Renewable power generation rises in the UK

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The amount of power generated in the UK from renewable sources rose to 5.5% of total electricity generation in 2008, an increase of 4.9% over 2007.

According to the statistics published in the Digest of United Kingdom Energy Statistics 2009, published by the Department of Energy and Climate Change (DECC), on a renewable obligation basis, 5.4% of electricity came from eligible sources, which is nearly treble the 1.8% achieved 2002. Overall, UK energy consumption in 2008 decreased 1.1%.

In 2008, renewables again showed an increase in contribution to the overall energy generation picture. Under the Renewables Obligation to the UK electricity sales policy, energy from renewables has grown from 4.5% in 2006 to 4.8% in 2007 and 5.4% in 2008. Installed electrical generating capacity of renewable sources rose by 19% in 2008, thanks mainly to a 49% increase in offshore wind capacity, a 38% increase in onshore wind capacity and a modest 4% increase in the capacity of sites fuelled by biomass and wastes.

Electricity supplied from nuclear sources continued to decline in 2008, accounting for 47.7 terawatt hours (TWh), or 13% of the total electricity supply of 379 TWh. This is the lowest proportion contributed by nuclear power since 1981.

On the other hand, overall gas demand rose 3.1%, with gas demand for electricity generation rising 6.2%. Gas' share of the UK's supply of electricity was 45%. Conversely, coal consumption fell 7.5% overall in 2008, while there was a 9% decrease in consumption by major power producers, which typically accounts for 82% of total coal demand. About 32% of the electricity generated in the UK came from coal in 2008, down from 34% in 2007.

Last year saw a 0.4% decrease in the total supply of electricity in the UK in 2008 to 399.6 TWh, the third successive year that total electricity supply has fallen. Indigenous electricity supply fell 1.8%, but net imports of electricity more than doubled to 11 TWh caused by both higher imports and lower exports.

Unlike 2007, last year saw the domestic sector becoming the largest electricity consumer (117.8 TWh), while the industrial sector consumed 113.6 TWh. In 2008, domestic consumption increased 2.4%, and industrial consumption decreased 2.9%. The largest energy-consuming industrial sector was Chemical Processing Industry, which accounted for 18% of all industrial energy consumption.

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OEB issues decision on Hydro One's first combined T&D rates application

OEB Hydro One Rate Decision 2023-2027 sets approved transmission and distribution rates in Ontario, with a settlement reducing revenue requirement, modest bill impacts, higher productivity factors, inflation certainty, DVA credits, and First Nations participation measures.

 

Key Points

OEB-approved Hydro One 2023-2027 transmission and distribution rates settlement, lowering costs and limiting bill impacts.

✅ $482.7M revenue reductions vs. original proposal

✅ Avg bill impact: +$0.69 trans., +$2.43 distr. per month

✅ Faster DVA refunds; productivity and efficiency incentives

 

The Ontario Energy Board (OEB) issued its Decision and Order on an application filed by Hydro One Networks Inc. (Hydro One) on August 5, 2021 seeking approval for changes to the rates it charges for electricity transmission and distribution, beginning January 1, 2023 and for each subsequent year through to December 31, 2027. 

The proceeding resulted in the filing of a settlement proposal that the OEB has now approved after concluding that it is in the public interest. 

The negotiated reductions in Hydro One's transmission and distribution revenue requirements over the 2023 to 2027 period total $482.7 million compared to the requests made by Hydro One in its application.

The OEB found that the reductions in Hydro One's proposed capital expenditure and operating, maintenance and administration costs were reasonable, and should not compromise the safety and reliability of Hydro One's transmission and distribution systems. It also concluded that the estimated bill impacts for both transmission and distribution customers are reasonable, and that the January 1, 2023 implementation and effective date of the new rates is appropriate.

In the broader Canadian context, pressures on utility finances at other companies, such as Manitoba Hydro's debt provide additional background for stakeholders.

 

Bill Impacts

This proceeding related to both transmission and distribution operations.

 

Transmission

The new transmission revenue requirement will affect Ontario electricity consumers across the province because it will be incorporated into updated transmission rates, which are paid by electricity distributors and other large consumers connected directly to the transmission system, and distributors then pass this cost on to their customers.

As a result of the settlement approved on the transmission portion of the application, it is estimated that for a typical Hydro One residential customer with a monthly consumption of 750 kWh, the total bill impact averaged over the 2023-2027 period will be an increase of $0.69 per month or 0.5%, which follows the 2021 electricity rate reductions that affected many businesses.

 

Distribution

The new OEB-approved distribution rates will affect Hydro One's distribution customers, including areas served through acquisitions such as the Peterborough Distribution sale which expanded its customer base.

As a result of the settlement reached on the distribution portion of the application, it is estimated that for a typical residential distribution customer of Hydro One with a monthly consumption of 750 kWh, the total bill impact averaged over the 2023-2027 period will be an increase of $2.43 per month or 1.5%.
This proceeding included 24 approved intervenors representing a wide variety of customer classes and other interests. Representatives of 18 of those intervenors participated in the settlement conference. Having this diversity of perspective enriches the already thorough examination of evidence and argument that the OEB routinely undertakes when considering an application.

Other features of the settlement proposal include:

  • A commitment by Hydro One to include, in future operational and capital investment plans, a discussion of how the proposed spending will directly support the achievement of Hydro One's climate change policy.
  • Eliminating further updates to reflect changes to inflation in 2022 and 2023 as originally proposed, to provide Hydro One's customers with greater certainty as to the potential impacts of inflation on their bills.
  • Increases in the productivity factors and supplemental stretch factors for both the distribution and transmission business segments which will provide Hydro One with additional incentives to achieve greater efficiencies during the 2023 to 2027 period.
  • Undertaking certain measures to seek economic participation or equity investment opportunities from First Nations.
  • Disposition of net credit balances in deferral and variance accounts (DVAs) owed to customers will be returned over a shorter period of time:
  • Transmission DVA – $22.5M over a one-year period in 2023 (versus five years)
  • Distribution DVA – $85.9M over a three-year period – 2023-2025 (versus five years)
  • Undertaking certain measures to continue examining cost-effective transmission and distribution line losses
  • In the decision, the OEB acknowledged the efforts involved by parties to participate in this entire proceeding, including the settlement conference, considering the number of participants, the complexity of the issues, and the challenging logistics of a "virtual" proceeding. The OEB commended the parties and OEB staff for achieving a comprehensive settlement on all issues.

 

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Nunavut's electricity price hike explained

Nunavut electricity rate increase sees QEC raise domestic electricity rates 6.6% over two years, affecting customer rates, base rates, subsidies, and kWh overage charges across communities, with public housing exempt and territory-wide pricing denied.

 

Key Points

A 6.6% QEC hike over 2018-2019, affecting customer rates, subsidies, and kWh overage; public housing remains exempt.

✅ 3.3% on May 1, 2018; 3.3% on Apr 1, 2019

✅ Subsidy caps: 1,000 kWh Oct-Mar; 700 kWh Apr-Sep

✅ Territory-wide base rate denied; public housing exempt

 

Ahead of the Nunavut government's approval of the general rate increase for the Qulliq Energy Corporation, many Nunavummiut wondered how the change would impact their electricity bills.

QEC's request for a 6.6-per-cent increase was approved by the government last week. The increase will be spread out over two years, a pattern similar to BC Hydro's two-year rate plan, with the first increase (3.3 per cent) effective May 1, 2018. The remaining 3.3 per cent will be applied on April 1, 2019.

Public housing units, however, are exempt from the government's increase altogether.

The power corporation also asked for a territory-wide rate, so every community would pay the same base rate (we'll go over specific terms in a minute if you're not familiar with them). But that request was denied, even as Manitoba Hydro scaled back increases next year, and QEC will now take the next two years reassessing each community's base rate.

#google#

So, what does this mean for your home's power bill? Well, there's a few things you need to know, which we'll get to in a second.

But in essence, as long as you don't go over the government-subsidized monthly electricity usage limit, you're paying an extra 3.61 cents per kilowatt hour (kWh).

To be clear, we're talking about non-government domestic rates — basically, private homeowners — and those living in a government-owned unit but pay for their own power.

 

The basics

First, some quick terminology. The "base rate" term we're going to use (and used above) in this story refers to the community rate. As in, what QEC charges customers in every community. The "customer rate" is the rate customers actually pay, after the government's subsidy.

 

The first thing you need to know is everyone in Nunavut starts off by paying the same customer rate, unlike jurisdictions using a price cap to limit spikes.

That's because the government subsidizes electricity costs, and that subsidy is different in every community, because the base rate is different.

For example, Iqaluit's new base rate after the 3.3 per cent increase (remember, the 6.6 per cent is being applied over two years) is 56.69 cents per kWh, while Kugaaruk's base rate rose to 112.34 cents per kWh. Those, by the way, are the territory's lowest and highest respective base rates.

However, customers in both Iqaluit and Kugaaruk will each now pay 28.35 cents per kWh because, remember, the government subsidizes the base rates in every community.

Now, remember earlier we mentioned a "government-subsidized monthly electricity usage limit?" That's where customers in various communities start to pay different amounts.

As simply as we can explain it, the government will only cover so much electricity usage in a month, in every household.

Between October and March, the government will subsidize the first 1,000 kilowatt hours, and only 700 kilowatt hours from April to September. QEC says the average Nunavut home will use about 500 kilowatt hours every month over the course of a year.

But if your household goes over that limit, you're at the mercy of your community's base rate for any extra electricity you use. Homes in Kugaaruk in December, for instance, will have to pay that 122.34 cents for every extra kilowatt hour it uses, while homes in Iqaluit only have to pay 56.69 cents per kWh for its extra electricity.

That's where many Nunavummiut have criticized the current rate structure, because smaller communities are paying more for their extra costs than larger communities.

QEC had hoped — as it had asked for — to change the structure so every community pays the same base rate. So regardless of if people go over their electricity usage limits for the government subsidy, everyone would pay the same overage rates.

But the government denied that request.

 

New rate is actually lower

The one thing we should highlight, however, is the new rate after the increase is actually lower than what customers were paying in 2014.

For the past seven months, customers have been getting power from QEC at a discount, whereas Newfoundland customers began paying for Muskrat Falls during the same period, to different effect.

That's because when QEC sets its rates, it does so based on global oil price forecasts. Since 2014, the price of oil worldwide has slumped, and so QEC was able to purchase it at less than it had anticipated.

When that happens, and QEC makes more than $1 million within a six month period thanks to the lower oil prices, it refunds the excess profits back to customers through a discount on electricity base rates — a mechanism similar to a lump-sum credit used elsewhere — the government subsidy, however, doesn't change so the savings are passed on directly to customers.

Now, the 6.6 per cent increase to electricity rates, is actually being applied to the discounted base rate from the last seven months.

So again, while customers are paying more than they have been for the last seven months, it's lower than what they were paying in 2014.

Lastly, to be clear, all the figures used in this story are only for domestic non-government rates. Commercial rates and changes have not been explored in this story, given the differences in subsidy and rate application.

 

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Ireland goes 25 days without using coal to generate electricity

Ireland Coal-Free Electricity Record: EirGrid reports 25 days without coal on the all-island grid, as wind power, renewables, and natural gas dominated generation, cutting CO2 emissions, with Moneypoint sidelined by market competitiveness.

 

Key Points

It is a 25-day period when the grid used no coal, relying on gas and renewables to reduce CO2 emissions.

✅ 25 days coal-free between April 11 and May 7

✅ Gas 60%, renewables 30% of generation mix

✅ Eurostat: 6.8% drop in Ireland's CO2 emissions

 

The island of Ireland has gone a record length of time without using coal-fired electricity generation on its power system, Britain's week-long coal-free run providing a recent comparator, Eirgrid has confirmed.

The all-island grid operated without coal between April 11th and May 7th – a total of 25 days, it confirmed. This is the longest period of time the grid has operated without coal since the all-island electricity market was introduced in 2007, echoing Britain's record coal-free stretch seen recently.

Ireland’s largest generating station, Moneypoint in Co Clare, uses coal, with recent price spikes in Ireland fueling concerns about dispatchable capacity, as do some of the larger generation sites in Northern Ireland.

The analysis coincides with the European statistics agency, Eurostat publishing figures showing annual CO2 emissions in Ireland fell by 6.8 per cent last year; partly due to technical problems at Moneypoint.

Over the 25-day period, gas made up 60 per cent of the fuel mix, while renewable energy, mainly wind, accounted for 30 per cent, echoing UK wind surpassing coal in 2016 across the market. Coal-fired generation was available during this period but was not as competitive as other methods.

EirGrid group chief executive Mark Foley said this was “a really positive development” as coal was the most carbon intense of all electricity sources, with its share hitting record lows in the UK in recent years.

“We are acutely aware of the challenges facing the island in terms of meeting our greenhouse gas emission targets, mindful that low-carbon generation stalled in the UK in 2019, through the deployment of more renewable energy on the grid,” he added.

Last year 33 per cent of the island’s electricity came from renewable energy sources, German renewables surpassing coal and nuclear offering a parallel milestone, a new record. Coal accounted for 9 per cent of electricity generation, down from 12.9 per cent in 2017.

 

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Pickering NGS life extensions steer Ontario towards zero carbon horizon

OPG Pickering Nuclear Refurbishment extends four CANDU reactors to bolster Ontario clean energy, grid reliability, and decarbonization goals, leveraging Darlington lessons, mature supply chains, and AtkinsRealis OEM expertise for cost effective life extension.

 

Key Points

Modernizing four Pickering CANDU units to extend life, add clean power, and enhance Ontario grid reliability.

✅ Extends four 515 MW CANDU reactors by 30 years

✅ Supports clean, reliable baseload and decarbonization

✅ Leverages Darlington playbook and AtkinsRealis OEM supply chain

 

In a pivotal shift last month, Ontario Power Generation (OPG) revised its strategy for the Pickering Nuclear Power Station, scrapping plans to decommission its six remaining reactors. Instead, OPG has opted to modernize four reactors (Pickering B Units 5-8) starting in 2027, while Units 1 and 4 are slated for closure by the end of the current year.

This revision ensures the continued operation of the four 515 MW Canada Deuterium Uranium (CANDU) reactors—originally constructed in the 1970s and 1980s—extending their service life by at least 30 more years amid an extension request deadline for Pickering.

Todd Smith, Ontario's Energy Minister, underscored the significance of nuclear power in maintaining Ontario's status as a region with one of the cleanest and most reliable electricity grids globally. He emphasized the integral role of nuclear facilities, particularly the Pickering station, in the provincial energy strategy during the announcement supporting continued operations, which was made in the presence of union workers at the plant.

The Pickering station has demonstrated remarkable efficiency and reliability, notably achieving its second-highest output in 2023 and setting a record in 2022 for continuous operation. Extending the lifespan of nuclear plants like Pickering is deemed the most cost-effective method for sustaining low-carbon electricity, according to research conducted by the International Energy Agency (IEA) and the OECD Nuclear Energy Agency (NEA) across 243 plants in 24 countries.

The refurbishment project is poised to significantly boost Ontario's economy, projected to add CAN$19.4 billion to the GDP over 11 years and generate approximately 11,000 jobs annually. The Independent Electricity System Operator (IESO) has indicated that to meet the province's future electrification and decarbonization goals, as it faces a growing electricity supply gap, Ontario will need to double its nuclear capacity by 2050, requiring an addition of 17.8 GW of nuclear power.

Subo Sinnathamby, OPG's Senior Vice President of Nuclear Refurbishment, emphasized the necessity of nuclear energy in reducing reliance on natural gas. Sinnathamby, who is leading the refurbishment efforts at OPG's Darlington nuclear power station, where SMR plans are also underway, highlighted the positive impact of the Darlington and Bruce Power projects on the nuclear power supply chain and workforce.

The procurement strategy employed for Darlington, which involved placing orders early to ensure readiness among suppliers, is set to be replicated for the Pickering refurbishment. This approach aims to facilitate a seamless transition of skilled workers and resources from Darlington to Pickering refurbishment, leveraging a matured supply chain and experienced vendors.

AtkinsRealis, the original equipment manufacturer (OEM) for CANDU reactors, has a track record of successfully refurbishing CANDU plants worldwide. The CANDU reactor design, known for its refurbishment capabilities, allows for individual replacement of pressure tubes and access to fuel channels without decommissioning the reactor. Gary Rose, Executive Vice-President of Nuclear at AtkinsRealis, highlighted the economic benefits and environmental benefits of refurbishing reactors, stating it as a viable and swift solution to maximize fossil-free energy.

Looking forward, AtkinsRealis is exploring the potential for multiple refurbishments of CANDU reactors, which could extend their operational life beyond 100 years, addressing local energy needs and economic factors in the decision-making process. This innovative approach underscores the role of nuclear refurbishment in meeting global energy demands sustainably and economically.

 

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New England Emergency fuel stock to cost millions

Inventoried Energy Program pays ISO-NE generators for fuel security to boost winter reliability, with FERC approval, covering fossil, nuclear, hydropower, and batteries, complementing capacity markets to enhance grid resilience during severe cold snaps.

 

Key Points

ISO-NE program paying generators to hold fuel or energy reserves for emergencies, boosting winter reliability.

✅ FERC-approved stopgap for 2023 and 2024 winter seasons

✅ Pays for on-site fuel or stored energy during cold-trigger events

✅ Open to fossil, nuclear, hydro, batteries; limited gas participation

 

Electricity ratepayers in New England will pay tens of millions of dollars to fossil fuel and nuclear power plants later this decade under a program that proponents say is needed to keep the lights on during severe winters but which critics call a subsidy with little benefit to consumers or the grid, even as Connecticut is pushing a market overhaul across the region.

Last week the Federal Energy Regulatory Commission said ISO-New England, which runs the six-state power grid, can create what it calls the Inventoried Energy Program or IEP. This basically will pay certain power plants to stockpile of fuel for use in emergencies during two upcoming winters as longer-term solutions are developed.

The federal commission called it a reasonable short-term solution to avoid brownouts which doesn’t favor any given technology.

Not all agree, however, including FERC Commissioner Richard Glick, who wrote a fiery dissent to the other three commissioners.

“The program will hand out tens of millions of dollars to nuclear, coal and hydropower generators without any indication that those payments will cause the slightest change in those generators’ behavior,” Glick wrote. “Handing out money for nothing is a windfall, not a just and reasonable rate.”

The program is the latest reaction by ISO-NE to the winter of 2013-14 when New England almost saw brownouts because of a shortage of natural gas to create electricity during a pair of week-long deep freezes.

ISO-New England says the situation is more critical now because of the possible retirement of the gas-fired Mystic Generating Station in Massachusetts. As with closed nuclear plants such as Vermont Yankee and Pilgrim in Massachusetts, power plant owners say lower electricity prices, partly due to cheap renewables and partly to stagnant demand, means they can’t be profitable just by selling power.

Programs like the IEP are meant to subsidize such plants – “incentivize” is the industry term – even though some argue there is no need to subsidize nuclear in deregulated markets so they’ll stay open if they are needed.

The IEP approved last week will be applied to the winters of 2023 and 2024, after a different subsidy program expires. It sets prices, despite warnings about rushing pricing changes from industry groups, for stocking certain amounts of fuel and payments during any “trigger” event, defined as a day when the average of high and low temperatures at Bradley International Airport in Connecticut is no more than 17 degrees Fahrenheit.

These payments will be made on top of a complex system of grid auctions used to decide how much various plants get paid for generating electricity at which times.

ISO-NE estimates the new program will cost between $102 million and $148 million each winter, depending on weather and market conditions.

It says the payments are open to plants that burn oil, coal, nuclear fuel, wood chips or trash; utility-scale battery storage facilities; and hydropower dams “that store water in a pond or reservoir.” Natural gas plants can participate if they guarantee to have fuel available, but that seems less likely because of winter heating contracts.

A major complaint and groups that filed petitions opposing the project is that ISO-NE presented little supporting evidence of how prices, amount and overall cost were determined. ISO-NE argued that there wasn’t time for such analysis before the Mystic shutdown, and FERC agreed.

“The proposal is a step in the right direction … while ISO-NE finishes developing a long-term market solution,” the commission said in its ruling.

The program is the latest example of complexities facing the nation’s electricity system evolves in the face of solar and wind power, which produce electricity so cheaply that they can render traditional power uneconomic but which can’t always produce power on demand, prompting discussions of Texas grid improvements among policymakers. Another major factor is climate change, which has increased the pressure to support renewable alternatives to plants that burn fossil fuels, as well as stagnant electricity demand caused by increased efficiency.

Opponents, including many environmental groups, say electricity utilities and regulators are too quick to prop up existing systems, as the 145-mile Maine transmission line debate shows, built when electricity was sent one way from a few big plants to many customers. They argue that to combat climate change as well as limit cost, the emphasis must be on developing “non-wire alternatives” such as smart systems for controlling demand, in order to take advantage of the current system in which electricity goes two ways, such as from rooftop solar back into the grid.

 

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Romania enhances safety at Cernavoda, IAEA reports

IAEA OSART Cernavoda highlights strengthened operational safety at Romania’s Cernavoda NPP, citing improved maintenance practices, simulator training, and deficiency reporting, with ongoing actions on spare parts procurement, procedure updates, and chemical control for nuclear compliance.

 

Key Points

An IAEA follow-up mission confirming improved operational safety at Cernavoda NPP, with remaining actions tracked.

✅ Enhanced simulator training and crew performance

✅ Improved field deficiency identification and reporting

✅ Ongoing upgrades to procedures, spares, and chemical control

 

The International Atomic Energy Agency (IAEA) said yesterday that the operator of Romania’s Cernavoda nuclear power plant had demonstrated "strengthened operational safety" by addressing the findings of an initial IAEA review in 2016. The Operational Safety Review Team (OSART) concluded a five-day follow-up mission on 8 March to the Cernavoda plant, which is on the Danube-Black Sea Canal, about 160 km from Bucharest.

The plant's two 706 MWe CANDU pressurised heavy water reactors, reflecting Canadian nuclear projects, came online in 1996 and 2007, respectively.

The OSART team was led by Fuming Jiang, a senior nuclear safety officer at the IAEA, which recently commended China's nuclear security in separate assessments.

"We saw improvements in key areas, such as the procurement of important spare parts, the identification and reporting of some deficiencies, and some maintenance work practices, as evidenced by relevant performance indicators," Jiang said, noting milestones at nuclear projects worldwide this year.

The team observed that several findings from the 2016 review had been fully addressed, including: enhanced operator crew performance during simulator training; better identification and reporting of deficiencies in the field; and improvement in maintenance work practices.

More time is required, it said, to fully implement some actions, including: further improvements in the procurement of important spare parts with relevance to safety; further enhancement in the revision and update of some operating procedures, drawing on lessons from Pickering NGS life extensions undertaken in Ontario; and control and labelling of some plant chemicals.

Dan Bigu, site vice president of Cernavoda NPP, said the 2016 mission had "proven to be very beneficial", adding that the current follow-up mission would "provide further catalyst support to our journey to nuclear excellence".

The team provided a draft report of the mission to the plant's management and a final report will be submitted to the Romanian government, which recently moved to terminate talks with a Chinese partner on a separate nuclear project, within three months.

OSART missions aim to improve operational safety by objectively assessing safety performance, even as the agency reports mines at Ukraine's Zaporizhzhia plant amid ongoing risks, using the IAEA's safety standards and proposing recommendations and suggestions for improvement where appropriate. The follow-up missions are standard components of the OSART programme and, as the IAEA has warned of risks from attacks on Ukraine's power grids, are typically conducted within two years of the initial mission.

 

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