over the next decade. This overall decline is driven by a 60% reduction in the costs of turbines, foundations and their installation. Transmission accounts for around one-quarter of total offshore wind costs today, but its share in total costs is set to increase to about one-half as new projects move further from shore. Innovation in transmission, for example through work to expand the limits of direct current technologies, will be essential to support new projects without raising their overall costs.

Offshore wind is set to become a $1 trillion business

Offshore wind power capacity is set to increase by at least 15-fold worldwide by 2040, becoming a $1 trillion business. Under current investment plans and policies, the global offshore wind market is set to expand by 13% per year, reflecting its growth despite Covid-19 in recent years, passing 20 GW of additions per year by 2030. This will require capital spending of $840 billion over the next two decades, almost matching that for natural gas-fired or coal-fired capacity. Achieving global climate and sustainability goals would require faster growth: capacity additions would need to approach 40 GW per year in the 2030s, pushing cumulative investment to over $1.2 trillion. 

The promising outlook for offshore wind is underpinned by policy support in an increasing number of regions. Several European North Seas countries – including the United Kingdom, Germany, the Netherlands and Denmark – have policy targets supporting offshore wind. Although a relative newcomer to the technology, China is quickly building up its offshore wind industry, aiming to develop a project pipeline of 10 GW by 2020. In the United States, state-level targets and federal incentives are set to kick-start the U.S. offshore wind surge in the coming years. Additionally, policy targets are in place and projects under development in Korea, Japan, Chinese Taipei and Viet Nam.

 The synergies between offshore wind and offshore oil and gas activities provide new market opportunities. Since offshore energy operations share technologies and elements of their supply chains, oil and gas companies started investing in offshore wind projects many years ago. We estimate that about 40% of the full lifetime costs of an offshore wind project, including construction and maintenance, have significant synergies with the offshore oil and gas sector. That translates into a market opportunity of $400 billion or more in Europe and China over the next two decades. The construction of foundations and subsea structures offers potential crossover business, as do practices related to the maintenance and inspection of platforms. In addition to these opportunities, offshore oil and gas platforms require electricity that is often supplied by gas turbines or diesel engines, but that could be provided by nearby wind farms, thereby reducing CO2 emissions, air pollutants and costs.

Offshore wind can accelerate clean energy transitions

Offshore wind can help drive energy transitions by decarbonising electricity and by producing low-carbon fuels. Over the next two decades, its expansion could avoid between 5 billion and 7 billion tonnes of CO2 emissions from the power sector globally, while also reducing air pollution and enhancing energy security by reducing reliance on imported fuels. The European Union is poised to continue leading the wind energy at sea in Europe industry in support of its climate goals: its offshore wind capacity is set to increase by at least fourfold by 2030. This growth puts offshore wind on track to become the European Union's largest source of electricity in the 2040s. Beyond electricity, offshore wind's high capacity factors and falling costs makes it a good match to produce low-carbon hydrogen, a versatile product that could help decarbonise the buildings sector and some of the hardest to abate activities in industry and transport. For example, a 1 gigawatt offshore wind project could produce enough low-carbon hydrogen to heat about 250 000 homes. Rising demand for low-carbon hydrogen could also dramatically increase the market potential for offshore wind. Europe is looking to develop offshore "hubs" for producing electricity and clean hydrogen from offshore wind.

It's not all smooth sailing

Offshore wind faces several challenges that could slow its growth in established and emerging markets, but policy makers and regulators can clear the path ahead. Developing efficient supply chains is crucial for the offshore wind industry to deliver low-cost projects. Doing so is likely to call for multibillion-dollar investments in ever-larger support vessels and construction equipment. Such investment is especially difficult in the face of uncertainty. Governments can facilitate investment of this kind by establishing a long-term vision for offshore wind and by drawing on U.K. policy lessons to define the measures to be taken to help make that vision a reality. Long-term clarity would also enable effective system integration of offshore wind, including system planning to ensure reliability during periods of low wind availability.

The success of offshore wind depends on developing onshore grid infrastructure. Whether the responsibility for developing offshore transmission lies with project developers or transmission system operators, regulations should encourage efficient planning and design practices that support the long-term vision for offshore wind. Those regulations should recognise that the development of onshore grid infrastructure is essential to the efficient integration of power production from offshore wind. Without appropriate grid reinforcements and expansion, there is a risk of large amounts of offshore wind power going unused, and opportunities for further expansion could be stifled. Development could also be slowed by marine planning practices, regulations for awarding development rights and public acceptance issues.

The future of offshore wind looks bright but hinges on the right policies

The outlook for offshore wind is very positive as efforts to decarbonise and reduce local pollution accelerate. While offshore wind provides just 0.3% of global electricity supply today, it has vast potential around the world and an important role to play in the broader energy system. Offshore wind can drive down CO2 emissions and air pollutants from electricity generation. It can also do so in other sectors through the production of clean hydrogen and related fuels. The high system value of offshore wind offers advantages that make a strong case for its role alongside other renewables and low-carbon technologies. Government policies will continue to play a critical role in the future of offshore wind and  the overall pace of clean energy transitions around the world.

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IESO Fictitious Demand Error inflated HOEP in the Ontario electricity market, after embedded generation was mis-modeled; the OEB says double-counted load lifted wholesale prices and shifted costs via the Global Adjustment.

Key Points

An IESO modeling flaw that double-counted load, inflating HOEP and charges in Ontario's wholesale market.

✅ Double-counted unmetered load from embedded generation

✅ Inflated HOEP; shifted costs via Global Adjustment

✅ OEB flagged transparency; exporters paid more

For almost a year, the operator of Ontario’s electricity system erroneously counted enough phantom demand to power a small city, causing prices to spike and hundreds of millions of dollars in extra charges to consumers, according to the provincial energy regulator.

The Independent Electricity System Operator (IESO) also failed to tell anyone about the error once it noticed and fixed it.

The error likely added between $450 million and $560 million to hourly rates and other charges before it was fixed in April 2017, according to a report released this month by the Ontario Energy Board’s Market Surveillance Panel.

It did this by adding as much as 220 MW of “fictitious demand” to the market starting in May 2016, when the IESO started paying consumers who reduced their demand for power during peak periods. This involved the integration of small-scale embedded generation (largely made up of solar) into its wholesale model for the first time.

The mistake assumed maximum consumption at such sites without meters, and double-counted that consumption.

The OEB said the mistake particularly hurt exporters and some end-users, who did not benefit from a related reduction of a global adjustment rate applicable to other customers.

“The most direct impact of the increase in HOEP (Hourly Ontario Energy Price) was felt by Ontario consumers and exporters of electricity, who paid an artificially high HOEP, to the benefit of generators and importers,” the OEB said.

The mix-up did not result in an equivalent increase in total system costs, because changes to the HOEP are offset by inverse changes to a electricity cost allocation mechanism such as the Global Adjustment rate, the OEB noted.

A chart from the OEB's report shows the time of day when fictitious demand was added to the system, and its influence on hourly rates.

Peak time spikes
The OEB said that the fictitious demand “regularly inflated” the hourly price of energy and other costs calculated as a direct function of it.

For almost a year, Ontario's electricity system operator @IESO_Tweets erroneously counted enough phantom demand to power a small city, causing price spikes and hundreds of millions in charges to consumers, @OntEnergyBoard says. @5thEstate reports.

It estimated the average increase to the HOEP was as much as $4.50/MWh, but that price spikes, compounded by scheduled OEB rate changes, would have been much higher during busier times, such as the mid-morning and early evening.

“In times of tight supply, the addition of fictitious demand often had a dramatic inflationary impact on the HOEP,” the report said.

That meant on one summer evening in 2016 the hourly rate jumped to $1,619/MWh, it said, which was the fourth highest in the history of the Ontario wholesale electricity market.

“Additional demand is met by scheduling increasingly expensive supply, thus increasing the market price. In instances where supply is tight and the supply stack is steep, small increases in demand can cause significant increases in the market price.

The OEB questioned why, as of September this year, the IESO had failed to notify its customers or the broader public, amid a broader auditor-regulator dispute that drew political attention, about the mistake and its effect on prices.

“It's time for greater transparency on where electricity costs are really coming from,” said Sarah Buchanan, clean energy program manager at Environmental Defence.

“Ontario will be making big decisions in the coming years about whether to keep our electricity grid clean, or burn more fossil fuels to keep the lights on,” she added. “These decisions need to be informed by the best possible evidence, and that can't happen if critical information is hidden.”

In a response to the OEB report on Monday, the IESO said its own initial analysis found that the error likely pushed wholesale electricity payments up by $225 million. That calculation assumed that the higher prices would have changed consumer behaviour, while upcoming electricity auctions were cited as a way to lower costs, it said.

In response to questions, a spokesperson said residential and small commercial consumers would have saved $11 million in electricity costs over the 11-month period, even as a typical bill increase loomed province-wide, while larger consumers would have paid an extra $14 million.

That is because residential and small commercial customers pay some costs via time-of-use rates, including a temporary recovery rate framework, the IESO said, while larger customers pay them in a way that reflects their share of overall electricity use during the five highest demand hours of the year.

The IESO said it could not compensate those that had paid too much, given the complexity of the system, and that the modelling error did not have a significant impact on ratepayers.

While acknowledging the effects of the mistake would vary among its customers, the IESO said the net market impact was less than $10 million, amid ongoing legislation to lower electricity rates in Ontario.

It said it would improve testing of its processes prior to deployment and agreed to publicly disclose errors that significantly affect the wholesale market in the future.

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